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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
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2023
For the transition period from to
Commission File Number 001-32942
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
Nevada
(State or other jurisdiction of
incorporation or organization)
41-1781991
(IRS Employer
Identification No.)
1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079
(Address of principal executive offices and zip code)
(713) 935-0122
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class
Common Stock, $0.001 par value
Securities registered pursuant to Section 12(g) of the Act: None
Trading Symbol(s)
Name of Each Exchange On Which Registered
EPM
NYSE American
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes: ☐ No: ☒
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes: ☐ No: ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such
shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes: ☒ No: ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during
the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes: ☒ No: ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definition of
"large accelerated filer", "accelerated filer", "smaller reporting company" and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
☐
Accelerated filer
☒
Non-accelerated filer
☐
Smaller reporting company
Emerging growth company
☒
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards
provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under
Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: ☐ No: ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2022, the last business day of the registrant’s most recently completed second fiscal
quarter, based on the closing price on that date of $7.55 on the NYSE American was $233.4 million.
The number of shares outstanding of the registrant’s common stock, par value $0.001, as of September 8, 2023, was 33,235,723.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the proxy statement related to the registrant’s 2023 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.
Table of Contents
EVOLUTION PETROLEUM CORPORATION
2023 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Forward-Looking Statements
Glossary of Selected Petroleum Industry Terms
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
PART II
Item 5.
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
Item 9C.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Item 16.
Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Reserved
Management’s Discussion and Analysis of Financial Condition and Results of Operations
Quantitative and Qualitative Disclosures About Market Risks
Consolidated Financial Statements and Supplementary Data
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Directors, Executive Officers, and Corporate Governance
Executive Compensation
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Certain Relationships and Related Transactions, and Director Independence
Principal Accounting Fees and Services
Exhibits and Financial Statement Schedules
From 10-K Summary
Exhibit Index
Signatures
ii
iv
1
15
26
26
26
26
27
27
28
29
39
40
75
75
76
76
77
77
77
77
77
77
78
78
78
79
82
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. All statements, except for statements of historical fact, are forward-looking statements.
The words “plan,” “expect,” “project,” “estimate,” “may,” “assume,” “believe,” “anticipate,” “intend,” “budget,”
“forecast,” “predict” and other similar expressions are intended to identify forward-looking statements, although not all
forward-looking statements contain such identifying words or phrases. 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, which may include, but are not limited to, the following:
● our expectations of plans, strategies and objectives, including anticipated development activity and capital
spending;
● our capital allocation strategy, capital structure, anticipated sources of funding, growth in long-term
shareholder value and ability to preserve balance sheet strength;
● the benefits of our multi-basin portfolio, including operational and commodity flexibility;
● our ability to maximize cash flow and the application of excess cash flows to pay dividends and repurchase
shares pursuant to our share repurchase program;
● estimates of our oil, natural gas and NGLs production and commodity mix;
● anticipated oil, natural gas and NGL prices;
● anticipated drilling and completions activity;
● estimates of our oil, natural gas and NGL reserves and recoverable quantities;
● our ability to access credit facilities and other sources of liquidity to meet financial obligations throughout
commodity price cycles;
● limitations on our ability to obtain funding based on environmental, social, and corporate governance
(“ESG”) performance;
● future interest expense;
● our ability to manage debt and financial ratios, finance growth and comply with financial covenants;
● the implementation and outcomes of risk management programs, including exposure to commodity price and
interest rate fluctuations, the volume of oil and natural gas production hedged, and the markets or physical
sales locations hedged;
● the impact of changes in federal, state, provincial and local, rules and regulations;
● anticipated compliance with current or proposed environmental requirements, including the costs thereof;
● the possible impact of greenhouse gas (“GHG”) emissions limitations and renewable energy incentives;
● adequacy of provisions for abandonment and site reclamation costs;
● our operational and financial flexibility, discipline and ability to respond to evolving market conditions;
● the declaration and payment of future dividends and any anticipated repurchase of our outstanding common
shares;
● the adequacy of our provision for taxes and legal claims;
● our ability to manage cost inflation and expected cost structures, including expected operating,
transportation, processing and labor expenses;
● our competitiveness relative to our peers, including with respect to capital, materials, people, assets and
production;
● oil, natural gas and NGL inventories and global demand for oil, natural gas and NGLs;
● the outlook of the oil and natural gas industry generally, including impacts from changes to the geopolitical
environment;
● adverse weather events;
● anticipated staffing levels;
● anticipated payments related to our commitments, obligations and contingencies, and the ability to satisfy the
same; and
● the possible impact of accounting and tax pronouncements, rule changes and standards.
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Readers are cautioned against unduly relying on forward-looking statements which, by their nature, involve numerous
assumptions and are subject to both known and unknown risks and uncertainties (many of which are beyond our control)
that may cause actual events or results to differ materially and/or adversely from those expressed or implied, which
include, but are not limited to the following assumptions:
● future commodity prices and basis differentials;
● our ability to access credit facilities and shelf prospectuses;
● assumptions contained in our corporate guidance;
● the availability of attractive commodity or financial hedges and the enforceability of risk management
programs;
● expectations that counterparties will fulfill their obligations pursuant to gathering, processing, transportation
and marketing agreements;
● access to adequate gathering, transportation, processing and storage facilities;
● assumed tax, royalty and regulatory regimes;
● expectations and projections made in light of, and generally consistent with, our historical experience and our
perception of historical industry trends; and
● the other assumptions contained herein.
Readers are cautioned that the assumptions, risks and uncertainties referenced above, and in the other documents
incorporated herein by reference (if any), are not exhaustive. Although we believe the expectations represented by our
forward-looking statements are reasonable based on the information available to us as of the date such statements are
made, forward-looking statements are only predictions and statements of our current beliefs and there can be no assurance
that such expectations will prove to be correct.
When considering any forward-looking statement, the reader 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, natural gas and NGLs, 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 future reports we file
with the Securities and Exchange Commission. Readers should also consider such information in conjunction with our
consolidated financial statements and related notes and Item 7. 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. Readers are advised, however, to review any further disclosures we make on
related subjects in our filings with the Securities and Exchange Commission.
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Term
Bbl
BCF
BFPD
BOE
BOEPD
BOPD
BTU
CO2
Developed
Reserves
EOR
Field
Farmout
Gross Acres or
Gross Wells
Horizontal
Drilling
Hydraulic
Fracturing
LOE
MBBL
MMBBL
MBOE
MBOEPD
MMBOE
MCF
MMCF
MMBTU
Mineral Royalty
Interest
GLOSSARY OF SELECTED PETROLEUM INDUSTRY TERMS
Definition
One stock tank barrel, of 42 U.S. gallons of liquid volume, used herein in reference to oil or NGL.
Billion cubic feet.
Barrels of fluid per day.
Barrels of oil equivalent. BOE is calculated by converting six MCF of natural gas and 42 gallons of
NGL to one Bbl of oil which reflects energy equivalence and not price equivalence. Natural gas
prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of
oil.
Barrels of oil equivalent per day.
Barrels of oil per day.
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 one degree Fahrenheit. One Bbl of oil is typically 5.8
MMBTU, and one standard MCF is typically one MMBTU.
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.
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.
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.
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.*
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.
The total acres or number of wells participated in, regardless of the amount of working interest
owned.
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.
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 natural gas.
Lease Operating Expense(s); a current period expense incurred to operate a well.
One thousand barrels.
One million barrels.
One thousand barrels of oil equivalent.
One thousand barrels of oil equivalent per day.
One million barrels of oil equivalent.
One thousand cubic feet of natural gas at standard conditions, being approximately sea level pressure
and 60 degrees Fahrenheit temperature.
One million cubic feet of natural gas at standard conditions, being approximately sea level pressure
and 60 degrees Fahrenheit temperature.
One million British Thermal Units.
A royalty interest that is retained by the owner of the minerals underlying a lease. See “Royalty
Interest.”
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Net Acres or Net
Wells
NGL
Non-operated
Interest
Non-operated
Working Interest
NYMEX
OOIP
Operator
Overriding
Royalty Interest
or ORRI
Permeability
Porosity
Primary
Recovery Method
Producing
Reserves
Producing Well
Proved Developed
Reserves
Proved Developed
Nonproducing
Reserves
Proved Developed
Producing
Reserves (“PDP”)
Proved Reserves
The sum of the fractional working interests owned in gross acres or gross wells.
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.
An interest in an oil and/or natural gas property but does not participate in or have any responsibility
for actual operation of the property.
An interest in an oil and/or natural gas property but does not participate in or have any responsibility
for actual operation of the property, but is burdened with the cost of development and operation of
the property.
New York Mercantile Exchange.
Original Oil in Place; an estimate of the barrels originally contained in a reservoir before any
production therefrom.
An oil and natural 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 natural gas production, except for those non-operators who take their production
in-kind.
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.”
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
millidarcy. Extremely low permeability of 10 millidarcy, 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 darcy or more.
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.
The extraction of oil and natural gas from reservoirs using natural or initial reservoir pressure
combined with artificial lift techniques such as pumps.
Any category of reserves that have been developed and production has been initiated.*
Any well that has been developed and production has been initiated.*
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 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 natural gas sales pipeline.*
Proved Reserves that have been developed and production has been initiated.*
Estimated quantities of oil, natural gas, and NGLs 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.*
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Proved
Undeveloped
Reserves (“PUD”)
Present Value
Productive Well
PV-10
Reservoir
Royalty or
Royalty Interest
Secondary
Recovery Method
Shut-in Well
Standardized
Measure
Tertiary Recovery
Method
Undeveloped
Reserves
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.
When used with respect to oil and natural gas reserves, present value means the estimated future net
revenues computed by applying current prices of oil and natural gas reserves (with consideration of
price changes only to the extent provided by contractual arrangements) to estimated future
production of proved oil and natural 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.
A well that is producing oil or natural gas or that is capable of production.
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.
A porous and permeable underground formation containing a natural accumulation of producible oil
and/or natural gas that is confined by impermeable rock or water barriers and is individual and
separate from other reservoirs.
The mineral owner’s share of oil or natural gas production (typically between 1/8 and ¼), 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.
The extraction of oil and natural gas from reservoirs utilizing water injection (waterflooding) in
order to maintain or increase reservoir pressure and direct the displacement of oil into producing
wells.
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.
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 are 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”).
The extraction of oil and natural gas from reservoirs which employs injection of gas, heat, or
chemicals into the reservoir in order to change the physical properties of the oil and aid in its
extraction, also known as Enhanced Oil Recovery (EOR).
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.*
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Water Injection
Well
Working Interest
Workover
A well which is used to inject water under high pressure into a producing formation to maintain
sufficient pressure to produce the recoverable reserves.
The interest in the oil and natural gas in place which is burdened with the cost of development and
operation of the property. Also called the operating interest.
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 iv.
General
Evolution Petroleum Corporation (“Evolution,” and together with its consolidated subsidiaries, the “Company”, “our”,
“we, “us” or similar terms) is an independent energy company focused on maximizing total returns to its shareholders
through the ownership of and investment in onshore oil and natural gas properties in the United States. Our long-term goal
is to maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through
acquisition and through selective development opportunities, production enhancement, and other exploitation efforts on our
oil and natural gas properties.
Recent Developments
Dividend Declaration
On September 11, 2023, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common
share payable September 29, 2023.
Senior Secured Credit Facility
On May 5, 2023, we entered into the Tenth Amendment to our Senior Secured Credit Facility which has a current
borrowing base of $50.0 million. This amendment, among other things, extends the maturity of our Senior Secured Credit
Facility to April 9, 2026 and converts our benchmark interest rate from London Interbank Offered Rate (“LIBOR”) to a
Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment of 0.05%. For further discussion of this
amendment and our Senior Secured Credit Facility, see “Liquidity and Capital Resources” within Item 7. Management’s
Discussion and Analysis of Financial Conditions and Results of Operations.
Appointment of Chief Operating Officer
On February 23, 2023, we announced that the Board of Directors appointed J. Mark Bunch as Chief Operating Officer
(“COO”). Mr. Bunch had been providing consulting services to the Company since 2016. We entered into an offer letter
with Mr. Bunch setting forth his compensation as COO on February 21, 2023.
Appointment of Chief Executive Officer
On October 27, 2022, we announced that the Board of Directors selected Kelly W. Loyd as President and Chief Executive
Officer (“CEO”). Mr. Loyd had been serving as Interim CEO since June 2022 and has served as a member of the Board of
Directors since 2008. We entered into an offer letter with Mr. Loyd setting forth his compensation as CEO on October 25,
2022. Upon commencing employment, Mr. Loyd no longer receives compensation for his services as a member of the
Board of Directors.
Share Repurchase Program
On September 8, 2022, the Board of Directors approved a share repurchase program under which we are authorized to
repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. We intend to fund
repurchases from available working capital and cash provided by operating activities. As we continue to focus on our goal
of maximizing total shareholder return, the Board of Directors and management team believe that a share repurchase
program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder
return. The shares may be repurchased from time to time in open market transactions, through privately negotiated
transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of
shares repurchased under the program, will depend on a variety of factors, including management’s
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assessment of the intrinsic value of our shares, our capital needs and resources, the market price of our common stock,
general market and economic conditions, and applicable legal requirements. The value of shares authorized for repurchase
by our Board of Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased,
and the program may be suspended, modified, or discontinued at any time without prior notice.
Once we completed repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period
in December 2022, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market
subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not
allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum
authorized amount of $5.0 million over that period. During the year ended June 30, 2023, 0.6 million shares of our
common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct
transaction costs. These treasury shares were subsequently cancelled. We may enter into additional Rule 10b5-1 plans in
the future, the terms of which will be approved by the Board of Directors.
Business Strategy
Our business strategy is to maximize total shareholder return based on our assessment of the operating environment and
marketplace, subject to our obligations to other stakeholders. The key elements of our strategy to accomplish our goal of
maximizing shareholder return are:
● Maintaining a strong balance sheet and conservative financial management;
● Growing the asset base through investment in our existing properties, direct acquisitions of new low decline,
long-life oil and natural gas properties, selective development opportunities, or accretive acquisitions of similar
companies; and
● Returning cash to shareholders by sustaining and growing our dividend payout over time or repurchases of our
shares in the open market.
Properties
Our oil and natural gas properties consist of non-operated interests in the following areas: the Jonah Field in Sublette
County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton Dome
Field located in Hot Springs County, Wyoming; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana; as
well as small overriding royalty interests in four onshore central Texas wells.
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Jonah Field – Sublette County, Wyoming
Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of
approximately 20% average net working interest and approximately 15% average net revenue interest located on
approximately 950 net acres all held by production. The properties are operated by Jonah Energy (“Jonah”), an established
operator in the geographic region.
For the year ended June 30, 2023, our average net daily production from the Jonah Field properties was 1.9 MBOEPD
consisting of 90% natural gas, 5% NGLs, and 5% oil. Hydrocarbons produced from our Jonah Field properties are sold to
West Coast markets.
Williston Basin – Williston, North Dakota
Our non-operated interests in the Williston Basin, oil and natural gas producing properties, consist of approximately 39%
average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net
acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
The properties are operated by Foundation Energy Management (“Foundation”), an established operator in the geographic
region.
For the year ended June 30, 2023, our average net daily production from the Willison Basin properties was 0.5 MBOEPD
consisting of 78% oil, 13% NGLs, and 9% natural gas. The primary producing reservoirs are the Three Forks, Pronghorn,
and Bakken formations. Hydrocarbons produced from the Williston Basin properties are sold to local refineries and
purchasers.
Barnett Shale - North Texas
Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately
17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding
royalty interests) located on 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. The oil and natural gas
properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated by six other
operators.
For the year ended June 30, 2023, our average net daily production from the Barnett Shale properties was 3.2 MBOEPD
consisting of 76% natural gas, 23% NGLs, and 1% oil. The producing reservoir is the Barnett Shale, which is also the
source rock. Hydrocarbons produced from our Barnett Shale properties are sold to Gulf Coast markets.
Hamilton Dome – Hot Springs County, Wyoming
Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to
pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net
revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of
which we hold approximately 1,400 net acres, 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. The Hamilton
Dome Field is located in the southwest region of the Big Horn Basin in northwest Wyoming.
For the year ended June 30, 2023, our average net daily production from the Hamilton Dome Field properties was 0.4
MBOEPD consisting of 100% oil. The primary producing reservoirs in the field are the Tensleep and Phosphoria. Produced
oil from the field is subject to Western Canadian Select pricing.
Delhi Field – Enhanced Oil Recovery CO2 Flood – Onshore Louisiana
Our non-operated interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working
interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately
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7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC
(“Denbury”), a subsidiary of Denbury Inc. The Delhi Field is located in northeast Louisiana in Franklin, Madison, and
Richland Parishes and encompasses approximately 14,000 gross unitized acres, or approximately 3,200 net acres.
For the year ended June 30, 2023, our average net daily production from the Delhi Field properties was 1.1 MBOEPD
consisting of 80% oil and 20% NGLs. The primary producing reservoirs in the field are the Tuscaloosa and Paluxy
formations. Produced oil from the field is priced off of Louisiana Light Sweet (“LLS”) crude, which often trades at a
premium to West Texas Intermediate (“WTI").
Refer to “Production volumes, average sales price and average production costs” table below for further information
regarding our properties and their fiscal year results.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues
The Securities and Exchange Commission (“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 2023
Our proved reserves as of June 30, 2023, denominated in thousands of barrels of oil equivalent (“MBOE”), were estimated
by our independent reservoir engineers, Netherland, Sewell & Associates, Inc. (“NSAI”) and DeGolyer and MacNaughton
(“D&M”), both worldwide petroleum consultants.
NSAI evaluated the reserves for our Jonah Field and Williston Basin properties. NSAI began evaluating these properties
when we acquired each of them during the fiscal year ended June 30, 2022. 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.
D&M evaluated the reserves for our Barnett Shale, Hamilton Dome, and Delhi Field properties. The scope and results of
their procedures are summarized in a letter from the firm, which is included as Exhibit 99.2 to this Annual Report on
Form 10-K.
The following table sets forth our estimated proved reserves as of June 30, 2023. For additional reserve information, see
our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial statements in
Item 8. Financial Statements and Supplementary Data. The New York Mercantile Exchange (“NYMEX”) previous 12-
month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $83.23 per
barrel of oil and $4.78 per MMBtu of natural gas. The net price per barrel of NGLs was $33.71, 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.
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Proved Reserves as of June 30, 2023
Reserve Category
Proved:
Developed Producing
Developed Non-
Producing
Undeveloped
Total Proved
Product Mix
Total Proved by
Property:
Jonah Field
Williston Basin
Barnett Shale
Hamilton Dome Field
Delhi Field
Total Proved
Oil
(MBbls)
Natural Gas
(MMcf)
NGLs
(MBbls)
Total Reserves
(MBOE)(1)
Percent of
Total Proved
7,062
122
2,687
9,871
32%
346
4,219
90
2,331
2,885
9,871
90,103
29
2,431
92,563
49%
34,743
3,655
54,165
—
—
92,563
5,263
9
605
5,877
19%
417
886
3,380
—
1,194
5,877
27,343
136
3,697
31,176
100%
6,554
5,714
12,498
2,331
4,079
31,176
87.7 %
0.4 %
11.9 %
100.0 %
21.0 %
18.3 %
40.1 %
7.5 %
13.1 %
100.0 %
(1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion
ratio which reflects energy equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per
barrel often differ significantly from the equivalent amount of oil.
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 internal reserve engineering team, which includes our COO. Our
internal reserve engineering team has a combined experience of over 80 years in Petroleum Engineering. Our COO, the
person responsible for overseeing the preparation of our reserves estimates, has a Bachelor of Science Degree in Petroleum
Engineering from Texas A&M University, is a registered Professional Engineer in the State of Texas (No. 86704), has over
40 years of oil and natural gas experience including large independents and financial firm services for projects and
acquisitions. Our Board of Directors also has oversight of our reserve estimation process and contains a Reserves
Committee with an independent director who is a Registered Professional Engineer in the State of Texas (No. 47279) with
experience in energy company reserve evaluations. Such reserve 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 NSAI and D&M. The person responsible for the
preparation of the reserve report at NSAI is Matthew D. Pankey, P.E., Petroleum Engineer. Mr. Pankey, a licensed
Professional Engineer in the State of Texas (No. 142931), has been practicing consulting petroleum engineering at NSAI
since 2019 and has over six years of prior industry experience. The person responsible for the preparation of the reserve
report at D&M is Dr. Dilhan Ilk, P.E., Executive Vice President. Dr. Ilk 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 13 years of experience in oil and natural
gas reservoir studies and evaluations and is a licensed Professional Engineer in the state of Texas (No. 139334).
We provide NSAI and D&M with our property interests, production, current operating costs, current production prices,
estimated abandonment costs and other information in order for them to prepare the reserve estimates. This information is
reviewed by our senior management team and designated operations personnel to ensure accuracy and completeness of the
data prior to submission to the reserve engineers. The scope and results of NSAI’s and D&M’s procedures, as well as their
professional qualifications, are summarized in the letters included as Exhibit 99.1 and Exhibit 99.2, respectively, to this
Annual Report on Form 10-K.
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Proved Undeveloped Reserves
During the year ended June 30, 2023 our proved undeveloped (“PUD”) reserves changed as follows:
Proved undeveloped reserves:
June 30, 2022
Revisions of previous estimates
Improved recovery, extensions
and discoveries
June 30, 2023
Oil
(MBbls)
Natural Gas
(MMcf)
NGLs
(MBbls)
Total Reserves
(MBOE)(1)
2,608
(19)
98
2,687
2,197
234
—
2,431
623
(38)
20
605
3,597
(18)
118
3,697
(1) Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion
ratio which reflects energy equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per
barrel often differ significantly from the equivalent amount of oil.
Our PUD reserves were 3.7 MMBOE as of June 30, 2023, with related future development costs of approximately
$71.7 million, which are primarily associated with the Williston Basin properties. The downward revisions were due to
adjustments of development timing and economic assumptions at the Williston Basin properties. Extensions of 0.1
MMBOE are associated with two new wells that Denbury, the operator of the Delhi Field, is currently drilling. See
“Drilling and Present Activities” below for a further discussion of our expected development of the PUDs for the Williston
Basin properties.
Drilling and Present Activities
Currently, none of our oil and natural gas properties are operated by us. We therefore rely on information from our
operators regarding near-term drilling programs. As certain of our properties are considered fully developed, there are no
plans to drill new wells in fiscal year 2024 in the Jonah Field, the Barnett Shale, and the Hamilton Dome Field. At this
time, operators of our properties at Williston Basin, Hamilton Dome Field and Delhi Field are periodically running
workover rigs focusing on projects to return wells to production that have experienced mechanical issues.
At Delhi Field, the third-party operator, Denbury, is currently drilling two new down dip wells in the field. Completion and
first production of these wells are expected in the first quarter of fiscal year 2024. Denbury is also evaluating the technical
and economic feasibility of development of Test Site V. Should they choose to propose proceeding with this project, we
anticipate being an active participant based on our current analysis of the project. As of June 30, 2023, Test Site V is not
included in our proved reserves due to timing. For fiscal year 2024, at the Williston Basin, we are evaluating drilling two
sidetrack locations targeting the Birdbear formation with our operator, Foundation. Efforts to continue evaluating other
sidetrack locations and undeveloped drilling locations at the Williston Basin is ongoing.
For further discussion, see “Capital Expenditures” within Item 7. Management’s Discussion and Analysis of Financial
Conditions and Results of Operations.
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Production volumes, average sales price and average production costs
The following table summarizes our crude oil, natural gas, and natural gas liquids production volumes, average sales price
per unit, average daily production on an equivalent basis, production costs, and production costs per unit for the periods
indicated:
2023
Years Ended June 30,
2022
2021
Volume Price
Volume Price
Volume Price
Production:
Crude oil (MBBL)
Jonah Field
Williston Basin
Barnett Shale
Hamilton Dome Field
Delhi Field
Other
Total
Natural gas (MMCF)
Jonah Field
Williston Basin
Barnett Shale
Other
Total
Natural gas liquids (MBBL)
Jonah Field
Williston Basin
Barnett Shale
Delhi Field
Other
Total
Equivalent (MBOE) (1)
Jonah Field(2)
Williston Basin(2)
Barnett Shale
Hamilton Dome Field
Delhi Field
Other
Total
Average daily production (BOEPD) (1)
Jonah Field(2)
Williston Basin(2)
Barnett Shale
Hamilton Dome Field
Delhi Field
Other
Total
$ 84.58
79.38
76.12
65.18
81.57
88.03
$ 77.46
$ 10.63
4.48
4.55
4.66
7.00
$
$ 34.76
27.23
32.54
34.95
26.15
$ 32.86
$ 63.37
68.12
28.89
65.18
72.13
73.71
$ 49.56
36
144
9
149
319
2
659
3,675
96
5,337
1
9,109
36
24
274
81
1
416
685
184
1,173
149
400
2
2,593
1,877
504
3,214
408
1,096
5
7,104
$ 112.50
101.25
82.56
76.03
86.57
58.57
$ 85.11
$
$
7.80
6.30
5.11
1.21
5.49
$ 52.92
38.50
46.91
48.02
18.33
$ 46.89
$ 50.57
88.93
34.27
76.03
79.32
52.08
$ 50.13
10
71
9
150
358
21
619
1,000
40
6,087
14
7,141
12
10
256
83
3
364
189
88
1,280
150
441
25
2,173
518
241
3,507
411
1,208
68
5,953
— $
—
2
143
410
—
555
—
—
52.50
42.23
49.43
—
$ 47.59
— $
—
963
—
963
$
—
—
2.73
—
2.73
— $
—
78
93
—
171
—
—
24.37
18.95
—
$ 21.42
— $
—
241
143
503
—
887
—
—
19.23
42.23
43.80
—
$ 36.87
—
—
660
392
1,378
—
2,430
Production costs (in thousands, except per BOE)
Lease operating costs
Jonah Field
Williston Basin
Barnett Shale
Hamilton Dome Field
Delhi Field
Other
Total
Amount
$ 12,350
5,581
20,756
5,574
15,275
9
$ 59,545
per BOE Amount
$ 2,990
$ 18.03
30.42
2,419
22,825
17.70
37.45
5,480
14,933
38.22
3.35
10
$ 48,657
$ 22.96
$
per BOE Amount
$ 15.82
27.49
17.83
36.53
33.86
0.40
$ 22.39
— $
—
3,028
4,080
9,463
16
$ 16,587
per BOE
—
—
12.56
28.53
18.81
—
$ 18.69
(1)
Equivalent oil reserves are defined as six Mcf of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy
equivalence and not price equivalence. Natural gas prices per Mcf and NGL prices per barrel often differ significantly from the equivalent amount
of oil.
(2) Average daily production presented in the table above represents our fiscal year production divided by 365 days in the year. At Williston and Jonah,
our average daily production since their respective acquisition dates of January 14, 2022 and April 1, 2022 through June 30, 2022, was 0.5
MBOEPD and 2.1 MBOEPD, respectively.
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Productive Wells
The following table sets forth the number of productive oil and natural gas wells in which we own a working interest as of
June 30, 2023.
Oil
Natural gas
Total
Company Operated
Gross Net
—
—
—
—
—
—
Non-Operated
Gross Net
344
1,491
1,835
84.3
216.8
301.1
Total
Gross
344
1,491
1,835
Net
84.3
216.8
301.1
Acreage
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of
June 30, 2023. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would
allow production of oil and natural 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 natural gas in commercial quantities
whether or not the acreage contains proved reserves.
Field(1)
Jonah Field, Wyoming
Williston Basin, North Dakota
Barnett Shale, Texas
Hamilton Dome Field, Wyoming
Delhi Field, Louisiana
Total(2)
Developed Acreage
Net
Gross
Undeveloped Acreage
Gross
Net
5,280
124,800
123,777
5,908
9,126
268,891
956
37,306
20,918
1,389
2,180
62,749
—
20,943
—
—
4,510
25,453
—
6,020
—
—
1,077
7,097
Total
Gross
5,280
145,743
123,777
5,908
13,636
294,344
Net
956
43,326
20,918
1,389
3,257
69,846
(1) Except for our undeveloped acreage in Williston Basin, North Dakota (see expiration table below), 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 late fiscal year 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.
The table below reflects our net undeveloped acreage in Williston Basin, North Dakota as of June 30, 2023 that will expire
each year if we do not establish production in paying quantities on the units in which such acreage is included to maintain
the lease:
Fiscal Year
2024
2025
2026
2027
2028 & beyond
Net Acreage
Expiration(1)
440
1,664
860
—
309
3,273
(1) Excluded 2,747 net acres held by existing production as long as continuous production is maintained in the unit.
Markets and Customers
Our production is marketed to third parties in a manner consistent with industry practices. In the United States market
where our properties are operated, crude oil, natural gas, and NGLs are readily transportable and marketable. In the
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Jonah Field, we take our natural gas and NGL working interest production in-kind and market separately to purchasers on
six-month contracts for natural gas and to Enterprise Products Partners L.P. for NGLs. We do not currently market our
share of oil, natural gas, or NGLs production from the Williston Basin, the Barnett Shale, the Hamilton Dome Field, or the
Delhi 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.
As a non-operator, we are highly dependent on the success of our third-party operators and the decisions made in
connection with their operations. With the exception of the Jonah Field, our third-party operators sell our oil, natural gas,
and NGLs to purchasers, collect the cash, and distribute the cash to us. In the year ended June 30, 2023, approximately
83% of our total revenues were realized from the Jonah Field, Barnett Shale and Delhi Field combined. Diversified, our
largest operator at Barnett remitted approximately 26% of our total revenue proceeds to us and at Delhi Field, Denbury, the
operator of the Field, remitted approximately 22% of our total revenue proceeds to us. At Jonah Field, where we take our
natural gas and NGL production in-kind, during the current year, we sold approximately 17% of our total revenues to
Conoco Phillips. In the year ended June 30, 2022, three operators each distributed over 10% of our oil, natural gas and
NGL revenues making up approximately 83% of total revenues for the year.
The loss of a purchaser at any of our five major producing properties or disruption to pipeline transportation from these
fields could adversely affect our net realized pricing and potentially our near-term production levels.
Market Conditions
Prices we receive for crude 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, the relative strength of the U.S.
dollar, government regulation, weather, and actions of major foreign producers.
Oil and natural gas prices over the past few years have been volatile and we expect that volatility to continue. 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 and domestic factors also influence prices for oil, natural gas, and NGLs and include
increasing or decreasing production trends, quality differences, regulation, legislation 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
We are exposed to certain risks relating to our ongoing business operations, including commodity price risk. In accordance
with our company policies and the covenants under the Senior Secured Credit Facility, 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 do not enter into derivative contracts for speculative
trading purposes.
While there are many different types of derivative instruments available, historically we have used costless collars and
fixed-price swaps to attempt to manage price risk. Costless collar agreements are put and call options used to establish
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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. 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.
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. We will continue to evaluate the benefit of employing
derivatives in the future. Our hedge strategies and objectives may change as our operational profile changes. See Item 7A.
Quantitative and Qualitative Disclosures About Market Risk and Note 7, “Derivatives” to our consolidated financial
statements in Item 8. Financial Statements and Supplementary Data for additional information.
Government Regulation
As an oil and natural gas exploration and production company, our interests are subject to numerous legal requirements.
Regulation of Oil and Natural Gas Production
Federal, state and local authorities have promulgated extensive rules covering oil and natural gas exploration, production
and related operations. Those regulations require our third-party operator to obtain permits, post bonds and submit reports.
They also may address conservation, including unitization or pooling of oil and natural gas properties, well locations, the
method of drilling and casing wells, surface use and restoration of properties where wells are drilled, sourcing and disposal
of water used in the process of drilling, completion and abandonment, the establishment of maximum rates of production
from wells, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural
gas that we can produce and to limit the number of wells or the locations at which we can produce. Moreover, many states
impose a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids
within their jurisdictions. Failure to comply with any applicable legal requirements may result in substantial
penalties. Because such regulations are frequently amended or reinterpreted, we are unable to predict future compliance
costs or impacts. Significant expenditures may be required to comply with governmental laws and regulations, however,
and may have a material adverse effect on our financial condition and results of operations.
Regulation of Transportation of Oil and Natural Gas
The prices for crude oil, condensate and natural gas liquids and natural gas are negotiated and not currently regulated. But
Congress, which has been active in oil and natural gas regulation, could impose price controls in the future.
Our sales of crude oil and natural gas are affected by the availability, terms and cost of transportation. The Federal Energy
Regulatory Commission (“FERC”) primarily regulates interstate oil and natural gas transportation rates. In some
circumstances, FERC regulations also may affect intrastate pipelines. In addition, states may impose on intrastate pipelines
various obligations relating to such matters as safety, environmental protection, nondiscriminatory take and pay rates. The
basis for intrastate oil and natural gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to such
matters, vary from state to state. To the extent effective interstate and intrastate rates are equally applicable to all
comparable shippers, we believe that the regulation of oil and natural gas transportation rates will not affect our business in
any way that is of material difference from those of our competitors who are similarly situated.
Environmental Matters
Our properties are subject to extensive and changing federal, state and local laws and regulations relating to the protection
of the environment, worker safety and human health. Such requirements may address:
● the generation, storage, handling, emission, transportation and disposal of materials;
● reclamation or remediation of sites, including former operating areas;
● the acquisition of a permit or other authorization;
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● air emissions;
● protection of water supplies;
● limits on construction, drilling and other activities in wilderness or other environmentally sensitive areas; and
● assessment of environmental impacts.
Failure to comply with such requirements may result in a variety of sanctions, including fines, administrative orders and
injunctions. In addition, issuing authorities may revoke, adversely condition or deny permits necessary for our operations.
In the opinion of management, our properties are in substantial compliance with applicable environmental laws and
regulations, and we have no material commitments for capital expenditures to comply with existing environmental
requirements. Nevertheless, changes in existing environmental laws and regulations or in interpretations thereof could have
a significant impact on our company, as well as the oil and natural gas industry in general. Significant environmental
requirements that may affect our operations are described below.
The Comprehensive Environmental, Response, Compensation, and Liability Act (“CERCLA”) and comparable state
statutes impose strict liability, and in some cases joint and several liability, on owners and operators of sites and on persons
who arranged for the disposal of “hazardous substances” found at such sites. It is not uncommon for neighboring
landowners or other third parties to also file claims for personal injury and property damage allegedly caused by any
hazardous substances released into the environment. Although CERCLA currently excludes petroleum from its definition
of “hazardous substance,” our operations do entail handling other chemicals that may be subject to the statute. In addition,
state laws affecting our properties may impose cleanup liability relating to petroleum and petroleum related products. The
Federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes govern the disposal of “solid
waste” and “hazardous waste.” Violations may result in substantial fines. Although RCRA currently classifies certain oil
field wastes as “non-hazardous,” such exploration and production wastes could be reclassified as hazardous, thereby
subjecting our operations to more stringent handling and disposal requirements. In some circumstances, moreover, RCRA
authorizes both the federal government and private persons to seek injunctions requiring the cleanup of wastes, whether
hazardous or non-hazardous.
The Endangered Species Act (“ESA”) protects fish, wildlife and plants that are listed as threatened or endangered. Under
the ESA, exploration and production operations may not significantly impair or jeopardize a protected species or its
habitat. The ESA provides for criminal penalties for willful violations. Our operations also may be subject to other statutes
that protect animals and plants such as the Migratory Bird Treaty Act. Although we believe that our properties are in
compliance with such statutes, any change in these statutes or any reclassification of a species as endangered could subject
our company (directly or indirectly through our third-party operators) to significant expenses to modify operations, could
force discontinuation of certain operations altogether and could limit the locations our third-party operators may utilize in
the future.
The Clean Air Act (“CAA”) is the comprehensive federal law addressing sources of air emissions. Oil and natural gas
production and natural gas processing operations are among the many source categories subject to the CAA. Regulated
emissions from oil and natural gas operations include sulfur dioxide, volatile organic compounds (“VOCs”) and hazardous
air pollutants such as benzene, among others.
In particular, the Environmental Protection Agency (“EPA”) issued proposed CAA regulations in November 2021, which it
strengthened and expanded in November 2022, that would impose more comprehensive restrictions on emissions of
methane (a greenhouse gas) and VOCs from new, existing and modified facilities in the oil and gas sector. Among other
things, EPA’s proposed new rule would require states to implement plans that meet or exceed established emission
reduction guidelines for oil and natural gas facilities. These regulations and proposals and any other new regulations
requiring the installation of more sophisticated pollution control equipment could have a material adverse impact on our
business, results of operations and financial condition.
The Clean Water Act (the “CWA”) is the primary federal law controlling the discharge of produced waters and other
pollutants into waters of the United States. Permits must be obtained for such discharges and to conduct construction
activities in waters and wetlands. Some states also require permits for discharges or operations that may impact
groundwater.
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The CAA, CWA and comparable state statutes authorize civil, criminal and administrative penalties for violations. Further,
the CWA and Oil Pollution Act may impose liability on owners or operators of onshore facilities that impact surface
waters.
Pursuant to the Safe Drinking Water Act, EPA (or an authorized state) regulates the construction, operation, permitting, and
closure of injection wells used to place oil and natural gas wastes and other fluids underground for enhanced hydrocarbon
recovery, storage or disposal. The primary objective of injection well operating requirements is to ensure the mechanical
integrity of the injection apparatus and to prevent migration of fluids from the injection zone into underground sources of
drinking water. Underground injection associated with oil and gas operations, particularly the disposal of produced water,
has been linked in some cases to localized earthquakes. This in turn has led to new legislative and regulatory initiatives,
which have the potential to restrict injection in certain wells or limit operations in certain areas.
Certain of the oil and natural gas production in which we have an interest is developed from unconventional sources that
require hydraulic fracturing as part of the completion process. Hydraulic fracturing involves the injection into the
formation of water, sand and chemicals under pressure to stimulate production. From time to time, legislation has been
proposed in the United States Congress to repeal the Safe Drinking Water Act’s exemption for hydraulic fracturing from
the definition of “underground injection” and to require federal permitting of hydraulic fracturing. If ever enacted, such
legislation would add to costs for hydraulic fracturing.
Scrutiny of hydraulic fracturing activities continues in other ways. Several states where our properties are located have
proposed or adopted legislative or regulatory restrictions on hydraulic fracturing. A number of municipalities likewise have
enacted bans on hydraulic fracturing. We cannot predict whether any other legislation restricting hydraulic fracturing will
be enacted and if so, what its provisions would be. If additional levels of regulation and permits were to be required
through the adoption of new laws and regulations at the federal, state or local level, it could lead to delays, increased
operating costs and process prohibitions that could materially adversely affect our revenue and results of operations.
The National Environmental Policy Act (“NEPA”) requires federal agencies to assess the environmental effects of their
proposed actions prior to making decisions. Among the broad range of actions covered by NEPA are decisions on permit
applications and federal land management. Many of the activities of our third-party operators involve federal decisions
subject to NEPA. Such federal actions may trigger robust NEPA review, which could lead to delays and increased costs that
could materially adversely affect our revenues and results of operations. In 2022, moreover, the Biden Administration
reversed changes to NEPA rules enacted under the Trump Administration that had been intended to streamline NEPA
review. The revised regulations lay the foundation for additional scrutiny of impacts on climate change, which could affect
the assessment of projects ranging from oil and gas leasing to development on public and Indian lands.
Climate Change
Climate change has become a major public concern and policy issue in the United States and around the world. Much of
the debate has focused on greenhouse gas (“GHG”) emissions from oil and natural gas, particularly carbon dioxide and
methane.
In the United States, there is no comprehensive federal regulatory statute addressing climate change, although Congress
does periodically consider such measures. At the federal level, the United States therefore has primarily addressed climate
change through executive actions and regulatory initiatives pursuant to existing statutes. These include rejoining the Paris
Agreement on climate change, the Biden Administration’s commitment to cut greenhouse gas emissions by 2030 to 50-52
percent of 2005 levels, various executive orders, limiting land available for oil and gas leasing, the United States Methane
Emissions Reduction Action Plan (intended to reduce overall methane emissions by 30% below 2020 levels by 2030), and
Clean Air Act rules (such as the November 2021 proposal to regulate methane from the oil and gas sector). In addition,
several states have already implemented or are considering programs to reduce GHG emissions. These include cap and
trade programs, promotion of alternative forms of energy, transportation standards and restrictions
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on particular GHGs. To the extent that new climate change measures are adopted, and our third-party operators must
further control GHG emissions, our business may be adversely impacted.
In addition, recent court decisions have left open the question of whether tort claims alleging property damage may
proceed against sources of GHG emissions under state common law. Thus, there is some litigation risk for such claims.
Legislation or regulations that may be adopted to address climate change could also affect the markets for our products by
making our products more or less desirable than competing sources of energy. To the extent that our products are
competing with higher GHG emitting energy sources, for example, our products would become more desirable in the
market with more stringent limitations on GHG emissions. But in 2022, the United States enacted the Inflation Reduction
Act that, among other things, creates a series of financial incentives intended to discourage use of oil and natural gas
(including imposing a fee on methane emissions) and to promote alternative sources of energy. To the extent that our
products are competing with lower GHG emitting energy sources such as solar and wind, our products may become less
desirable in the market with such government intervention. We cannot predict with any certainty at this time how these
possibilities may affect our operations.
Various studies on climate change indicate that extreme weather conditions and other risks may occur in the future in the
areas where we operate. Although we have not experienced any material impact from such extreme conditions to date, no
assurance can be given that they will not have a material adverse effect on our business in the future.
See discussion captioned “Government regulation and liability for oil and natural gas operations and environmental matters
may adversely affect our business and results of operations” in Item 1A. Risk Factors.
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, but is not limited to, 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 business interruption or lost profits coverage.
Human Capital, Sustainability, and ESG
Employees
As of June 30, 2023, we had eleven full-time employees, not including contract personnel and outsourced service
providers. Due to our current focus on non-operating properties, our staff is disproportionately weighted towards higher
wage professionals. We believe that we have positive relations with our 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. For our full-time employees, our
benefits package, as determined by our Board of Directors, includes medical, dental, and vision insurance, short-term
disability, 401(k) contributions based on a portion of the employee’s base salary, short and long-term performance-based
and service-based incentive pay (i.e., annual bonuses and stock awards), and paid time off.
Our workforce is provided with annual training and is expected to sign an acknowledgement regarding our policies and
disclosures which include, but are not limited to, the Corporate Sustainability Report (“CSR”), employee handbook, human
rights, code of ethics, health and safety, emergency procedures, conflicts of interest, insider trading, bribery, kickbacks,
discrimination, diversity, equality, and inclusion.
Sustainability and ESG
In fiscal year 2023, we formed a Sustainability Committee which is responsible for overseeing our Environmental Social
Governance (“ESG”) initiatives. In fiscal year 2021-2022, under the supervision of our Board of Directors, the Nominating
and Corporate Governance committee, and senior management, the foundation of our sustainability efforts
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and CSR were led by an ESG Task Force. Evolution’s most recent CSR was published in October 2022. This report is
accessible on our website at www.evolutionpetroleum.com.
The ESG Task Force formalized our existing ESG programs, proposed and implemented new ESG initiatives, monitored
adherence to our internal and third-party sustainability standards, and provided public disclosures for our stakeholders.
Each year, we continue to disclose, enhance, implement, and provide training for a number of new and existing policies
and procedures. These include, but are not limited to: implementing a charitable donation program and employee volunteer
initiative, an annual company-wide ESG training program for both the Board of Directors and our workforce,
implementation of safety inspections and health and safety coordinators, and incorporating ESG considerations into our
compensation structure.
We are committed to high standards of conduct and ethics in order to contribute to the sustainability of our business. Our
core values are the base to support our strategy and long-term success. We believe integrity is paramount and we are
committed to developing and producing energy resources in environmentally, socially, and ethically respectful and
responsible ways. Our people are critical to our success and as such we promote and maintain a safe and inclusive work
environment. We strategically plan for the long-term and strive to maintain capital discipline, stakeholder transparency, and
continuous focus on returning capital to shareholders. We work with third-party operators that share our desire to operate
and work responsibly, particularly for the natural environments in which they operate.
Denbury Inc., the operator of our Delhi Field property, is an industry leader in Carbon Capture, Utilization and Storage
with a network of CO2 EOR operations and the United States’ largest operated system of CO2 transmission pipelines. As of
year-end 2022, Denbury reportedly injects over three million tons of captured industrial-sourced CO2 annually, and has a
goal to reach Net Zero for Scope 1, Scope 2 and Scope 3 CO2 emissions by 2030, primarily through increasing the amount
of captured industrial-sourced CO2 used in their operations.
Jonah Energy, the operator of our Jonah Field property, is one of the leading sustainable natural gas producers in the U.S.
In 2021, Jonah was the first and only U.S. company to achieve the Gold Standard Rating, announced by the United Nations
Environment Programme International Methane Emissions Observatory.
As a non-operator of our current properties, we do not have direct control over environmental initiatives at a property-level.
However, we believe it is important to partner with third-party operators that share our core values and are committed to
being environmental stewards as they responsibly produce energy resources. We recognize that the expectations,
requirements, and responsibilities of operators regarding safeguarding the environment and environmental stewardship
continue to evolve. We are, and will continue to be, committed to supporting our third-party operators as they respond to
these expectations, requirements, and responsibilities.
In fiscal year 2023, we implemented our first annual voluntary Environmental Operator Questionnaire to collect various
environmental metrics on behalf of our third-party operators. In addition, we host regular operations meetings with our
third-party operators in which we discuss asset level operations, expenses, any environmental issues and compliance,
including ESG and health and safety related topics.
We do not report Scope 1 GHG, or direct, emissions to the EPA as we are not the operator of our properties, nor do we
have financial control over our oil and natural gas properties and operations. We prefer to partner with third-party operators
that work to reduce their Scope 1 GHG emissions, and we encourage them to accelerate their efforts as appropriate in this
regard. The Company reports in its CSR the estimated Scope 2 GHG emissions for its corporate office located in Houston,
Texas. Scope 2 GHG emissions are based on indirect emissions representing purchased electricity. We are one of many
tenants leasing space in our corporate office building and do not know the actual amount of electricity used in our space.
As such, we estimate our consumption by multiplying the electricity purchased for the entire building by the percentage of
the floor area that we occupy. Water use is also reported in the CSR and is calculated in a similar fashion.
We maintain a hotline which operates 24/7/365 and allows anonymous and confidential reporting for employees,
consultants, partners, and contractors, including the ability to report concerns or violations of our policies through the
phone or internet (Phone: 877-628-7489 / Website: www.epm.alertline.com).
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Additional Information
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and other reports
with the SEC. Our reports filed with the SEC are available free of charge to the general public through our website at
www.evolutionpetroleum.com. These reports are accessible on our website as soon as reasonably practicable after being
filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by
contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or calling (713) 935-0122.
These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The
public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The
SEC also maintains a website at www.sec.gov that contains reports, proxy and information statements and other
information regarding issuers that file electronically with the SEC.
Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual
Report on Form 10-K, actually occurs, our business, financial condition, or results of operations could suffer. The risks
described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider
to be immaterial also may adversely affect us.
Risks Related to Our Business:
A substantial or extended decline in oil and natural gas prices may adversely affect our business, financial condition,
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, capital
spending, and future rate of growth. At June 30, 2023, approximately 32% of our proved reserves were oil reserves, 49%
were natural gas and 19% were NGLs. Oil, natural gas and NGLs are commodities and their prices are subject to wide
fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for oil, natural gas,
and NGLs 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;
● worldwide and regional economic conditions impacting the global supply and demand for oil and natural gas;
● social unrest, political instability or armed conflict in major oil and natural gas producing regions outside the
United States, such as the conflict between Ukraine and Russia, and acts of terrorism or sabotage;
● the ability and willingness of the members of OPEC+ to agree and maintain oil price and production controls;
● the price and quantity of imports of foreign oil and natural gas;
● governmental, scientific, and public concern over the threat of climate change arising from greenhouse gas
emissions;
● the relative strength or weakness of the U.S. dollar compared to other currencies;
● 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, including embargoes, sanctions, tariffs, and environmental
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;
● increasing attention to ESG matters; and
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● the price, availability and use 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. Generally, we hedge substantially
less than all of our anticipated oil and natural gas production and typically only with the requirements of our Senior
Secured Credit Facility. To the extent that we have not hedged production, any significant and extended decline in oil,
natural gas, and NGL prices may adversely affect our financial position.
Our existing developed oil and natural gas production will decline; we may be unable to acquire or develop the
additional oil and natural gas reserves that are required in order to sustain our production and business operations.
The volume of production from developed oil and natural gas properties declines as reserves are depleted, with the rate of
decline depending on reservoir characteristics. Environmental issues, operating problems, or lack of extended future
investment in any of our properties would 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.
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, naturally fractured,
or low permeability reservoirs. Our Hamilton Dome Field and Delhi Field properties produce from relatively shallow
reservoirs, while our Jonah Field, Williston Basin and Barnett Shale properties produce from deeper reservoirs. Shallower
reservoirs usually have lower pressure, which generally translates into lower reserves volumes in place. Deeper reservoirs
have higher pressures and usually more reserves volumes in place, but capturing those reserves often comes at increased
drilling and completion costs and risks and, generally, a higher rate of initial production decline. Low permeability
reservoirs require 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, or more expensive, technologies to produce incremental reserves. Our approach on the development
and application of technologies on these different types of reservoirs could have a material adverse effect on our results of
operations.
The 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. On July 13, 2023,
Exxon Mobil Corporation (“Exxon”) announced it had entered into a definitive agreement to acquire Denbury. Exxon’s
plans with respect to the Delhi Field are unknown. Additional capital remains to be invested to fully develop the EOR
project and maximize the value of the properties. The operator’s failure to manage these and other technical,
environmental, operational, 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 could have a
material adverse effect on our results of operations and financial condition.
We have limited control over the activities on properties we do not operate.
All of our property interests are operated by third-party working interest owners, not by us. As a result, we have limited
ability to influence or control the operations or future development of such properties, including compliance with
environmental, safety, and other standards, 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 condition and results of operations.
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We will be subject to risks in connection with acquisitions.
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:
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recoverable reserves;
future oil and natural gas prices and their appropriate differentials;
development and operating costs;
potential for future drilling and production;
validity of the seller’s title to properties, which may be less than expected at closing; and
potential environmental issues, litigation, and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of
the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all
existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their
deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and
environmental problems are not necessarily observable at the ground surface or otherwise when an inspection is performed.
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 and, importantly, that our assumptions regarding future oil and
natural gas prices, differentials, reserves, or production could prove materially inaccurate and have a material adverse
effect on our financial condition, results of operations, or cash flows.
We may encounter difficulties integrating the operations of newly acquired oil and natural gas properties or businesses.
Increasing our reserve base through acquisitions has been an important part of our business strategy. We may encounter
difficulties integrating newly acquired oil and natural gas properties or businesses. In particular, we may face significant
challenges in consolidating functions and integrating procedures, personnel, and business operations in an effective
manner. The failure to successfully integrate such properties or businesses into our Company may adversely affect our
business and results of operations. Any acquisition we make may involve numerous risks, including:
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a significant increase in our indebtedness and working capital requirements;
the inability to timely and effectively integrate the operations of recently acquired businesses or assets;
the incurrence of substantial costs to address unforeseen environmental and other liabilities arising out of the
acquired businesses or assets;
liabilities arising from the operation of the acquired businesses or assets before our acquisition;
our lack of drilling or operational history in the areas in which the acquired business operates;
customer or key employee loss from the acquired business;
increased administration of new personnel;
additional costs due to increased scope and complexity of our business;
potential disruption of our ongoing business; and
assumptions made on estimated development by the operator may not be accurate or may change.
Additionally, significant acquisitions can change the nature of our operations and business depending upon the character of
the acquired properties, which may have substantially different operating and geological characteristics or be in different
geographic locations than our existing properties. To the extent that we acquire properties substantially different from the
properties we currently own or that require different technical expertise, we may not be able to realize the economic
benefits of these acquisitions as effectively as with acquisitions within our current footprint and expertise. We may not be
successful in addressing these risks or any other problems encountered in connection with any acquisition we may make.
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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 future development programs on our properties. Drilling for oil
and natural gas and extracting NGLs and re-working existing wells involve numerous risks. 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;
● well blowouts and other releases of hazardous materials;
● inability to obtain or maintain leases on economic terms, where applicable;
● the cost and availability of goods and services, such as drilling rigs, fracture stimulation services, and
tubulars;
● 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 economic quantities. Our future drilling, completion and production 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 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 wells will, if drilled, encounter
reservoirs of commercially productive oil or natural gas.
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, workover 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
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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.
Under the terms of our Senior Secured Credit Facility, we are required to hedge a certain portion of our anticipated oil and
natural gas production for future periods when we reach a defined utilization percentage. We may also elect to hedge
additional production volumes from time to time based upon our view of the attractiveness of commodity futures and the
risks that downward price fluctuations might pose to our business plans. When we engage in hedging transactions, we may
utilize costless collars, fixed price swaps or purchased floors to cost-effectively provide us with some protection against
price changes. 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:
● actual 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, in a rising commodity price environment, derivative arrangements may limit the extent to which we might
benefit from increases in prices of oil and natural gas and may expose us to cash margin requirements.
Our operations may require significant amounts of capital and additional financing may be necessary in order for us to
continue our exploitation activities.
Cash flow from our production 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 oil and natural gas acquisitions, exploitation, and development activities.
If our revenues decrease as a result of decreases in production, 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 be available to us on favorable terms.
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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 change
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 addressing protection of human health and the environment that apply to the
development, production, handling, storage, and transportation of oil, natural gas, and their by-products; the disposal of
related wastes; the emission of CO2, other greenhouse gases, and volatile organic compounds; and the management of
other substances and materials released, 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 by, among other things, requiring us to make
significant expenditures in order to comply and restricting the areas available for oil and gas production. Failure to comply
with these laws and regulations may result in substantial liabilities to third-parties or governmental entities. In addition, we
may be liable for significant environmental damages and cleanup costs, without regard to fault, for releases of hazardous
materials on or from property we own or operate, even if we did not cause or contribute to the release. 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 by imposing new
emission controls, penalties, fines and/or fees, taxes and tariffs on carbon that could have the effect of raising prices to the
end user and thereby reducing the demand for our products.
The risks arising out of the threat of climate change, including transition risks and physical risks, may adversely affect
our business and results of operations.
The threat of climate change poses both transition risks and physical risks that could have a material adverse effect on us.
Transition risks may arise from political and regulatory, legal, technological or financial changes as society tries to
safeguard the climate, while physical risks may result from extreme weather events or other shifts in the natural world.
We have been facing increased political and regulatory risks as federal, state and local governments have adopted new
measures to restrict sources of greenhouse gas emissions and promote energy alternatives. Many such measures have been
proposed, and still more can be expected. From time to time, there are proposals to ban hydraulic fracturing of oil and
natural gas wells and to remove more lands, both onshore and offshore, from new hydrocarbon production. Many other
actions could be pursued such as more rigorous requirements for drilling and construction permits, stricter greenhouse gas
emissions standards for both new and existing sources, further limits on construction of new pipelines, reinstatement of the
ban on oil exports, enhanced reporting obligations, taxing carbon emissions and creating further incentives for use of
alternative energy sources. These actions may cause operational delays or restrictions, increased operating costs and
additional regulatory burdens.
Litigation risks are also increasing for oil and natural gas companies. A number of suits alleging, among other things, that
oil and natural gas companies created public nuisances by producing fuels that contributed to climate change have been
brought in state or federal court.
Technological changes may drive market demand for products other than oil and natural gas. Wider adoption of hybrid
engines and electric cars, for example, would reduce demand for our products. At the same time, our capital and operating
costs may increase if we need to add new emission reduction technologies.
There are also financial risks for the petroleum industry. It may become more difficult for us to access the capital markets if
the threat of climate change discourages new investment. 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.
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The threat of climate change also may subject our operations and business to severe weather or other natural hazards, such
as flooding, drought, wildfires, and extreme temperatures. Any such event could halt production or exploration activities,
damage equipment, disrupt transportation, reduce consumer demand and significantly increase our costs.
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, volatile oil and natural gas prices, geopolitical issues, the
availability and cost of credit, the United States mortgage market, uncertainties with regard to European sovereign debt, the
slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases
in tariffs or other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished
expectations for the global economy. Concerns about global economic conditions have had a significant adverse impact on
domestic and international financial markets and commodity prices. If uncertain or poor economic, business, or industry
conditions in the United States or abroad remain prolonged, demand for petroleum products could diminish or stagnate,
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.
Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the global
outbreak of a novel strain of the coronavirus (“COVID-19”), may materially adversely affect our business.
We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could
significantly disrupt our operations and adversely affect our financial condition. In December 2019, COVID-19 was
identified in Wuhan, China and rapidly spread around the world. This virus and its variants, and governmental actions to
contain it, had material adverse economic impacts 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, governmental restrictions intended to contain COVID-19 or future pandemics have in the past,
and may in the future, significantly impact economic activity and markets and dramatically reduce actual or anticipated
demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and duration of
any such events are uncertain and difficult to predict, as is the extent that such events may have on our business.
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 operators. 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 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 government has issued warnings indicating that energy
assets may be specific targets of cybersecurity threats. Our
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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
and storms, flooding, pollution, releases of toxic gas, and other environmental hazards and risks, which can result in (1)
damage to or destruction of wells and/or production facilities, (2) damage to or destruction of formations, (3) injury to
persons, (4) loss of life, or (5) 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. Should we experience any losses, the costs of our premiums may rise, which could in turn
reduce the amount of insurance we are able to carry.
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 our executive officers to source, evaluate, and close deals, raise capital, and oversee our
development activities and operations. Presently, we are not a beneficiary of any key man life insurance.
Oilfield 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 providing services for any reason or we may not be able to source
the services or materials we need. Any delay in locating, establishing relationships, and training our sources could result in
production shortages and maintenance problems, resulting in loss of revenue to us. In addition, if costs for such services
and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may
have assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes
may result from the long lead times often necessary to execute and complete our redevelopment plans.
We may assume risks and financial responsibility for drilling and completing wells on our Williston Basin properties if
our third-party operator declines to drill wells and it or other joint interest owners elect not to participate.
As discussed elsewhere in this report, pursuant to agreements related to our interests in the Williston Basin properties,
we have the ability to propose to the operator a drilling plan for certain wells, which the operator may accept or reject. In
the event the operator rejects our proposed drilling plan, we have the right to undertake all necessary activities to drill and
complete the wells and related facilities in accordance with our proposed drilling plan. In the event we undertake to do so,
and the operator and other joint interest owners elect not to participate, we will bear the entire liability and expense
associated with drilling and completing the wells and related facilities, subject only to our right to recoup costs incurred on
behalf of non-participating joint interest owners to the extent a well generates sufficient revenues to do so. We thus may be
required to bear a share of such expenses to an extent that is disproportionate to our economic interest in the property. If we
elect to proceed to drill and complete wells we have proposed and the operator has rejected, we also will bear many of the
other risks highlighted elsewhere herein, including, without limitation, failing to find economic quantities of oil and natural
gas, drilling accidents, potential environmental liabilities, unavailability of insurance at a reasonable cost to cover
associated liabilities, and price increases and delivery delays for required drilling and completion equipment, products and
services. Ongoing operations of any wells we elect to drill will be turned over to the operator of the property upon
completion.
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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 and production 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 natural 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, natural 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.
Unanticipated changes in effective tax rates or laws or adverse outcomes resulting from examination of our income or
other tax returns could adversely affect our financial condition and results of operations.
We are subject to tax by U.S. federal, state, and local tax authorities. Our future effective tax rates could be subject to
volatility or adversely affected by a number of factors, including:
● changes in the valuation of our deferred tax assets and liabilities;
● expected timing and amount of the release of any tax valuation allowances;
● tax effects of stock-based compensation;
● costs related to intercompany restructurings; or
● changes in tax laws, regulations, or interpretations thereof.
For example, in previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax
deductions historically available to oil and natural gas exploration and production companies. Such proposed changes have
included: (1) a repeal of the percentage depletion allowance for oil and natural gas properties; (2) the elimination of
deductions for intangible drilling and exploration and development costs; (3) the elimination of the deduction for certain
production activities; and (4) an extension of the amortization period for certain geological and geophysical
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expenditures. Under the current Administration there is an increased risk of the enactment of legislation that alters,
eliminates, or defers these or other tax deductions utilized within the industry, which could adversely affect our business,
financial condition, results of operations, and cash flows.
In addition, we may be subject to audits of its income, sales, and other transaction taxes by U.S. federal, state, and local
taxing authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of
operations.
Risks Associated with our Common Stock
Our stock price has been and may continue to be volatile.
Our common stock has a relatively low trading volume and the market price has been, and is likely to continue to be,
volatile. The variance in our stock price makes it difficult to forecast 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;
● 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, 2023, our executive officers and directors, in the aggregate, beneficially owned approximately 2,959,269
million shares, or approximately 8.9% of our outstanding common stock and, based on recent filings with the SEC, we
believe one large unaffiliated fund complex owned in excess of 8% of the outstanding shares of our common stock. As a
result, a significant percentage of our common stock is concentrated in the hands of relatively few shareholders. These
shareholders 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 any matter that requires
shareholder approval, including 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. Trading volume in our common stock is relatively low compared to
larger companies. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the
trading volume and price of our stock at that time relative to the quantity of shares to be sold.
If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the
price of our common stock could decline.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry
or securities analysts publish. To our knowledge, only two research analysts actively cover our company. The limited
number of published reports by 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
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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.
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
our 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 paying dividends to our shareholders, there is no guarantee that we will be able to do so.
There may be future sales or issuances of our common stock, which will dilute the ownership interests of stockholders
and may adversely affect the market price of our common stock.
We may in the future issue additional shares of common stock, including securities that are convertible into or
exchangeable for, or that represent the right to receive, common stock or substantially similar securities, which may result
in dilution to our stockholders. In addition, our stockholders may be further diluted by future issuances under our equity
incentive plans. The market price of our common stock could decline as a result of sales or issuances of a large number of
shares of our common stock or similar securities in the market after this offering or the perception that such sales or
issuances could occur.
Non-U.S. holders may be subject to U.S. income tax and withholding tax with respect to gain on disposition of the
Company’s common stock.
We believe we are a U.S. real property holding corporation. As a result, Non-U.S. holders that own (or are treated as
owning under constructive ownership rules) more than a specified amount of our common stock during a specified time
period may be subject to U.S. federal income tax and withholding on a sale, exchange or other disposition of such common
stock, and may be required to file a U.S. federal income tax return.
Investor sentiment towards climate change, fossil fuels, sustainability, and other ESG matters could adversely affect our
business and our stock price.
There have been efforts in recent years aimed at the investment community, including investment advisors, sovereign
wealth funds, public pension funds, universities, and other groups, to promote the divestment of shares of fossil fuel
companies, as well as to pressure lenders and other financial services companies to limit or curtail activities with fossil fuel
companies. As a result, some financial intermediaries, investors, and other capital markets participants have reduced or
ceased lending to, or investing in, companies that operate in industries with higher perceived environmental exposure, such
as the oil and natural gas industry. For example, in December 2020, the State of New York announced that it will be
divesting the state’s Common Retirement Fund from fossil fuels. If this or similar divestment efforts are continued, the
price of our common stock or debt securities, and our ability to access capital markets or to otherwise obtain new
investment or financing, may be negatively impacted.
Members of the investment community are also increasing their focus on ESG practices and disclosures, including
practices and disclosures related to greenhouse gases and climate change in the energy industry in particular, and diversity
and inclusion initiatives and governance standards among companies more generally. The SEC, for example, proposed new
rules in 2022 that would require disclosure of various specific risks related to climate. The growing emphasis on ESG may
lead the investment community to screen our ESG performance before investing in our common stock or debt securities or
lending to us. Over the past few years there also has been an acceleration in investor demand for ESG investing
opportunities, and many large institutional investors have committed to increasing the percentage of their portfolios that are
allocated towards ESG-focused investments. As a result, there has been a proliferation of ESG-focused investment funds
seeking ESG-oriented investment products.
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If we are unable to meet the ESG standards or investment or lending criteria set by these investors and funds, we may lose
investors, investors may allocate a portion of their capital away from us, our cost of capital may increase, the price of our
common stock may be negatively impacted, and our reputation may be negatively affected.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding our properties is included in Item 1. Business above and in Note 4, “Property and Equipment” to
our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data, which
information is incorporated herein by reference.
Item 3. Legal Proceedings
See Note 10, “Commitments and Contingencies” to our consolidated financial statements in Item 8. Consolidated
Financial Statements and Supplementary Data 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
Market Information
Our common stock is currently traded on the NYSE American stock exchange under the ticker symbol “EPM”.
Shares Outstanding and Holders
As of June 30, 2023, there were 33,247,523 shares of common stock issued and outstanding. As of September 1, 2023,
there were approximately 219 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, we
made the following cash dividends per share:
Fourth quarter ended June 30,
Third quarter ended March 31,
Second quarter ended December 31,
First quarter ended September 30,
$
Fiscal Year
2023
2022
$
0.120
0.120
0.120
0.120
0.100
0.100
0.075
0.075
As of June 30, 2023, we have paid 39 consecutive quarterly dividends on our common stock. In September 2023, the
Company declared a $0.12 per share dividend payable on September 30, 2023. 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.
Securities Authorized For Issuance Under Equity Compensation Plans
Number of
securities to
be issued
upon exercise
of outstanding
options,
warrants and
rights (a)
Weighted-average
exercise
price of
outstanding
Options, warrants
and rights (b)
Number of securities
remaining
available for future
issuance under
equity compensation
plans (excluding
securities reflected
in column (a))(1)
Plan category
Equity compensation plans approved by security holders:
Outstanding options
Outstanding contingent rights to shares
Total
Equity compensation plans not approved by security holders
Total
— $
96,398 (1)
96,398
—
96,398
$
—
—
—
—
—
1,277,898
—
1,277,898
(1) The Evolution Petroleum Corporation 2016 Equity Incentive Plan (as amended, the “2016 Plan”) authorizes the issuance of 3.6
million shares of common stock prior to its expiration on December 8, 2026. As of June 30, 2023, we have granted 2.3 million
equity awards under the 2016 Plan and 1.3 million shares of common stock remain available for future grants.
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Issuer Purchases of Equity Securities
The table below summarizes information about the Company’s purchases of its equity securities during the three months
ended June 30, 2023.
(a) Total number
of shares
purchased and
received (1)
2,223
—
21,163
(b) Average price
paid per share (1)
6.89
$
—
8.07
(c) Total number
of shares
purchased as part
of public announced
plans or programs(2)
(d) Maximum dollar value
of shares that may yet be
purchased under the
plans or programs
(in thousands)(2)
— $
—
—
21,152
21,152
21,152
Period
April 2023
May 2023
June 2023
(1) During the three months ended June 30, 2023, no shares were purchased under the share repurchase program, discussed further
below. All of the shares listed in the table above were surrendered by employees in exchange for the payment of tax withholding
upon the vesting of restricted stock awards.
(2) On September 8, 2022, the Company’s Board of Directors approved a share repurchase program, under which the Company is
authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The shares may
be repurchased from time to time in open market transactions, through privately negotiated transactions or by other means in
accordance with federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will
depend on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price
of the Company's common stock, our capital needs and resources, general market and economic conditions, and applicable legal
requirements. The value of shares authorized for repurchase by the Company's Board of Directors does not require the Company to
repurchase such shares or guarantee that such shares will be repurchased, and the program may be suspended, modified, or
discontinued at any time without prior notice. In December 2022, the Company entered into a Rule 10b5-1 plan that authorizes a
broker to repurchase shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a
30-day cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30,
2023 and had a maximum authorized amount of $5.0 million over that period. We may enter into additional Rule 10b5-1 plans in
the future, the terms of which will be approved by the Board of Directors.
Item 6. Reserved
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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 and Estimates
General
Executive Overview
Evolution Petroleum Corporation is an independent energy company focused on maximizing total returns to its
shareholders through the ownership of and investment in onshore oil and natural gas properties in the United States. In
support of that objective, our long-term goal is to maximize total shareholder return from a diversified portfolio of long-life
oil and natural gas properties built through acquisitions and through selective development opportunities, production
enhancements, and other exploitation efforts on our oil and natural gas properties.
Our oil and natural gas properties consist of non-operated interests in the Jonah Field in Sublette County, Wyoming, a
natural gas producing field; non-operated interests in the Williston Basin in North Dakota, a producing oil and natural gas
property; non-operated interests in the Barnett Shale located in North Texas, a natural gas producing property; non-
operated interests in the Hamilton Dome Field located in Hot Springs County, Wyoming, a secondary recovery field
utilizing water injection wells to pressurize the reservoir; non-operated interests in the Delhi Holt-Bryant Unit in the Delhi
Field in Northeast Louisiana, a CO2 enhanced oil recovery (“EOR”) project; and small overriding royalty interests in four
onshore central Texas wells.
Our non-operated interests in the Jonah Field, a natural gas and NGL property in Sublette County, Wyoming, consist of
approximately 20% average net working interest and approximately 15% average net revenue interest located on
approximately 950 net acres. The properties are operated by Jonah Energy, an established operator in the geographic
region.
Our non-operated interests in the Williston Basin, an oil and natural gas producing property, consist of approximately 39%
average net working interest and approximately 33% average net revenue interest located on approximately 43,300 net
acres (approximately 92% held by production) across Billings, Golden Valley, and McKenzie Counties in North Dakota.
The properties are operated by Foundation Energy Management, an established operator in the geographic region.
Our non-operated interests in the Barnett Shale, a natural gas and NGL producing shale reservoir, consist of approximately
17% average net working interest and approximately 14% average net revenue interest (inclusive of small overriding
royalty interests). The approximately 21,000 net acres are held by production across nine North Texas counties. The oil and
natural gas properties are primarily operated by Diversified Energy Company with approximately 10% of wells operated
by six other operators.
Our non-operated interests in the Hamilton Dome Field, a secondary recovery field utilizing water injection wells to
pressurize the reservoir, consist of approximately 24% average net working interest, with an associated 20% average net
revenue interest (inclusive of a small overriding royalty interest). The approximately 5,900 gross acre unitized field, of
which we hold approximately 1,400 net acres, is operated by Merit Energy Company, who owns the vast majority of the
remaining working interest in the Hamilton Dome Field. The Hamilton Dome Field is located in the southwest region of
the Big Horn Basin in northwest Wyoming.
Our non-operated interests in the Delhi Field, a CO2-EOR project, consist of approximately 24% average net working
interest, with an associated 19% revenue interest and separate overriding royalty and mineral interests of approximately
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7% yielding a total average net revenue interest of approximately 26%. The field is operated by Denbury Onshore LLC.
The Delhi Field is located in northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses
approximately 14,000 gross unitized acres, or approximately 3,200 net acres.
Recent Developments
Dividend Declaration
On September 11, 2023, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common
share payable September 29, 2023.
Senior Secured Credit Facility
On May 5, 2023, we entered into the Tenth Amendment to our Senior Secured Credit Facility, which has a current
borrowing base of $50.0 million. This amendment, among other things, extends the maturity of our Senior Secured Credit
Facility to April 9, 2026 and converts our benchmark interest rate from LIBOR to SOFR plus a credit spread adjustment of
0.05%. For further discussion of the amendment and our Senior Secured Credit Facility, see “Liquidity and Capital
Resources” below.
Appointment of Chief Operating Officer
On February 23, 2023, we announced that the Board of Directors appointed J. Mark Bunch as COO. Mr. Bunch had been
providing consulting services to the Company since 2016. We entered into an offer letter with Mr. Bunch setting forth his
compensation as COO on February 21, 2023.
Appointment of Chief Executive Officer
On October 27, 2022, we announced that the Board of Directors selected Kelly W. Loyd as President and CEO. Mr. Loyd
had been serving as Interim CEO since June 2022 and has served as a member of the Board of Directors since 2008. We
entered into an offer letter with Mr. Loyd setting forth his compensation as CEO on October 25, 2022. Upon commencing
employment, Mr. Loyd no longer receives compensation for his services as a member of the Board of Directors.
Share Repurchase Program
On September 8, 2022, the Board of Directors approved a share repurchase program under which we are authorized to
repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. We intend to fund
repurchases from available working capital and cash provided by operating activities. As we continue to focus on our goal
of maximizing total shareholder return, the Board of Directors and management team believe that a share repurchase
program is complimentary to the existing dividend policy and is a tax efficient means to further improve shareholder
return. The shares may be repurchased from time to time in open market transactions, through privately negotiated
transactions or by other means in accordance with federal securities laws. The timing, as well as the number and value of
shares repurchased under the program, will depend on a variety of factors, including management’s assessment of the
intrinsic value of our shares, our capital needs and resources, the market price of our common stock, general market and
economic conditions, and applicable legal requirements. The value of shares authorized for repurchase by our Board of
Directors does not require us to repurchase such shares or guarantee that such shares will be repurchased, and the program
may be suspended, modified, or discontinued at any time without prior notice.
Once we completed repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout period
in December 2022, we entered into a Rule 10b5-1 plan that authorized a broker to repurchase shares in the open market
subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that did not
allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a
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maximum authorized amount of $5.0 million over that period. During the year ended June 30, 2023, 0.6 million shares of
our common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental
direct transaction costs. These treasury shares were subsequently cancelled. We may enter into additional Rule 10b5-1
plans in the future, the terms of which will be approved by the Board of Directors.
Proved Reserves
The following table is a summary of our proved reserves as of June 30, 2023 and 2022:
Proved Reserves MMBOE
% Developed
Liquids %
Standardized Measure ($MM)
Proved Reserves
2023
2022
31.2
88.1 %
50.5 %
238.2
$
36.2
90.1 %
50.8 %
314.8
$
Change
(13.8)%
(2.0)%
(0.3)%
(24.3)%
Proved oil equivalent reserves as of June 30, 2023 were 31.2 MMBOE, a 5.0 MMBOE, or 13.8%, decrease from the
previous year of 36.2 MMBOE. The net decrease in total proved reserves was primarily due production of 2.6 MMBOE
and net negative revisions of 2.6 MMBOE partially offset by additions and extensions of 0.1 MMBOE. Net negative
revisions of 2.6 MMBOE are primarily due to declines in SEC trailing 12-month pricing that impacted late-in-life
economic limits of production, adjustment to projections and increased production costs partially offset by restored
production at Hamiton Dome Field and improved economics from our differentials at Jonah Field.
The Standardized Measure for proved reserves decreased 24.3% to $238.2 million, primarily due to sales of oil, natural gas
and NGLs produced during the period, decreases in reserves estimates, decreases in the SEC mandated trailing 12-month
average first day of the month prices for oil and natural gas and the price received for our NGLs. Prices decreased from
$85.82 per barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs at June 30, 2022 to $83.23 per
barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs at June 30, 2023. Our proved reserves consist
of 32% oil, 49% natural gas, and 19% NGLs; 88.1% are classified as proved developed producing and 11.9% are proved
undeveloped.
Additional property and project information is included under Item 1. Business and in Note 4, “Property and Equipment”
and our Supplemental Disclosure about Oil and Natural Gas Properties (unaudited) to our consolidated financial
statements in Item 8. Financial Statements and Supplementary Data, and in Exhibit 99.1 and 99.2 of this Form 10-K.
Risks and uncertainties
The global economy was deeply impacted by the effects of the novel coronavirus (“COVID-19”) pandemic and related
efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second
quarter of 2020 and remaining depressed through much of 2020.
Beginning in 2021, the demand for oil and natural gas started to recover primarily as a result of the roll-out of the COVID-
19 vaccine and lessening of pandemic related government restrictions on individuals and businesses. In addition, the
military activities of Russia into Ukraine and the subsequent sanctions imposed on Russia and other actions have created
significant market uncertainties, including uncertainties around potential supply disruptions for oil and natural gas, which
further enhanced volatility in global commodity prices in the first half of 2022.
Additionally, in March 2023, the closures of Silicon Valley Bank and Signature Bank and their placement into receivership
with the Federal Deposit Insurance Corporation (“FDIC”) created broad uncertainty around world-wide financial
institutions and liquidity risk. While we do not have exposure to these banks, we do maintain cash balances in excess of
FDIC insurance protections at banks we believe to be financially sound. We also utilize insured cash sweep deposits to
maximize the amount of our cash that is protected by FDIC insurance. We also rely heavily on our third-party operators
who manage their own liquidity with various financial institutions.
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Given the dynamic nature of these events, we cannot reasonably estimate the period of time that these market conditions
will persist; predict the broader impact of liquidity concerns around financial institutions; or the impact on the commodity
prices that we realize.
Currently, our oil and natural gas properties are operated by third-party operators and involve other third-party working
interest owners. As a result, we have limited ability to influence the operation or future development of such properties.
Despite these uncertainties, we remain focused on our long-term objectives and continue to be proactive with our third-
party operators to review capital expenditures and present alternative plans as necessary.
Liquidity and Capital Resources
As of June 30, 2023, we had no borrowings outstanding on our Senior Secured Credit Facility and $11.0 million in cash
and cash equivalents compared to $21.3 million of borrowings on our Senior Secured Credit Facility and $8.3 million in
cash and cash equivalents at June 30, 2022. Our primary sources of liquidity and capital resources during the year ended
June 30, 2023 were cash provided by operations and the unused portion of our Senior Secured Credit Facility. Our primary
uses of liquidity and capital resources for the year ended June 30, 2023 were repayments on our Senior Secured Credit
Facility, cash dividend payments to our common stockholders, common stock repurchases, and capital expenditures on our
existing oil and natural gas properties. As of June 30, 2023, working capital was $8.9 million, an increase of $2.8 million
from working capital of $6.1 million as of June 30, 2022.
The Senior Secured Credit Facility has a maximum capacity of $50.0 million subject to a borrowing base determined by
the lender based on the value of our oil and natural gas properties. The Senior Secured Credit Facility has a current
borrowing base of $50.0 million. The Senior Secured Credit Facility is secured by substantially all of our oil and natural
gas properties and matures on April 9, 2026.
Borrowings bear interest, at our option, at either the SOFR plus 2.80% or the Prime Rate, as defined under the Senior
Secured Credit Facility, plus 1.0%. For the year ended June 30, 2023, the weighted average interest on our borrowings was
5.25%. The Senior Secured Credit Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not
more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net worth of not
less than $40.0 million, each as defined in the Senior Secured Credit Facility. It also contains other customary affirmative
and negative covenants, including a hedging covenant discussed below, and events of default. As of June 30, 2023, we
were in compliance with all covenants under the Senior Secured Credit Facility.
On May 5, 2023, we entered into the Tenth Amendment to the Senior Secured Credit Facility. This amendment, among
other things, extended the maturity of our Senior Secured Credit Facility to April 9, 2026, converted our benchmark
interest rate from LIBOR to SOFR plus a credit spread adjustment of 0.05%, and modified the Margined Collateral Value,
as defined in the Ninth Amendment to the Senior Secured Credit Facility, to $95.0 million. We are required to enter into
hedges on a rolling 12-month basis when the borrowings under the Senior Secured Credit Facility exceed 25% of the
Margined Collateral Value. The required amount of hedged oil and natural gas production is related to the amount of
borrowings outstanding. At each redetermination, our Margined Collateral Value takes into account the estimated value of
our oil and natural gas properties, proved developed reserves, total indebtedness, and other relevant factors consistent with
customary oil and natural gas lending criteria.
On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured Credit Facility. This amendment, among
other things, modified the definition of utilization percentage related to the required hedging covenant such that for the
purposes of determining the amount of future production to hedge, the utilization of the Senior Secured Credit Facility will
be based on the Margined Collateral Value, as amended above, to the extent it exceeds the borrowing base then in effect.
This amendment also required us to enter into hedges for the 12-month period ending February 2023, covering 25% of
expected oil and natural gas production over that period.
On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured Credit Facility. This amendment,
among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby we must
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Table of Contents
hedge a certain amount of our future production on a rolling 12-month basis when 25% or more of the borrowing base is
utilized. The hedging covenant was amended in the Ninth Amendment, as discussed above.
On August 5, 2021, we entered into the Seventh Amendment of our Senior Secured Credit Facility which, among other
things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral Interests
EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0 million from
$50.0 million.
We have historically funded operations through cash from operations and working capital. Our primary source of cash is
the sale of produced crude oil, natural gas, and NGLs. A portion of these cash flows is used to fund capital expenditures
and pay cash dividends to shareholders. We expect to fund near-future capital development activities for our properties
with cash flows from operating activities and existing working capital.
We are pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, we
have access to the undrawn portion of the borrowing base available under our Senior Secured Credit Facility, totaling $50.0
million as of June 30, 2023. We also have an effective shelf registration statement with the SEC under which we may issue
up to $500.0 million of new debt or equity securities.
Our Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 39 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 our financial strategy, and it is our long-term goal to increase dividends over
time, as appropriate. On September 11, 2023, the Board of Directors declared a quarterly cash dividend of $0.12 per share
of common stock to shareholders of record on September 22, 2023 and payable on September 29, 2023.
On September 8, 2022, our Board of Directors approved a share repurchase program, under which we are authorized to
repurchase up to $25.0 million of our common stock in the open market through December 31, 2024. We intend to fund
any repurchases from working capital and cash provided by operating activities. As we continue to focus on our goal of
maximizing total shareholder return, the Board of Directors along with the management team believe that a share
repurchase program is complimentary to the existing dividend policy and is a tax efficient means to further improve
shareholder return.
Once we completed the repayment of borrowings on our Senior Secured Credit Facility and emerged from our blackout
period in December 2022, we entered into a Rule 10b5-1 plan that authorizes a broker to repurchase shares in the open
market subject to pre-defined limitations on trading volume and price. The plan included a 30-day cooling off period that
did not allow repurchases to commence until January 2023. The plan was effective until June 30, 2023 and had a maximum
authorized amount of $5.0 million over that period. During the year ended June 30, 2023, 0.6 million shares of our
common stock were repurchased under the plan at a total cost of approximately $3.9 million, including incremental direct
transaction costs. These treasury shares were subsequently cancelled. We may enter into additional Rule 10b5-1 plans in
the future, the terms of which will be approved by the Board of Directors.
Capital Expenditures
For the year ended June 30, 2023, we incurred $6.2 million on development capital expenditures and $0.2 million for
plugging and abandoning costs. During the latter half of fiscal year 2023, we participated in the completion and fracture
stimulation of a vertical Bakken well. Toward the end of fiscal 2023 and into fiscal 2024 we have participated in the
drilling of two new down dip wells in the Delhi Field. Completion and first production of the wells are expected in the first
quarter of fiscal 2024.
Based on discussions with our operators, we expect capital workover projects to continue in all the fields. Overall, for
fiscal year 2024, we expect budgeted capital expenditures to be in the range of $4.0 million to $5.0 million, which excludes
any potential acquisitions. Our expected capital expenditures for the next 12 months include the two new drill wells at
Delhi Field, discussed above, and also include Foundation, the operator of our Williston Basin properties, drilling two
sidetrack locations targeting the Birdbear formation.
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Table of Contents
As of June 30, 2023, our PUD reserves included 3.7 MMBOE of reserves and approximately $71.7 million of future
development costs primarily associated with the Williston Basin properties.
Funding for our anticipated capital expenditures over the near-term is expected to be met from cash flows from operations
and current working capital, and as needed from borrowings under our Senior Secured Credit Facility.
Full Cost Pool Ceiling Test
Under the full cost method of accounting, capitalized costs of oil and natural gas properties, net of accumulated depletion,
depreciation, and amortization 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 as of
June 30, 2023 were $83.23 per barrel of oil, $4.78 per MMBtu of natural gas and $33.71 per barrel of NGLs. As of
June 30, 2023, our capitalized costs of oil and natural gas properties were below the full cost valuation ceiling. If
commodity price levels were to substantially decline from the 12-month average first day of the month pricing levels as of
June 30, 2023 and remain down for a prolonged period of time, our valuation ceiling over our capitalized costs may be
reduced and 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. Additionally, a 10% reduction in respective commodity
prices at June 30, 2023, while all other factors remained constant, would not have generated an impairment.
Overview of Cash Flow Activities
Cash flows provided by operating activities
Cash flows used in investing activities
Cash flows (used in) provided by financing activities
Net increase in cash and cash equivalents
$
$
51,272
(6,992)
(41,526)
2,754
$
$
52,460
(54,873)
5,416
3,003
$
$
Years Ended June 30,
2022
2023
Change
(1,188)
47,881
(46,942)
(249)
Cash provided by operating activities decreased $1.2 million during the fiscal year ended June 30, 2023 compared to
fiscal year ended June 30, 2022 primarily due to decreases in our operating assets and liabilities from the timing of
converting working capital into cash. These decreases are partially offset by increases in total revenues over our increase in
operating costs. Total revenues increased $19.6 million as compared to the prior year driven by an increase in our average
daily production primarily due to our acquisition of non-operated working interests in the Jonah Field and Williston Basin
in April 2022 and January 2022, respectively, partially offset by decreases in the average realized price per BOE.
Cash used in investing activities for the year ended June 30, 2023 decreased $47.9 million from the prior year. In fiscal
year 2022, we completed the acquisition of our Jonah Field properties totaling $26.4 million and the acquisition of our
Williston Basin properties total $25.8 million. The decrease was partially offset by an increase in development capital
expenditures in the current fiscal year.
Net cash flows used in financing activities for the year ended June 30, 2023 were $41.5 million which included the
repayment of $21.3 million of borrowings outstanding under our Senior Secured Credit Facility, $16.1 million in dividends
paid to our common stockholders, and $3.9 million paid to repurchase shares of common stock under our share repurchase
program. Net cash flows provided by financing activities for the year ended June 30, 2022 were $5.4 million which
primarily included $17.3 million in net borrowings under our Senior Secured Credit Facility offset by $11.8 million in
dividends paid to our common stockholders.
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Table of Contents
Results of Operations
Years Ended June 30, 2023 and 2022
We reported net income of $35.2 million and $32.6 million for the years ended June 30, 2023 and 2022, respectively. The
following table summarizes the comparison of financial information for the periods presented:
(in thousands, except per unit and per BOE amounts)
Net income (loss)
Revenues:
Crude oil
Natural gas
Natural gas liquids
Total revenues
Operating costs:
Lease operating costs:
CO2 costs
Ad valorem and production taxes
Other lease operating costs
Depletion, depreciation, and accretion:
Depletion of full cost proved oil and natural gas properties
Depreciation of other property and equipment
Accretion of asset retirement obligations
General and administrative expenses:
General and administrative
Stock-based compensation
Other income (expense):
Net gain (loss) on derivative contracts
Interest and other income
Interest expense
Income tax (expense) benefit
Production:
Crude oil (MBBL)
Natural gas (MMCF)
Natural gas liquids (MBBL)
Equivalent (MBOE)(1)
Average daily production (BOEPD)(1)
Average price per unit(2):
Crude oil (BBL)
Natural gas (MCF)
Natural Gas Liquids (BBL)
Equivalent (BOE)(1)
Average cost per unit:
Operating costs:
Lease operating costs:
CO2 costs
Ad valorem and production taxes
Other lease operating costs
Depletion of full cost proved oil and natural gas properties
General and administrative expenses:
General and administrative
Stock-based compensation
Years Ended June 30,
2022
2023
Variance
$
35,217
$
32,628
$
2,589
51,044
63,800
13,670
128,514
7,375
8,158
44,012
13,142
—
1,131
7,944
1,639
513
121
(458)
(10,072)
659
9,109
416
2,593
7,104
77.46
7.00
32.86
49.56
2.84
3.15
16.97
5.07
3.06
0.63
$
$
52,683
39,174
17,069
108,926
7,708
6,960
33,989
7,518
4
531
6,710
125
(3,763)
95
(572)
(8,513)
619
7,141
364
2,173
5,953
85.11
5.49
46.89
50.13
3.55
3.20
15.64
3.46
3.09
0.06
$
$
$
(1,639)
24,626
(3,399)
19,588
(333)
1,198
10,023
5,624
(4)
600
1,234
1,514
4,276
26
114
(1,559)
40
1,968
52
420
1,151
(7.65)
1.51
(14.03)
(0.57)
(0.71)
(0.05)
1.33
1.61
(0.03)
0.57
Variance %
7.9 %
(3.1) %
62.9 %
(19.9) %
18.0 %
(4.3) %
17.2 %
29.5 %
74.8 %
(100.0) %
113.0 %
18.4 %
1,211.2 %
(113.6) %
27.4 %
(19.9) %
18.3 %
6.5 %
27.6 %
14.3 %
19.3 %
19.3 %
(9.0) %
27.5 %
(29.9) %
(1.1) %
(20.0) %
(1.6) %
8.5 %
46.5 %
(1.0) %
950.0 %
(1) Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy
equivalence and not price equivalence. Natural gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount
of oil.
(2) Amounts exclude the impact of cash paid or received on the settlement of derivative contracts since we did not elect to apply hedge accounting.
35
Table of Contents
Revenues
Fiscal year ended June 30, 2023 revenues increased 18.0% to $128.5 million compared to $108.9 million for the fiscal year
ended June 30, 2022. The increase in revenue is primarily due to our acquisitions of non-operated working interests in the
Jonah Field and Williston Basin in the second half of fiscal year 2022. Average daily equivalent production increased
19.3%, from 5,953 BOEPD to 7,104 BOEPD in the current year. Production increases were driven by our acquisitions of
non-operated working interests in the Jonah Field and Williston Basin in the second half of fiscal 2022, which increased
current fiscal year production by approximately 1,621 BOEPD. The increase in our average daily production from our
acquisitions was partially offset by decreases related to downtime at our Barnett Shale properties due to compressor and
pipeline repairs as well as shut-in wells and our Delhi Field properties due to winter storms, and Delhi heat exchanger
upgrade installation and NGL plant repairs during the fourth fiscal quarter. Our average realized commodity price
(excluding the impact of derivative contracts) decreased approximately $0.57 per BOE, or 1.1%, for the fiscal year ended
June 30, 2023 compared to June 30, 2022. Realized oil and NGL prices decreased approximately 9.0% and 29.9%
respectively, over the prior year. These decreases are partially offset by an increase of approximately 27.5% in realized
natural gas prices from the prior year period despite the substantial decrease in natural gas prices that occurred in late third
quarter. The year over year increase in realized natural gas prices is primarily attributed to the benefit of natural gas price
differentials received at the Jonah Field where our realized price for natural gas for the current year period was $10.63 per
MCF.
Lease Operating Costs
Ad valorem and production taxes were $8.2 million and $7.0 million for the years ended June 30, 2023 and 2022,
respectively. The increase in ad valorem and production taxes is primarily due to increased production volumes described
above as production taxes are based on sales at the wellhead. On a per unit basis, ad valorem and production taxes were
$3.15 per BOE and $3.20 per BOE for the years ended June 30, 2023 and 2022, respectively. The decrease in ad valorem
and production taxes on a per unit basis are due to the increased production volumes described above.
The following table summarizes CO2 costs per Mcf and CO2 volumes for the years ended June 30, 2023 and 2022. CO2
purchase costs are for the Delhi Field. Under our contract with the Delhi Field 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.
CO2 costs per MCF
CO2 volumes (MMCF per day, gross)
$
$
0.99
85.2
$
1.07
82.6
Variance %
(7.5) %
3.1 %
(0.08)
2.6
Years Ended June 30,
2023
2022
Variance
The $0.3 million decrease in CO2 costs for the fiscal year ended June 30, 2023 was primarily due to a 7.5% decrease in
CO2 costs per MCF, which was driven by a decrease in our average realized oil price partially offset by a 3.1% increase in
purchased CO2 volumes. CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s
recycle facilities provide the other 80%. We do not have any ownership in the CO2 pipeline which is owned and operated
by Denbury. On a per unit basis, CO2 costs were $2.84 per BOE and $3.55 per BOE for the years ended June 30, 2023 and
2022, respectively.
Other lease operating costs include remedial workover costs and gathering and transportation costs for our oil and natural
gas production. Compared to the prior year, other lease operating costs increased $10.0 million, or 29.5%, to $44.0 million
in the year ended June 30, 2023 primarily due to the acquisitions in the Jonah Field and Williston Basin in April 2022 and
January 2022, respectively, which increased current year other lease operating costs by $8.0 million. Other lease operating
costs on a per BOE basis increased to $16.97 per BOE in the current year from $15.64 per BOE in the prior year, an
increase of $1.33 per BOE.
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Table of Contents
Depletion of Full Cost Proved Oil and Natural Gas Properties
Depletion expense increased $5.6 million or 74.8% from $7.5 million for the fiscal year ended June 30, 2022 to $13.1
million for the fiscal year ended June 30, 2023 primarily due to an increase in production. On a per unit basis, depletion
expense was $5.07 per BOE and $3.46 per BOE for the fiscal years ended June 30, 2023 and 2022, respectively. The
increase in depletion per BOE was due primarily to an increase in the depletable base of our unit of production calculation
due to our acquisitions in fiscal year 2022 and an increase in our future development costs associated with our proved
undeveloped reserve addition in fiscal year 2022 combined with a decrease in our proved reserve volumes.
General and Administrative Expenses
General and administrative expenses for the fiscal year ended June 30, 2023 increased $1.2 million, or 18.4%, to $7.9
million compared to $6.7 million for the fiscal year ended June 30, 2022. The increase is primarily due to approximately
$0.6 million for salary and employee benefits due to additional personnel added as additional assets were acquired, and
$0.3 million in professional fees associated with our search for a CEO. The remaining increase is associated with fees for
accounting and audit-related services and public reporting expenses due to the increased size of our Company. On a per
unit basis, general and administrative expenses decreased $0.03 per BOE to $3.06 per BOE for the year ended June 30,
2023 from $3.09 per BOE for the prior year. The decrease in general and administrative expenses on a per unit basis are
due to the increased production volumes described above.
Stock-based Compensation Expenses
Stock-based compensation increased $1.5 million to $1.6 million for the year ended June 30, 2023 compared to $0.1
million the prior period due primarily to the $1.2 million reduction in prior year expense related to the forfeiture of
unvested shares in connection with severance, combined with the addition of new personnel, including our CEO and COO,
and the associated new awards granted during the current year period to all staff and directors. In addition, approximately
$0.1 million of the current year period increase related to a one-time share award granted in November 2022, which vested
and was fully expensed immediately.
Net Gain (Loss) on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in oil and natural
gas prices. We have elected not to designate our open derivative contracts for hedge accounting, and accordingly, we
recorded the net change in the mark-to-market valuation of the derivative contracts in the consolidated statements of
operations. The amounts recorded on the consolidated statements of operations related to derivative contracts represent the
(i) gains (losses) 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. The table below summarizes our net
realized and unrealized gains (losses) on derivative contracts as well as the impact of net realized (gains) losses on our
average realized prices for the periods presented. As a result of our acquisitions during fiscal year 2022 and the
corresponding borrowings on our Senior Secured Credit Facility, we were required by terms in our Senior Secured Credit
Facility to hedge a portion of our production. The increase in commodity prices since entering into the hedges resulted in
realized losses on derivative contracts for the current and prior years. As of June 30, 2023, we did not have any open crude
oil or natural gas derivative contracts.
(in thousands, except per unit and per BOE amounts)
Realized gain (loss) on derivative contracts
Unrealized gain (loss) on derivative contracts
Total net gain (loss) on derivative contracts
Average realized crude oil price per BBL
Cash effect of oil derivative contracts per BBL
Crude oil price per Bbl (including impact of realized derivatives)
Average realized natural gas price per MCF
Cash effect of natural gas derivative contracts per MCF
Natural gas price per Mcf (including impact of realized derivatives)
Years Ended June 30,
2022
2023
$
$
$
$
$
$
(1,481)
1,994
513
77.46
(0.37)
77.09
7.00
(0.14)
6.86
$
$
$
$
$
$
(1,769)
(1,994)
(3,763)
85.11
(1.24)
83.87
5.49
(0.14)
5.35
$
$
$
$
$
$
Variance
Variance %
288
3,988
4,276
(7.65)
0.87
(6.78)
1.51
—
1.51
(16.3) %
(200.0) %
(113.6) %
(9.0) %
(70.2) %
(8.1) %
27.5 %
— %
28.2 %
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Interest Expense
Interest expense decreased $0.1 million during the fiscal year ended June 30, 2023 compared to fiscal year 2022 primarily
due to the repayment of borrowings outstanding on our Senior Secured Credit Facility throughout the year.
Income tax (expense) provision
For the year ended June 30, 2023, we recognized income tax expense of $10.1 million on net income before income taxes
of $45.3 million compared to an income tax expense of $8.5 million on net income before income taxes of $41.1 million
for the year ended June 30, 2022. The effective tax rates were 22.2% and 20.7% for the years ended June 30, 2023 and
2022, respectively. In the prior year, the Company benefited from certain EOR tax credits whereas in the current year the
credits were not available.
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 1, “Summary of Significant Events and Accounting Policies” 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, 2023, 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. Additionally, a
10% decrease in commodity prices used to determine our proved reserves as of
38
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June 30, 2023, while all other factors remained constant, would not have resulted in an impairment of our oil and natural
gas properties. Holding all other factors constant, a reduction in our proved reserve estimates at June 30, 2023 of 10%
would affect depletion, depreciation, and amortization expense by approximately $0.4 million.
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 forecasted 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.
Stock-based Compensation. The fair value, and for certain awards the expected vesting period, of our performance-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 our 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 performance-based awards is based on our total common stock return compared to a peer group of other
companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set
target.
Recent Accounting Pronouncements. Refer to Note 1, “Summary of Significant Events and Accounting Policies” to our
consolidated financial statements in Item 8. Financial Statements and Supplementary Data for discussion of the recent
accounting pronouncements issued by the Financial Accounting Standards Board.
Item 7A. Quantitative and Qualitative Disclosures About Market Risks
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 and natural gas
prices. We do not enter into derivative contracts for speculative trading purposes.
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 2023 and 2022, we did not
post collateral. 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 7, “Derivatives” to our consolidated financial statements for
more details.
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 SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum SOFR of
0.50%, 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 practices, we
do not use interest rate derivative instruments to manage exposure to interest rate changes.
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Item 8. Consolidated Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm (PCAOB ID No. 659) on Consolidated
Financial Statements
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Consolidated Balance Sheets as of June 30, 2023 and 2022
Consolidated Statements of Operations for the Years Ended June 30, 2023 and 2022
Consolidated Statements of Cash Flows for the Years Ended June 30, 2023 and 2022
Consolidated Statements of Changes in Stockholders’ Equity for the Years Ended June 30, 2023 and 2022
Notes to Consolidated Financial Statements
Supplemental Disclosure about Oil and Natural Gas Properties (unaudited)
41
44
46
47
48
49
50
71
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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, 2023 and 2022, 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, 2023 and 2022, and the consolidated results of its operations and its cash
flows for the years then ended, in conformity with accounting principles generally accepted in the United States of
America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the Company’s internal control over financial reporting as of June 30, 2023, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission and our report dated September 13, 2023 expressed an unqualified opinion on the Company’s
internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to
express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting
firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the
U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the
PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and
perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material
misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material
misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond
to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the
consolidated financial statements. Our audits also included evaluating the accounting principles used and significant
estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We
believe that our audits provide a reasonable basis for our opinion.
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 Depletion, Depreciation, and Amortization (“DD&A”) and
Full Cost Ceiling Test Impairment Calculation (“Ceiling Test”)
As described in Note 1, 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
41
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gas reserves in accordance with accounting principles generally accepted in the United States of America and SEC
guidelines. For the year ended June 30, 2023, the Company recorded DD&A related to its proved oil and natural gas
properties of approximately $13.1 million, and there was no ceiling test impairment.
The Company engages two independent reservoir engineering firms to serve as a management specialist and 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 specialists 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:
● Evaluating the knowledge, skill, and ability of the Company’s third-party reservoir engineering specialists and
their relationship to the Company, inquiries of those reservoir engineers regarding the process followed and
judgments made to estimate the proved reserve volumes, and reading the reserve report prepared by the reservoir
engineering specialists.
● Evaluating significant assumptions used by management and its specialists 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 specialists for
completeness and accuracy and an evaluation of the specialist’s findings. The procedures performed included:
o Testing the operating effectiveness of controls over the Company’s estimation of oil and natural gas
reserve quantities;
o Testing the data inputs used by specialist for completeness and accuracy;
o Testing the specialist’s findings for mathematical accuracy; and,
o
Performing analytical procedures on pricing, reserve quantities and cost estimates developed by
management and its specialists. Those procedures entailed comparisons of:
◾ prices to historical benchmark prices, adjusted for pricing differentials,
◾ production forecasts to recent historical actual production,
◾ projections of lease operating costs to costs incurred by property during fiscal year ended June
30, 2023, and
◾ projected production taxes to recent historical taxes incurred and to statutory tax rates.
● Evaluating the accuracy of revenue and working interest percentages used in the reserve reports by comparing a
sample of such interests to the land records.
● Performing retrospective review of historical estimates of proved oil and natural gas reserves to identify potential
management bias in estimates.
● Testing the accuracy of the Company’s depletion and impairment calculations that included these proved reserves.
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/s/ Moss Adams LLP
Houston, Texas
September 13, 2023
We have served as the Company’s auditor since 2017.
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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 Internal Control over Financial Reporting
We have audited Evolution Petroleum Corporation and subsidiaries (the “Company”) internal control over financial
reporting as of June 30, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the
Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company
maintained, in all material respects, effective internal control over financial reporting as of June 30, 2023, based on criteria
established in Internal Control – Integrated Framework (2013) issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United
States) (“PCAOB”), the consolidated balance sheets of Evolution Petroleum Corporation and subsidiaries as of June 30,
2023 and 2022, the related consolidated statements of operations, cash flows, and changes in stockholders’ equity for the
years then ended, and the related notes (collectively referred to as the “consolidated financial statements”) and our report
dated September 13, 2023 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s
Report on Internal Control over Financial Reporting included in Item 9A. Our responsibility is to express an opinion on the
Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the
PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities
laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in
all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing
the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control
based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the
circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with
generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and
procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded
as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and
that receipts and expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized
acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
44
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/s/ Moss Adams LLP
Houston, Texas
September 13, 2023
We have served as the Company’s auditor since 2017.
45
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EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED BALANCE SHEETS
(In thousands, except share and per share amounts)
June 30, 2023
June 30, 2022
Assets
Current assets
Cash and cash equivalents
Receivables from crude oil, natural gas, and natural gas liquids revenues
Derivative contract assets
Prepaid expenses and other current assets
Total current assets
Property and equipment, net of depletion, depreciation, and impairment
Oil and natural gas properties, net—full-cost method of accounting, of
which none were excluded from amortization
Other assets
Total assets
Liabilities and Stockholders’ Equity
Current liabilities
Accounts payable
Accrued liabilities and other
Derivative contract liabilities
State and federal taxes payable
Total current liabilities
Long term liabilities
Senior secured credit facility
Deferred income taxes
Asset retirement obligations
Operating lease liability
Total liabilities
Commitments and contingencies (Note 10)
Stockholders’ equity
Common stock; par value $0.001; 100,000,000 shares authorized: issued and
outstanding 33,247,523 and 33,470,710 shares as of June 30, 2023
and 2022, respectively
Additional paid-in capital
Retained earnings
Total stockholders’ equity
Total liabilities and stockholders’ equity
$
$
$
$
11,034
7,884
—
2,277
21,195
105,781
1,341
128,317
5,891
6,027
—
365
12,283
—
6,803
17,012
125
36,223
33
40,098
51,963
92,094
128,317
$
$
$
$
8,280
24,043
170
3,875
36,368
110,508
1,171
148,047
15,133
11,893
2,164
1,095
30,285
21,250
7,099
13,899
—
72,533
33
42,629
32,852
75,514
148,047
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF OPERATIONS
(In thousands, except per share amounts)
Revenues
Crude oil
Natural gas
Natural gas liquids
Total revenues
Operating costs
Lease operating costs
Depletion, depreciation, and accretion
General and administrative expenses
Total operating costs
Income (loss) from operations
Other income (expense)
Net gain (loss) on derivative contracts
Interest and other income
Interest expense
Income (loss) before income taxes
Income tax (expense) benefit
Net income (loss)
Net income (loss) per common share:
Basic
Diluted
Weighted average number of common shares outstanding:
Basic
Diluted
$
$
$
$
Years Ended June 30,
2023
2022
$
$
$
$
51,044
63,800
13,670
128,514
59,545
14,273
9,583
83,401
45,113
513
121
(458)
45,289
(10,072)
35,217
1.05
1.04
32,985
33,190
52,683
39,174
17,069
108,926
48,657
8,053
6,835
63,545
45,381
(3,763)
95
(572)
41,141
(8,513)
32,628
0.97
0.96
32,952
33,306
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In thousands)
Cash flows from operating activities:
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
$
35,217
$
32,628
Years Ended June 30,
2022
2023
Depletion, depreciation, and accretion
Stock-based compensation
Settlement of asset retirement obligations
Deferred income taxes
Unrealized (gain) loss on derivative contracts
Accrued settlements on derivative contracts
Other
Changes in operating assets and liabilities:
Receivables from crude oil, natural gas, and natural gas liquids revenues
Prepaid expenses and other current assets
Accounts payable and accrued liabilities and other
State and federal taxes payable
Net cash provided by operating activities
Cash flows from investing activities:
Acquisition of oil and natural gas properties
Capital expenditures for oil and natural gas properties
Net cash used in investing activities
Cash flows from financing activities:
Common stock dividends paid
Common stock repurchases, including stock surrendered for tax withholding
Borrowings under senior secured credit facility
Repayments of senior secured credit facility
Net cash (used in) provided by financing activities
Net increase (decrease) in cash and cash equivalents
Cash and cash equivalents, beginning of period
Cash and cash equivalents, end of period
Supplemental disclosures of cash flow information:
Cash paid for interest on senior secured credit facility
Cash paid for income taxes
Cash received from income tax refunds
Non-cash investing and financing transactions:
Increase (decrease) in accrued capital expenditures for oil and natural gas properties
Oil and natural gas property costs attributable to the recognition of asset retirement obligations
14,273
1,639
(174)
(296)
(1,994)
(919)
(4)
18,441
(692)
(13,489)
(730)
51,272
(31)
(6,961)
(6,992)
(16,106)
(4,170)
—
(21,250)
(41,526)
2,754
8,280
11,034
498
11,876
—
766
2,015
$
$
$
$
$
$
8,053
125
—
1,142
1,994
919
(10)
(11,427)
(538)
18,516
1,058
52,460
(53,342)
(1,531)
(54,873)
(11,796)
(38)
34,000
(16,750)
5,416
3,003
5,277
8,280
523
6,294
3,223
1,094
7,807
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS’ EQUITY
(In thousands)
Balances at June 30, 2021
Issuance of restricted common stock
Forfeitures of restricted stock
Common stock repurchases, including stock
surrendered for tax withholding
Retirements of treasury stock
Stock-based compensation
Net income (loss)
Common stock dividends paid
Balances at June 30, 2022
Issuance of restricted common stock
Forfeitures of restricted stock
Common stock repurchases, including stock
surrendered for tax withholding
Retirements of treasury stock
Stock-based compensation
Net income (loss)
Common stock dividends paid
Balances at June 30, 2023
Common Stock
Additional
Paid-in
Par Value Capital
34
—
(1)
42,541
—
1
$
$
Shares
33,515
336
(373)
—
(7)
—
—
—
33,471
476
(26)
—
(673)
—
—
—
33,248
$
$
—
—
—
—
—
33
1
—
—
(1)
—
—
—
33
$
$
—
(38)
125
—
—
42,629
(1)
—
—
(4,169)
1,639
—
—
40,098
Retained
Earnings
Treasury
Stock
Total
Stockholders’
Equity
$
$
$
12,020
—
—
—
—
—
32,628
(11,796)
32,852
—
—
—
—
—
35,217
(16,106)
51,963
$
$
$
— $
—
—
(38)
38
—
—
—
— $
—
—
(4,170)
4,170
—
—
—
— $
54,595
—
—
(38)
—
125
32,628
(11,796)
75,514
—
—
(4,170)
—
1,639
35,217
(16,106)
92,094
See accompanying notes to consolidated financial statements.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1. Summary of Significant Events and Accounting Policies
Nature of Operations. Evolution Petroleum Corporation (“Evolution,” and together with its consolidated subsidiaries, the
“Company”) is an independent energy company focused on maximizing returns to stockholders through the ownership of
and investment in onshore oil and natural gas properties in the United States. The Company’s long-term goal is to
maximize total shareholder return from a diversified portfolio of long-life oil and natural gas properties built through
acquisitions and through selective development opportunities, production enhancement, and other exploitation efforts on its
oil and natural gas properties.
The Company’s producing properties consist of non-operated interests in the following areas: the Jonah Field in Sublette
County, Wyoming, a natural gas and natural gas liquids producing field; the Williston Basin in North Dakota, producing oil
and natural gas properties; the Barnett Shale located in North Texas, natural gas producing properties; the Hamilton Dome
Field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the
reservoir; the Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO2 enhanced oil recovery project; as
well as small overriding royalty interests in four onshore Texas wells.
Principles of Consolidation and Reporting. The consolidated financial statements include the accounts of Evolution
Petroleum Corporation and its wholly-owned subsidiaries. All significant intercompany transactions have been eliminated
in consolidation. The consolidated financial statements for the previous year may include certain reclassifications to
conform to the current presentation. To conform with the current year presentation, “Other receivables” disclosed in
Footnote 14, “Additional Financial Information” is included with “Prepaid expenses and other current assets” instead of
“Receivables from crude oil, natural gas, and natural gas liquids revenues” at June 30, 2022 on the consolidated balance
sheets. This reclassification has no impact on previously reported net income or stockholders’ equity.
Risk and Uncertainties. The Company’s oil and natural gas interests are operated by third-party operators and involve
other third-party working interest owners. As a result, the Company has a limited ability to influence the operation or
future development of such properties. However, the Company is proactive with its third-party operators to review capital
projects and related spending and present alternative plans as appropriate.
Use of Estimates. The preparation of financial statements in conformity with generally accepted accounting principles in
the United States requires the Company to make estimates and assumptions that affect the reported amounts of assets and
liabilities and the disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements
and the reported amounts of revenues and expenses during the respective reporting periods. Significant estimates include
(a) reserve quantities and estimated future cash flows associated with proved reserves, which may significantly impact
depletion expense and potential impairments of oil and natural gas properties, (b) asset retirement obligations, (c) stock-
based compensation, (d) fair values of derivative contract assets and liabilities, (e) income taxes and the valuation of
deferred income tax assets, (f) commitments and contingencies, and (g) accruals of crude oil, natural gas, and natural gas
liquids (“NGL”) revenues and expenses. The Company analyzes estimates and judgements based on historical experience
and various other assumptions and information that are believed to be reasonable. Estimates and assumptions about future
events and their effects cannot be predicted with certainty and, accordingly, these estimates may change as additional
information is obtained, as new events occur, and as the Company’s environment changes. Actual results may differ from
the estimates and assumptions used in the preparation of the Company’s consolidated financial statements.
Cash and Cash Equivalents. The Company considers all highly liquid investments, with original maturities of 90 days or
less when purchased, to be cash and cash equivalents.
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable consist of accrued hydrocarbon
revenues due under normal trade terms, generally requiring payment within 30 to 60 days of production, and other
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied
to the earliest unpaid items. The Company establishes provisions for losses on accounts receivable if it is determined that
collection of all or a part of an outstanding balance is not probable. Collectability is reviewed regularly and an allowance is
established or adjusted, as necessary, using the specific identification method. As of June 30, 2023 and 2022, no allowance
for doubtful accounts was considered necessary.
Oil and Natural Gas Properties. The Company uses the full-cost method of accounting for its investments in oil and
natural gas properties. Under this method of accounting, all costs incurred in the acquisition, exploration and development
of oil and natural gas properties, including unproductive wells, are capitalized. 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.
The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of depletion, estimated
future development costs, and asset retirement costs (net of salvage values) not included in oil and natural gas properties,
less costs excluded from amortization. The depreciable base of oil and natural gas properties is amortized using the unit-of-
production method over total proved reserves.
The capitalized costs of the Company’s oil and natural gas properties, net of accumulated amortization and related deferred
income taxes are subject to a full cost ceiling limitation in which the costs are not allowed to exceed their related estimated
future net revenues discounted at 10%, net of tax considerations. Any excess over the full cost ceiling limitation is charged
to expense as an impairment and is reflected as additional accumulated depletion, depreciation, and impairment or as a
credit to oil and natural gas properties.
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. These costs are excluded until the project is evaluated
and proved reserves are established or impairment is determined. As of June 30, 2023 and 2022, the Company did not have
any costs excluded from depletion and amortization.
Other Property and Equipment. Other property and equipment includes building leasehold improvements, data
processing and telecommunications equipment, office furniture, and office equipment. These items are recorded at cost and
depreciated over expected lives of the individual assets or group of assets, which range from three to seven years. The
assets are depreciated using the straight-line method. Realization of the carrying value of other property and equipment is
reviewed for possible impairment whenever events or changes in circumstances indicate that the carrying amount may not
be recoverable. Assets are determined to be impaired if a forecast of undiscounted estimated future net operating cash
flows directly related to the asset, including disposal value, if any, is less than the carrying amount of the asset. If any asset
is determined to be impaired, the loss is measured as the amount by which the carrying amount of the asset exceeds its fair
value. Repair and maintenance costs are expensed in the period incurred.
Asset Retirement Obligations. An asset retirement obligation (“ARO”) associated with the retirement of a tangible long-
lived asset is recognized as a liability in the period incurred. It is associated with an increase in the carrying amount of the
related long-lived asset, the Company’s oil and natural gas properties. The cost of the tangible asset, including the asset
retirement cost, is depleted over the useful life of the asset. The initial recognition or subsequent revision of asset
retirement cost is considered a Level 3 fair value measurement. The asset retirement obligation is recorded at its estimated
fair value, measured by reference to the expected future cash outflows required to satisfy the retirement obligation
discounted at the Company’s credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the
discounted liability is accreted to its expected settlement value. If the estimated future cost of the asset retirement
obligation changes, an adjustment is recorded to both the asset retirement obligation and the long-lived asset. Revisions
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to estimated asset retirement obligations can result from changes in retirement cost estimates, revisions to estimated
inflation rates, and changes in the estimated timing of abandonment.
Fair Value of Financial Instruments. The Company’s financial instruments consist of cash and cash equivalents, accounts
receivable, accounts payable, derivative instruments, and debt. Except for derivatives, the carrying amounts of cash and
cash equivalents, accounts receivable and accounts payable are short-term instruments and approximate fair value due to
their highly liquid nature. The carrying amount of debt approximates fair value as the variable rates on the Senior Secured
Credit Facility, as defined in Note 5, “Senior Secured Credit Facility,” are market interest rates. The fair values of the
Company’s derivative assets and liabilities are based on a third-party industry-standard pricing model that uses market data
obtained from third-party sources, including quoted forward prices for oil and natural gas, discount rates, and volatility
factors.
Concentrations of Credit Risk. The Company’s primary concentrations of credit risk are the risks of uncollectible accounts
receivable, and to a lesser extent, the non-performance by counterparties under the Company’s derivative contracts, and
cash and cash equivalent balances in excess of limits federally insured by the Federal Deposit Insurance Corporation.
Substantially all of the Company’s accounts receivable as of June 30, 2023 and 2022 are from crude oil, natural gas, and
NGL sales to third-party purchasers in the oil and natural gas industry. The Company holds working interests in crude oil
and natural gas properties for which a third-party serves as operator. As a non-operator, the Company primarily markets its
production through its field operators, except at the Jonah Field, where the Company takes its natural gas and NGL
production in-kind. As a non-operator, the Company is highly dependent on the success of its third-party operators and the
decisions made in connection with their operations. With the exception of the Jonah Field, the third-party operator sells the
crude oil, natural gas, and NGLs to the purchaser, collects the cash, and distributes the cash to the Company. In the year
ended June 30, 2023, approximately 83% of the Company’s total revenues were realized from the Jonah Field, Barnett
Shale and Delhi Field combined. Diversified, the Company’s largest operator at Barnett, remitted approximately 26% of
total revenue proceeds to the Company and at Delhi Field, Denbury, the operator of the Field, remitted approximately 22%
of total revenue proceeds to the Company. At Jonah Field, where the Company takes its natural gas and NGL production
in-kind, during the current year, the Company sold approximately 17% of its total revenues to Conoco Phillips. In the year
ended June 30, 2022, three operators each distributed over 10% of the Company’s crude oil, natural gas and NGL revenues
making up approximately 83% of total revenues for the year, respectively. The majority of the Company’s crude oil, natural
gas, and NGL production is sold to purchasers under short-term (less than 12 months) contracts at market-based prices.
Derivative Instruments. The Company follows Accounting Standards Codification (“ASC”) 815, Derivatives and Hedging
(“ASC 815”). From time to time, in accordance with the Company’s risk management strategy and with certain covenants
under the Senior Secured Credit Facility, it may hedge a portion of its forecasted crude oil, natural gas, and NGL
production. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability
measured at fair value. The Company nets its derivative instrument fair value amounts executed with the same counterparty
pursuant to an International Swap Dealers Association Master Agreement (“ISDA”); the agreement provides for net
settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative
instruments provide an economic hedge of the Company’s exposure to commodity price volatility, the Company elected
not to meet the criteria to qualify its derivative instruments for hedge accounting treatment. Accordingly, the Company
records the net change in the mark-to-market valuation of these positions, as well as payments and receipts on settled
contracts, in “Net gain (loss) on derivative contracts” on the consolidated statements of operations.
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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
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 the Company’s 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 the Company’s financial statements. Material
revisions to reserve estimates and/or significant changes in commodity prices could substantially affect the Company’s
estimated future net cash flows of its proved reserves. These changes could affect the Company’s quarterly ceiling test
calculation and could significantly affect its depletion rate.
Income Taxes. The Company recognizes deferred income tax assets and liabilities based on the differences between the
tax basis of assets and liabilities and its reported amounts in the financial statements that may result in taxable or deductible
amounts in future years. The measurement of deferred income tax assets may be reduced by a valuation allowance based
upon management’s assessment of available evidence if it is deemed more likely than not that some or all of the deferred
income tax assets will not be realizable. The Company recognizes a tax benefit from an uncertain position when it is more
likely than not that the position will be sustained upon examination which is based on the technical merits of the position.
The Company records the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement
with a taxing authority. The Company classifies any interest and penalties associated with income taxes as income tax
expense.
Earnings (Loss) Per Share. The Company grants restricted stock awards which entitle the recipient to all of the rights of
a shareholder of the Company including non-forfeitable rights to receive all dividends or other distributions paid with
respect to such share; therefore, it applies the two-class method of calculating basic and diluted earnings (loss) per share
(“EPS”) in accordance with ASC 260, Earnings Per Share (“ASC 260”). Basic EPS is computed by dividing earnings or
loss available to common stockholders, after allocating undistributed earnings to participating securities, by the weighted-
average number of common shares outstanding during the period. The computation of diluted EPS is similar to the
computation of basic EPS, except that the denominator is increased to include the number of additional common shares
that would have been outstanding if potentially dilutive common shares had been issued. Unvested performance-based
restricted stock awards and unvested contingent restricted share units are only potentially dilutive if the awards meet their
respective performance criteria as of the period end. The Company uses the treasury stock method to determine the effect
of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. The unamortized stock-
based compensation expense related to unvested awards is assumed to be used to repurchase shares of common stock at the
average market price during the period. The incremental shares (the difference between the number of shares assumed
issued and the number of shares assumed repurchased) are included in the denominator of the diluted EPS computation.
Awards with performance-based vesting restrictions are included in the computation of diluted shares, if dilutive, when the
underlying performance conditions either (i) were satisfied as of the end of the reporting period or (ii) would be considered
satisfied if the end of the reporting period were the end of the related contingency period.
Recently Issued Accounting Pronouncements
In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (“ASU 2016-13”). ASU 2016-13
changes the impairment model for most financial assets and certain other instruments, including trade and other
receivables, and requires the use of a new forward-looking expected loss model that will result in the earlier recognition of
allowances for losses. Early adoption is permitted and entities must adopt the amendment using a modified retrospective
approach to the first reporting period in which the guidance is effective. For smaller reporting companies, as provided by
ASU 2019-10, Financial Instruments - Credit Losses (Topic 326), Derivatives and Hedging (Topic 815), and Leases (Topic
842), ASU 2016-13 is effective for annual periods, including interim periods within those annual periods, beginning after
December 15, 2022. The Company is currently evaluating the impact of ASU 2016-13 but does
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
not expect that it will have a material effect on the Company’s financial position, results of operations, cash flows or
disclosures.
Other accounting pronouncements that have recently been issued by the FASB or other standards-setting bodies are not
expected to have a material impact on the Company’s financial position, results of operations, cash flows or disclosures.
Note 2. Revenue Recognition
The Company’s revenues are primarily generated from its crude oil, natural gas and NGL production from the Jonah Field
in Sublette County, Wyoming; the Williston Basin in North Dakota; the Barnett Shale located in North Texas; the Hamilton
Dome Field in Wyoming; and the Delhi Field in Northeast Louisiana. Additionally, an overriding royalty interest retained
in a past divestiture of Texas properties provides de minimis revenue. The following table disaggregates the Company’s
revenues by major product for the years ended June 30, 2023 and 2022 (in thousands):
Revenues
Crude oil
Natural gas
Natural gas liquids
Total revenues
Years Ended June 30,
2023
2022
$
$
51,044
63,800
13,670
128,514
$
$
52,683
39,174
17,069
108,926
In the Jonah Field, the Company has elected to take its natural gas and NGL working interest production in-kind and
markets its NGL production to Enterprise Products Partners L.P. and its natural gas production to different purchasers.
The Company does not take production in-kind at any of its other properties and does not negotiate contracts with
customers for such production. The Company recognizes crude oil, natural gas, and NGL production revenue at the point
in time when custody and title (“control”) of the product transfers to the customer. The sales of oil and natural gas are made
under contracts which the Company’s third-party operators of its wells have negotiated with customers, which typically
include variable consideration that is based on pricing tied to local indices and volumes delivered in the current month. The
Company receives payment from the sale of oil and natural gas production one to two months after delivery.
Judgments made in applying the guidance in ASC 606, Revenue from Contracts with Customers, relate primarily to
determining the point in time when control of product transfers to the customer. The Company does not believe that
significant judgments are required with respect to the determination of the transaction price, including amounts that
represent variable consideration, as volume and price carry a low level of estimation uncertainty given the precision of
volumetric measurements and the use of index pricing with predictable differentials. Accordingly, the Company does not
consider estimates of variable consideration to be constrained.
The Company’s contractual performance obligations arise upon the production of hydrocarbons from wells in which the
Company has an ownership interest. The performance obligations are considered satisfied upon control of produced
hydrocarbons transferring to a customer at a specified delivery point. Consideration is allocated to completed performance
obligations at the end of an accounting period.
Revenue is recorded in the month when contractual performance obligations are satisfied. However, settlement statements
from the purchasers of hydrocarbons and the related cash consideration are received by field operators one to two months
before the Company receives payment and documentation from the operator, which is typical in the oil and natural gas
industry. As a result, the Company must estimate the amount of production delivered to the customer and the consideration
that will ultimately be received for the sale of the product. To estimate accounts receivable from operators’ contracts with
customers, the Company uses knowledge of its properties, information from field operators, historical performance,
contractual arrangements, index pricing, quality and transportation differentials, and other factors. Because
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
the contractual performance obligations have been satisfied and an unconditional right to consideration exists as of the
balance sheet date, the Company recognized amounts due from contracts with field operators as “Receivables from crude
oil, natural gas, and natural gas liquids revenues” on the consolidated balance sheets. Differences between estimates and
actual amounts received for product sales are recorded in the month that payments received from purchasers are remitted to
the Company by field operators.
Note 3. Acquisitions
On April 1, 2022, the Company closed the acquisition of non-operated interests in the Jonah Field in Sublette County,
Wyoming from Exaro Energy III, LLC (the “Jonah Field Acquisition”). After taking into account customary closing
adjustments and an effective date of February 1, 2022, total cash consideration for the Jonah Field Acquisition was
$26.4 million. The Company accounted for this transaction as an asset acquisition and allocated all of the purchase price
(including $0.2 million of transaction costs) to proved oil and natural gas properties. Approximately, $1.6 million of the
consideration transferred related to deposits transferred to the Company at closing, the largest related to a $1.2 million
deposit with Enterprise for a gas gathering contract which was recorded to “Other assets” on the consolidated balance
sheets. In addition, the Company recognized $3.0 million in non-cash asset retirement obligations. The transaction was
funded with cash on hand and $17.0 million in borrowings under the Company’s Senior Secured Credit Facility.
On January 14, 2022, the Company completed the acquisition of non-operated working interests in the Williston Basin in
North Dakota from Foundation Energy Fund VII-A, LP and Foundation Energy Management, LLC (the “Williston Basin
Acquisition”). After taking into account customary closing adjustments and an effective date of June 1, 2021, cash
consideration was $25.2 million which included $0.3 million of capitalized transaction costs related to the acquisition. The
Company accounted for the transaction as an asset acquisition and allocated all of the purchase price (including capitalized
transaction costs) to proved oil and natural gas properties. The Company also recognized $2.4 million in non-cash asset
retirement obligations. The transaction was funded with cash on hand and $16.0 million in borrowings under the
Company’s Senior Secured Credit Facility.
In accordance with the FASB’s authoritative guidance on asset acquisitions, the Company allocated the cost of the above
acquisitions to the assets acquired and liabilities assumed based on a relative fair value basis of the assets acquired and
liabilities assumed, with no recognition of goodwill or bargain purchase gain recorded. Incremental legal and professional
fees related directly to the acquisitions were capitalized as part of the acquisition cost. The fair value is the price that would
be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the
measurement date (exit price). Fair value measurements also utilize market assumptions of market participants.
Note 4. Property and Equipment
Property and equipment as of June 30, 2023 and 2022 consisted of the following (in thousands):
Oil and natural gas properties
Property costs subject to amortization
Less: Accumulated depletion, depreciation, and
impairment
Oil and natural gas properties, net
June 30, 2023
June 30, 2022
$
$
197,049
(91,268)
105,781
$
$
188,634
(78,126)
110,508
As of June 30, 2023 and 2022, all oil and natural gas property costs were subject to amortization. Depletion on oil and
natural gas properties was $13.1 million and $7.5 million for the years ended June 30, 2023 and 2022, respectively.
Depreciation on other properties and equipment was less than $0.1 million for the year ended June 30, 2022. The
Company’s other properties and equipment were fully depreciated as of June 30, 2022.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
During the years ended June 30, 2023 and 2022, the Company incurred development capital expenditures of $6.2 million
and $2.6 million, respectively. In addition, during the year ended June 30, 2022, the Company recorded a downward
$0.9 million purchase adjustment related to its acquisition of the Barnett Shale properties. The Company received $0.9
million during the year ended June 30, 2022 primarily related to effective date net revenues received from the previous
owner of the properties.
The Company uses the full cost method of accounting for its investments in oil and natural gas properties. All costs of
acquisition, exploration, and development of oil and natural gas reserves are capitalized as the cost of oil and natural gas
and properties when incurred. To the extent capitalized costs of evaluated oil and natural gas properties, net of accumulated
depletion, exceed the discounted future net revenues of proved oil and natural gas reserves, net of deferred taxes, such
excess capitalized costs would be charged to expense as a write-down of oil and natural gas properties.
At June 30, 2023, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month
average for the 12-months ended June 30, 2023 of the West Texas Intermediate (“WTI”) crude oil spot price of $83.23 per
barrel and Henry Hub natural gas spot price of $4.78 per MMBtu, adjusted by market differentials by field. The net price
per barrel of NGLs was $33.71, which was based on historical differentials to WTI as NGLs do not have any single
comparable reference index price. Using these prices at June 30, 2023, the cost center ceiling was higher than the
capitalized costs of oil and natural gas properties, and as a result, no write-down was necessary.
At June 30, 2022, the ceiling test value of the Company’s reserves was calculated based on the first-day-of-the-month
average for the 12-months ended June 30, 2022 of the WTI crude oil spot price of $85.82 per barrel and Henry Hub natural
gas spot price of $5.19 per MMBtu, adjusted by market differentials by field. The net price per barrel of NGLs was $44.24,
which was based on historical differentials to WTI as NGLs do not have any single comparable reference index price.
Using these prices at June 30, 2022, the cost center ceiling was higher than the capitalized costs of oil and natural gas
properties, and as a result, no write-down was necessary.
Note 5. Senior Secured Credit Facility
On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility, as amended, (the
“Senior Secured Credit Facility”) with MidFirst Bank in an amount up to $50.0 million with a current borrowing base of
$50.0 million. On May 5, 2023, the Company entered into the Tenth Amendment to the Senior Secured Credit Facility
extending the maturity to April 9, 2026. The Tenth Amendment also replaced the London Interbank Offered Rate
("LIBOR") with the Secured Overnight Financing Rate (“SOFR”) plus a credit spread adjustment of 0.05% to effectively
convert SOFR to a LIBOR equivalent and modifies the Margined Collateral Value, as defined in the Ninth Amendment to
the Senior Secured Credit Facility, to $95.0 million. The borrowing base will be redetermined semiannually, with the
lenders and the Company each having the right to one interim unscheduled redetermination between any two consecutive
semi-annual redeterminations. The borrowing base takes into account the estimated value of the Company’s oil and natural
gas properties, proved reserves, total indebtedness, and other relevant factors consistent with customary oil and natural gas
lending criteria. The Senior Secured Credit Facility carries a commitment fee of 0.25% per annum on the undrawn portion
of the borrowing base. Any borrowings under the Senior Secured Credit Facility will bear interest, at the Company’s
option, at either SOFR plus 2.80%, which includes a 0.05% credit spread adjustment from LIBOR, subject to a minimum
SOFR of 0.50%, or the Prime Rate, as defined under the Senior Secured Credit Facility, plus 1.00%.
The Company may elect, at its option, to prepay any borrowings outstanding under the Senior Secured Credit Facility
without premium or penalty. Amounts outstanding under the Senior Secured Credit Facility are guaranteed by the
Company’s direct and indirect subsidiaries and secured by a security interest in substantially all of the properties of the
Company and its subsidiaries. Borrowings under the Senior Secured Credit Facility may be used for the acquisition and
development of oil and natural gas properties, investments in cash flow generating properties complimentary to the
production of oil and natural gas, and for letters of credit or other general corporate purposes.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The Senior Secured Credit Facility contains certain events of default, including non-payment; breaches or representation
and warranties; non-compliance with covenants; cross-defaults to material indebtedness; voluntary or involuntary
bankruptcy; judgments and change in control. The Senior Secured Credit Facility also contains financial covenants
including a requirement that the Company maintain, as of the last day of each fiscal quarter, (i) a maximum total leverage
ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00 to 1.00, and (iii) a consolidated tangible net
worth of not less than $40.0 million, each as defined in the Senior Secured Credit Facility. As of June 30, 2023, the
Company did not have any borrowings outstanding under its Senior Secured Credit Facility, resulting in $50.0 million of
available borrowing capacity. As of June 30, 2023, the Company was in compliance with the financial covenants under the
Senior Secured Credit Facility.
On February 7, 2022, the Company entered into the Ninth Amendment to the Senior Secured Credit Facility. This
amendment, among other things, modified the definition of utilization percentage related to the required hedging covenant
such that for the purposes of determining the amount of future production to hedge, the utilization of the Senior Secured
Credit Facility will be based on the Margined Collateral Value, as defined in the agreement, to the extent it exceeds the
borrowing base then in effect. This amendment also required the Company to enter into hedges for the next 12-month
period ending February 2023, covering 25% of expected crude oil and natural gas production over that period.
On November 9, 2021, the Company entered into the Eighth Amendment to the Senior Secured Credit Facility. This
amendment, among other things, increased the borrowing base to $50.0 million and added a hedging covenant whereby the
Company must hedge a minimum of 25% to 75% of future production on a rolling 12-month basis when 25% or more of
the borrowing base is utilized. The hedging covenant was amended in the Ninth Amendment, as discussed above.
On August 5, 2021 the Company entered into the Seventh Amendment to the Senior Secured Credit Facility which, among
other things, added definitions for the terms “Acquired Entity or Mineral Interests” and “Acquired Entity or Mineral
Interests EBITDA Adjustment.” Additionally, the consolidated tangible net worth covenant level was reduced to $40.0
million from $50.0 million.
Note 6. Income Taxes
The Company files a consolidated federal income tax return in the United States and various combined and separate filings
in several state and local jurisdictions.
There were no unrecognized tax benefits, nor any accrued interest or penalties associated with unrecognized tax benefits
during the years ended June 30, 2023 and 2022. The Company believes that it has appropriate support for the income tax
positions taken and to be taken on the Company’s tax returns and that the accruals for tax liabilities are adequate for all
open years based on its assessment of many factors including past experience and interpretations of tax law applied to the
facts of each matter. The Company’s federal and state income tax returns are open to audit under the statute of limitations
for the fiscal years ended June 30, 2020 through June 30, 2022 for federal tax purposes and for the fiscal years ended
June 30, 2018 through June 30, 2022 for state tax purposes. To the extent the Company utilizes net operating losses
(“NOLs”) generated in earlier years, such earlier years may also be subject to audit.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Income tax (expense) benefit for the years ended June 30, 2023 and 2022 is comprised of the following (in thousands):
Current:
Federal
State
Total current income tax (expense) benefit
Deferred:
Federal
State
Total deferred income tax (expense) benefit
Total income tax (expense) benefit
June 30, 2023
June 30, 2022
$
$
(9,600)
(768)
(10,368)
457
(161)
296
(10,072)
$
$
(6,309)
(1,062)
(7,371)
(913)
(229)
(1,142)
(8,513)
For the year ended June 30, 2023 the Company recognized income tax expense of $10.1 million and had an effective tax
rate of 22.2% compared to income tax expense of $8.5 million and an effective tax rates of 20.7% for the year ended
June 30, 2022. During the years ended June 30, 2023 and 2022, the Company recognized an income tax benefit of $0.1
million for both periods related to the vesting of restricted stock awards.
The Company’s effective tax rate will typically differ from the statutory federal rate as a result of state income taxes,
primarily in the states of Louisiana, North Dakota, and Texas, due to percentage depletion in excess of basis, enhanced oil
recovery credit, and other permanent differences. The following table presents the reconciliation of the Company’s income
taxes calculated at the statutory federal tax rate to the income tax (expense) benefit (in thousands).
% of Income
Before
% of Income
Before
June 30, 2023 Income Taxes June 30, 2022 Income Taxes
Income tax (expense) benefit computed at the statutory
federal rate:
Reconciling items:
Depletion in excess of tax basis
State income taxes, net of federal tax benefit
Permanent differences related to stock-based compensation
and other
Federal valuation allowance
EOR credit benefit
Other
Income tax (expense) benefit
$
(9,511)
21.0 % $
(8,640)
78
(734)
96
—
—
(1)
(10,072)
$
(0.2)%
1.6 %
(0.2)%
— %
— %
— %
22.2 % $
190
(1,020)
3
623
377
(46)
(8,513)
21.0 %
(0.5)%
2.5 %
— %
(1.5)%
(0.9)%
0.1 %
20.7 %
In certain prior years, the Company undertook a project to seek potential cash tax savings opportunities identifying
available Enhanced Oil Recovery credits (“EOR credits”) related to its interests in the Delhi Field. During the year ended
June 30, 2022, the Company recognized an income tax benefit of $0.4 million attributable to the EOR credit. The EOR
credit was not available for fiscal year 2023.
In the prior year, the Company released its valuation allowance of $0.6 million. The Company considered all positive and
negative evidence to assess the likelihood that it will be able to realize its deferred tax assets. Realization is dependent on
generating sufficient taxable income over the period the deferred tax assets are deductible. For the three-year period ending
June 30, 2022, the Company was in a cumulative income position. Based on the weight of available evidence, the
Company believed that is more likely than not that the deferred tax assets will be realized.
Deferred income taxes primarily represent the net tax effect of temporary differences between the carrying amounts of
assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. The components of net
deferred income tax assets (liabilities) recognized are as follows (in thousands):
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Deferred tax assets:
Non-qualified stock-based compensation
Net operating loss carry-forwards and other carry-forwards
Derivative losses
Asset retirement obligations
Other deferred tax assets
$
Net deferred tax assets
Deferred tax liability:
Oil and natural gas properties
Total deferred tax liability
June 30, 2023
June 30, 2022
$
250
—
—
3,883
201
4,334
106
8
427
3,128
238
3,907
(11,137)
(11,137)
(11,006)
(11,006)
Net deferred tax liability
$
(6,803)
$
(7,099)
Note 7. Derivatives
The Company is exposed to certain risks relating to its ongoing business operations, including commodity price risk and
interest rate risk. In accordance with the Company’s strategy and the requirements under the Senior Secured Credit Facility
(as discussed in Note 5, “Senior Secured Credit Facility”), it may hedge or may be required to hedge a varying portion of
anticipated oil and natural gas production for future periods. Derivatives are carried at fair value on the consolidated
balance sheets as assets or liabilities, with the changes in the fair value included in the consolidated statements of
operations for the period in which the change occurs. The Company’s hedge policies and objectives may change
significantly as its operational profile changes or as required under the Senior Secured Credit Facility. The Company does
not enter into derivative contracts for speculative trading purposes.
It is the Company’s policy to enter into derivative contracts only with counterparties that are creditworthy financial or
commodity hedging institutions deemed by management as competent and competitive market makers. As of
June 30, 2023, all of the Company’s derivative contracts had expired. The Company has no open derivative contracts as of
June 30, 2023, and the Company did not post collateral under any of its derivative contracts during the year as they were
secured under the Company’s Senior Secured Credit Facility.
The Company has in the past and may utilize in the future costless put/call collars and fixed-price swaps to hedge a portion
of its anticipated future production. A costless collar consists of a sold call, which establishes a maximum price the
Company will receive for the volumes under contract, and a purchased put that establishes a minimum price. Fixed-price
swaps are designed so that the Company receives or makes payments based on a differential between fixed and variable
prices for the volumes under contract. The Company has elected not to designate its open derivative contracts for hedge
accounting. Accordingly, the Company records the net change in the mark-to-market valuation of the derivative contracts
and all payments and receipts on settled derivative contracts in “Net gain (loss) on derivative contracts” on the
consolidated statements of operations.
All derivative contracts are recorded at fair market value in accordance with ASC 815 and ASC 820, Fair Value
Measurement (“ASC 820”) and included in the consolidated balance sheets as assets or liabilities. The “Derivative contract
assets” and “Derivative contract liabilities” represent the difference between the market commodity prices and the hedged
prices for the remaining volumes of production hedges as of June 30, 2022 (the “mark-to-market valuation”).
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table summarizes the location and fair value amounts of all derivative contracts in the consolidated balance
sheets as of June 30, 2023 and 2022 (in thousands):
Derivatives not designated
as hedging contracts
under ASC 815
Commodity contracts
Commodity contracts
Total derivatives not designated as
hedging contracts under ASC 815
Balance sheet
location
Derivative Contract Assets
June 30, 2023 June 30, 2022
Current assets -
derivative contract
assets
Other assets -
derivative contract
assets
$
$
— $
170
—
— $
—
170
Balance sheet
location
Current liabilities -
derivative contract
liabilities
Long term
liabilities -
derivative contract
liabilities
Derivative Contract Liabilities
June 30, 2023 June 30, 2022
$
$
— $
2,164
—
—
— $
2,164
The following table summarizes the location and amounts of the Company’s realized and unrealized gains and losses on
derivative contracts in the Company’s consolidated statements of operations for the years ended June 30, 2023 and 2022 (in
thousands). “Realized gain (loss) on derivative contracts” represents all receipts (payments) on derivative contracts settled
during the period. “Unrealized gain (loss) on derivative contracts” represents the net change in the mark-to-market
valuation of the derivative contracts.
Derivatives not designated
as hedging contracts
under ASC 815
Commodity contracts:
Realized gain (loss) on derivative contracts
Unrealized gain (loss) on derivative contracts
Total net gain (loss) on derivative contracts
Location of gain (loss)
recognized in income on
derivative contracts
Other income and expenses - net gain
(loss) on derivative contracts
Other income and expenses - net gain
(loss) on derivative contracts
Years Ended June 30,
2023
2022
$
$
(1,481)
1,994
513
$
$
(1,769)
(1,994)
(3,763)
The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The
following table shows the potential effects of master netting arrangements on the fair value of the Company’s derivative
contracts as of June 30, 2022 (in thousands):
Offsetting of Derivative Assets and Liabilities
Gross amounts presented in the Consolidated Balance Sheet
Amounts not offset in the Consolidated Balance Sheet
Net amount
$
$
Derivative Contracts Assets
June 30, 2022
Derivative Contracts Liabilities
June 30, 2022
170
(170)
—
$
$
2,164
(170)
1,994
The Company enters into an ISDA with each counterparty prior to a derivative contract with such counterparty. The ISDA
is a standard contract that governs all derivative contracts entered into between the Company and the respective
counterparty. The ISDA allows for offsetting of amounts payable or receivable between the Company and the counterparty,
at the election of both parties, for transactions that occur on the same date and in the same currency.
Note 8. Fair Value Measurement
Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value
measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different
levels depending on the observability of the inputs employed in the measurement.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The three levels are defined as follows:
Level 1—Observable inputs such as quoted prices in active markets at the measurement date for identical,
unrestricted assets or liabilities.
Level 2—Other inputs that are observable directly or indirectly, such as quoted prices in markets that are not
active or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or
liability.
Level 3—Unobservable inputs for which there are little or no market data and which the Company makes its own
assumptions about how market participants would price the assets and liabilities.
Fair Value of Derivative Instruments. The Company’s determination of fair value incorporates not only the credit standing
of the counterparties involved in transactions with the Company resulting in receivables on the Company’s consolidated
balance sheets, but also the impact of the Company’s nonperformance risk on its own liabilities. Fair value is defined as the
price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market
participants at the measurement date. ASC 820 establishes a fair value hierarchy that prioritizes the inputs to valuation
techniques used to measure fair value. The Company utilizes market data or assumptions that market participants would
use in pricing the asset or liability, including assumptions about risk and the risks inherent in the inputs to the valuation
technique. These inputs can be readily observable (Level 1) market corroborated (Level 2), or generally unobservable
(Level 3). The Company classifies fair value balances based on observability of those inputs.
As required by ASC 820, a financial instrument’s level within the fair value hierarchy is based on the lowest level of input
that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the
fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their
placement within the fair value hierarchy levels. There were no transfers between fair value hierarchy levels for any period
presented. The following table, set forth by level within the fair value hierarchy, shows the Company’s financial assets and
liabilities that were accounted for at fair value as of June 30, 2022 (in thousands). The Company did not have any open
positions as of June 30, 2023.
Level 1
Level 2
Level 3
Total
June 30, 2022
Assets
Derivative contract assets
Liabilities
Derivative contract liabilities
$
$
— $
170
$
— $
170
— $
2,164
$
— $
2,164
Derivative contracts listed above as Level 2 include costless put/call collars that are carried at fair value. The Company
records the net change in fair value of these positions in “Net gain (loss) on derivative contracts” in the Company’s
consolidated statements of operations. The Company is able to value the assets and liabilities based on observable market
data for similar instruments, which resulted in the Company reporting its derivatives as Level 2. This observable data
includes the forward curves for commodity prices based on quoted market prices and implied volatility factors related to
changes in the forward curves. See Note 7, “Derivatives,” for additional discussion of derivatives.
Historically, the Company’s derivative contracts were with large utilities with investment grade credit ratings which are
believed to have minimal credit risk. As such, the Company was exposed to credit risk to the extent of nonperformance by
the counterparties in the derivative contracts. To date, the Company has not experienced such nonperformance.
Other Fair Value Measurements. The following disclosure of the estimated fair value of financial instruments is made in
accordance with the requirements of ASC 825, Financial Instruments. The estimated fair value amounts have been
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
determined at discrete points in time based on relevant market information. These estimates involve uncertainties and
cannot be determined with precision. The estimated fair value of cash and cash equivalents, accounts receivable, and
accounts payable approximates their carrying value due to their short-term nature. The estimated fair value of the
Company’s Senior Secured Credit Facility approximates carrying value because the interest rates approximate current
market rates.
The Company follows the provisions of ASC 820, for nonfinancial assets and liabilities measured at fair value on a non-
recurring basis. These provisions apply to the Company’s initial measurement and any subsequent revision of ARO for
which fair value is calculated using discounted future cash flows derived from historical costs and management’s
expectations of future cost environments. Significant Level 3 inputs used in the calculation of ARO include the costs of
plugging and abandoning wells, surface restoration, and reserve lives. Subsequent to initial recognition, revisions to
estimated asset retirement obligations are made when changes occur for input values. See Note 9, “Asset Retirement
Obligations,” for a reconciliation of the beginning and ending balances of the liability for the Company’s ARO.
Note 9. Asset Retirement Obligations
The Company’s ARO represents the estimated present value of the amount expected to be incurred to plug, abandon, and
remediate its oil and natural gas properties at the end of their productive lives in accordance with applicable laws and
regulations. The Company records the ARO liability on the consolidated balance sheets and capitalizes the cost in “Oil and
natural gas properties, net” during the period in which the obligation is incurred. The Company records the accretion of its
ARO liabilities in “Depletion, depreciation and amortization” expense in the consolidated statements of operations.
The following is a reconciliation of the activity related to the Company’s ARO liability (inclusive of the current portion)
for the years ended June 30, 2023 and 2022 (in thousands):
Asset retirement obligations — beginning of period
Liabilities incurred
Liabilities settled
Liabilities acquired(1)
Accretion of discount
Revisions of previous estimates(2)
Asset retirement obligations — end of period
Less: current asset retirement obligations
Long-term portion of asset retirement obligations
$
$
June 30, 2023
June 30, 2022
13,921
57
(136)
—
1,131
2,094
17,067
(55)
17,012
$
$
5,583
219
(17)
5,400
531
2,205
13,921
(22)
13,899
(1)
(2)
See Note 3, “Acquisitions,” for additional information on the Company’s acquisition activities.
Primarily related to upward revisions for increased estimates for the years ended June 30, 2023 and 2022.
Note 10. Commitments and Contingencies
The Company is subject to various claims and contingencies in the normal course of business. In addition, from time to
time, the Company receives communications from government or regulatory agencies concerning investigations or
allegations of noncompliance with laws or regulations in jurisdictions in which the Company operates. The Company
discloses such matters if it believes there is a reasonable possibility that a future event or events will confirm a material
loss through impairment of an asset or the incurrence of a material liability. The Company accrues a material loss if it
believes it probable that a future event or events will confirm a loss and the loss is reasonably estimable. Furthermore, the
Company will disclose any matter that is unasserted if it considers it probable that a claim will be asserted and there is a
reasonable possibility that the outcome will be unfavorable and material in amount. The Company expenses legal defense
costs as they are incurred.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 11. Stockholders’ Equity
Common Stock
As of June 30, 2023, the Company had 33,247,523 shares of common stock outstanding.
The Company began paying quarterly cash dividends on common stock in December 2013. As of June 30, 2023, the
Company has cumulatively paid over $102.4 million in cash dividends. The Company paid dividends of $16.1 million and
$11.8 million to its common stockholders during the years ended June 30, 2023 and 2022, respectively. The following table
reflects the dividends paid per share within the respective quarterly periods:
Fourth quarter ended June 30,
Third quarter ended March 31,
Second quarter ended December 31,
First quarter ended September 30,
$
Fiscal Year
2023
2022
$
0.120
0.120
0.120
0.120
0.100
0.100
0.075
0.075
On September 11, 2023, Evolution’s Board of Directors approved and declared a quarterly dividend of $0.12 per common
share payable September 29, 2023. Refer to Note 15, “Subsequent Events,” for a further discussion.
On September 8, 2022, the Board of Directors approved a share repurchase program, under which the Company is
authorized to repurchase up to $25.0 million of its common stock in the open market through December 31, 2024. The
Company intends to fund repurchases from working capital and cash provided by operating activities. The Board of
Directors along with the management team believe that a share repurchase program is complimentary to the existing
dividend policy and is a tax efficient means to further improve shareholder return. The shares may be repurchased from
time to time in open market transactions, through privately negotiated transactions or by other means in accordance with
federal securities laws. The timing, as well as the number and value of shares repurchased under the program, will depend
on a variety of factors, including management’s assessment of the intrinsic value of the Company’s shares, the market price
of the Company’s common stock, the Company’s capital needs and resources, general market and economic conditions,
and applicable legal requirements. The value of shares authorized for repurchase by the Company's Board of Directors does
not require the Company to repurchase such shares or guarantee that such shares will be repurchased, and the program may
be suspended, modified, or discontinued at any time without prior notice.
Once the Company completed repayment of borrowings on its Senior Secured Credit Facility and emerged from its
blackout period in December 2022, the Company entered into a Rule 10b5-1 plan that authorized a broker to repurchase
shares in the open market subject to pre-defined limitations on trading volume and price. The plan included a 30-day
cooling off period that did not allow repurchases to commence until January 2023. The plan was effective until June 30,
2023 and had a maximum authorized amount of $5.0 million over that period. During the year ended June 30, 2023, 0.6
million shares of the Company’s common stock were repurchased under the plan at a total cost of approximately $3.9
million, including incremental direct transaction costs. These treasury shares were subsequently cancelled.
During the years ended June 30, 2023 and 2022, the Company also acquired treasury stock upon the vesting of employee
stock-based awards to fund payroll tax withholding obligations. These treasury shares were subsequently cancelled.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Such shares were valued at fair market value on the date of vesting. The following table summarizes all treasury stock
purchases in the years ended June 30, 2023 and 2022 (in thousands, except per share amounts):
Number of treasury shares acquired(1)
Average cost per share(1)
Total cost of treasury shares acquired
Years Ended June 30,
2023
2022
673
6.20
4,170
$
$
7
5.09
38
$
$
(1)
For the year ended June 30, 2023, includes 633,789 shares repurchased under the Company’s share repurchase program for a
weighted average price of $6.07 per share.
Expected Tax Treatment of Dividends
For the fiscal year ended June 30, 2022, all common stock dividends for that fiscal year were treated for tax purposes as
qualified dividend income to the recipients. Based on its current projections for the fiscal year ended June 30, 2023, the
Company expects all common stock dividends for such period to be treated as qualified dividend income to the recipients.
Stock-Based Incentive Plan
The Evolution Petroleum Corporation 2016 Equity Incentive Plan (as amended the “2016 Plan”), authorizes the issuance of
3.6 million shares of common stock prior to its expiration on December 8, 2026. Incentives under the 2016 Plan may be
granted to employees, directors, and consultants of the Company in any one or a combination of the following forms:
incentive stock options and non-statutory stock options, stock appreciation rights, restricted stock awards and restricted
stock unit awards, performance share awards, performance cash awards, and other forms of incentives valued in whole or
in part by reference to, or otherwise based on, the Company’s common stock, including its appreciation in value. As of
June 30, 2023 and 2022, approximately 1.3 million shares and 1.8 million shares, respectively, remained available for grant
under the 2016 Plan.
The Company estimates the fair value of stock-based compensation awards on the grant date to provide the basis for future
compensation expense. For the years ended June 30, 2023, and 2022, the Company recognized $1.6 million and $0.1
million, respectively, related to stock-based compensation expense recorded as a component of “General and
administrative expenses” on the consolidated statements of operations. During the year ended June 30, 2022, the Company
recognized a reduction of $1.2 million to stock-based compensation expense for the forfeiture of unvested shares in
connection with severance.
Time-Vested Restricted Stock Awards
Time-vested restricted stock awards contain service-based vesting conditions and expire after a maximum of four years
from the date of grant if unvested. The common shares underlying these awards are issued on the date of grant and
participate in dividends paid by the Company. These service-based awards vest with continuous employment by the
Company, generally in annual installments over terms of three to four years. Awards to the Company’s directors generally
have one-year cliff vesting. For such awards, grant date fair value is based on market value of the Company’s common
stock at the time of grant. This value is then amortized ratably over the service period. Previously recognized amortization
expense subsequent to the last vesting date of an award is reversed in the event that the holder has no longer rendered
service to the Company resulting in forfeiture of the award.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Performance-Based Restricted Stock Awards and Performance-Based Contingent Stock Units
Performance-based restricted stock awards and performance-based contingent stock units contain market-based vesting
conditions based on the price of the Company’s common stock, the intrinsic value indexed solely to its common stock or
the intrinsic value indexed to its common stock compared to the performance of the common stock of its peers. The
common shares underlying the Company’s performance-based restricted stock awards are issued on the date of grant and
participate in dividends paid by the Company and expire after a maximum of four years from the date of grant if unvested.
Performance-based contingent share units do not participate in dividends and shares are only issued in part or in full upon
the attainment of vesting conditions, generally have a lower probability of achievement and expire after a maximum of
four years from the date of grant if unvested. Shares underlying performance-based contingent share units are reserved
from the 2016 Plan. Performance-based restricted stock awards and contingent restricted stock units are valued using a
Monte Carlo simulation and geometric Brownian motion techniques applied to the historical volatility of the Company’s
total stock return compared to the historical volatilities of other companies or indices to which the Company compares its
performance and/or the Company’s absolute total stock return. For certain awards, this Monte Carlo simulation also
provides an expected vesting term. Stock-based compensation is recognized ratably over the expected vesting period, so
long as the award holder remains an employee of the Company. Previously recognized compensation expense is only
reversed for the awards with market-based vesting conditions if the requisite service period is not rendered by the holder
resulting in forfeiture of the award or as a result of regulatory required clawback.
Vesting of grants with performance-based vesting conditions is dependent on the future price of the Company’s common
stock. Such awards vest in part or in full if the trailing total returns on the Company’s common stock for a specified three-
year period exceed the corresponding total returns of various quartiles of indices consisting of peer companies or, in some
cases, vest when the average of the Company’s closing common stock price over a defined measurement period meets or
exceeds a required common stock price.
For performance-based awards granted during the years ended June 30, 2023 and 2022, the assumptions used in the Monte
Carlo simulation valuations were as follows:
Weighted average fair value of performance-based awards granted
Risk-free interest rate
Expected term in years
Expected volatility
Dividend yield
Years Ended June 30,
$
$
2023
6.52
3.91% to 4.51%
2.36 to 2.78
56.5% to 70.9%
6.1% to 7.8%
2022
3.10
0.53% to 0.60%
2.64 to 2.79
64.7%
4.8% to 6.3%
Unvested restricted stock awards as of June 30, 2023 consisted of the following:
Award Type
Time-vested awards
Performance-based awards
Unvested at June 30, 2023
65
Number of
Restricted
Shares
Weighted
Average
Grant-Date
Fair Value
453,041
142,373
595,414
$
$
6.61
6.08
6.48
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
The following table sets forth the restricted stock award transactions for the years ended June 30, 2023 and 2022:
Weighted
Average
Number of
Restricted Grant-Date
Unamortized
Compensation
Expense
Weighted
Average
Remaining
Amortization
Shares
Fair Value (In thousands) Period (Years)
Aggregate Intrinsic
Value (1)
(In thousands)
Unvested at June 30, 2021
Time-vested shares granted
Performance-based shares granted
Vested
Forfeited
Unvested at June 30, 2022
Time-vested shares granted
Performance-based shares granted
Vested
Forfeited
Unvested at June 30, 2023
669,295
205,077
131,293
(291,227)
(373,227)
341,211
376,015
100,239
(196,431)
(25,620)
595,414
$
$
$
3.37
5.88
3.31
3.77
3.35
4.54
7.18
7.39
4.91
6.51
6.48
$
$
1,092
2.1
$
1,863
2,827
2.4
$
4,805
(1) The intrinsic value of restricted stock was calculated as the closing market price on June 30, 2023 and 2022 of the
underlying stock multiplied by the number of restricted shares that would be issuable. The total fair value of shares
vested was $1.4 million and $1.5 million for the years ended June 30, 2023 and 2022, respectively.
The following table sets forth contingent restricted stock units transactions for the years ended June 30, 2023 and 2022:
Unamortized
Number of Weighted Average Compensation
Restricted
Stock Units
Grant-Date
Fair Value
Expense
(In thousands) Period (Years)
Weighted
Average
Remaining
Amortization
Aggregate Intrinsic
Value (1)
(In thousands)
Unvested at June 30, 2021
Performance-based awards granted
Forfeited
Unvested at June 30, 2022
Performance-based awards granted
Forfeited
Unvested at June 30, 2023
323,080
65,649
(338,667)
50,062
50,123
(3,787)
96,398
$
$
$
2.84
2.67
2.90
2.21
4.79
3.69
3.49
$
$
68
195
1.7
$
1.9
$
273
778
(1) The intrinsic value of contingent restricted stock units was calculated as the closing market price on June 30, 2023
and 2022 of the underlying stock multiplied by the number of restricted shares that would be issuable.
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 12. Earnings (Loss) per Common Share
The following table sets forth the computation of basic and diluted earnings (loss) per common share, reflecting the
application of the two-class method (in thousands, except per share amounts):
Numerator
Net income (loss)
Undistributed earnings allocated to unvested restricted stock
Net income (loss) for earnings per share calculation
Denominator
Weighted average number of common shares outstanding — Basic
Effect of dilutive securities:
Unvested restricted stock awards
Unvested contingent restricted stock units
Weighted average number of common shares and dilutive potential common shares used in
diluted earnings per share
Net income (loss) per common share — Basic
Net income (loss) per common share — Diluted
Years Ended June 30,
2022
2023
35,217
(560)
34,657
$
$
32,628
(673)
31,955
32,985
32,952
193
12
354
—
33,190
33,306
1.05
1.04
$
$
0.97
0.96
$
$
$
$
Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 90,000 for the year
ended June 30, 2023 were not included in the computation of diluted earnings per common share because the effect would
have been anti-dilutive.
Unvested restricted stock awards (both time-vested and performance-based), totaling approximately 20,000 for the year
ended June 30, 2022, were not included in the computation of diluted earnings per common share because the effect would
have been anti-dilutive.
In addition, unvested performance-based restricted stock awards and unvested contingent restricted stock units that would
not meet the performance criteria as of the period end are excluded from the computation of diluted earnings per common
share.
Note 13. Leases
Operating leases are reflected as an operating lease right of use (“ROU”) asset included in “Other assets”, and as a ROU
liability in “Accrued liabilities and other” and “Operating lease liability” on the Company’s consolidated balance sheets.
Operating lease ROU assets and liabilities are recognized at the commencement date of an arrangement based on the
present value of lease payments over the lease term. In addition to the present value of lease payments, the operating lease
ROU asset would also include any lease payments made to the lessor prior to lease commencement less any lease
incentives and initial direct costs incurred, if any. Lease expense for operating lease payments is recognized on a straight-
line basis over the lease term and are presented as “General and administrative expenses” in the consolidated statements of
operations. Certain leases have payment terms that vary based on the usage of the underlying assets. Variable lease
payments are not included in ROU assets and lease liabilities. For all operating leases, lease and non-lease components are
accounted for as a single lease component.
As a non-operator and having adequate liquidity, the Company has generally not entered into lease transactions. The
Company’s only operating lease is for corporate office space in Houston, Texas, effective May 1, 2019 and amended
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
November 30, 2022 and set to expire September 30, 2026. The Company has no leases that meet the criteria for
classification as a finance lease or a short-term lease.
The Company makes certain assumptions and judgments when evaluating a contract that meets the definition of a lease
under ACS 842, Leases. As the Company’s operating leases have not provide an implicit rate, an incremental borrowing
rate was calculated using information available at the commencement date of the lease. The incremental borrowing rate for
a lease is the rate of interest for which the Company would pay on a collateralized basis to borrow an amount equal to the
lease payments under similar terms. The lease term was determined by considering any option available to extend or to
early terminate the lease which the Company believed was reasonably certain to be exercised.
The table below summarized the Company’s leases for the years ended June 30, 2023 and 2022 (in thousands, except years
and discount rate):
Statements of Operations:
Operating lease costs
Variable lease costs
Total lease costs
Statements of Cash Flow:
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases
Other:
ROU assets obtained in exchange for new operating lease liabilities
Weighted average remaining lease term in years
Weighted average discount rate
Balance Sheets:
Operating lease ROU asset (included in other assets)
Accrued liabilities and other - current
Operating lease liability - long-term
68
Years Ended June 30,
2023
2022
$
$
$
$
$
$
$
$
58
33
91
62
212
3.18
6.44 %
52
38
90
62
—
0.42
5.15 %
June 30, 2023
June 30, 2022
$
$
183
59
125
21
26
—
Table of Contents
EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
As of June 30, 2023, the future minimum lease payments associated with the Company’s non-cancellable operating lease
for office space are as follows (in thousands):
Fiscal Year
2024
2025
2026
2027
2028
Thereafter
Total operating lease payments
Less: discount to present value
Total operating lease liabilities
Less: current operating lease liabilities
Non current operating lease liabilities
June 30, 2023
61
62
64
16
—
—
203
(19)
184
59
125
$
$
The Company applied the following practical expedients as provided in the standards update which provide elections to not
reassess:
● Not to apply the recognition requirements in the lease standard to short-term leases (a lease that at
commencement date has a lease term of 12 months or less and does not contain a purchase option that the
Company is reasonably certain to exercise).
● Whether an expired or existing pre-adoption date contracts contained leases.
● Lease classification of any expired or existing leases.
● Initial direct costs for any expired or existing leases.
● Not to separate lease components from non-lease components in a contract and accounting for the
combination as a lease (reflected by asset class).
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EVOLUTION PETROLEUM CORPORATION
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 14. Additional Financial Statement Information
Certain amounts on the consolidated balance sheets are comprised of the following (in thousands):
June 30, 2023
June 30, 2022
Prepaid expenses and other current assets:
Receivable for settlement proceeds from acquisitions(1)
Other receivables
Prepaid insurance
Prepaid federal and state income taxes
Prepaid subscription and licenses
Carryback of EOR tax credit
Prepaid other
Total prepaid expenses and other current assets
Other assets:
Deposit(2)
Right of use asset under operating lease
Total other assets
Accrued liabilities and other:
Accrued payables
Accrued capital expenditures
Accrued incentive and other compensation
Accrued royalties payable(3)
Accrued taxes other than income
Accrued severance
Accrued settlements on derivative contracts
Operating lease liability
Asset retirement obligations due within one year
Accrued - other
Total accrued liabilities and other
$
$
$
$
$
$
— $
18
727
805
68
347
312
2,277
$
1,158
183
1,341
3,566
167
941
977
178
81
—
59
55
3
6,027
$
$
$
$
2,263
37
743
8
38
347
439
3,875
1,150
21
1,171
8,070
—
626
1,517
178
332
919
26
22
203
11,893
(1) Receivables as of June 30, 2022 related to customary purchase adjustments of $1.6 million and $0.7 million related to
the Jonah Field Acquisition and Williston Basin Acquisition, respectively. See Note 3, “Acquisitions” for a further
discussion.
(2) The deposit of $1.2 million is related to a long-term gas gathering deposit with Enterprise entered into at closing of the
Jonah Field Acquisition. See Note 3, “Acquisitions” for additional information.
(3) Accrued royalties payable relate to royalty and owner payments in the Jonah Field as the Company takes its natural
gas and NGL working interest production in-kind. See Note 2, “Revenue Recognition” for a further discussion.
Note 15. Subsequent Events
On September 11, 2023, the Company declared a quarterly cash dividend of $0.12 per share of common stock to
shareholders of record on September 22, 2023 and payable on September 29, 2023.
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Table of Contents
Supplemental Disclosure about Oil and Natural Gas Properties (unaudited)
Capitalized costs relating to oil and natural gas producing activities
The following table summarizes the amounts of capitalized costs relating to oil and natural gas producing activities and the
amount of related accumulated depletion (in thousands).
Oil and natural gas properties
Property costs subject to amortization
Less: Accumulated depletion, depreciation, and amortization
Oil and natural gas properties, net
June 30, 2023 June 30, 2022 June 30, 2021
$
$
197,049
(91,268)
105,781
$
$
188,634
(78,126)
110,508
$
$
129,123
(70,607)
58,516
Costs incurred for oil and natural gas property acquisition, exploration, and development activities
The following table summarizes costs incurred and capitalized in oil and natural gas property acquisition, exploration, and
development activities (in thousands). Property acquisition costs are those costs incurred to lease property, including both
undeveloped leasehold, and the purchase of reserves in place. Exploration costs include costs of identifying areas that may
warrant examination, examining specific areas that are considered to have prospects containing oil and natural gas reserves,
costs of drilling exploratory wells, geologic and geophysical assessment costs, and carrying costs on undeveloped
properties. Development costs are incurred to obtain access to proved reserves, including the cost of drilling. Development
costs also include amounts incurred due to the recognition of asset retirement obligations of $2.0 million, $7.8 million, and
$2.9 million during the years ended June 30, 2023, 2022, and 2021, respectively.
For the Years Ended June 30,
2023
2022
2021
Oil and Natural Gas Activities
Property acquisition costs:
Proved property
Unproved property
Exploration costs
Development costs
Total costs incurred for oil and natural gas activities
Estimated Net Quantities of Proved Oil and Natural Gas Reserves
$
$
31 $
—
—
8,384
8,415 $
49,920 $
—
—
9,591
59,511 $
18,297
—
—
3,436
21,733
The following estimates of net proved oil and natural gas reserves of the Company’s oil and natural gas properties located
entirely within the United States are based on evaluations prepared by third-party reservoir engineers, Netherland, Sewell
& Associates, Inc. (“NSAI”) and DeGolyer & MacNaughton (“D&M”). Reserve volumes and values were determined
under the method prescribed by the SEC for the fiscal years ended June 30, 2023, 2022 and 2021. SEC methodology
requires the application of the previous 12-month unweighted arithmetic average first-day-of-the-month price, and current
costs held constant throughout the projected reserve life, when estimating whether reserve quantities are economical to
produce.
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 internal reserve engineering team, which includes our Chief
Operating Officer (COO). Our internal reserve engineering team and third-party consultants have a combined experience of
over 80 years in Petroleum Engineering. Our COO, the person responsible for overseeing the preparation of our reserves
estimates has a Bachelor of Science Degree in Petroleum Engineering from Texas A&M University, is a registered
Professional Engineer in the State of Texas (No. 86704), has over 40 years of oil and natural gas experience including large
independents and financial firm services for projects and acquisitions. Our Board of Directors also has oversight of our
reserve estimation process and contains a Reserves Committee with an independent director who is a Register Professional
Engineer in the State of Texas (No. 47279) with experience in energy company reserve
71
Table of Contents
evaluations. Such reserve estimates comply with generally accepted petroleum engineering and evaluation principles,
definitions, and guidelines as established by the SEC.
The person responsible for the preparation of the reserve report at NSAI is Matthew D. Pankey, P.E., Petroleum Engineer.
Mr. Pankey, a licensed Professional Engineer in the State of Texas (No. 142931), has been practicing consulting petroleum
engineering at NSAI since 2019 and has over six years of prior industry experience. The person responsible for the
preparation of the reserve report at D&M is Dr. Dilhan Ilk, P.E, Executive Vice President. Dr. Ilk 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 13 years of
experience in oil and natural gas reservoir studies and evaluations and is a licensed Professional Engineer in the state of
Texas (No. 139334).
Proved oil and natural gas reserves are estimated quantities of oil, natural gas, and NGLs that geologic and engineering
data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing
economic and operating conditions. Proved developed oil and natural gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods. There are uncertainties inherent in
estimating quantities of proved oil and natural gas reserves, projecting future production rates, and timing of development
expenditures. Accordingly, reserve estimates often differ from the quantities of oil and natural gas that are ultimately
recovered.
Estimated quantities of proved oil, natural gas, and NGL reserves and changes in quantities of proved developed and
undeveloped reserves for each of the periods indicated are as follows:
Proved developed and undeveloped reserves:
June 30, 2020
Revisions of previous estimates
Purchase of reserves in place
Production (sales volumes)
June 30, 2021
Revisions of previous estimates
Improved recovery, extensions and discoveries
Purchase of reserves in place
Production (sales volumes)
June 30, 2022
Revisions of previous estimates
Improved recovery, extensions and discoveries
Production (sales volumes)
June 30, 2023
Crude Oil
(MBbls)
Natural Gas
(MMcf)
Natural Gas
Liquids
(MBbls)
Equivalent
(MBOE)
8,226
662
87
(555)
8,420
(1,111)
2,608
2,172
(619)
11,470
(1,038)
98
(659)
9,871
—
—
49,534
(963)
48,571
25,268
2,197
38,096
(7,141)
106,991
(5,352)
33
(9,109)
92,563
1,993
92
4,957
(171)
6,871
(944)
623
755
(364)
6,941
(668)
20
(416)
5,877
10,219
754
13,300
(887)
23,386
2,157
3,597
9,276
(2,173)
36,243
(2,598)
124
(2,593)
31,176
72
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Proved developed and undeveloped reserves:
June 30, 2020
Revisions of previous estimates
Purchase of reserves in place
Production (sales volumes)
June 30, 2021
Revisions of previous estimates
Improved recovery, extensions and discoveries
Purchase of reserves in place
Production (sales volumes)
June 30, 2022
Revisions of previous estimates
Improved recovery, extensions and discoveries
Production (sales volumes)
June 30, 2023
Proved
Developed
Reserves
MBOE
Proved
Undeveloped
Reserves
Total
Proved
Reserves
8,355
805
13,300
(887)
21,573
3,970
—
9,276
(2,173)
32,646
(2,580)
6
(2,593)
27,479
1,864
(51)
—
—
1,813
(1,813)
3,597
—
—
3,597
(18)
118
—
3,697
10,219
754
13,300
(887)
23,386
2,157
3,597
9,276
(2,173)
36,243
(2,598)
124
(2,593)
31,176
For the fiscal year ended June 30, 2023, notable changes in total proved reserves included the following:
● Production. The company produced 2.6 MBOE during the year ended June 30, 2023.
● Improved recovery, extensions and discoveries. During the fiscal year 2023, the Company added 0.1 MMBOE of
proved reserves primarily associated with the addition of two new PUD wells at Delhi Field.
● Revisions of previous estimates. Net Revisions in fiscal year 2023 totaled 2.6 MMBOE primarily associated the
Delhi Field and Barnett Shale. Reserve projections were revised downward at Delhi Field due to actual fiscal
2023 production coming in lower than fiscal year end 2022 projection. Additionally, Barnett Shale reserves
decreased due primarily to increased production costs in the field shortening the economic life of many wells.
For the fiscal year ended June 30, 2022, notable changes in total proved reserves included the following:
● Purchase of reserves in place. During the fiscal year ended 2022, the Company completed the Williston Basin
Acquisition and the Jonah Field Acquisition. See Note 4, “Acquisitions” for more details.
● Improved recovery, extensions and discoveries. During the fiscal year 2022, the Company added 3.6 MBOE of
PUD reserves associated with drilling locations at its Willison Basin properties.
● Revisions of previous estimates. Net Revisions in fiscal year 2022 totaled 2.2 MMBOE, which included a net
positive revision in the Company’s proved developed reserves of 4.0 MMBOE offset by the removal of 1.8
MMBOE of PUD reserves at the Delhi Field, related to Test Site V. At this time, the operator at Delhi does not
currently have Test Site V on its expenditure schedule for the next five years and, as a result, has been excluded
from the Company’s PUD reserves. The net positive revision in the Company’s proved developed reserves of 4.0
MMBOE includes positive revisions totaling 4.7 MMBOE primarily related to the improvement in the SEC
trailing 12-month pricing offset by a 0.7 MMBOE downward adjustment at Delhi due to lower than anticipated
production during fiscal year 2022.
For the fiscal year ended June 30, 2021, notable changes in total proved reserves included the following:
● Purchase of reserves in place. During the fiscal year ended 2021, the Company completed the acquisition of its
Barnett Shale properties totaling $17.4 million.
● Revisions of previous estimates. Revisions in fiscal year 2021 were primarily due to positive revisions at
Hamilton Dome Field reflecting the impact of increased oil pricing in the field on future production and extension
of reserves economic limit. Positive NGL revisions at Delhi Field reflect the impact of increased pricing on future
production and the extension of reserves economic limit. Positive natural gas revisions in the Barnett Shale
properties reflect the impact of increased natural gas prices from the date the Barnett Shale acquisition was
completed on May 7, 2021 to the end of the fiscal year on June 30, 2021.
Future oil and natural gas sales, production, and development costs have been estimated using prices and costs in effect at
the end of the years indicated, as required by ASC 932, Extractive Activities - Oil and Gas (“ASC 932”). ASC 932
73
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requires that net cash flow amounts be discounted at 10%. Future production and development costs are computed by
estimating the expenditures to be incurred in developing and producing proved oil and natural gas reserves and for asset
retirement obligations, assuming continuation of existing economic conditions. Future income tax expenses are computed
by applying the appropriate period-end statutory tax rates to the future pretax net cash flow related to proved oil and natural
gas reserves, less the tax basis of the related properties. The future income tax expenses do not give effect to tax credits,
allowances, or the impact of general and administrative costs of ongoing operations relating to the Company’s proved oil
and natural gas reserves. Changes in the demand for oil and natural gas, inflation, and other factors make such estimates
inherently imprecise and subject to substantial revision. The table below should not be construed to be an estimate of the
current market value of the Company’s proved reserves.
The Standardized Measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30,
2023, 2022 and 2021 are as follows (in thousands):
Future cash inflows
Future production costs and severance taxes
Future development costs
Future income tax expenses
Future net cash flows
10% annual discount for estimated timing of cash flows
Standardized measure of discounted future net cash flows
$
$
$
$
2023
For the Years Ended June 30,
2022
1,846,708
(997,362)
(105,966)
(159,912)
583,468
(268,685)
314,783
1,521,363
(860,054)
(120,648)
(109,189)
431,472
(193,295)
238,177
$
$
2021
632,620
(398,022)
(29,339)
(42,368)
162,891
(75,308)
87,583
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the
previous 12-month unweighted arithmetic average first-day-of-the-month commodity prices for each year and reflect
adjustments for lease quality, transportation fees, energy content, and regional price differentials.
NYMEX prices used in determining future cash flows:
Oil (Bbl)
Gas (MMBtu)
For the Years Ended June 30,
2022
2021
2023
$
83.23
4.78
$
85.82
5.19
$
49.72
2.46
The NGL prices utilized for future cash inflows were based on historical prices received, where available.
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved oil, natural
gas, and NGL reserves is as follows (in thousands):
Balance, beginning of year
Net changes in sales prices and production costs related to future
production
Changes in estimated future development costs
Sales of oil, natural gas and NGLs produced, net of production costs
Net change due to extensions, discoveries, and improved recovery
Net change due to revisions in quantity estimates
Net change due to purchase of minerals in place
Accretion of discount
Net change in discounted income taxes
Other
Balance, end of year
$
$
74
For the Years Ended June 30,
2022
2021
$
87,583
$
62,491
2023
314,783
(31,923)
(8,286)
(68,969)
4,695
(34,056)
—
40,382
26,006
(4,455)
238,177
$
171,602
(6,320)
(60,269)
43,495
48,177
100,675
14,425
(65,559)
(19,026)
314,783
$
11,538
403
(16,115)
—
6,841
31,461
7,529
(10,678)
(5,887)
87,583
Table of Contents
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
We maintain disclosure controls and procedures that are designed to ensure that information required to be disclosed in our
Exchange Act reports is recorded, processed, summarized, and reported within the time periods specified in the Securities
and Exchange Commission’s rules and forms; this information is accumulated and communicated to our management,
including our Principal Executive Officer and Principal Financial Officer, as appropriate to allow for timely decisions
regarding required disclosure.
As required by Securities and Exchange Commission Rule 13a-15(b), we carried out an evaluation, under the supervision
and with the participation of our management, including our Principal Executive Officer and Principal Financial Officer, of
the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered
by this report. Based on this evaluation, our Principal Executive Officer and Principal Financial Officer concluded that our
disclosure controls and procedures are effective in ensuring that the information required to be disclosed in our reports filed
or submitted under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in
the Securities and Exchange Commission rules and forms.
Management’s Annual Report on Internal Control Over Financial Reporting
Our management is responsible for establishing and maintaining adequate internal control over financial reporting (as
defined in Rules 13a-15(f) and 15d-15(f) of the Exchange Act) as a process designed by, or under the supervision of, our
principal executive and principal financial officers and effected by our Board of Directors, management and other
personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial
statements for external purposes in accordance with accounting principles generally accepted in the United States of
America. Generally accepted accounting principles include those policies and procedures that:
● pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions
and dispositions of the assets of the company;
● provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with accounting principles generally accepted in the United States of America and
that receipts and expenditures of the company are being made only in accordance with authorizations of
management and directors of the company; and
● provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.
Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial
statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to
risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the
policies or procedures may deteriorate. Under the supervision and with the participation of management, including the
Principal Executive Officer and the Principal Financial Officer, an evaluation was conducted on the effectiveness of our
internal control over financial reporting based on criteria established in the Internal Control-Integrated Framework issued
by the Committee of Sponsoring Organizations of the Treadway Commission in 2013. Management concluded that we
maintained effective internal control over financial reporting as of June 30, 2023.
The effectiveness of the Company’s internal controls over financial reporting as of June 30, 2023, has been audited by
Moss Adams LLP., an independent registered public accounting firm, as stated in their report.
75
Table of Contents
Changes in Internal Control Over Financial Reporting
There has been no change in our internal control over financial reporting during the three months ended June 30, 2023 that
has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information
On September 7, 2023, the Board of Directors of the Company approved and adopted Amended and Restated Bylaws for
the Company, which were originally adopted effective January 2, 2004. The principal changes to the Bylaws are: (i) adding
a new Section 2.10 specifying the procedures to be followed for shareholders in proposing nominees for director and other
items of business at annual and special meetings of stockholders; (ii) expanding the ability of the Company to implement
procedures that allow shareholders to participate in meetings remotely; (iii) providing for mandatory indemnification of
officers and directors for certain actions to the extent permitted by Nevada law; and (iv) allowing shareholders to take
action by written consent to the extent that such consent is signed by the holders of no less than two-thirds (2/3rds) of the
outstanding shares of stock entitled to vote thereon. A copy of the Amended and Restated Bylaws of the Company is
attached hereto as Exhibit 3.3 and is incorporated in this Item 9B by reference.
Also on September 7, 2023, the Board of Directors of the Company approved and adopted an Incentive Compensation
Recoupment Policy intended to meet the requirements of newly adopted Section 811 of the NYSE American Company
Guide and new Rule 10D-1 of the Securities Exchange Act of 1934, as amended. The Company is adopting the policy in
advance of the deadline mandated by Section 811. As required by Section 811, the Company’s policy provides for the
recovery of incentive compensation from current or former executive officers in the event of an accounting restatement. A
copy of the Company’s Incentive Compensation Recoupment Policy is attached hereto as Exhibit 97 and is incorporated in
this Item 9B by reference.
Item 9C. Disclosure regarding foreign jurisdictions that prevent inspections
Not applicable.
76
Table of Contents
Item 10. Directors, Executive Officers, and Corporate Governance
PART III
Incorporated by reference to our Proxy Statement to be filed with the Securities and Exchange Commission pursuant to
Regulation 14A within 120 days of the end of our 2023 fiscal year.
Item 11. Executive Compensation
Incorporated by reference to our Proxy Statement to be filed with the Securities and Exchange Commission pursuant to
Regulation 14A within 120 days of the end of our 2023 fiscal year.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Incorporated by reference to our Proxy Statement to be filed with the Securities and Exchange Commission pursuant to
Regulation 14A within 120 days of the end of our 2023 fiscal year.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Incorporated by reference to our Proxy Statement to be filed with the Securities and Exchange Commission pursuant to
Regulation 14A within 120 days of the end of our 2023 fiscal year.
Item 14. Principal Accountant Fees and Services
Incorporated by reference to our Proxy Statement to be filed with the Securities and Exchange Commission pursuant to
Regulation 14A within 120 days of the end of our 2023 fiscal year.
77
Table of Contents
PART IV.
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as part of this report:
1. Financial Statements.
The consolidated financial statements of the Company and its subsidiaries are included in Part II, Item 8 of
this report:
Report of Independent Registered Public Accounting Firm on Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Cash Flows
Consolidated Statements of Changes in Stockholders’ Equity
Notes to the Consolidated Financial Statements
Supplemental Disclosure about Oil and Natural Gas Properties (unaudited)
2. Financial Statements Schedules and Supplementary Information Required to be Submitted:
None.
3. Exhibits
A list of the exhibits filed or furnished with this report on Form 10-K (or incorporated by reference to exhibits
previously filed or furnished by us) is provided in the Exhibit Index of this report. Those exhibits incorporated by
reference herein are indicated as such by the information supplied in the parenthetical thereafter. Otherwise, the
exhibits are filed herewith.
Item 16. Form 10-K Summary
None.
78
Table of Contents
EXHIBIT INDEX
EXHIBIT
NUMBER
3.1
3.3*
4.1
4.1.1
4.2
4.3†
4.4†
4.4.1†
4.4.2†*
4.5†
4.5.1†*
4.6†
10.1
10.2
10.2.1
10.2.2
10.2.3
10.2.4
10.2.5
10.2.6
EXHIBIT INDEX
DESCRIPTION
Restated Articles of Incorporation (incorporated by reference to Exhibit 3.1 of our Quarterly Report on
Form 10-Q filed February 8, 2023)
Amended and Restated Bylaws
Description of Evolution Petroleum Corporations, securities registered under Section 12 of the Exchange
Act (incorporated by reference to our Registration of Securities on Form 8-A filed July 13, 2006)
Specimen form of the Company's Common Stock Certificate (incorporated by reference to Exhibit 4.7 of
our Registration Statement on Form S-3 filed June 19, 2013)
Majority Voting Policy for Directors (incorporated by reference to Exhibit 99.1 of our Current Report on
Form 8-K filed October 31, 2012)
2016 Equity Incentive Plan (incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-
Q filed February 8, 2017)
Form of Restricted Stock Agreement under 2016 Equity Incentive Plan (incorporated by reference to
Exhibit 4.1 of our Quarterly Report on Form 10-Q filed February 8, 2018)
Form of Restricted Stock Agreement under 2016 Equity Incentive Plan as Revised on July 9, 2019
(incorporated by reference to Exhibit 4.12 of our Annual Report on Form 10-K filed September 13, 2019)
Form of Restricted Stock Agreement under 2016 Incentive Plan as revised on May 4, 2023
Form of Contingent Restricted Stock Agreement under 2016 Equity Incentive Plan (incorporated by
reference to Exhibit 4.2 of our Quarterly Report on Form 10-Q filed February 8, 2018)
Form of Contingent Restricted Stock Agreement under 2016 Equity Incentive Plan as revised on May 4,
2023
Form of Performance Share Unit Award Agreement under 2016 Equity Incentive Plan as Revised on July
9, 2019 (incorporated by reference to Exhibit 4.13 of our Annual Report on Form 10-K filed September 13,
2019)
Form of Indemnification Agreement for Officers and Directors, as adopted on September 20, 2006
(incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed September 22, 2006)
Credit Agreement dated April 11, 2016 between Evolution Petroleum Corporation and MidFirst Bank
(incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed April 15, 2016)
First Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation
and MidFirst Bank effective October 18, 2016 (incorporated by reference to Exhibit 10.1 of our Quarterly
Report on Form 10-Q filed November 9, 2016)
Second Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation
and MidFirst Bank effective February 1, 2018 (incorporated by reference to exhibit 10.1 of our Quarterly
Report on Form 10-Q filed February 8, 2018)
Third Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation
and MidFirst Bank effective May 25, 2018 (incorporated by reference to Exhibit 10.10 of our Annual
Report on Form 10-K filed September 10, 2018)
Fourth Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation
and MidFirst Bank effective December 31, 2018 (incorporated by reference to Exhibit 10.1 of our
Quarterly Report on Form 10-Q filed February 8, 2019)
Fifth Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation
and MidFirst Bank effective November 2, 2020 (incorporated by reference to Exhibit 10.1 of our Quarterly
Report on Form 10-Q filed November 9, 2020)
Sixth Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation
and MidFirst Bank effective December 28, 2020 (incorporated by reference to Exhibit 10.1 of our Current
Report on Form 8-K filed on January 11, 2021)
79
Table of Contents
EXHIBIT
NUMBER
10.2.7
10.2.8
10.2.9
10.2.10
10.3
10.5†
10.6
10.6.1
10.6.2
10.6.3
10.7
10.8
10.9†
10.10†
14.1
21.1*
23.1*
23.2*
23.3*
31.1*
31.2*
32.1**
DESCRIPTION
Seventh Amendment to Credit Agreement dated August 5, 2021, between Evolution Petroleum
Corporation and MidFirst Bank effective June 30, 2021 (incorporated by reference to Exhibit 10.8 of our
Quarterly Report on Form 10-Q filed May 12, 2022)
Eighth Amendment to Credit Agreement dated November 9, 2021, between Evolution Petroleum
Corporation and MidFirst Bank effective November 9, 2021 (incorporated by reference to Exhibit 10.1 of
our Quarterly Report on Form 10-Q filed November 10, 2021)
Ninth Amendment to the Credit Agreement dated February 7, 2022, between Evolution Petroleum
Corporation and MidFirst Bank effective February 4, 2022 (incorporated by reference to Exhibit 10.9 of
our Quarterly Report on Form 10-Q filed May 12, 2022)
Tenth Amendment to the Credit Agreement dated May 5, 2023, between Evolution Petroleum Corporation
and MidFirst Bank (incorporated by reference to Exhibit 10.2.10 of our Quarterly Report on Form 10-Q
filed May 10, 2023)
Settlement Agreement, dated June 24, 2016, by and among Denbury Onshore, LLC, Denbury Inc., NGS
Sub Corp., Tertiaire Resources Company, and the Company (incorporated by reference to Exhibit 10.7 of
our Annual Report on Form 10-K filed September 9, 2016)
Employment Offer Letter to Ryan Stash dated October 9, 2020 (incorporated by reference to Exhibit 10.1
of our Annual Report on Form 10-K filed September 14, 2021)
Purchase and Sale Agreement, dated March 29, 2021, between Evolution Petroleum Corporation and TG
Barnett Resources LLP (incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed
on May 11, 2021)
First Amendment to the Purchase and Sale Agreement, dated March 29, 2021, effective April 20, 2021
(incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed on May 11, 2021)
Second Amendment to the Purchase and Sale Agreement, dated March 29, 2021, effective May 4, 2021
(incorporated by reference to Exhibit 10.3 of our Current Report on Form 8-K filed on May 11, 2021)
Third Amendment to the Purchase and Sale Agreement, dated March 29, 2021, effective May 6, 2021
(incorporated by reference to Exhibit 10.4 of our Current Report on Form 8-K filed on May 11, 2021)
Purchase and Sale Agreement, dated January 14, 2022, between Evolution Petroleum Corporation,
Foundation Energy Fund VII-A, LP and Foundation Energy Management, LLC (incorporated by reference
to Exhibit 10.6 our Quarterly Report on Form 10-Q filed May 12, 2022)
Purchase and Sale Agreement, dated April 1, 2022, between Evolution Petroleum Corporation and Exaro
Energy III, LL (incorporated by reference to Exhibit 10.7 of our Quarterly Report on Form 10-Q filed May
12, 2022)
Employment Offer Letter to Kelly Loyd dated October 25, 2022 (incorporated by reference to Exhibit 10.9
of our Quarterly Report on Form 10-Q filed February 8, 2023)
Employment Offer Letter to J. Mark Bunch dated February 21, 2023 (incorporated by reference to Exhibit
10.10 of our Quarterly Report on Form 10-Q filed May 10, 2023)
Code of Business Conduct and Ethics (incorporated by reference to Exhibit 14.1 of our Annual Report on
Form 10-K filed September 14, 2021)
List of Subsidiaries of Evolution Petroleum Corporation
Consent of Moss Adams LLP
Consent of Netherland, Sewell & Associates, Inc.
Consent of DeGolyer & MacNaughton
Certification of Principal Executive Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of
1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Principal Financial Officer Pursuant to Rule 15D-14 of the Securities Exchange Act of
1934, as Amended as Adopted Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
Certification of Principal Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
80
Table of Contents
EXHIBIT
NUMBER
32.2**
99.1*
99.2*
97*
101.INS*
101.SCH*
101.CAL*
101.DEF*
101.LAB*
101.PRE*
104*
DESCRIPTION
Certification of Principal Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002
The summary of Netherland, Sewell & Associates, Inc.’s Report as of June 30, 2023, on oil and gas
reserves (SEC Case) dated August 10, 2023 and certificate of qualification
The summary of DeGolyer and MacNaughton’s Report as of June 30, 2023, on oil and gas reserves (SEC
Case) dated August 7, 2023 and certificate of qualification
Incentive Compensation Recoupment Policy
Inline XBRL Instance Document
Inline XBRL Taxonomy Extension Schema Document
Inline XBRL Taxonomy Extension Calculation Linkbase Document
Inline XBRL Taxonomy Extension Definition Linkbase Document
Inline XBRL Taxonomy Extension Label Linkbase Document
Inline XBRL Taxonomy Extension Presentation Linkbase Document
Cover Page Interactive Data File (embedded within the Inline XBRL document)
* Attached hereto.
** Furnished herewith.
† Indicates management contract or compensatory plan or arrangement
81
Table of Contents
SIGNATURES
In accordance with Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant caused this report to be
signed on its behalf by the undersigned, thereunto duly authorized in the City of Houston, Texas, on the date indicated.
Evolution Petroleum Corporation
Date: September 13, 2023
By:
/s/ KELLY W. LOYD
Kelly W. Loyd
President and Chief Executive Officer
(Principal Executive Officer) and Director
In accordance with the Securities Exchange Act of 1934, this report has been signed below by the following persons on
behalf of the registrant and in the capacities and on the dates indicated.
Date
Signature
Title
September 13, 2023
/s/ ROBERT S. HERLIN
Chairman of the Board
September 13, 2023
Robert S. Herlin
/s/ KELLY W. LOYD
Kelly W. Loyd
September 13, 2023
/s/ RYAN STASH
Ryan Stash
President and Chief Executive
Officer (Principal Executive Officer) and
Director
Senior Vice President, Chief Financial
Officer and Treasurer (Principal
Financial Officer)
September 13, 2023
/s/ KELLY M. BEATTY
Kelly M. Beatty
Controller (Principal
Accounting Officer)
September 13, 2023
/s/ EDWARD J. DIPAOLO
Edward J. DiPaolo
Lead Director
September 13, 2023
September 13, 2023
/s/ MYRA C. BIERRIA
Myra C. Bierria
/s/ WILLIAM DOZIER
William Dozier
September 13, 2023
/s/ MARJORIE A. HARGRAVE
Marjorie A. Hargrave
Director
Director
Director
82
EXHIBIT 3.3
BYLAWS
OF
EVOLUTION PETROLEUM CORPORATION
(Amended and Restated as of September 7, 2023)
BYLAWS
OF
EVOLUTION PETROLEUM CORPORATION
(Amended and Restated as of September 7, 2023)
ARTICLE I OFFICES
ARTICLE II SHAREHOLDERS
ARTICLE III BOARD OF DIRECTORS
ARTICLE IV COMMITTEES
ARTICLE V OFFICERS
ARTICLE VI INDEMNIFICATION OF DIRECTORS, OFFICERS AND OTHERS
ARTICLE VII STOCK
ARTICLE VIII NOTICES
ARTICLE IX MISCELLANEOUS
ARTICLE X AMENDMENTS
2
3
3
10
13
13
15
18
19
19
20
BYLAWS
OF
EVOLUTION PETROLEUM CORPORATION
(Amended and Restated as of September 7, 2023)
ARTICLE I
OFFICES
Section 1.1 Principal Office
The principal executive office of the Corporation shall be such location as deemed necessary from
time to time by the Board of Directors.
Section 1.2 Other Offices
The Corporation may also have such other offices, either within or without the State of Nevada, as
the Board of Directors may from time to time determine or the business of the Corporation may
require.
ARTICLE II
SHAREHOLDERS
Section 2.1 Annual Meeting
An annual meeting of the shareholders, for the selection of directors to succeed those whose terms
expire and for the transaction of such other business as may properly come before the meeting,
shall be held at the principal office of the Corporation no later than the fifteenth day of the sixth
month following the end of the fiscal year of the Corporation or, if such date shall fall on a holiday,
the next business day thereafter. The Board of Directors may change the date or elect to have no
annual meeting for a particular year. If the election of directors is not held on the day designated
for any annual meeting of the shareholders or at any adjournment of the meeting, the Board of
Directors shall call for the election to be held at a special meeting of the Shareholders as soon
thereafter as possible.
Section 2.2 Special Meetings
Special meetings of the shareholders, for any purpose or purposes prescribed in the notice of the
meeting, may be called by the Board of Directors, the chief executive officer, or the holders of not
less than one-tenth of all the shares entitled to vote at the meeting, and shall be held at such place,
on such date, and at such time as they or he shall fix.
Section 2.3 Notice of Meetings
Written notice of the place, date and time of all meetings of the shareholders shall be given, not
3
less than ten nor more than sixty days before the date on which the meeting is to be held, to each
stockholder entitled to vote at such meeting, except as otherwise provided herein or required by
law (meaning, here and hereinafter, as required from time to time by the Corporation statutes of the
State of Nevada, as contained in Chapter 78 of Nevada Revised Statutes, or the Articles of
Incorporation).
When a meeting is adjourned to another place, date or time, written notice need not be given of
the adjourned meeting if the place, date and time thereof are announced at the meeting at which
the adjournment is taken; provided, however, that if the date of any adjourned meeting is more
than thirty days after the date for which the meeting was originally noticed, or if a new record date
is fixed for the adjourned meeting, written notice of the place, date, and time of the adjourned
meeting shall be given in conformity herewith. At any adjourned meeting, any business may be
transacted which might have been transacted at the original meeting.
Section 2.4 Quorum
At any meeting of the shareholders, the holders of a majority of all of the shares of the stock
entitled to vote at the meeting, present in person or by proxy, shall constitute a quorum for all
purposes, unless or except to the extent that the presence of a larger number may be required by
law.
If a quorum shall fail to attend any meeting, the chairman of the meeting or the holders of a
majority of the shares of the stock entitled to vote who are present, in person or by proxy, may
adjourn the meeting to another reasonable place, date and time of day.
If a notice of any adjourned special meeting of shareholders is sent to all shareholders entitled
to vote thereat, stating that it will be held with those present constituting a quorum, then except
as otherwise required by law, those present at such adjourned meeting shall constitute a
quorum, and all matters shall be determined by a majority of the votes cast at such meeting.
Section 2.5 Organization
Such person as the Board of Directors may have designated or, in the absence of such a person, the
highest ranking officer of the Corporation who is present shall call to order any meeting of the
shareholders and act as chairman of the meeting. In the absence of the Secretary of the
Corporation, the secretary of the meeting shall be the person the chairman appoints.
Section 2.6 Conduct of Business
The chairman of any meeting of shareholders shall determine the order of business and the
procedure at the meeting, including such regulation of the manner of voting and the conduct of
discussion as seem to him in order.
Section 2.7 Proxies and Voting
At any meeting of the shareholders, every shareholder entitled to vote may vote in person or by
4
proxy authorized by an instrument in writing filed in accordance with the procedure established for
the meeting.
Each shareholder shall have one vote for every share of stock entitled to vote which is registered
in his name on the record date for the meeting, except as otherwise provided herein or required by
law.
All voting, except on the election of directors and where otherwise required by law, may be by a
voice vote; provided, however, that upon demand therefor by a shareholder entitled to vote or his
proxy, a stock vote shall be taken. Every stock vote shall be taken by ballots, each of which shall
state the name of the shareholder or proxy voting and such other information as may be required
under the procedure established for the meeting. Every vote taken by ballots shall be counted by
an inspector or inspectors appointed by the chairman of the meeting.
If a quorum is present, the affirmative vote of the majority of the shares represented at the meeting
and entitled to vote on the subject matter shall be the act of the shareholders, unless the vote of a
greater number or voting by class is required by law, the Articles of Incorporation, or these By-
laws.
Section 2.8 Shareholder Action By Written Consent
Any action which may be taken at a meeting of the Shareholders may be taken by written consent
without a meeting if such action is taken in conformance with the Nevada Corporations Code and
is signed by the holders of not less than two-thirds of the outstanding shares of stock of the
Corporation entitled to vote thereon.
Section 2.9 Stock List
A complete list of shareholders entitled to vote at any meeting of shareholders, arranged in
alphabetical order for each class of stock and showing the address of each such shareholder and the
number of shares registered in his name, shall be open to the examination of any such shareholder,
for any purpose germane to the meeting, during ordinary business hours for a period of at least ten
(10) days prior to the meeting, either at a place within the city where the meeting is to be held,
which place shall be specified in the notice of the meeting, or if not so specified, at the place where
the meeting is to be held.
The Stock list shall also be kept at the place of the meeting during the whole time thereof and
shall be open to the examination of any such shareholder who is present. This list shall
presumptively determine the identity of the shareholders entitled to vote at the meeting and the
number of shares held by each of them.
Section 2.10 Nominations and Business at Stockholder Meetings.
(A) Annual Meetings of Stockholders.
(1) Nominations of persons for election to the Board of Directors of the Corporation and the
proposal of other business to be considered by the stockholders may be made at an annual
5
meeting of stockholders (a) pursuant to the Corporation’s notice of meeting, (b) by or at the
direction of the Board of Directors or (c) by any stockholder of the Corporation (i) who was a
stockholder of record at the time of giving of notice provided for in this Section 2.10, and at the
time of the annual meeting, (ii) is entitled to vote at the meeting and (iii) complies with the notice
procedures set forth in this Section 2.10 as to such business or nomination.
(2) Without qualification, for any nominations or any other business to be properly brought
before an annual meeting by a stockholder pursuant to clause (c) of paragraph (A)(1) of this
Section 2.10, the stockholder must have given timely notice thereof in writing to the Secretary of
the Corporation and such other business must otherwise be a proper matter for stockholder action.
To be timely, a stockholder’s notice shall be delivered to the Secretary at the principal executive
offices of the Corporation not later than the close of business on the 60th day nor earlier than the
close of business on the 90th day prior to the first anniversary of the preceding year’s annual
meeting; provided, however, that in the event that the date of the annual meeting is more than 30
days before or more than 60 days after such anniversary date, notice by the stockholder to be
timely must be so delivered not earlier than the close of business on the 90th day prior to such
annual meeting and not later than the close of business on the later of the 60th day prior to such
annual meeting or the 10th day following the day on which public announcement of the date of
such meeting is first made by the Corporation. In no event shall the public announcement of an
adjournment or postponement of an annual meeting commence a new time period for the giving of
a stockholder’s notice as described above.
(3) To be in proper form, a stockholder’s notice (whether given pursuant to paragraph (A)(l)
above or paragraph (B) below) to the Secretary must: (a) set forth, as to the stockholder giving the
notice and the beneficial owner, if any, on whose behalf the nomination or proposal is made (i) the
name and address of such stockholder, as they appear on the Corporation’s books, and of such
beneficial owner, if any, (ii) (A) the class or series and number of shares of the Corporation which
are, directly or indirectly, owned beneficially and of record by such stockholder and such
beneficial owner, (B) any option, warrant, convertible security, stock appreciation right, or similar
right with an exercise or conversion privilege or a settlement payment or mechanism at a price
related to any class or series of shares of the Corporation or with a value derived in whole or in
part from the value of any class or series of shares of the Corporation, whether or not such
instrument or right shall be subject to settlement in the underlying class or series of capital stock of
the Corporation or otherwise (a “Derivative Instrument”) directly or indirectly owned beneficially
by such stockholder and any other direct or indirect opportunity to profit or share in any profit
derived from any increase or decrease in the value of shares of the Corporation, (C) any proxy,
contract, arrangement, understanding, or relationship pursuant to which such stockholder has a
right to vote any shares of any security of the Company, (D) any short interest in any security of
the Company (for purposes of this Section 2.10, a person shall be deemed to have a short interest
in a security if such person, directly or indirectly, through any contract, arrangement,
understanding, relationship or otherwise, has the opportunity to profit or share in any profit derived
from any decrease in the value of the subject security), (E) any rights to dividends on the shares of
the Corporation owned beneficially by such stockholder that are separated or separable from the
underlying shares of the Corporation, (F) any proportionate interest in shares of the Corporation or
Derivative Instruments held, directly or indirectly, by a general or limited partnership in which
such stockholder is a general partner or, directly or
6
indirectly, beneficially owns an interest in a general partner and (G) any performance-related fees
(other than an asset-based fee) that such stockholder is entitled to based on any increase or
decrease in the value of shares of the Corporation or Derivative Instruments, if any, as of the date
of such notice including, without limitation, any such interests held by members of such
stockholder’s immediate family sharing the same household (which information shall be
supplemented by such stockholder and beneficial owner, if any, not later than 10 days after the
record date for the meeting to disclose such ownership as of the record date), and (iii) any other
information relating to such stockholder and beneficial owner, if any, that would be required to be
disclosed in a proxy statement or other filings required to be made in connection with solicitations
of proxies for, as applicable, the proposal and/or for the election of directors in a contested election
pursuant to Section 14 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”),
and the rules and regulations promulgated thereunder; (b) if the notice relates to any business other
than a nomination of a director or directors that the stockholder proposes to bring before the
meeting, set forth (i) a brief description of the business desired to be brought before the meeting,
the reasons for conducting such business at the meeting and any material interest of such
stockholder and beneficial owner, if any, in such business and (ii) a description of all agreements,
arrangements and understandings between such stockholder and beneficial owner, if any, and any
other person or persons (including their names) in connection with the proposal of such business
by such stockholder; (c) set forth, as to each person, if any, whom the stockholder proposes to
nominate for election or reelection to the Board of Directors (i) all information relating to such
person that would be required to be disclosed in a proxy statement or other filings required to be
made in connection with solicitations of proxies for election of directors in a contested election
pursuant to Section 14 of the Exchange Act and the rules and regulations promulgated thereunder
(including such person’s written consent to being named in the proxy statement as a nominee and
to serving as a director if elected) and (ii) a description of all direct and indirect compensation and
other material monetary agreements, arrangements and understandings during the past three years,
and any other material relationships, between or among such stockholder and beneficial owner, if
any, and their respective affiliates and associates, or others acting in concert therewith, on the one
hand, and each proposed nominee, and his or her respective affiliates and associates, or others
acting in concert therewith, on the other hand, including, without limitation all information that
would be required to be disclosed pursuant to Rule 404 promulgated under Regulation S-K (or any
successor rule) if the stockholder making the nomination and any beneficial owner on whose
behalf the nomination is made, if any, or any affiliate or associate thereof or person acting in
concert therewith, were the “registrant” for purposes of such rule and the nominee were a director
or executive officer of such registrant; and (d) with respect to each nominee for election or
reelection to the Board of Directors, include a completed, dated and signed questionnaire,
representation and agreement and any other information required by paragraph (D) below.
(4) Notwithstanding anything in the second sentence of paragraph (A)(2) of this Section 2.10 to
the contrary, in the event that the number of directors to be elected to the Board of Directors of the
Corporation is increased and there is no public announcement by the Corporation naming all of the
nominees for director or specifying the size of the increased Board of Directors at least 70 days
prior to the first anniversary of the preceding year’s annual meeting, a stockholder’s notice
required by this Section 2.10 shall also be considered timely, but only with respect to nominees for
any new positions created by such increase, if it shall be delivered to the Secretary at the
7
principal executive offices of the Corporation not later than the close of business on the 10th day
following the day on which such public announcement is first made by the Corporation.
(B) Special Meetings of Stockholders. Only such business shall be conducted at a special
meeting of stockholders as shall have been brought before the meeting pursuant to the
Corporation’s notice of meeting. Nominations of persons for election to the Board of Directors
may be made at a special meeting of stockholders at which directors are to be elected pursuant to
the Corporation’s notice of meeting (1) by or at the direction of the Board of Directors or (2)
provided that the Board of Directors has determined that directors shall be elected at such meeting,
by any stockholder of the Corporation who (a) is a stockholder of record at the time of giving of
notice provided for in this Section 2.10, (b) is entitled to vote at the meeting, and (c) complies with
the notice procedures set forth in this Section 2.10 as to such nomination. In the event the
Corporation calls a special meeting of stockholders for the purpose of electing one or more
directors to the Board of Directors, any such stockholder may nominate a person or persons (as the
case may be), for election to such position(s) as specified in the Corporation’s notice of meeting, if
the stockholder’s notice required by paragraph (A)(2) of this Section 2.10 with respect to any
nomination (including the completed and signed questionnaire, representation and agreement
required by paragraph (D) below) shall be delivered to the Secretary at the principal executive
offices of the Corporation not earlier than the close of business on the 90th day prior to the date of
such special meeting and not later than the close of business on the later of the 60th day prior to the
date of such special meeting or, if the first public announcement of the date of such special
meeting is less than 70 days prior to the date of such special meeting, the 10th day following the
day on which public announcement is first made of the date of the special meeting and of the
nominees proposed by the Board of Directors to be elected at such meeting. In no event shall the
public announcement of an adjournment or postponement of a special meeting commence a new
time period for the giving of a stockholder’s notice as described above.
(C) General.
(1) Only such persons who are nominated in accordance with the procedures set forth in this
Section 2.10 shall be eligible for election to the Board of Directors at a meeting of stockholders
and only such other business shall be conducted at a meeting of stockholders as shall have been
brought before the meeting in accordance with the procedures set forth in this Section 2.10. Except
as otherwise provided by law, the Articles of Incorporation or these Bylaws, the Chairman of the
meeting shall have the power and duty to determine whether a nomination or any other business
proposed to be brought before the meeting was made or proposed, as the case may be, in
accordance with the procedures set forth in this Section 2.10 and, if any proposed nomination or
business is not in compliance with this Section 2.10, to declare that such defective proposal or
nomination shall be disregarded.
(2) For purposes of this Section 2.10, “public announcement” shall mean disclosure in a press
release reported by a national news service or in a document publicly filed by the Corporation with
the Securities and Exchange Commission pursuant to Section 13, 14 or 15(d) of the Exchange Act
and the rules and regulations promulgated thereunder.
8
(3) Notwithstanding the foregoing provisions of this Section 2.10, a stockholder shall also
comply with all applicable requirements of the Exchange Act and the rules and regulations
thereunder with respect to the matters set forth in this Section 2.10; provided, however, that any
reference in these Bylaws to the Exchange Act or the rules and regulations promulgated thereunder
are not intended to and shall not limit the requirements applicable to nominations or proposals as to
any other business to be considered pursuant to paragraph (A)(1)(c) or paragraph (B) of this
Section 2.10. Nothing in this Section 2.10 shall be deemed to affect any rights (i) of stockholders
to request inclusion of proposals in the Corporation’s proxy statement pursuant to Rule 14a-8
under the Exchange Act or (ii) of the holders of any series of preferred stock if and to the extent
provided for under law, the Articles of Incorporation or these Bylaws.
(D) Submission of Questionnaire, Representation and Agreement; Other Information. To be
eligible to be a nominee for election or reelection as a director of the Corporation, a person must
deliver (in accordance with the time periods prescribed for delivery of notice under this Section
2.10) to the Secretary at the principal executive offices of the Corporation a written questionnaire
with respect to the background and qualification of such person and the background of any other
person or entity on whose behalf the nomination is being made (which questionnaire shall be
provided by the Secretary upon written request) and a written representation and agreement (in the
form provided by the Secretary upon written request) that such person (1) is not and will not
become a party to (a) any agreement, arrangement or understanding with, and has not given any
commitment or assurance to, any person or entity as to how such person, if elected as a director of
the Corporation, will act or vote on any issue or question (a “Voting Commitment”) that has not
been disclosed to the Corporation or (b) any Voting Commitment that could limit or interfere with
such person’s ability to comply, if elected as a director of the Corporation, with such person’s
fiduciary duties under applicable law, (2) is not and will not become a party to any agreement,
arrangement or understanding with any person or entity other than the Corporation with respect to
any direct or indirect compensation, reimbursement or indemnification in connection with service
or action as a director that has not been disclosed therein, and (3) in such person’s individual
capacity and on behalf of any person or entity on whose behalf the nomination is being made,
would be in compliance, if elected as a director of the Corporation, and will comply with all
applicable publicly disclosed corporate governance, conflict of interest, confidentiality and stock
ownership and trading policies and guidelines of the Corporation. The Corporation may also
require any proposed nominee to furnish such other information as may reasonably be required by
the Corporation to determine the eligibility of such proposed nominee to serve as an independent
director of the Corporation or that could be material to a reasonable stockholder’s understanding of
the independence, or lack thereof, of such nominee.
Section 2.11 Participation by Remote Communication.
Stockholders not physically present at a meeting of the stockholders may participate in the meeting
by remote communication, including (without limitation) electronic communication,
videoconference, teleconference, or other available technology if the Corporation implements
reasonable measures to: (a) verify the identity of each stockholder participating by remote
communication; and (b) provide the stockholders a reasonable opportunity to participate and vote,
including an opportunity to communicate and read or hear the proceedings in a substantially
concurrent manner with the proceedings. Stockholders participating by remote communication
shall be considered present in person at the meeting.
ARTICLE III
9
Section 3.1 Number and Term of Office
BOARD OF DIRECTORS
The Board of Directors shall consist of a minimum of one director. Each director shall be selected
for a term of one year and until his successor is elected and qualified, except as otherwise provided
herein or required by law.
Whenever the authorized number of directors is increased between annual meetings of the
shareholders, a majority of the directors then in office shall have the power to elect such new
directors for the balance of a term and until their successors are elected and qualified. Any
decrease in the authorized number of directors shall not become effective until the expiration of
the term of the directors then in office unless, at the time of such decrease, there shall be vacancies
on the board which are being eliminated by the decrease.
Section 3.2 Vacancies
Vacancies in the board of directors may be filled by a majority vote of the remaining directors,
though less than a quorum, by a sole remaining director, or by the shareholders. Each director so
elected shall hold office until a successor is elected at an annual or a special meeting of the
shareholders.
A vacancy in the board of directors shall be deemed to exist in case of the death, resignation or
removal of any director; if the authorized number of directors is increased; or if the shareholders
fail to elect the full authorized number of directors.
The shareholders may elect a director at any time to fill any vacancy not filled by the directors.
If the board of directors accepts the resignation of a director tendered to take effect at a future
time, the board or the shareholders shall have power to elect a successor to take office when the
resignation is to become effective.
No reduction of the authorized number of directors shall have the effect of removing any
director prior to the expiration of the director’s term of office.
Section 3.3 Regular Meetings
Regular meetings of the Board of Directors shall be held at such place or places, on such date or
dates, and at such time or times as shall have been established by the Board of Directors and
publicized among all directors. A notice of each regular meeting shall not be required.
Section 3.4 Special Meetings
Special meetings of the Board of Directors may be called by one-third of the directors then in
10
office or by the chief executive officer and shall be held at such place, on such date and at such
time as they or he shall fix. Notice of the place, date and time of each such special meeting shall be
given to each director by whom it is not waived by mailing written notice not less than three days
before the meeting or at least 18 hours before the meeting if by telephone or by being personally
delivered or sent by telex, telecopy, electronic transmission, email or similar means. Unless
otherwise indicated in the notice thereof, any and all business may be transacted at a special
meeting.
Section 3.5 Quorum
At any meeting of the Board of Directors, a majority of the total number of the whole board shall
constitute a quorum for all purposes. If a quorum shall fail to attend any meeting, a majority of
those present may adjourn the meeting to another place, date or time, without further notice or
waiver thereof.
Section 3.6 Participation in Meetings by Conference Telephone
Members of the Board of Directors or of any committee thereof, may participate in a meeting of
such board or committee by means of conference telephone or similar communications equipment
that enables all persons participating in the meeting to hear each other. Such participation shall
constitute presence in person at such meeting.
Section 3.7 Conduct of Business
At any meeting of the Board of Directors, business shall be transacted in such order and manner as
the board may from time to time determine, and all matters shall be determined by the vote of a
majority of the directors present, except as otherwise provided herein or required by law. Action
may be taken by the Board of Directors without a meeting if all members thereof consent thereto in
writing, and the writing or writings are filed with the minutes of proceedings of the Board of
Directors.
Section 3.8 Powers
The Board of Directors may, except as otherwise required by law, exercise all such powers and do
all such acts and things as may be exercised or done by the Corporation, including, without
limiting the generality of the foregoing, the unqualified power:
(a) To declare dividends from time to time in accordance with law;
(b) To purchase or otherwise acquire any property, rights or privileges on such terms as it shall
determine;
(c) To authorize the creation, making and issuance, in such form as it may determine, of written
obligations of every kind, negotiable or non-negotiable, secured or unsecured, and to do all
things necessary in connection therewith;
(d) To remove any officer of the Corporation with or without cause, and from time to time to
devolve the powers and duties of any officer upon any other person for the time being;
11
(e) To confer upon any officer of the Corporation the power to appoint, remove and suspend
subordinate officers and agents;
(f) To adopt from time to time such stock option, stock purchase, bonus or other
compensation plans for directors, officers and agents of the Corporation and its
subsidiaries as it may determine;
(g) To adopt from time to time such insurance, retirement and other benefit plans for
directors, officers and agents of the Corporation and its subsidiaries as it may determine;
and
(h) To adopt from time to time regulations, not inconsistent with these By-laws, for the
management of the Corporation’s business and affairs.
Section 3.9 Compensation of Directors
Directors, as such, may receive, pursuant to resolution of the Board of Directors, fixed
fees and other compensation for their services as directors, including, without limitation,
their services as members of committees of the directors.
Section 3.10 Interested Directors
No contract or transaction between the Corporation and one or more of its directors or officers, or
between the Corporation and any other corporation, partnership, association, or other organization
in which one or more of its directors or officers, are directors or officers, or have a financial
interest, shall be void or voidable solely for this reason, or solely because the director or officer is
present at or participates in the meeting of the board or committee which authorizes the contract or
transaction, or solely because his or their votes are counted for such purpose, if;
The material facts as to the relationship or interest and as to the contract or transaction are
disclosed or are known to the Board of Directors or the committee, and the board or
committee in good faith authorizes the contract or transaction by the affirmative votes of a
majority of the disinterested directors, even though the disinterested directors be less than a
quorum; or
The material facts as to his relationship or interest and as to the contract or transaction are
disclosed or are known to the shareholders entitled to vote thereon, and the contract or
transaction is specifically approved in good faith by vote of the shareholders; or
The contract or transaction is fair as to the Corporation as of the time it is authorized,
approved or ratified, by the Board of Directors, a committee or the shareholders.
Common or interested directors may be counted in determining the presence of a quorum at a
meeting of the Board of Directors or of a committee which authorizes the contract or
transaction.
Section 3.11 Loans
12
The Corporation shall not lend money to or use its credit to assist its officers, directors or other
control persons without authorization in the particular case by the shareholders, but may lend
money to and use its credit to assist any employee, excluding such officers, directors or other
control persons of the Corporation or of a subsidiary, if such loan or assistance benefits the
Corporation.
ARTICLE IV
COMMITTEES
Section 4.1 Committees of the Board of Directors
The Board of Directors, by a vote of a majority of the whole board, may from time to time
designate committees of the board, with such lawful powers and duties as it thereby confers, to
serve at the pleasure of the board and shall, for those committees and any others provided for
herein, elect a director or directors to serve as the member or members, designating, if it desires,
other directors as alternative members who may replace any absent or disqualified member at any
meeting of the committee. Notwithstanding the foregoing, no committee so designated may
exercise the power and authority of the Board of Directors to declare a dividend or to authorize the
issuance of stock, though a committee may be charged with the responsibility to make
recommendations to the Board of Directors with respect to such matters. In the absence or
disqualification of any member of any committee and any alternate member in his place, the
member or members of the committee present at the meeting and not disqualified from voting,
whether or not he or they constitute a quorum, may by unanimous vote appoint another member of
the Board of Directors to act at the meeting in the place of the absent or disqualified member.
Section 4.2 Conduct of Business
Each committee may determine the procedural rules for meeting and conducting its business and
shall act in accordance therewith, except as otherwise provided herein or required by law.
Adequate provisions shall be made for notice to members of all meetings; a majority of the
members shall constitute a quorum unless the committee shall consist of one or two members, in
which event one member shall constitute a quorum; and all matters shall be determined by a
majority vote of the members present. Action may be taken by any committee without a meeting
if all members thereof consent thereto in writing, and the writing or writings are filed with the
minutes of the proceedings of such committee.
ARTICLE V
OFFICERS
Section 5.1 Generally
The officers of the Corporation shall consist of a president, one or more vice-presidents, a
secretary, a treasurer and such other subordinate officers as may from time to time be appointed by
the Board of Directors. Officers shall be elected by the Board of Directors, which shall consider
that subject at its first meeting after every annual meeting of shareholders. Each officer
13
shall hold his office until his successor is elected and qualified or until his earlier resignation or
removal. Any number of offices may be held by the same person.
Section 5.2 President
The President shall be the chief executive officer of the Corporation, except as set forth in Section
5.6 of this Article. Subject to the provisions of these By-laws and to the direction of the Board of
Directors, he shall have the responsibility for the general management and control of the affairs
and business of the Corporation and shall perform all duties and have all powers which are
commonly incident to the office of chief executive or which are delegated to him by the Board of
Directors. He shall have power to sign all stock certificates, contracts and other instruments of the
Corporation which are authorized. He shall have general supervision and direction of all of the
other officers and agents of the Corporation.
Section 5.3 Vice-president
Each vice-president shall perform such duties as the Board of Directors shall prescribe. In the
absence or disability of the President, the vice-president who has served in such capacity for the
longest time shall perform the duties and exercise the powers of the President.
Section 5.4 Treasurer
The treasurer shall have the custody of the monies and securities of the Corporation and shall keep
regular books of account. He shall make such disbursements of the funds of the Corporation as are
proper and shall render from time to time an account of all such transactions and of the financial
condition of the Corporation.
Section 5.5 Secretary
The secretary shall issue all authorized notices for, and shall keep minutes of, all meetings of the
shareholders and the Board of Directors and shall have charge of the corporate books.
Section 5.6 General Manager
The Board of Directors may employ and appoint a general manager who may, or may not, be one
of the officers or directors of the Corporation. If employed by the Board of Directors he shall be
the chief operating officer of the Corporation and, subject to the directions of the Board of
Directors, shall have general charge of the business operations of the Corporation and general
supervision over its employees and agents. He shall have the exclusive management of the
business of the Corporation and of all of its dealings, but at all times subject to the control of the
Board of Directors. Subject to the approval of the Board of Directors or a committee, he shall
employ all employees of the Corporation, or delegate such employment to subordinate officers, or
division officers, or division chiefs, and shall have authority to discharge any person so employed.
He shall make a report to the President and directors quarterly, or more often if required to do so,
setting forth the results of the operations under his charge, together with
14
suggestions regarding the improvement and betterment of the condition of the Corporation, and
shall perform such other duties as the Board of Directors shall require.
Section 5.7 Delegation of Authority
The Board of Directors may, from time to time, delegate the powers or duties of any officer to any
other officers or agents, notwithstanding any provision hereof.
Section 5.8 Removal
Any officer of the Corporation may be removed at any time, with or without cause, by the Board of
Directors.
Section 5.9 Action with Respect to Securities of Other Corporation
Unless otherwise directed by the Board of Directors, the president shall have power to vote and
otherwise act on behalf of the Corporation, in person or by proxy, at any meeting of shareholders
of or with respect to any action of shareholders of any other corporation in which this Corporation
may hold securities and otherwise to exercise any and all rights and powers which this Corporation
may possess by reason of its ownership of securities in such other corporation.
ARTICLE VI
INDEMNIFICATION OF DIRECTORS, OFFICERS AND OTHERS
Section 6.1 Generally
(A) Indemnity for Claim Not in Name of Corporation.
The Corporation shall indemnify any person who was or is a party or is threatened
(1)
to be made a party to any threatened, pending or completed action, suit or proceeding,
whether civil, criminal, administrative or investigative (other than an action by or in the
right of the Corporation) by reason of the fact that he is or was a director, officer, employee
or agent of the Corporation, or is or was serving at the request of the Corporation as a
director, officer, employee or agent of another corporation, partnership, joint venture, trust
or other enterprise, against expenses (including attorney’s fees), judgments, fines and
amounts paid in settlement actually and reasonably incurred by him in connection with
such action, suit or proceeding if he acted in good faith and in a manner he reasonably
believed to be in or not opposed to the best interests of the Corporation, and, with respect to
any criminal action or proceeding, had no reasonable cause to believe his conduct was
unlawful.
The termination of any action, suit or proceeding by judgment, order, settlement,
(2)
conviction, or upon a plea of nolo contendere or items equivalent, shall not, of itself, create
a presumption that the person did not act in good faith and in a manner which he
reasonably believed to be in or not opposed to the best interests of the Corporation, and
15
with respect to any criminal action or proceeding, had reasonable cause to believe that his
conduct was lawful.
(B) Indemnity for Claims in Name of Corporation
(1) The Corporation shall indemnify any person who was or is a party or is threatened to be
made a party to any threatened, pending or completed action or suit by or in the right of the
Corporation to procure a judgment in its favor by reason of the fact that he is or was a
director, officer, employee or agent of the Corporation, or is or was serving at the request of
the Corporation as a director, officer, employee or agent of another corporation,
partnership, joint venture, trust or other enterprise against expenses (including attorney’s
fees) actually and reasonably incurred by him in connection with the defense or settlement
of such action or suit if he acted in good faith and in a manner he reasonably believed to be
in or not opposed to the best interests of the Corporation. The Corporation may not
indemnify any such person if it is proven that such person’s act, or failure to act, constituted
a breach of such person’s fiduciary duties as a director or office, and such breach of those
duties involved intentional misconduct, fraud or a knowing violation of law, making such
person liable pursuant to Section 78.138 of the Nevada Revised Statutes.
(2) Indemnification may not be made in respect of any claim, issue or matter as to which
such person shall have been adjudged to be liable for negligence or misconduct in the
performance of his duty to the Corporation unless and only to the extent that the court in
which such action or suit was brought shall determine upon application that, despite the
adjudication of liability but in view of all circumstances of the case, such person is fairly
and reasonably entitled to indemnity for such expenses which such court shall deem proper.
Section 6.2 Expenses
To the extent that a director, officer, employee or agent of the Corporation has been successful on
the merits or otherwise in defense of any action, suit or proceeding referred to in Section 6.1 of this
Article, or in defense of any claim, issue or matter therein, he shall be indemnified against
expenses (including attorney’s fees) actually and reasonably incurred by him in connection
therewith. Expenses incurred in defending a civil or criminal action, suit or proceeding may be
paid by the Corporation in advance of the final disposition of such action, suit or proceeding as
authorized in the manner provided in Section 6.3 of this Article upon receipt of an undertaking by
or on behalf of the director, officer, employee or agent to repay such amount unless it shall
ultimately be determined that he is entitled to be indemnified by the Corporation as authorized in
this Article.
Section 6.3 Determination by Board of Directors
Any indemnification under Section 6.1 of this Article (unless ordered by a court) shall be made by
the Corporation only as authorized in the specific case upon a determination that indemnification
of the director, officer, employee or agent is proper in the circumstances because
16
he has met the applicable standard of conduct set forth in Section 6.1 of this Article. Such
determination shall be made by the Board of Directors by a majority vote of a quorum of the
directors, or by the shareholders.
Section 6.4 Non-exclusive Right
The indemnification provided by this Article shall not be deemed exclusive of any other rights to
which those indemnified may be entitled under any by-law, agreement, vote of shareholders or
interested directors or otherwise, both as to action in his official capacity and as to action in
another capacity while holding such office and shall continue as to a person who has ceased to be a
director, officer, employee or agent and shall inure to the benefit of the heirs, executors and
administrators of such a person.
Section 6.5 Insurance
The Corporation shall have the power to purchase and maintain insurance on behalf of any person
who is or was a director, officer, employee or agent of the Corporation, or is or was serving at the
request of the Corporation as a director, officer, employee or agent of another corporation,
partnership, joint venture, trust or other enterprise against any liability asserted against him and
incurred by him in any such capacity or arising out of his status as such, whether or not the
Corporation would have the power to indemnify him against such liability under the provisions of
this Article.
The Corporation’s indemnity of any person who is or was a director, officer, employee or agent of
the Corporation, or is or was serving at the request of the Corporation as a director, officer,
employee or agent of another corporation, partnership, joint venture, trust or other enterprise, shall
be reduced by any amounts such person may collect as indemnification (i) under any policy of
insurance purchased and maintained on his behalf by the Corporation or (ii) from such other
corporation, partnership, joint venture, trust or other enterprise.
Section 6.6 Violation of Law
Nothing contained in this Article, or elsewhere in these By-laws, shall operate to indemnify any
director or officer if such indemnification is for any reason contrary to law, either as a matter of
public policy, or under the provisions of the Federal Securities Act of 1933, the Securities
Exchange Act of 1934, or any other applicable state or federal law.
Section 6.7 Coverage
For the purposes of this Article, references to “the Corporation” include all constituent
corporations absorbed in a consolidation or merger as well as the resulting or surviving corporation
so that any person who is or was a director, officer, employee or agent of such a constituent
corporation or is or was serving at the request of such a constituent corporation as a director,
officer, employee or agent of another corporation, partnership, joint venture, trust or other
enterprise shall stand in the same position under the provisions of this Article with respect to the
resulting or surviving corporation as he would if he had served the resulting or surviving
corporation in the same capacity.
17
Section 6.8 Effect of Amendment
No amendment, modification or repeal of this Article or any provision hereof shall in any manner
terminate, reduce or impair the right of any person who is or was a director, officer, employee or
agent of the Corporation, or is or was serving at the request of the Corporation as a director,
officer, employee or agent of another corporation, partnership, joint venture, trust or other
enterprise to be indemnified by the Corporation, nor the obligation of the Corporation to indemnify
any such person under and in accordance with the provisions of this Article 6 as in effect
immediately prior to such amendment, modification or repeal with respect to claims arising, in
whole or in part, from a state of facts existing on the date of, or relating to matters occurring prior
to, such amendment, modification or repeal, regardless of when such claims may arise or be
asserted.
ARTICLE VII
STOCK
Section 7.1 Certificates of Stock Each shareholder shall be entitled to a certificate signed by, or in
the name of the Corporation by, the President or a vice-president, and by the secretary or an
assistant secretary, or the treasurer or an assistant treasurer, certifying the number of shares owned
by him. Any of or all the signatures on the certificate may be facsimile.
Section 7.2 Transfers of Stock
Transfers of stock shall be made only upon the transfer books of the Corporation kept at an office
of the Corporation or by transfer agents designated to transfer shares of the stock of the
Corporation. Except where a certificate is issued in accordance with Section 7.4 of this Article, an
outstanding certificate for the number of shares involved shall be surrendered for cancellation
before a new certificate is issued therefor.
Section 7.3 Record Date
The Board of Directors may fix a record date, which shall not be more than sixty nor less than ten
days before the date of any meeting of shareholders, nor more than sixty days prior to the time for
the other action hereinafter described, as of which there shall be determined the shareholders who
are entitled: to notice of or to vote at any meeting of shareholders or any adjournment thereof; to
express consent to corporate action in writing without a meeting; to receive payment of any
dividend or other distribution or allotment of any rights; or to exercise any rights with respect of
any change, conversion or exchange of stock or with respect to any other lawful action.
Section 7.4 Lost, Stolen or Destroyed Certificates In the event of the loss, theft or destruction of
any certificate of stock, another may be issued in its place pursuant to such regulations as the
Board of Directors may establish concerning proof of such loss, theft or destruction and
concerning the giving of a satisfactory bond or bonds of indemnity.
Section 7.5 Regulations
18
The issue, transfer, conversion and registration of certificates of stock shall be governed by such
other regulations as the Board of Directors may establish.
ARTICLE VIII
NOTICES
Section 8.1 Notices
Whenever notice is required to be given to any shareholder, director, officer, or agent, such
requirement shall not be construed to mean personal notice. Such notice may in every instance be
effectively given by depositing a writing in a post office or letter box, in a postpaid, sealed
wrapper, or by dispatching a prepaid telegram, addressed to such shareholder, director, officer, or
agent at his or her address as the same appears on the books of the Corporation. The time when
such notice is dispatched shall be the time of the giving of the notice.
Section 8.2 Waivers
A written waiver of any notice, signed by a shareholder, director, officer or agent, whether before
or after the time of the event for which notice is given, shall be deemed equivalent to the notice
required to be given to such shareholder, director, officer or agent. Neither the business nor the
purpose of any meeting need be specified in such a waiver.
ARTICLE IX
MISCELLANEOUS
Section 9.1 Facsimile Signatures
In addition to the provisions for the use of facsimile signatures elsewhere specifically authorized in
these By laws, facsimile signatures of any officer or officers of the Corporation may be used
whenever and as authorized by the Board of Directors or a committee thereof.
Section 9.2 Corporate Seal
The Board of Directors may provide a suitable seal, containing the name of the Corporation, which
seal shall be in the charge of the secretary. If and when so directed by the Board of Directors or a
committee thereof, duplicates of the seal may be kept and used by the treasurer or by the assistant
secretary or assistant treasurer.
Section 9.3 Reliance upon Books, Reports and Records
Each director, each member of any committee designated by the Board of Directors, and each
officer of the Corporation shall, in the performance of his duties, be fully protected in relying in
good faith upon the books of account or other records of the Corporation, including reports made
19
to the Corporation by any of its officers, by an independent certified public accountant, or by an
appraiser selected with reasonable care.
Section 9.4 Fiscal Year
The fiscal year of the Corporation shall be as fixed by resolution of the Board of Directors.
Section 9.5 Time Periods
In applying any of these By-laws which require that an act be done or not done a specified
number of days prior to any event or that an act be done during a period of a specified number of
days prior to an event, calendar days shall be used, the day of the doing of the act shall be
excluded and the day of the event shall be included.
ARTICLE X
AMENDMENTS
Section 10.1 Amendments
These By-laws, or any portion hereof, may be amended or repealed by the Board of Directors at
any meeting or by the shareholders at any meeting.
CERTIFICATE OF SECRETARY
I hereby certify that the foregoing Bylaws are a true, complete, and correct copy of the Bylaws of
the Corporation as adopted as of September 7, 2023.
/s/ RYAN STASH
Ryan Stash, Corporate Secretary
20
Evolution Petroleum Corporation
Restricted Stock [and Performance Share] Award Agreement
EXHIBIT 4.4.2
This Restricted Stock Award Agreement (this "Agreement") is made and entered into as of
[DATE] (the "Grant Date") by and between Evolution Petroleum Corporation, a Nevada
corporation (the "Company") and [NAME] (the "Participant").
WHEREAS, the Company has adopted the Evolution Petroleum Corporation 2016 Equity
Incentive Plan (the "Plan") pursuant to which awards of Restricted Stock may be granted; and
WHEREAS, the Committee has determined that it is in the best interests of the Company and its
shareholders to grant the award of Restricted Stock provided for herein.
NOW, THEREFORE, the parties hereto, intending to be legally bound, agree as follows:
1.
Grant of Restricted Stock. Pursuant to Section 7.2 of the Plan, the Company hereby
issues to the Participant on the Grant Date a Restricted Stock Award consisting of, in the
aggregate, [NUMBER] shares of Common Stock of the Company (the "Restricted Stock"), on the
terms and conditions and subject to the restrictions set forth in this Agreement and the Plan.
Capitalized terms that are used but not defined herein have the meaning ascribed to them in the
Plan.
2.
Restricted Period; Vesting.
2.1
The following vesting schedule(s) shall apply:
(a)
As to [NUMBER] shares of Restricted Stock, except as otherwise
provided herein, provided that the Participant remains in Continuous Service through
each Vesting Date, such shares will vest in accordance with the following schedule:
Vesting Date
[DATE]
[DATE]
[DATE]
[DATE]
Number of Shares of the Restricted
Stock Vested
[NUMBER]
[NUMBER]
[NUMBER]
[NUMBER]
(b)
[As to [NUMBER] shares of Restricted Stock, except as otherwise
provided herein, provided that the Participant remains in Continuous Service through the
end of the three-year measurement period below, such shares will vest as follows:
[INSERT PERFORMANCE CRITERIA]]
Page 1 of 8
Evolution Petroleum Corporation
Restricted Stock [and Performance Share] Award Agreement
(c)
The period over which the Restricted Stock vests is referred to as the
"Restricted Period".
2.2
All unvested shares of Restricted Stock set forth in Section 2.1(a) [and 2.1(b)]
above shall be forfeited upon termination of Participant’s Continuous Service with the
Company and its Affiliates, and neither the Company nor any Affiliate shall have any further
obligations to the Participant under this Agreement with respect thereto, except as follows:
(a)
With respect to Restricted Stock for time-based service set forth in
Section 2.1(a) above, in the event that the Participant's Continuous Service is terminated
by: (i) death or Disability, or by the Company without Cause, then a pro rata amount of
the shares of Restricted Stock scheduled to vest on the next scheduled Vesting Date shall
also vest based upon the number of elapsed days during the current vesting period up to
and including the date of termination of Participant’s Continuous Service (for example,
if the date of termination occurs halfway through the year, one half of the Restricted
Stock vesting at the next scheduled Vesting Date shall vest).
(b)
If on or prior to the date Participant’s Continuous Service terminates, a
Change in Control Event occurs as defined in the Evolution Petroleum Corporation
Severance Policy for Change in Control Events, as adopted August 11, 2010, as it may
be amended from time to time after the date hereof (as amended, the “CIC Policy”), then
shares of Restricted Stock shall vest in accordance with the CIC Policy then in effect.
3.
Restrictions. Subject to any exceptions set forth in this Agreement or the Plan, during
the Restricted Period, the Restricted Stock or the rights relating thereto may not be assigned,
alienated, pledged, attached, sold or otherwise transferred or encumbered by the Participant. Any
attempt to assign, alienate, pledge, attach, sell or otherwise transfer or encumber the Restricted
Stock or the rights relating thereto during the Restricted Period shall be wholly ineffective.
4.
Rights as Shareholder; Dividends.
4.1
The Participant shall be the owner of the Restricted Stock until the shares of
Common Stock are forfeited, sold or otherwise disposed of, and until such time shall be
entitled to all of the rights of a shareholder of the Company including, without limitation, the
right to vote such shares and receive all dividends or other distributions paid with respect to
such shares.
4.2
The Company may issue stock certificates or evidence the Participant's interest
by using a restricted book entry account with the Company's transfer agent. In such
circumstance, physical possession or custody of any stock certificates that are issued shall be
retained by the Company until such time as the Restricted Stock vests.
Page 2 of 8
Evolution Petroleum Corporation
Restricted Stock [and Performance Share] Award Agreement
4.3
If the Participant forfeits any rights he or she has under this Agreement in
accordance with Section 2, the Participant shall, on the date of such forfeiture, no longer have
any rights as a shareholder with respect to the forfeited Restricted Stock and shall no longer be
entitled to vote or receive dividends on such shares.
5.
No Right to Continued Service. Neither the Plan nor this Agreement shall confer upon
the Participant any right to be retained in any position, as an Employee, Consultant or Director of
the Company. Further, nothing in the Plan or this Agreement shall be construed to limit the
discretion of the Company to terminate the Participant's Continuous Service at any time, with or
without Cause.
6.
Adjustments. If any change is made to the outstanding Common Stock or the capital
structure of the Company, if required, the shares of Common Stock shall be adjusted or terminated
in any manner as contemplated by Section 11 of the Plan.
7.
Tax Liability and Withholding.
7.1
The Participant shall be required to pay to the Company, and the Company shall
have the right to deduct from any compensation paid to the Participant pursuant to the Plan,
the amount of any required withholding taxes in respect of the Restricted Stock and to take all
such other action as the Committee deems necessary to satisfy all obligations for the payment
of such withholding taxes. The Committee may permit the Participant to satisfy any federal,
state or local tax withholding obligation by any of the following means, or by a combination
of such means:
(a)
Tendering a cash payment;
(b)
Authorizing the Company to withhold shares of Common Stock from the
shares of Common Stock otherwise issuable or deliverable to the Participant as a result
of the vesting of the Restricted Stock; provided, however, that no shares of Common
Stock shall be withheld with a value exceeding the Participant’s maximum marginal
income tax rates, including federal, state and local, as applicable; and
(c)
of Common Stock.
Delivering to the Company previously owned and unencumbered shares
7.2
Notwithstanding any action the Company takes with respect to any or all income
tax, social insurance, payroll tax, or other tax-related withholding ("Tax-Related Items"), the
ultimate liability for all Tax-Related Items is and remains the Participant's responsibility and
the Company (a) makes no representation or undertakings regarding the treatment of any Tax-
Related Items in connection with the grant or vesting of the Restricted Stock or the subsequent
sale of any shares; and (b) does not commit to structure the Restricted Stock to reduce or
eliminate the Participant's liability for Tax-Related Items.
Page 3 of 8
Evolution Petroleum Corporation
Restricted Stock [and Performance Share] Award Agreement
8.
Section 83(b) Election. The Participant may make an election under Code Section 83(b)
(a "Section 83(b) Election") with respect to the Restricted Stock. Any such election must be made
within thirty (30) days after the Grant Date. If the Participant elects to make a Section 83(b)
Election, the Participant shall provide the Company with a copy of an executed version and
satisfactory evidence of the filing of the executed Section 83(b) Election with the U.S. Internal
Revenue Service. The Participant agrees to assume full responsibility for ensuring that the Section
83(b) Election is actually and timely filed with the U.S. Internal Revenue Service and for all tax
consequences resulting from the Section 83(b) Election.
9.
Compliance with Law. The issuance and transfer of shares of Common Stock shall be
subject to compliance by the Company and the Participant with all applicable requirements of
federal and state securities laws and with all applicable requirements of any stock exchange on
which the Company’s shares of Common Stock may be listed. No shares of Common Stock shall
be issued or transferred unless and until any then applicable requirements of state and federal laws
and regulatory agencies have been fully complied with to the satisfaction of the Company and its
counsel. The Participant understands that the Company is under no obligation to register the
shares of Common Stock with the Securities and Exchange Commission, any state securities
commission or any stock exchange to effect such compliance.
10. Legends. A legend may be placed on any certificate(s) or other document(s) delivered to
the Participant indicating restrictions on transferability of the shares of Restricted Stock pursuant
to this Agreement or any other restrictions that the Committee may deem advisable under the rules,
regulations and other requirements of the Securities and Exchange Commission, any applicable
federal or state securities laws or any stock exchange on which the shares of Common Stock are
then listed or quoted.
11. Notices. Any notice required to be delivered to the Company under this Agreement shall
be in writing and addressed to the Company at the Company’s principal corporate offices. Any
notice required to be delivered to the Participant under this Agreement shall be in writing and
addressed to the Participant at the Participant's address as shown in the records of the Company.
Either party may designate another address in writing (or by such other method approved by the
Company) from time to time.
12. Governing Law. This Agreement will be construed and interpreted in accordance with
the laws of the State of Nevada without regard to conflict of law principles.
13.
Interpretation. Any dispute regarding the interpretation of this Agreement shall be
submitted by the Participant or the Company to the Committee for review. The resolution of such
dispute by the Committee shall be final and binding on the Participant and the Company.
14. Restricted Stock Subject to Plan. This Agreement is subject to the Plan as approved by
the Company’s shareholders. The terms and provisions of the Plan as it may be amended from
time to time are hereby incorporated herein by reference. In the event of a conflict between any
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Evolution Petroleum Corporation
Restricted Stock [and Performance Share] Award Agreement
term or provision contained herein and a term or provision of the Plan, the applicable terms and
provisions of the Plan will govern and prevail.
15. Clawbacks. Participant shall be required to forfeit or reimburse the Company with
respect to the Restricted Stock granted under this Agreement and the Plan to the extent required by
any clawback or recoupment policy of the Company now in effect or as may be adopted by the
Company from time to time, including, without limiting the foregoing, any clawback or
recoupment policy adopted in accordance with Section 304 of the Sarbanes-Oxley Act of 2002,
Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act, or as otherwise
required by applicable law, rule or regulation.
16.
Successors and Assigns. The Company may assign any of its rights under this
Agreement. This Agreement will be binding upon and inure to the benefit of the successors and
assigns of the Company. Subject to the restrictions on transfer set forth herein, this Agreement will
be binding upon the Participant and the Participant's beneficiaries, executors, administrators and
the person(s) to whom the Restricted Stock may be transferred by will or the laws of descent or
distribution.
17.
Severability. The invalidity or unenforceability of any provision of the Plan or this
Agreement shall not affect the validity or enforceability of any other provision of the Plan or this
Agreement, and each provision of the Plan and this Agreement shall be severable and enforceable
to the extent permitted by law.
18. Discretionary Nature of Plan. The Plan is discretionary and may be amended, cancelled
or terminated by the Company at any time, in its discretion. The grant of the Restricted Stock in
this Agreement does not create any contractual right or other right to receive any Restricted Stock
or other Awards in the future. Future Awards, if any, will be at the sole discretion of the Company.
Any amendment, modification, or termination of the Plan shall not constitute a change or
impairment of the terms and conditions of the Participant's employment with the Company.
19. Amendment. The Committee has the right to amend, alter, suspend, discontinue or
cancel the Restricted Stock, prospectively or retroactively; provided, that, no such amendment
shall adversely affect the Participant's material rights under this Agreement without the
Participant's consent; provided that the Committee may amend or modify this Agreement to the
extent that the Committee determines, in its sole discretion, that the terms and conditions of the
Award violate or may violate Code Section 409A; provided that, any such amendment or
modification of an Award made pursuant to this Section 19 shall maintain, to the maximum extent
practicable, the original intent of the applicable Award provision without contravening the
provisions of Code Section 409A.
The amendment or modification of any Award pursuant to this Section 19 shall be at the
Committee’s sole discretion and neither the Committee nor the Company shall be obligated to
amend or modify any Award or the Plan, nor shall the Company be liable for any adverse tax or
other consequences to a Participant resulting from such amendments or modifications or the
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Evolution Petroleum Corporation
Restricted Stock [and Performance Share] Award Agreement
Committee’s failure to make any such amendments or modifications for purposes of complying
with Code Section 409A or for any other purpose. To the extent the Committee amends or
modifies an Award pursuant to this Section 19, the Participant shall receive notification of any
such changes to his or her Award and, unless the Committee determines otherwise, the changes
described in such notification shall be deemed to amend the terms and conditions of the Award and
this Agreement.
20. No Impact on Other Benefits. The value of the Participant's Restricted Stock is not part
of his normal or expected compensation for purposes of calculating any severance, retirement,
welfare, insurance or similar employee benefit.
21. Counterparts. This Agreement may be executed in counterparts, each of which shall be
deemed an original but all of which together will constitute one and the same instrument.
Counterpart signature pages to this Agreement transmitted by facsimile transmission, by electronic
mail in portable document format (.pdf), or by any other electronic means intended to preserve the
original graphic and pictorial appearance of a document, will have the same effect as physical
delivery of the paper document bearing an original signature.
22. Acceptance. The Participant hereby acknowledges receipt of a copy of the Plan and this
Agreement. The Participant has read and understands the terms and provisions thereof, and accepts
the Restricted Stock subject to all of the terms and conditions of the Plan and this Agreement. The
Participant acknowledges that there he or she has been advised to consult a tax advisor to
understand the tax consequences of such grant, vesting and disposition. By acceptance of the
restricted shares and performance share ward shares, the Participant accepts the terms of this
Agreement.
Page 6 of 8
Evolution Petroleum Corporation
Restricted Stock [and Performance Share] Award Agreement
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first
above written.
EVOLUTION PETROLEUM
CORPORATION
By: _____________________
Name: Title:
PARTICIPANT
By: _____________________
Name:
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Evolution Petroleum Corporation
Performance Share Unit Award Agreement
EXHIBIT 4.5.1
This Performance Share Unit Award Agreement (this "Agreement") is made and
entered into as of [DATE] (the "Grant Date") by and between Evolution Petroleum
Corporation, a Nevada corporation (the "Company") and [NAME] (the "Participant").
WHEREAS, the Company has adopted the Evolution Petroleum Corporation 2016
Equity Incentive Plan (the "Plan") pursuant to which Performance Share Units may be
granted; and
WHEREAS, the Committee has determined that it is in the best interests of the
Company and its shareholders to grant the award of Performance Share Units provided for
herein.
NOW, THEREFORE, the parties hereto, intending to be legally bound, agree as
follows:
1.
Grant of Performance Share Units. Pursuant to Section 7.3 of the Plan, the
Company hereby grants to the Participant an Award covering a target number of
Each
[TARGET NUMBER] Performance Share Units (the "Target Award").
Performance Share Unit (“PSU”) represents the right to receive one share of Common
Stock, subject to the terms and conditions set forth in this Agreement and the Plan. The
number of shares of Common Stock under the PSUs that the Participant actually earns for
the Performance Period (up to a maximum of [MAXIMUM NUMBER] will be
determined by the level of achievement of the Performance Goals in accordance with
Exhibit I attached hereto (the “Performance Shares”). Capitalized terms that are used but
not defined herein have the meanings ascribed to them in the Plan.
2.
Performance Period. For purposes of this Agreement, the term "Performance
Period" shall be the period commencing on [DATE] and ending on [DATE].
3.
Performance Goals.
3.1
The number of Performance Shares earned by the Participant under the
PSUs for the Performance Period will be determined at the end of the Performance
Period based on the level of achievement of the Performance Goals in accordance with
Exhibit I. All determinations of whether Performance Goals have been achieved, the
number of Performance Shares earned under the PSUs by the Participant, and all other
matters related to this Section 3 shall be made by the Committee in its sole discretion.
3.2
As soon as administratively practicable following completion of the
Performance Period, the Committee will review and certify in writing (a) whether, and
to what extent, the Performance Goals for the Performance Period have been achieved,
and (b) the number of Performance Shares that the Participant shall earn, if any,
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Evolution Petroleum Corporation
Performance Share Unit Award Agreement
subject to Section 4. Such certification shall be final, conclusive and binding on the
Participant, and on all other persons, to the maximum extent permitted by law.
4.
Vesting of PSUs. The PSUs are subject to forfeiture until they vest. Except as
otherwise provided herein (including Section 24), the PSUs will vest and become
nonforfeitable on the last day of the Performance Period, subject to (a) the achievement of
the minimum threshold Performance Goals for payout set forth in Exhibit I attached hereto,
and (b) the Participant's Continuous Service from the Grant Date through the last day of the
Performance Period. The number of Performance Shares that become payable under this
Agreement pursuant to the PSUs shall be determined by the Committee based on the level
of achievement of the Performance Goals set forth in Exhibit I and shall be rounded to the
nearest whole share.
5.
Termination of Continuous Service. Except as otherwise expressly provided in
Section 6 of this Agreement, if the Participant's Continuous Service terminates for any
reason at any time before all of his or her PSUs have vested, the Participant's unvested
PSUs shall be automatically forfeited upon such termination of Continuous Service and
neither the Company nor any Affiliate shall have any further obligations to the Participant
under this Agreement.
6.
Effect of a Change in Control. Notwithstanding the vesting requirement in
Section 4, if a Change in Control Event occurs as defined in the Evolution Petroleum
Corporation Severance Policy for Change in Control Events, as adopted August 11, 2010,
as it may be amended from time to time after the date hereof (as amended, the “CIC
Policy”), then vesting shall occur in accordance with the CIC Policy then in effect.
7.
Transferability. Subject to any exceptions set forth in this Agreement or the Plan,
the PSUs or the rights relating thereto may not be assigned, alienated, pledged, attached,
sold or otherwise transferred or encumbered by the Participant, except by will or the laws
of descent and distribution, and upon any such transfer by will or the laws of descent and
distribution, the transferee shall hold such PSUs subject to all of the terms and conditions
that were applicable to the Participant immediately prior to such transfer.
8.
Rights as Shareholder; Dividend Equivalents.
8.1
Except as otherwise provided herein, the Participant shall not have any
rights of a shareholder with respect to the PSUs, including, but not limited to, voting
rights, liquidation rights and the right to receive or accrue dividends or dividend
equivalents.
8.2
Upon and following the vesting of the PSUs and issuance of the
Performance Shares, the Participant shall be the record owner of the shares of
Common Stock underlying the PSUs unless and until such shares are sold or otherwise
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Evolution Petroleum Corporation
Performance Share Unit Award Agreement
disposed of, and as record owner shall be entitled to all rights of a shareholder of the
Company (including voting and dividend rights).
9.
No Right to Continued Service. Neither the Plan nor this Agreement shall confer
upon the Participant any right to be retained in any position, as an Employee, Consultant or
Director of the Company. Further, nothing in the Plan or this Agreement shall be construed
to limit the discretion of the Company to terminate the Participant's Continuous Service at
any time, with or without Cause.
10. Adjustments. If any change is made to the outstanding Common Stock or the
capital structure of the Company, if required, the PSUs shall be adjusted or terminated in
any manner as contemplated by Section 11 of the Plan.
11. Tax Liability and Withholding.
11.1
The Participant shall be required to pay to the Company, and the
Company shall have the right to deduct from any compensation paid to the Participant
pursuant to the Plan, the amount of any required withholding taxes in respect of the
PSUs and to take all such other action as the Committee deems necessary to satisfy all
obligations for the payment of such withholding taxes. The Committee may permit
the Participant to satisfy any federal, state or local tax withholding obligation by any
of the following means, or by a combination of such means:
(a)
Tendering a cash payment;
(b)
Authorizing the Company to withhold shares of Common Stock
from the shares of Common Stock otherwise issuable or deliverable to the
Participant as a result of the vesting of the PSUs; provided, however, that no
shares of Common Stock shall be withheld with a value exceeding the
Participant’s maximum marginal income tax rates, including federal, state and
local, as applicable; and
(c)
Delivering to the Company previously owned and unencumbered
shares of Common Stock.
11.2 Notwithstanding any action the Company takes with respect to any or all
income tax, social insurance, payroll tax, or other tax-related withholding ("Tax-
Related Items"), the ultimate liability for all Tax-Related Items is and remains the
Participant's responsibility and the Company (a) makes no representation or
undertakings regarding the treatment of any Tax-Related Items in connection with the
grant, vesting or settlement of the PSUs or the subsequent sale of any shares, and (b)
does not commit to structure the PSUs to reduce or eliminate the Participant's liability
for Tax-Related Items.
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Evolution Petroleum Corporation
Performance Share Unit Award Agreement
12. Compliance with Law. The issuance and transfer of shares of Common Stock in
connection with the PSUs shall be subject to compliance by the Company and the
Participant with all applicable requirements of federal and state securities laws and with all
applicable requirements of any stock exchange on which the Company’s shares of
Common Stock may be listed. No shares of Common Stock shall be issued or transferred
unless and until any then applicable requirements of state and federal laws and regulatory
agencies have been fully complied with to the satisfaction of the Company and its counsel.
13. Notices. Any notice required to be delivered to the Company under this
Agreement shall be in writing and addressed to the Company at the Company's principal
corporate offices. Any notice required to be delivered to the Participant under this
Agreement shall be in writing and addressed to the Participant at the Participant's address
as shown in the records of the Company. Either party may designate another address in
writing (or by such other method approved by the Company) from time to time.
14. Governing Law. This Agreement will be construed and interpreted in accordance
with the laws of the State of Nevada without regard to conflict of law principles.
15.
Interpretation. Any dispute regarding the interpretation of this Agreement shall
be submitted by the Participant or the Company to the Committee for review. The
resolution of such dispute by the Committee shall be final and binding on the Participant
and the Company.
16. PSUs Subject to Plan. This Agreement is subject to the Plan as approved by the
Company’s shareholders. The terms and provisions of the Plan as it may be amended from
time to time are hereby incorporated herein by reference. In the event of a conflict between
any term or provision contained herein and a term or provision of the Plan, the applicable
terms and provisions of the Plan will govern and prevail.
17. Successors and Assigns. The Company may assign any of its rights under this
Agreement. This Agreement will be binding upon and inure to the benefit of the
successors and assigns of the Company. Subject to the restrictions on transfer set forth
herein, this Agreement will be binding upon the Participant and the Participant's
beneficiaries, executors, administrators and the person(s) to whom the PSUs may be
transferred by will or the laws of descent or distribution.
18. Severability. The invalidity or unenforceability of any provision of the Plan or
this Agreement shall not affect the validity or enforceability of any other provision of the
Plan or this Agreement, and each provision of the Plan and this Agreement shall be
severable and enforceable to the extent permitted by law.
19. Discretionary Nature of Plan. The Plan is discretionary and may be amended,
cancelled or terminated by the Company at any time, in its discretion. The grant of the
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Evolution Petroleum Corporation
Performance Share Unit Award Agreement
PSUs in this Agreement does not create any contractual right or other right to receive any
PSUs or other Awards in the future. Future Awards, if any, will be at the sole discretion of
the Company. Any amendment, modification, or termination of the Plan shall not
constitute a change or impairment of the terms and conditions of the Participant's
employment with the Company.
20. Amendment. The Committee has the right to amend, alter, suspend, discontinue
or cancel the PSUs, prospectively or retroactively; provided, that, no such amendment shall
adversely affect the Participant's material rights under this Agreement without the
Participant's consent; further provided that the Committee may amend or modify this
Agreement to the extent that the Committee determines, in its sole discretion, that the terms
and conditions of the Award violate or may violate Code Section 409A; provided that, any
such amendment or modification of an Award made pursuant to this Section 20 shall
maintain, to the maximum extent practicable, the original intent of the applicable Award
provision without contravening the provisions of Code Section 409A.
The amendment or modification of any Award pursuant to this Section 20 shall be at the
Committee’s sole discretion and neither the Committee nor the Company shall be obligated
to amend or modify any Award or the Plan, nor shall the Company be liable for any adverse
tax or other consequences to a Participant resulting from such amendments or
modifications or the Committee’s failure to make any such amendments or modifications
for purposes of complying with Code Section 409A or for any other purpose. To the extent
the Committee amends or modifies an Award pursuant to this Section 20, the Participant
shall receive notification of any such changes to his or her Award and, unless the
Committee determines otherwise, the changes described in such notification shall be
deemed to amend the terms and conditions of the Award and this Agreement.
21. Section 162(m). All payments under this Agreement are intended to constitute
"qualified performance-based compensation" within the meaning of Section 162(m) of the
Code. This Award shall be construed and administered in a manner consistent with such
intent.
22. Section 409A. This Agreement is intended to comply with Code Section 409A or
an exemption thereunder and shall be construed and interpreted in a manner that is
consistent with the requirements for avoiding additional taxes or penalties under Code
Section 409A. Notwithstanding the foregoing, the Company makes no representations that
the payments and benefits provided under this Agreement comply with Code Section 409A
and in no event shall the Company be liable for all or any portion of any taxes, penalties,
interest or other expenses that may be incurred by the Participant on account of non-
compliance with Code Section 409A. Additionally, with respect to any Award subject to
Code Section 409A, if the Participant is a specified employee at the time of the
Participant’s termination, any payment(s) with respect to any Award subject to Code
Section 409A to which such Participant would otherwise be entitled by reason of such
termination shall be
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Evolution Petroleum Corporation
Performance Share Unit Award Agreement
made no sooner than the date that is the first day of the seventh month after the
Participant’s termination (or, if earlier, the date of the Participant’s death).
23. No Impact on Other Benefits. The value of the Participant's PSUs or
Performance Shares is not part of his or her normal or expected compensation for purposes
of calculating any severance, retirement, welfare, insurance or similar employee benefit.
24. Clawbacks. Participant shall be required to forfeit or reimburse the Company
with respect to the PSUs or Performance Shares granted under this Agreement and the Plan
to the extent required by any clawback or recoupment policy of the Company now in effect
or as may be adopted by the Company from time to time, including, without limiting the
foregoing, any clawback or recoupment policy adopted in accordance with Section 304 of
the Sarbanes-Oxley Act of 2002, Section 954 of the Dodd-Frank Wall Street Reform and
Consumer Protection Act, or as otherwise required by applicable law, rule or regulation.
25. Counterparts. This Agreement may be executed in counterparts, each of which
shall be deemed an original but all of which together will constitute one and the same
instrument. Counterpart signature pages to this Agreement transmitted by facsimile
transmission, by electronic mail in portable document format (.pdf), or by any other
electronic means intended to preserve the original graphic and pictorial appearance of a
document, will have the same effect as physical delivery of the paper document bearing an
original signature.
26. Acceptance. The Participant hereby acknowledges receipt of a copy of the Plan
and this Agreement. The Participant has read and understands the terms and provisions
thereof, and accepts the PSUs subject to all of the terms and conditions of the Plan and this
Agreement. The Participant acknowledges that he or she has been advised to consult a tax
advisor to understand the tax consequences of such vesting, settlement or disposition. By
acceptance of the performance share unit ward shares, the Participant accepts the terms of
this Agreement.
[SIGNATURE PAGE FOLLOWS]
IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the
date first above written.
EVOLUTION PETROLEUM
CORPORATION
By: ________________________
Name: Title:
Page 6 of 9
Evolution Petroleum Corporation
Performance Share Unit Award Agreement
PARTICIPANT
By: ________________________
Name:
Page 7 of 9
Evolution Petroleum Corporation
Performance Share Unit Award Agreement
EXHIBIT 1
Performance Period
The Performance Period shall commence on [DATE] and end on [DATE].
Performance Measures
The number of Performance Shares earned shall be determined by reference to the
Company’s [PERFORMANCE MEASURE]
[CONTINUED]
Determining Performance Shares Earned Pursuant to Performance Share
Units
Except as otherwise provided in the Plan or the Agreement, the number of
Performance Shares earned with respect to the Performance Period shall be determined by
the performance measure.
[FORMULA FOR DETERMINING NUMBER OF
PERFORMANCE SHARES THAT WILL BE EARNED].
Award Range
Depending on the Company’s achievement of the performance measure above, the
Participant may earn between zero percent (0%) and [MAXIMUM PERCENTAGE] of
the Target Award.
Page 8 of 9
List of Subsidiaries of Evolution Petroleum Corporation
Name of Subsidiary
Evolution Royalties, Inc.
Evolution Petroleum West, Inc.
NGS Sub Corp.
NGS Technologies, Inc.
Evolution Operating Co., Inc.
Evolution Petroleum OK, Inc.
Tertiaire Resources Company
ARKLA Petroleum, LLC (Subsidiary of NGS Sub. Corp.)
NGS Resources, LLC (Subsidiary of NGS Technologies, Inc.)
Exhibit 21.1
Jurisdiction of
Incorporation or
Organization
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Texas
Louisiana
Texas
CONSENT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
We consent to the incorporation by reference in the Registration Statements on Forms S-3 (No. 333-265430 and No. 333-
193899), Form S-3/A (No. 333-231412) and Forms S-8 (333-251233, 333-152136, 333-140182, 333-183746 and 333-
216098) of Evolution Petroleum Corporation (the “Company”), of our report dated September 13, 2023, relating to the
consolidated financial statements of the Company which report expresses an unqualified opinion, appearing in this Annual
Report on Form 10-K of the Company for the year ended June 30, 2023.
Exhibit 23.1
/s/ Moss Adams LLP
Houston, Texas
September 13, 2023
EXHIBIT 23.2
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
As independent petroleum engineers, we hereby consent to the references to our firm, in the context in which they appear, and
to the references to and the incorporation by reference of our reserves report dated August 10, 2023, included in the Annual
Report on Form 10-K of Evolution Petroleum Corporation (the "Company") for the fiscal year ended June 30, 2023, as well as
in the notes to the financial statements included therein. We also hereby consent to the incorporation by reference of the
references to our firm, in the context in which they appear, and to our reserves reports into the Registration Statements on Form
S-3 No. 333-265430, Form S-3/A No. 333-231412, Form S-3 No. 333-193899, Form S-8 Nos. 333-251233, 333-152136, 333-
140182, 333-183746, and 333-216098.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By:
/s/ Richard B. Talley, Jr.
Richard B. Talley, Jr., P.E.
Chief Executive Officer
Houston, Texas
September 13, 2023
EXHIBIT 23.3
DEGOLYER AND MACNAUGHTON
5001 SPRING VALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244
September 13, 2023
Evolution Petroleum Corporation
1155 Dairy Ashford Road, Suite 425
Houston, Texas 77079
Ladies & Gentlemen:
We hereby consent to the use of the name DeGolyer and MacNaughton, to references to DeGolyer
and MacNaughton, to the inclusion of our report of third party dated August 7, 2023, and to the inclusion of
information taken from our report entitled "Report as of June 30, 2023 on Reserves and Revenue of Certain
Properties with interests attributable to Evolution Petroleum Corporation" in the Annual Report on Form 10-
K of Evolution Petroleum Corporation for the year ended June 30, 2023. We further consent to the
incorporation by reference of information in the Form 10-K in the Evolution Petroleum Corporation
Registration Statements on Form S-8 (File Nos. 333-251233, 333-152136, 333-140182, 333-183746, and
333-216098), Form S-3 (File No. 333-265430), Form S-3/A (File No. 333-231412) and Form S-3 (File No.
333-193899).
Very truly yours,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
CERTIFICATION
EXHIBIT 31.1
I, Kelly W. Loyd, President and Chief Executive Officer (Principal Executive Officer) and Director, of Evolution Petroleum Corporation,
certify that:
1.
I have reviewed this annual report on Form 10-K of Evolution Petroleum Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading
with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all
material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in
Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this
report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons
performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Dated: September 13, 2023
/s/ KELLY W. LOYD
Kelly W. Loyd
President and Chief Executive Officer (Principal Executive Officer)
and Director
CERTIFICATION
EXHIBIT 31.2
I, Ryan Stash, Senior Vice President, Chief Financial Officer (Principal Financial Officer) and Treasurer of Evolution Petroleum
Corporation, certify that:
1.
I have reviewed this annual report on Form 10-K of Evolution Petroleum Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading
with respect to the period covered by this report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all
material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods
presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures
(as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in
Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under
our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is
made known to us by others within those entities, particularly during the period in which this report is being prepared;
b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be
designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our
conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this
report based on such evaluation; and
d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the
registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has
materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over
financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons
performing the equivalent functions):
a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting
which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial
information; and
b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the
registrant’s internal control over financial reporting.
Dated: September 13, 2023
/s/ RYAN STASH
Ryan Stash
Senior Vice President, Chief Financial Officer (Principal Financial
Officer) and Treasurer
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
EXHIBIT 32.1
The undersigned, Kelly W. Loyd, President and Chief Executive Officer (Principal Executive Officer) and Director of Evolution
Petroleum Corporation (the “Company”), certifies in connection with the filing with the Securities and Exchange Commission of the
Company’s Annual Report on Form 10-K for the year ended June 30, 2023 (the “Report”) pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to his knowledge, that:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
IN WITNESS WHEREOF, the undersigned has executed this certification as of September 13, 2023.
/s/ KELLY W. LOYD
Kelly W. Loyd
President and Chief Executive Officer (Principal Executive Officer)
and Director
A signed original of this written statement require d by Section 906 has been provided to Evolution Petroleum Corporation and
will be retained by Evolution Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
The foregoing certificate is being furnished to the Securities and Exchange Commission as an exhibit to this Form 10-K and shall not be
considered filed as part of the Form 10-K.
CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002
EXHIBIT 32.2
The undersigned, Ryan Stash, Senior Vice President, Chief Financial Officer (Principal Financial Officer) and Treasurer of
Evolution Petroleum Corporation (the “Company”), certifies in connection with the filing with the Securities and Exchange Commission
of the Company’s Annual Report on Form 10-K for the year ended June 30, 2023 (the “Report”) pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to his knowledge, that:
1.
2.
The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
The information contained in the Report fairly presents, in all material respects, the financial condition and results of
operations of the Company.
IN WITNESS WHEREOF, the undersigned has executed this certification as of September 13, 2023.
/s/ RYAN STASH
Ryan Stash
Senior Vice President, Chief Financial Officer (Principal Financial
Officer) and Treasurer
A signed original of this written statement required by Section 906 has been provided to Evolution Petroleum Corporation and
will be retained by Evolution Petroleum Corporation and furnished to the Securities and Exchange Commission or its staff upon request.
The foregoing certificate is being furnished to the Securities and Exchange Commission as an exhibit to this Form 10-K and shall not be
considered filed as part of the Form 10-K.
EXHIBIT 99.1
August 10, 2023
Mr. Kelly W. Loyd
Evolution Petroleum Corporation
1155 Dairy Ashford Street, Suite 425
Houston, Texas 77079
Dear Mr. Loyd:
In accordance with your request, we have estimated the proved reserves and future revenue, as of June 30, 2023,
to the Evolution Petroleum Corporation (Evolution) interest in certain oil and gas properties located in North Dakota
and Wyoming, referred to herein as the Jonah and Williston Assets. We completed our evaluation on or about the
date of this letter. It is our understanding that the proved reserves estimated in this report constitute approximately
39 percent of all proved reserves owned by Evolution. The estimates in this report have been prepared in
accordance with the definitions and regulations of the U.S. Securities and Exchange Commission (SEC) and, with
the exception of the exclusion of future income taxes, conform to the FASB Accounting Standards Codification Topic
932, Extractive Activities—Oil and Gas. Definitions are presented immediately following this letter. This report has
been prepared for Evolution's use in filing with the SEC; in our opinion the assumptions, data, methods, and
procedures used in the preparation of this report are appropriate for such purpose.
We estimate the net reserves and future net revenue to the Evolution interest in the Jonah and Williston Assets, as
of June 30, 2023, to be:
Category
Oil
(MBBL)
Net Reserves
NGL
(MBBL)
Gas
(MMCF)
Proved Developed Producing
Proved Developed Non-Producing
Proved Undeveloped
1,853.7
122.2
2,588.8
709.0
8.5
585.4
35,937.7
29.9
2,430.6
Future Net Revenue (M$)
Total
227,709.2
3,479.5
84,107.9
Present Worth
at 10%
137,105.1
1,057.2
26,979.3
Total Proved
4,564.8
1,302.9
38,398.1
315,296.6
165,141.7
Totals may not add because of rounding.
The oil volumes shown include crude oil and condensate. Oil and natural gas liquids (NGL) volumes are expressed
in thousands of barrels (MBBL); a barrel is equivalent to 42 United States gallons. Gas volumes are expressed in
millions of cubic feet (MMCF) at standard temperature and pressure bases.
Reserves categorization conveys the relative degree of certainty; reserves subcategorization is based on
development and production status. As requested, probable and possible reserves that exist for these properties
have not been included. The estimates of reserves and future revenue included herein have not been adjusted for
risk. This report does not include any value that could be attributed to interests in undeveloped acreage beyond
those tracts for which undeveloped reserves have been estimated.
Gross revenue is Evolution's share of the gross (100 percent) revenue from the properties prior to any deductions.
Future net revenue is after deductions for Evolution's share of production taxes, ad valorem taxes, capital costs,
abandonment costs, and operating expenses but before consideration of any income taxes. The future net revenue
has been discounted at an annual rate of 10 percent to determine its present worth, which is shown to indicate the
effect of time on the value of money. Future net revenue presented in this report, whether discounted or
undiscounted, should not be construed as being the fair market value of the properties.
Prices used in this report are based on the 12-month unweighted arithmetic average of the first-day-of-the-month
price for each month in the period July 2022 through June 2023. For oil and NGL volumes, the average West Texas
Intermediate spot price of $83.23 per barrel is adjusted for quality, transportation fees, and market differentials. For
gas volumes, the average Henry Hub spot price of $4.78 per MMBTU is adjusted for energy content, transportation
fees, and market differentials. All prices are held constant throughout the lives of the properties. The average
adjusted product prices weighted by production over the remaining lives of the properties are $81.76 per barrel of
oil, $30.77 per barrel of NGL, and $7.51 per MCF of gas.
Operating costs used in this report are based on operating expense records of Evolution. These costs include the
per-well overhead expenses allowed under joint operating agreements along with estimates of costs to be incurred
at and below the district and field levels. Operating costs have been divided into per-well costs and per-unit-of-
production costs. Since all properties are nonoperated, headquarters general and administrative overhead
expenses are not included. Operating costs are not escalated for inflation.
Capital costs used in this report were provided by Evolution and are based on authorizations for expenditure and
actual costs from recent activity. Capital costs are included as required for workovers, new development wells, and
production equipment. Based on our understanding of future development plans, a review of the records provided
to us, and our knowledge of similar properties, we regard these estimated capital costs to be reasonable.
Abandonment costs used in this report are Evolution's estimates of the costs to abandon the wells and production
facilities, net of any salvage value. Capital costs and abandonment costs are not escalated for inflation.
For the purposes of this report, we did not perform any field inspection of the properties, nor did we examine the
mechanical operation or condition of the wells and facilities. We have not investigated possible environmental
liability related to the properties; therefore, our estimates do not include any costs due to such possible liability.
We have made no investigation of potential volume and value imbalances resulting from overdelivery or
underdelivery to the Evolution interest. Therefore, our estimates of reserves and future revenue do not include
adjustments for the settlement of any such imbalances; our projections are based on Evolution receiving its net
revenue interest share of estimated future gross production. Additionally, we have made no specific investigation of
any firm transportation contracts that may be in place for these properties; our estimates of future revenue include
the effects of such contracts only to the extent that the associated fees are accounted for in the historical field- and
lease-level accounting statements.
The reserves shown in this report are estimates only and should not be construed as exact quantities. Proved
reserves are those quantities of oil and gas which, by analysis of engineering and geoscience data, can be
estimated with reasonable certainty to be economically producible; probable and possible reserves are those
additional reserves which are sequentially less certain to be recovered than proved reserves. Estimates of reserves
may increase or decrease as a result of market conditions, future operations, changes in regulations, or actual
reservoir performance. In addition to the primary economic assumptions discussed herein, our estimates are based
on certain assumptions including, but not limited to, that the properties will be developed consistent with current
development plans as provided to us by Evolution, that the properties will be operated in a prudent manner, that no
governmental regulations or controls will be put in place that would impact the ability of the interest owner to recover
the reserves, and that our projections of future production will prove consistent with actual performance. If the
reserves are recovered, the revenues therefrom and the costs related thereto could be more or less than the
estimated amounts. Because of governmental policies and uncertainties of supply and demand, the sales rates,
prices received for the reserves, and costs incurred in recovering such reserves may vary from assumptions made
while preparing this report.
For the purposes of this report, we used technical and economic data including, but not limited to, well test data,
production data, historical price and cost information, and property ownership interests. The reserves in this report
have been estimated using deterministic methods; these estimates have been prepared in accordance with the
Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the
Society of Petroleum Engineers (SPE Standards). We used standard engineering and geoscience methods, or a
combination of methods, including performance analysis and analogy, that we considered to be appropriate and
necessary to categorize and estimate reserves in accordance with SEC definitions and regulations. As in all
aspects of oil and gas evaluation, there are uncertainties inherent in the interpretation of engineering and
geoscience data; therefore, our conclusions necessarily represent only informed professional judgment.
The data used in our estimates were obtained from Evolution, public data sources, and the nonconfidential files of
Netherland, Sewell & Associates, Inc. (NSAI) and were accepted as accurate. Supporting work data are on file in
our office. We have not examined the titles to the properties or independently confirmed the actual degree or type
of interest owned. The technical person primarily responsible for preparing the estimates presented herein meets
the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the SPE
Standards. Matthew D. Pankey, a Licensed Professional Engineer in the State of Texas, has been practicing
consulting petroleum engineering at NSAI since 2019 and has over 6 years of prior industry experience. We are
independent petroleum engineers, geologists, geophysicists, and petrophysicists; we do not own an interest in these
properties nor are we employed on a contingent basis.
Sincerely,
NETHERLAND, SEWELL & ASSOCIATES, INC.
Texas Registered Engineering Firm F-2699
/s/ Richard B. Talley, Jr.
Richard B. Talley, Jr., P.E.
Chief Executive Officer
/s/ Matthew D. Pankey
Matthew D. Pankey, P.E. 142931
Petroleum Engineer
Date Signed: August 10, 2023
By:
By:
MDP:MJM
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
The following definitions are set forth in U.S. Securities and Exchange Commission (SEC) Regulation S-X Section 210.4-10(a).
Also included is supplemental information from (1) the 2018 Petroleum Resources Management System approved by the
Society of Petroleum Engineers, (2) the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas,
and (3) the SEC's Compliance and Disclosure Interpretations.
(1) Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses
and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is
purchased in fee, brokers' fees, recording fees, legal costs, and other costs incurred in acquiring properties.
(2) Analogous reservoir. Analogous reservoirs, as used in resources assessments, have similar rock and fluid properties,
reservoir conditions (depth, temperature, and pressure) and drive mechanisms, but are typically at a more advanced stage of
development than the reservoir of interest and thus may provide concepts to assist in the interpretation of more limited data and
estimation of recovery. When used to support proved reserves, an "analogous reservoir" refers to a reservoir that shares the
following characteristics with the reservoir of interest:
(i) Same geological formation (but not necessarily in pressure communication with the reservoir of interest);
(ii) Same environment of deposition;
(iii) Similar geological structure; and
(iv) Same drive mechanism.
Instruction to paragraph (a)(2): Reservoir properties must, in the aggregate, be no more favorable in the analog than in the
reservoir of interest.
(3) Bitumen. Bitumen, sometimes referred to as natural bitumen, is petroleum in a solid or semi-solid state in natural deposits
with a viscosity greater than 10,000 centipoise measured at original temperature in the deposit and atmospheric pressure, on a
gas free basis. In its natural state it usually contains sulfur, metals, and other non-hydrocarbons.
(4) Condensate. Condensate is a mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and
pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.
(5) Deterministic estimate. The method of estimating reserves or resources is called deterministic when a single value for each
parameter (from the geoscience, engineering, or economic data) in the reserves calculation is used in the reserves estimation
procedure.
(6) Developed oil and gas reserves. Developed oil and gas reserves are reserves of any category that can be expected to be
recovered:
(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is
relatively minor compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the
extraction is by means not involving a well.
Supplemental definitions from the 2018 Petroleum Resources Management System:
Developed Producing Reserves – Expected quantities to be recovered from completion intervals that are open and producing
at the effective date of the estimate. Improved recovery Reserves are considered producing only after the improved recovery
project is in operation.
Developed Non-Producing Reserves – Shut-in and behind-pipe Reserves. Shut-in Reserves are expected to be recovered
from (1) completion intervals that are open at the time of the estimate but which have not yet started producing, (2) wells which
were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons.
Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work
or future re-completion before start of production with minor cost to access these reserves. In all cases, production can be
initiated or restored with relatively low expenditure compared to the cost of drilling a new well.
(7) Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating,
gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating
costs of support equipment and facilities and other costs of development activities, are costs incurred to:
(i) Gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining
specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and
power lines, to the extent necessary in developing the proved reserves.
(ii) Drill and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of
platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly.
(iii) Acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds,
measuring devices, and production storage tanks, natural gas cycling and processing plants, and central utility and
waste disposal systems.
Definitions - Page 1 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(iv) Provide improved recovery systems.
(8) Development project. A development project is the means by which petroleum resources are brought to the status of
economically producible. As examples, the development of a single reservoir or field, an incremental development in a
producing field, or the integrated development of a group of several fields and associated facilities with a common ownership
may constitute a development project.
(9) Development well. A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known
to be productive.
(10) Economically producible. The term economically producible, as it relates to a resource, means a resource which generates
revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. The value of the products that generate
revenue shall be determined at the terminal point of oil and gas producing activities as defined in paragraph (a)(16) of this
section.
(11) Estimated ultimate recovery (EUR). Estimated ultimate recovery is the sum of reserves remaining as of a given date and
cumulative production as of that date.
(12) Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are
considered to have prospects of containing oil and gas reserves, including costs of drilling exploratory wells and exploratory-type
stratigraphic test wells. Exploration costs may be incurred both before acquiring the related property (sometimes referred to in
part as prospecting costs) and after acquiring the property. Principal types of exploration costs, which include depreciation and
applicable operating costs of support equipment and facilities and other costs of exploration activities, are:
(i) Costs of topographical, geographical and geophysical studies, rights of access to properties to conduct those studies,
and salaries and other expenses of geologists, geophysical crews, and others conducting those studies. Collectively,
these are sometimes referred to as geological and geophysical or "G&G" costs.
(ii) Costs of carrying and retaining undeveloped properties, such as delay rentals, ad valorem taxes on properties, legal
costs for title defense, and the maintenance of land and lease records.
(iii) Dry hole contributions and bottom hole contributions.
(iv) Costs of drilling and equipping exploratory wells.
(v) Costs of drilling exploratory-type stratigraphic test wells.
(13) Exploratory well. An exploratory well is a well drilled to find a new field or to find a new reservoir in a field previously found
to be productive of oil or gas in another reservoir. Generally, an exploratory well is any well that is not a development well, an
extension well, a service well, or a stratigraphic test well as those items are defined in this section.
(14) Extension well. An extension well is a well drilled to extend the limits of a known reservoir.
(15) Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual
geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field which are separated
vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by
being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms "structural
feature" and "stratigraphic condition" are intended to identify localized geological features as opposed to the broader terms of
basins, trends, provinces, plays, areas-of-interest, etc.
(16) Oil and gas producing activities.
(i) Oil and gas producing activities include:
(A) The search for crude oil, including condensate and natural gas liquids, or natural gas ("oil and gas") in their natural
states and original locations;
(B) The acquisition of property rights or properties for the purpose of further exploration or for the purpose of removing
the oil or gas from such properties;
(C) The construction, drilling, and production activities necessary to retrieve oil and gas from their natural reservoirs,
including the acquisition, construction, installation, and maintenance of field gathering and storage systems, such
as:
(1) Lifting the oil and gas to the surface; and
(2) Gathering, treating, and field processing (as in the case of processing gas to extract liquid hydrocarbons); and
(D) Extraction of saleable hydrocarbons, in the solid, liquid, or gaseous state, from oil sands, shale, coalbeds, or other
nonrenewable natural resources which are intended to be upgraded into synthetic oil or gas, and activities
undertaken with a view to such extraction.
Instruction 1 to paragraph (a)(16)(i): The oil and gas production function shall be regarded as ending at a "terminal point",
which is the outlet valve on the lease or field storage tank. If unusual physical or operational circumstances exist, it may be
appropriate to regard the terminal point for the production function as:
Definitions - Page 2 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
a. The first point at which oil, gas, or gas liquids, natural or synthetic, are delivered to a main pipeline, a common carrier, a
b.
refinery, or a marine terminal; and
In the case of natural resources that are intended to be upgraded into synthetic oil or gas, if those natural resources are
delivered to a purchaser prior to upgrading, the first point at which the natural resources are delivered to a main
pipeline, a common carrier, a refinery, a marine terminal, or a facility which upgrades such natural resources into
synthetic oil or gas.
Instruction 2 to paragraph (a)(16)(i): For purposes of this paragraph (a)(16), the term saleable hydrocarbons means
hydrocarbons that are saleable in the state in which the hydrocarbons are delivered.
(ii) Oil and gas producing activities do not include:
(A) Transporting, refining, or marketing oil and gas;
(B) Processing of produced oil, gas, or natural resources that can be upgraded into synthetic oil or gas by a registrant
that does not have the legal right to produce or a revenue interest in such production;
(C) Activities relating to the production of natural resources other than oil, gas, or natural resources from which
synthetic oil and gas can be extracted; or
(D) Production of geothermal steam.
(17) Possible reserves. Possible reserves are those additional reserves that are less certain to be recovered than probable
reserves.
(i) When deterministic methods are used, the total quantities ultimately recovered from a project have a low probability of
exceeding proved plus probable plus possible reserves. When probabilistic methods are used, there should be at least
a 10% probability that the total quantities ultimately recovered will equal or exceed the proved plus probable plus
possible reserves estimates.
(ii) Possible reserves may be assigned to areas of a reservoir adjacent to probable reserves where data control and
interpretations of available data are progressively less certain. Frequently, this will be in areas where geoscience and
engineering data are unable to define clearly the area and vertical limits of commercial production from the reservoir by
a defined project.
(iii) Possible reserves also include incremental quantities associated with a greater percentage recovery of the
hydrocarbons in place than the recovery quantities assumed for probable reserves.
(iv) The proved plus probable and proved plus probable plus possible reserves estimates must be based on reasonable
alternative technical and commercial interpretations within the reservoir or subject project that are clearly documented,
including comparisons to results in successful similar projects.
(v) Possible reserves may be assigned where geoscience and engineering data identify directly adjacent portions of a
reservoir within the same accumulation that may be separated from proved areas by faults with displacement less than
formation thickness or other geological discontinuities and that have not been penetrated by a wellbore, and the
registrant believes that such adjacent portions are in communication with the known (proved) reservoir. Possible
reserves may be assigned to areas that are structurally higher or lower than the proved area if these areas are in
communication with the proved reservoir.
(vi) Pursuant to paragraph (a)(22)(iii) of this section, where direct observation has defined a highest known oil (HKO)
elevation and the potential exists for an associated gas cap, proved oil reserves should be assigned in the structurally
higher portions of the reservoir above the HKO only if the higher contact can be established with reasonable certainty
through reliable technology. Portions of the reservoir that do not meet this reasonable certainty criterion may be
assigned as probable and possible oil or gas based on reservoir fluid properties and pressure gradient interpretations.
(18) Probable reserves. Probable reserves are those additional reserves that are less certain to be recovered than proved
reserves but which, together with proved reserves, are as likely as not to be recovered.
(i) When deterministic methods are used, it is as likely as not that actual remaining quantities recovered will exceed the
sum of estimated proved plus probable reserves. When probabilistic methods are used, there should be at least a 50%
probability that the actual quantities recovered will equal or exceed the proved plus probable reserves estimates.
(ii) Probable reserves may be assigned to areas of a reservoir adjacent to proved reserves where data control or
interpretations of available data are less certain, even if the interpreted reservoir continuity of structure or productivity
does not meet the reasonable certainty criterion. Probable reserves may be assigned to areas that are structurally
higher than the proved area if these areas are in communication with the proved reservoir.
(iii) Probable reserves estimates also include potential incremental quantities associated with a greater percentage recovery
of the hydrocarbons in place than assumed for proved reserves.
(iv) See also guidelines in paragraphs (a)(17)(iv) and (a)(17)(vi) of this section.
Definitions - Page 3 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(19) Probabilistic estimate. The method of estimation of reserves or resources is called probabilistic when the full range of values
that could reasonably occur for each unknown parameter (from the geoscience and engineering data) is used to generate a full
range of possible outcomes and their associated probabilities of occurrence.
(20) Production costs.
(i) Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable
operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related
equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs
(sometimes called lifting costs) are:
(A) Costs of labor to operate the wells and related equipment and facilities.
(B) Repairs and maintenance.
(C) Materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and
facilities.
(D) Property taxes and insurance applicable to proved properties and wells and related equipment and facilities.
(E) Severance taxes.
(ii) Some support equipment or facilities may serve two or more oil and gas producing activities and may also serve
transportation, refining, and marketing activities. To the extent that the support equipment and facilities are used in oil
and gas producing activities, their depreciation and applicable operating costs become exploration, development or
production costs, as appropriate. Depreciation, depletion, and amortization of capitalized acquisition, exploration, and
development costs are not production costs but also become part of the cost of oil and gas produced along with
production (lifting) costs identified above.
(21) Proved area. The part of a property to which proved reserves have been specifically attributed.
(22) Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of
geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date
forward, from known reservoirs, and under existing economic conditions, 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.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it
and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii)
In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons
(LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology
establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential
exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir
only if geoscience, engineering, or performance data and reliable technology establish the higher contact with
reasonable certainty.
(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not
limited to, fluid injection) are included in the proved classification when:
(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the
reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the
project or program was based; and
(B) The project has been approved for development by all necessary parties and entities, including governmental
entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be
determined. The price shall be the average price during the 12-month period prior to the ending date of the period
covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each
month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon
future conditions.
(23) Proved properties. Properties with proved reserves.
Definitions - Page 4 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(24) Reasonable certainty. If deterministic methods are used, reasonable certainty means a high degree of confidence that the
quantities will be recovered. If probabilistic methods are used, there should be at least a 90% probability that the quantities
actually recovered will equal or exceed the estimate. A high degree of confidence exists if the quantity is much more likely to be
achieved than not, and, as changes due to increased availability of geoscience (geological, geophysical, and geochemical),
engineering, and economic data are made to estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more
likely to increase or remain constant than to decrease.
(25) Reliable technology. Reliable technology is a grouping of one or more technologies (including computational methods) that
has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the
formation being evaluated or in an analogous formation.
(26) Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be
economically producible, as of a given date, by application of development projects to known accumulations. In addition, there
must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the
production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to
implement the project.
Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults
until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that
are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low
reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from
undiscovered accumulations).
Excerpted from the FASB Accounting Standards Codification Topic 932, Extractive Activities—Oil and Gas:
932-235-50-30 A standardized measure of discounted future net cash flows relating to an entity's interests in both of the
following shall be disclosed as of the end of the year:
a. Proved oil and gas reserves (see paragraphs 932-235-50-3 through 50-11B)
b. Oil and gas subject to purchase under long-term supply, purchase, or similar agreements and contracts in which the
entity participates in the operation of the properties on which the oil or gas is located or otherwise serves as the producer
of those reserves (see paragraph 932-235-50-7).
The standardized measure of discounted future net cash flows relating to those two types of interests in reserves may be
combined for reporting purposes.
932-235-50-31 All of the following information shall be disclosed in the aggregate and for each geographic area for which
reserve quantities are disclosed in accordance with paragraphs 932-235-50-3 through 50-11B:
a. Future cash inflows. These shall be computed by applying prices used in estimating the entity's proved oil and gas
reserves to the year-end quantities of those reserves. Future price changes shall be considered only to the extent
provided by contractual arrangements in existence at year-end.
b. Future development and production costs. These costs shall be computed by estimating the expenditures to be incurred
in developing and producing the proved oil and gas reserves at the end of the year, based on year-end costs and
assuming continuation of existing economic conditions. If estimated development expenditures are significant, they shall
be presented separately from estimated production costs.
c. Future income tax expenses. These expenses shall be computed by applying the appropriate year-end statutory tax
rates, with consideration of future tax rates already legislated, to the future pretax net cash flows relating to the entity's
proved oil and gas reserves, less the tax basis of the properties involved. The future income tax expenses shall give
effect to tax deductions and tax credits and allowances relating to the entity's proved oil and gas reserves.
d. Future net cash flows. These amounts are the result of subtracting future development and production costs and future
income tax expenses from future cash inflows.
e. Discount. This amount shall be derived from using a discount rate of 10 percent a year to reflect the timing of the future
net cash flows relating to proved oil and gas reserves.
f. Standardized measure of discounted future net cash flows. This amount is the future net cash flows less the computed
discount.
(27) Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or gas
that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
(28) Resources. Resources are quantities of oil and gas estimated to exist in naturally occurring accumulations. A portion of the
resources may be estimated to be recoverable, and another portion may be considered to be unrecoverable. Resources include
both discovered and undiscovered accumulations.
(29) Service well. A well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of
service wells include gas injection, water injection, steam injection, air injection, salt-water disposal, water supply for injection,
observation, or injection for in-situ combustion.
Definitions - Page 5 of 6
DEFINITIONS OF OIL AND GAS RESERVES
Adapted from U.S. Securities and Exchange Commission Regulation S-X Section 210.4-10(a)
(30) Stratigraphic test well. A stratigraphic test well is a drilling effort, geologically directed, to obtain information pertaining to a
specific geologic condition. Such wells customarily are drilled without the intent of being completed for hydrocarbon production.
The classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon
exploration. Stratigraphic tests are classified as "exploratory type" if not drilled in a known area or "development type" if drilled in
a known area.
(31) Undeveloped oil and gas reserves. Undeveloped oil and gas reserves are 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.
(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.
From the SEC's Compliance and Disclosure Interpretations (October 26, 2009):
Although several types of projects — such as constructing offshore platforms and development in urban areas, remote
locations or environmentally sensitive locations — by their nature customarily take a longer time to develop and therefore often
do justify longer time periods, this determination must always take into consideration all of the facts and circumstances. No
particular type of project per se justifies a longer time period, and any extension beyond five years should be the exception,
and not the rule.
Factors that a company should consider in determining whether or not circumstances justify recognizing reserves even though
development may extend past five years include, but are not limited to, the following:
● The company's level of ongoing significant development activities in the area to be developed (for example, drilling only
the minimum number of wells necessary to maintain the lease generally would not constitute significant development
activities);
● The company's historical record at completing development of comparable long-term projects;
●
The amount of time in which the company has maintained the leases, or booked the reserves, without significant
development activities;
● The extent to which the company has followed a previously adopted development plan (for example, if a company has
changed its development plan several times without taking significant steps to implement any of those plans, recognizing
proved undeveloped reserves typically would not be appropriate); and
● The extent to which delays in development are caused by external factors related to the physical operating environment
(for example, restrictions on development on Federal lands, but not obtaining government permits), rather than by
internal factors (for example, shifting resources to develop properties with higher priority).
(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, as defined in paragraph (a)(2) of this
section, or by other evidence using reliable technology establishing reasonable certainty.
(32) Unproved properties. Properties with no proved reserves.
Definitions - Page 6 of 6
D e G o l y e r a n d M a c N a u g h t o n
5001 Spring Valley Road
Suite 800 East
Dallas, Texas 75244
August 7, 2023
EXHIBIT 99.2
Evolution Petroleum Corporation
1155 Dairy Ashford Rd., Suite 425
Houston, Texas 77079
Ladies and Gentlemen:
Pursuant to your request, this report of third party presents an independent evaluation, as of
June 30, 2023, of the extent and value of the estimated net proved oil, condensate, natural gas
liquids (NGL), and gas reserves of the Delhi field in Louisiana, the net proved developed producing
condensate, NGL, and gas reserves of the Barnett Shale in Texas, and the net proved developed
producing oil reserves of the Hamilton Dome field in Wyoming in which Evolution Petroleum
Corporation and its subsidiaries (collectively referred to herein as Evolution) have represented they
hold an interest. The properties evaluated herein consist of working and royalty interests. This
evaluation was completed on August 7, 2023. Evolution has represented that these properties
account for 60.65 percent on a net equivalent barrel basis of Evolution’s net proved reserves as of
June 30, 2023. The net proved reserves estimates have been prepared in accordance with the
reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities
and Exchange Commission (SEC). This report was prepared in accordance with the guidelines
specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC
filings by Evolution.
Reserves estimates included herein are expressed as net reserves. Gross reserves are
defined as the total estimated petroleum remaining to be produced from these properties after June
30, 2023. Net reserves are defined as that portion of the gross reserves attributable to the interests
held by Evolution after deducting all interests held by others.
Values for proved reserves in this report are expressed in terms of future gross revenue,
future net revenue, and present worth. Future gross revenue is defined as that revenue which will
accrue to the evaluated interests from the production and sale
2
DeGolyer and MacNaughton
of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad
valorem taxes, operating expenses, capital costs, and abandonment costs from future gross revenue.
Operating expenses include field operating expenses, carbon dioxide purchase expenses,
transportation and processing expenses, compression charges, and overhead that directly relates to
production activities. Capital costs include drilling and completion costs, facilities costs, and field
maintenance costs. Abandonment costs are represented by Evolution to be inclusive of those costs
associated with the removal of equipment, plugging of wells, and reclamation and restoration
associated with abandonment. At the request of Evolution, future income taxes were not taken into
account in the preparation of these estimates. Present worth is defined as future net revenue
discounted at a discount rate of 10 percent per year compounded at mid-year on an annual basis
over the expected period of realization. Present worth should not be construed as fair market value
because no consideration was given to additional factors that influence the prices at which
properties are bought and sold.
Estimates of reserves and revenue should be regarded only as estimates that may change as
further production history and additional information become available. Not only are such estimates
based on that information which is currently available, but such estimates are also subject to the
uncertainties inherent in the application of judgmental factors in interpreting such information.
Information used in the preparation of this report was obtained from Evolution and from
public sources. In the preparation of this report we have relied, without independent verification,
upon such information furnished by Evolution with respect to the property interests being
evaluated, production from such properties, current costs of operation and development, current
prices for production, agreements relating to current and future operations and sale of production,
and various other information and data that were accepted as represented. A field examination was
not considered necessary for the purposes of this report.
Definition of Reserves
Petroleum reserves included in this report are classified by degree of proof as proved. Only
proved reserves have been evaluated for this report. Reserves classifications used in this report are
in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the
SEC. Reserves are judged to be economically producible in future years from known reservoirs
under existing economic and operating conditions and assuming continuation of current regulatory
practices using conventional production methods and equipment. In the analyses of production-
decline curves, reserves were estimated only to the limit of economic rates of production under
existing economic and operating conditions using
DeGolyer and MacNaughton
prices and costs consistent with the effective date of this report, including consideration of changes
in existing prices provided only by contractual arrangements but not including escalations based
upon future conditions. The petroleum reserves are classified as follows:
3
Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil
and gas, which, by analysis of geoscience and engineering data, can be estimated
with reasonable certainty to be economically producible—from a given date
forward, from known reservoirs, and under existing economic conditions, 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.
(i) The area of the reservoir considered as proved includes:
(A) The area identified by drilling and limited by fluid contacts, if any, and
(B) Adjacent undrilled portions of the reservoir that can, with reasonable
certainty, be judged to be continuous with it and to contain economically
producible oil or gas on the basis of available geoscience and engineering
data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir
are limited by the lowest known hydrocarbons (LKH) as seen in a well
penetration unless geoscience, engineering, or performance data and
reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest
known oil (HKO) elevation and the potential exists for an associated gas
cap, proved oil reserves may be assigned in the structurally higher portions
of the reservoir only if geoscience, engineering, or performance data and
reliable technology establish the higher contact with reasonable certainty.
(iv) Reserves which can be produced economically through application of
improved recovery techniques (including, but not limited to, fluid
injection) are included in the proved classification when:
DeGolyer and MacNaughton
4
(A) Successful testing by a pilot project in an area of the reservoir with
properties no more favorable than in the reservoir as a whole, the operation
of an installed program in the reservoir or an analogous reservoir, or other
evidence using reliable technology establishes the reasonable certainty of
the engineering analysis on which the project or program was based; and
(B) The project has been approved for development by all necessary parties
and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which
economic producibility from a reservoir is to be determined. The price
shall be the average price during the 12-month period prior to the ending
date of the period covered by the report, determined as an unweighted
arithmetic average of the first-day-of-the-month price for each month
within such period, unless prices are defined by contractual arrangements,
excluding escalations based upon future conditions.
Developed oil and gas reserves – Developed oil and gas reserves are reserves of
any category that can be expected to be recovered:
(i) Through existing wells with existing equipment and operating methods
or in which the cost of the required equipment is relatively minor
compared to the cost of a new well; and
(ii) Through installed extraction equipment and infrastructure operational
at the time of the reserves estimate if the extraction is by means not
involving a well.
Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are 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.
(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.
DeGolyer and MacNaughton
5
(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, as defined in [section 210.4–10 (a) Definitions], or by
other evidence using reliable technology establishing reasonable certainty.
Methodology and Procedures
Estimates of reserves were prepared by the use of appropriate geologic, petroleum
engineering, and evaluation principles and techniques that are in accordance with the reserves
definition of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally
recognized by the petroleum industry as presented in the publication of the Society of Petroleum
Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in
Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The
method or combination of methods used in the analysis was tempered by experience with similar
reservoirs, stage of development, quality and completeness of basic data, and production history.
Based on the current stage of field development, production performance, the development
plans provided by Evolution, and analysis of areas offsetting existing wells with test or production
data, reserves were classified as proved.
The proved undeveloped reserves estimates were based on opportunities identified in the
plan of development provided by Evolution.
Evolution has represented that its senior management is committed to the development plan
provided by Evolution and that Evolution has the financial capability to execute the development
plan, including the drilling and completion of wells and the installation of equipment and facilities.
When applicable, the volumetric method was used to estimate the original oil in place
(OOIP). Structure maps were prepared to delineate each reservoir, and isopach maps were
6
DeGolyer and MacNaughton
constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and
other available data were used to prepare these maps as well as to estimate representative values for
porosity and water saturation.
Estimates of ultimate recovery were obtained after applying recovery factors to OOIP.
These recovery factors were based on consideration of the type of energy inherent in the reservoirs,
analyses of the petroleum, the structural positions of the properties, and the production histories.
Certain properties evaluated herein are produced using enhanced oil recovery methods involving
continuous carbon dioxide flooding operations. Therefore, carbon dioxide versus oil ratios and
carbon dioxide injection volumes were analyzed and projected and were used in the estimation of
reserves when applicable.
For depletion-type reservoirs or those whose performance disclosed a reliable decline in
producing-rate trends or other diagnostic characteristics, reserves were estimated by the application
of appropriate decline curves or other performance relationships. In the analyses of production-
decline curves, reserves were estimated only to the limits of economic production as defined under
the Definition of Reserves heading of this report.
For the evaluation of unconventional reservoirs, a performance-based methodology
integrating the appropriate geology and petroleum engineering data was utilized for this report.
Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve
analysis, and (3) model-based analysis (if necessary, based on availability of data). Production
diagnostics include data quality control, identification of flow regimes, and characteristic well
performance behavior.
Characteristic rate-decline profiles from diagnostic interpretation were translated to
modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an
exponential decline. Based on the availability of data, model-based analysis may be integrated to
evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on
well performance, and complex situations sourced by the nature of unconventional reservoirs.
In certain cases, reserves were estimated by incorporating elements of analogy with similar
wells or reservoirs for which more complete data were available.
Data provided by Evolution from wells drilled through June 30, 2023, and made available
for this evaluation were used to prepare the reserves estimates herein. These reserves estimates
were based on consideration of monthly production data available for certain properties only
through March 31, 2023. Estimated cumulative production, as of June
7
DeGolyer and MacNaughton
30, 2023, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This
required that production be estimated for up to 3 months.
Oil and condensate reserves estimated herein are to be recovered by normal field
separation. NGL reserves estimated herein include pentanes and heavier fractions (C5+) and
liquefied petroleum gas (LPG), which consists primarily of propane and butane fractions and are
the result of low-temperature plant processing. Oil, condensate, and NGL reserves included in this
report are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United
States gallons. For reporting purposes, oil and condensate reserves have been estimated separately
and are presented herein as a summed quantity.
Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total
gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel
usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated
herein are reported as sales gas. Gas quantities are expressed at a temperature base of 60 degrees
Fahrenheit (°F) and at the pressure base of the state in which the quantities are located. Gas
quantities included in this report are expressed in millions of cubic feet (MMcf).
Gas quantities are identified by the type of reservoir from which the gas will be produced.
Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir.
Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir
conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil
at initial reservoir conditions. Gas quantities estimated herein include both associated and
nonassociated gas.
Primary Economic Assumptions
Revenue values in this report were estimated using initial prices, expenses, and costs
provided by Evolution. Future prices were estimated using guidelines established by the SEC and
the Financial Accounting Standards Board (FASB). The following economic assumptions were
used for estimating the revenue values reported herein:
Oil, Condensate, and NGL Prices
Evolution has represented that the oil, condensate, and NGL prices were
based on a reference 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,
DeGolyer and MacNaughton
8
unless prices are defined by contractual agreements. The oil, condensate,
and NGL prices were calculated using differentials furnished by Evolution
to the West Texas Intermediate (WTI) reference price of $83.23 per barrel
and held constant thereafter. The volume-weighted average prices
attributable to the estimated proved reserves over the lives of the properties
were $76.44 per barrel of oil and condensate and $34.55 per barrel of
NGL.
Gas Prices
Evolution has represented that the gas prices were based on a reference
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, unless prices are defined by contractual
agreements. Evolution supplied differentials to the Henry Hub gas
reference price of $4.78 per million Btu. The prices were held constant
thereafter. Btu factors were provided by Evolution and used to convert
prices from dollars per million Btu to dollars per thousand cubic feet. The
volume-weighted average price attributable to the estimated proved
reserves over the lives of the properties was $4.731 per thousand cubic feet
of gas.
Production and Ad Valorem Taxes
Production taxes were calculated using rates provided by Evolution,
including, where appropriate, abatements for enhanced recovery programs.
Ad valorem taxes were calculated using rates provided by Evolution based
on recent payments.
Evolution has represented that the Delhi carbon dioxide flood has been
qualified as a tertiary recovery project and that no oil production taxes will
be charged until certain investment and interest expenses have been paid
out from the project revenue. Oil production taxes then revert to a 12.5-
percent rate, which rate is held constant until average oil production per
well drops below 25 barrels per day, and then reduced to 6.25 percent
thereafter. Payout is not expected to occur prior to depletion, so no oil
production taxes are included herein for the Delhi field.
DeGolyer and MacNaughton
Operating Expenses, Capital Costs, and Abandonment Costs
9
Estimates of operating expenses, provided by Evolution and based on
current expenses, were held constant for the lives of the properties. Future
capital expenditures were estimated using values from the 12 months prior
to the as-of date of this report, provided by Evolution, and were not
adjusted for inflation. In certain cases, future expenditures, either higher or
lower than current expenditures, may have been used because of
anticipated changes in operating conditions, but no general escalation that
might result from inflation was applied. Abandonment costs, which are
those costs associated with the removal of equipment, plugging of wells,
and reclamation and restoration associated with the abandonment, were
provided by Evolution and were not adjusted for inflation. Operating
expenses, capital costs, and abandonment costs were considered, as
appropriate, in determining the economic viability of the undeveloped
reserves estimated herein.
In our opinion, the information relating to estimated proved reserves, estimated future net
revenue from proved reserves, and present worth of estimated future net revenue from proved
reserves of oil, condensate, NGL, and gas contained in this report has been prepared in accordance
with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and
932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive
Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January
2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a)
(1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future
income tax expenses have not been taken into account in estimating the future net revenue and
present worth values set forth herein and (ii) estimates of the proved developed and proved
undeveloped reserves are not presented at the beginning of the year.
To
the extent
the above-enumerated rules, regulations, and statements require
determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express
an opinion as to whether the above-described information is in accordance therewith or sufficient
therefor.
10
DeGolyer and MacNaughton
Summary of Conclusions
DeGolyer and MacNaughton has performed an independent evaluation of the extent and
value of the estimated net proved oil, condensate, NGL, and gas reserves of certain properties in
which Evolution has represented it holds an interest.
The estimated net proved reserves, as of June 30, 2023, of the properties evaluated herein
were based on the definition of proved reserves of the SEC and are summarized as follows,
expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
Estimated by DeGolyer and MacNaughton
Net Reserves
as of
June 30, 2023
Oil and
Condensate
(Mbbl)
NGL
(Mbbl)
Sales Gas
(MMcf)
Proved Developed
Proved Undeveloped
Total Proved
5,208
98
5,306
4,554
20
4,574
54,165
0
54,165
DeGolyer and MacNaughton
11
The estimated future revenue to be derived from the production and sale of the net proved
reserves, as of June 30, 2023, of the properties evaluated using the guidelines established by the
SEC is summarized as follows, expressed in thousands of dollars (M$):
Proved
Developed (M$)
(M$)
Undeveloped
(M$)
(M$)
Total
Proved
(M$)
Future Gross Revenue
Production Taxes
Ad Valorem Taxes
Operating Expenses
Capital Costs
Abandonment Costs
Future Net Revenue
Present Worth at 10 Percent
811,022
20,109
19,596
521,143
6,235
25,250
218,689
131,390
8,842
5
63
1,166
861
72
6,675
4,679
819,864
20,114
19,659
522,309
7,096
25,322
225,364
136,069
Note: Future income taxes have not been taken into account in the preparation of
these estimates.
While the oil and gas industry may be subject to regulatory changes from time to time that
could affect an industry participant’s ability to recover its reserves, we are not aware of any such
governmental actions which would restrict the recovery of the June 30, 2023, estimated reserves.
DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that
has been providing petroleum consulting services throughout the world since 1936. DeGolyer and
MacNaughton does not have any financial interest, including stock ownership, in Evolution. Our
fees were not contingent on the results of our evaluation. This report has been prepared at the
request of Evolution. DeGolyer and MacNaughton has used all assumptions, data, procedures, and
methods that it considers necessary and appropriate to prepare this report.
Submitted,
/s/ DeGolyer and MacNaughton
DeGOLYER and MacNAUGHTON
Texas Registered Engineering Firm F-716
[Seal]
s/ Dilhan Ilk
Dilhan Ilk, P.E.
Executive Vice President
DeGolyer and MacNaughton
DeGolyer and MacNaughton
CERTIFICATE of QUALIFICATION
I, Dilhan Ilk, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road,
Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:
1. That I am an Executive Vice President with DeGolyer and MacNaughton, which firm did
prepare this report of third party addressed to Evolution dated
August 7, 2023, and that I, as Executive Vice President, was responsible for the preparation
of this report of third party.
2. That I attended Istanbul Technical University, and that I graduated with a Bachelor of
Science degree in Petroleum Engineering in the year 2003, a Master of Science degree in
Petroleum Engineering from Texas A&M University in 2005, and a Doctor of Philosophy
degree in Petroleum Engineering from Texas A&M University in 2010; that I am a
Registered Professional Engineer in the State of Texas; that I am a member of the Society
of Petroleum Engineers; and that I have in excess of 13 years of experience in oil and gas
reservoir studies and reserves evaluations.
[Seal]
s/ Dilhan Ilk
Dilhan Ilk, P.E.
Executive Vice President
DeGolyer and MacNaughton
Evolution Petroleum Corporation
Incentive Compensation Recoupment Policy (the “Policy”)
Effective as of September 7, 2023
EXHIBIT 97
1.
Recoupment
If Evolution Petroleum Corporation (the “Company”) is required to prepare a Restatement, the
Company’s board of directors (the “Board”) shall, unless the Board’s Compensation Committee
determines it to be Impracticable, take reasonably prompt action to recoup all Recoverable
Compensation from any Covered Person. Subject to applicable law, the Board may seek to recoup
Recoverable Compensation by requiring a Covered Person to repay such amount to the Company;
by adding “holdback” or deferral policies to incentive compensation; by adding post-vesting
“holding” or “no transfer” policies to equity awards; by set-off of a Covered Person’s other
compensation; by reducing future compensation; or by such other means or combination of means
as the Board, in its sole discretion, determines to be appropriate. This Policy is in addition to (and
not in lieu of) any right of repayment, forfeiture or off-set against any Covered Person that may be
available under applicable law or otherwise (whether implemented prior to or after adoption of this
Policy). The Board may, in its sole discretion and in the exercise of its business judgment,
determine whether and to what extent additional action is appropriate to address the circumstances
surrounding any Restatement to minimize the likelihood of any recurrence and to impose such
other discipline as it deems appropriate.
2.
Administration of Policy
The Board shall have full authority to administer, amend or terminate this Policy. The Board shall,
subject to the provisions of this Policy, make such determinations and interpretations and take such
actions in connection with this Policy as it deems necessary, appropriate or advisable. All
determinations and interpretations made by the Board shall be final, binding and conclusive. The
Board may delegate any of its powers under this Policy to the Compensation Committee of the
Board or any subcommittee or delegate thereof.
3.
Acknowledgement by Executive Officers
The Board shall provide notice to and seek written acknowledgement of this Policy from each
to provide such notice or obtain such
the failure
Executive Officer; provided
acknowledgement shall have no impact on the applicability or enforceability of this Policy.
that
4.
No Indemnification
Notwithstanding the terms of any of the Company’s organizational documents, any corporate
policy or any contract, no Covered Person shall be indemnified against the loss of any Recoverable
Compensation.
Evolution Petroleum Corporation
Incentive Compensation Recoupment Policy (the “Policy”)
Effective as of September 7, 2023
5.
Disclosures
The Company shall make all disclosures and filings with respect to this Policy and maintain all
documents and records that are required by the applicable rules and forms of the U.S. Securities
and Exchange Commission (the “SEC”) (including, without limitation, Rule 10D-1 promulgated
under the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) and any applicable
exchange listing standard.
6.
Definitions
In addition to terms otherwise defined in this Policy, the following terms, when used in this Policy,
shall have the following meanings:
“Applicable Period” means the three completed fiscal years preceding the earlier of: (i) the date
that the Board, a committee of the Board, or the officer or officers of the Company authorized to
take such action if Board action is not required, concludes, or reasonably should have concluded,
that the Company is required to prepare a Restatement; or (ii) the date a court, regulator, or other
legally authorized body directs the Company to prepare a Restatement.
“Covered Person” means any person who receives Recoverable Compensation.
“Executive Officer” includes the Company’s principal executive officer, principal financial
officer, principal accounting officer (or if there is no such accounting officer, the controller),
president, any vice-president of the Company in charge of a principal business unit, division, or
function (such as sales, administration, or finance), any other officer who performs a policy-
making function, or any other person (including any executive officer of the Company’s affiliates)
who performs similar policy-making functions for the Company.
“Financial Reporting Measure” means a measure that is determined and presented in accordance
with the accounting principles used in preparing the Company’s financial statements (including
“non-GAAP” financial measures, such as those appearing in earnings releases), and any measure
that is derived wholly or in part from such measure. Examples of Financial Reporting Measures
include measures based on: revenues, net income, operating income, financial ratios, EBITDA,
liquidity measures, return measures (such as return on assets), profitability of one or more
segments, sales per square foot, same store sales, revenue per user, and cost per employee. Stock
price and total shareholder return (“TSR”) also are Financial Reporting Measures.
“Impracticable” means, after exercising a normal due process review of all the relevant facts and
circumstances and taking all steps required by Exchange Act Rule 10D-1 and any applicable
exchange listing standard, the Compensation Committee determines that recovery of the Incentive-
Based Compensation is impracticable because: (i) it has determined that the direct expense that the
Company would pay to a third party to assist in recovering the Incentive-Based Compensation
would exceed the amount to be recovered; (ii) it has concluded that the recovery of the Incentive-
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Evolution Petroleum Corporation
Incentive Compensation Recoupment Policy (the “Policy”)
Effective as of September 7, 2023
Based Compensation would violate home country law adopted prior to November 28, 2022; or (iii)
it has determined that the recovery of Incentive-Based Compensation would cause a tax-qualified
retirement plan, under which benefits are broadly available to the Company’s employees, to fail to
meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and regulations thereunder.
“Incentive-Based Compensation” includes any compensation that is granted, earned, or vested
based wholly or in part upon the attainment of a Financial Reporting Measure; however it does not
include: (i) base salaries; (ii) discretionary cash bonuses; (iii) awards (either cash or equity) that
are based upon subjective, strategic or operational standards; and (iv) equity awards that vest
solely on the passage of time.
“Received” – Incentive-Based Compensation is deemed “Received” in any Company fiscal period
during which the Financial Reporting Measure specified in the Incentive-Based Compensation
award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after
the end of that period.
“Recoverable Compensation” means all Incentive-Based Compensation (calculated on a pre-tax
basis) Received after [DATE OF ADOPTION OF POLICY] by a person: (i) after beginning
service as an Executive Officer; (ii) who served as an Executive Officer at any time during the
performance period for that Incentive-Based Compensation; (iii) while the Company had a class of
securities listed on a national securities exchange or national securities association; and (iv) during
the Applicable Period, that exceeded the amount of Incentive-Based Compensation that otherwise
would have been Received had the amount been determined based on the Financial Performing
Measures, as reflected in the Restatement. With respect to Incentive-Based Compensation based on
stock price or TSR, when the amount of erroneously awarded compensation is not subject to
mathematical recalculation directly from the information in an accounting restatement, the amount
must be based on a reasonable estimate of the effect of the Restatement on the stock price or TSR
upon which the Incentive-Based Compensation was received.
“Restatement” means an accounting restatement of any of the Company’s financial statements
due to the Company’s material noncompliance with any financial reporting requirement under U.S.
securities laws, including any required accounting restatement to correct an error in previously
issued financial statements that is material to the previously issued financial statements (often
referred to as a “Big R” restatement), or that would result in a material misstatement if the error
were corrected in the current period or left uncorrected in the current period (often referred to as a
“little r” restatement). A Restatement does not include situations in which financial statement
changes did not result from material non-compliance with financial reporting requirements, such
as, but not limited to retrospective: (i) application of a change in accounting principles; (ii) revision
to reportable segment information due to a change in the structure of the Company’s internal
organization; (iii) reclassification due to a discontinued operation; (iv)
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Evolution Petroleum Corporation
Incentive Compensation Recoupment Policy (the “Policy”)
Effective as of September 7, 2023
application of a change in reporting entity, such as from a reorganization of entities under common
control; (v) adjustment to provision amounts in connection with a prior business combination; and
(vi) revision for stock splits, stock dividends, reverse stock splits or other changes in capital
structure.
Adopted by the Board of Directors on September 7, 2023.
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