Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended June 30, 2020
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission File Number 001-32942
EVOLUTION PETROLEUM CORPORATION
(Exact name of registrant as specified in its charter)
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:
Trading Symbol(s)
EPM
None
(Title of Class)
Name of Each Exchange On Which Registered
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
Non-accelerated filer
☐
☐
Accelerated filer
Smaller reporting company
Emerging growth company
☒
☒
☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange
Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.
7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.). Yes: ☐ No: ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates on December 31, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, based on the closing price on that date of
$5.47 on the NYSE American was $122,253,472.
The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 1, 2020, was 32,956,469.
Table of Contents
Portions of the proxy statement related to the registrant's 2020 Annual Meeting of Stockholders to be filed within 120 days of the end of the fiscal year covered by this report are incorporated by reference into Part III of this report.
DOCUMENTS INCORPORATED BY REFERENCE
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
2020 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.
Item 6.
Item 7.
Business
Risk Factors
Unresolved Staff Comments
Properties
Legal Proceedings
Mine Safety Disclosures
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Selected Financial Data
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A.
Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Item 16.
Financial Statements and Supplementary Data
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Controls and Procedures
Other Information
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
Signatures
Exhibit Index
ii
iii
1
14
23
23
23
23
24
24
26
27
38
39
66
66
67
68
68
68
68
68
68
69
69
69
70
71
We use the terms, "EPM," "Company," "we," "us" and "our" to refer to Evolution Petroleum Corporation, and unless the context otherwise requires, its wholly-owned subsidiaries.
i
Table of Contents
FORWARD-LOOKING STATEMENTS
This Form 10-K and the information referenced herein contains forward-looking statements within the meaning of the Private Securities Litigations Reform Act of 1995, Section 27A of the
Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,” “budget,” “forecast,”
“predict” and other similar expressions are intended to identify forward-looking statements. These statements appear in a number of places and include statements regarding our plans, beliefs or
current expectations, including the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should keep in mind the risk factors that could
cause our actual results to differ materially from those contained in any forward-looking statement. Important factors that could cause actual results to differ materially from those in the forward-
looking statements herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk factors as described in Part I, Item 1A, "Risk Factors"
and elsewhere in this report and as also may be described from time to time in our future reports we file with the Securities and Exchange Commission. You should read such information in
conjunction with our consolidated financial statements and related notes and "Management's Discussion and Analysis of Financial Condition and Results of Operations" in this report. There also may
be other factors that we cannot anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such factors could cause results to differ
materially from our expectations.
Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements other than as required by law. You are advised, however, to review any
further disclosures we make on related subjects in our periodic filings with the Securities and Exchange Commission.
ii
Table of Contents
Term
Definition
Bbls
Barrels of oil or natural gas liquids.
BFPD
Barrels of fluid per day.
GLOSSARY OF SELECTED PETROLEUM INDUSTRY TERMS
BOE
Barrels of oil equivalent. BOE is calculated by converting 6 MCF of natural gas to 1 Bbl of oil which reflects energy
equivalence and not price equivalence. Gas prices per MCF and NGL prices per barrel often differ significantly from the
equivalent amount of oil.
BOPD
Barrels of oil per day.
BTU
CO2
British Thermal Unit: the standard unit of measure of energy equal to the amount of heat required to raise the temperature of
one pound of water 1 degree Fahrenheit. One Bbl of crude is typically 5.8 MMBTU, and one standard MCF is typically one
MMBTU.
Carbon dioxide; CO2 is a gas that can be found in naturally occurring reservoirs, is typically associated with ancient
volcanoes, is a major byproduct from manufacturing and power production, and is also utilized in enhanced oil recovery
through injection into an oil reservoir.
Developed
Reserves
Reserves of any category that can be expected to be recovered (i) through existing wells with existing equipment and
operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and
(ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is
by a means not involving a well.
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 farm-out party), to an
assignee (the farm-in party) who assumes all or some of the burden of development, in return for an interest in the property.
The assignor may retain an overriding royalty or any other type of interest. For Federal tax purposes, a farm-out may be
structured as a sale or lease, depending on the specific rights and carved out interests retained by the assignor.
The total acres or number of wells participated in, regardless of the amount of working interest owned.
EOR
Field
Farmout
Gross
Acres or
Gross
Wells
Horizontal
Drilling
Involves drilling horizontally out from a vertical well bore, thereby potentially increasing the area and reach of the well bore
that is in contact with the reservoir.
Hydraulic
Fracturing
Involves pumping a fluid with or without particulates into a formation at high pressure, thereby creating fractures in the rock
and leaving the particulates in the fractures to ensure that the fractures remain open which potentially increases the ability of
the reservoir to produce oil or gas.
LOE
Means lease operating expense(s), a current period expense incurred to operate a well.
MBO
One thousand barrels of oil.
MBOE
One thousand barrels of oil equivalent.
MCF
One thousand cubic feet of natural gas at standard conditions, being approximately sea level pressure and 60 degrees
Fahrenheit temperature.
MMBOE
One million barrels of oil equivalent.
MMBTU
One million British Thermal Units.
MMCE
One million cubic feet of natural gas at standard temperature and pressure.
Mineral
Royalty
Interest
Net Acres
or Net
Wells
NGL
A royalty interest that is retained by the owner of the minerals underlying a lease. See "Royalty Interest".
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.
NYMEX
New York Mercantile Exchange.
OOIP
Original Oil in Place; an estimate of the barrels originally contained in a reservoir before any production therefrom.
Operator
An oil and gas joint venture participant that manages the joint venture, pays venture costs and bills the venture's non-operators
for their share of venture costs. The operator is also responsible to market all oil and gas production, except for those non-
operators who take their production in-kind.
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."
Overriding
Royalty
Interest or
ORRI
iii
Table of Contents
Permeability
The measure of ease with which a fluid can move through a reservoir. The unit of measure is a darcy(d), or any metric
derivation thereof, such as a millidarcy(md), where one darcy equals 1,000 millidarcys. Extremely low permeability of 10
millidarcys, or less, are often associated with source rocks, such as shale. Extraction of hydrocarbons from a source rock is
more difficult than a sandstone reservoir where permeability typically ranges one to two darcys or more.
Porosity
The relative volume of the pore space (or open area) compared to the total bulk volume of the reservoir, stated in percent.
Higher porosity rocks provide more storage space for hydrocarbon accumulations than lower porosity rocks in a given
cubic volume of reservoir.
Producing
Reserves
Proved
Developed
Reserves
Proved
Developed
Nonproducing
Reserves
Proved
Developed
Producing
Reserves
("PDP")
Proved
Reserves
Proved
Undeveloped
Reserves
("PUD")
Any category of reserves that have 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 gas sales pipeline.*
Proved Reserves that have been developed and production has been initiated.*
Estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, operating
methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless
evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used
for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably
certain that it will commence the project within a reasonable time.*
Proved Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion.*
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are
reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable
certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted
indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been
proved effective by actual projects in the same reservoir or an analogous reservoir or by other evidence using reliable
technology establishing reasonable certainty.
Present Value
When used with respect to oil and gas reserves, present value means the estimated future net revenues computed by
applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by
contractual arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance
sheet presented, less estimated future expenditures (based on current costs to be incurred in developing and producing the
proved reserves) computed using a discount factor and assuming continuation of existing economic conditions.
Productive
Well
PV-10
A well that is producing oil or 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.
Royalty or
Royalty
Interest
1) The mineral owner's share of oil or gas production (typically between 1/8 and 1/4), free of costs, but subject to
severance taxes unless the lessor is a government. In certain circumstances, the royalty owner bears a proportionate share
of the costs of making the natural gas saleable, such as processing, compression and gathering. 2) When a royalty interest
is coterminous with and carved out of an operating or working interest, it is an "Overriding Royalty Interest," which also
may generically be referred to as a Royalty.
Shut-in Well
A well that is not on production, but has not been plugged and abandoned. Wells may be shut-in in anticipation of future
utility as a producing well, plugging and abandonment or other use.
Standardized
Measure
The standardized measure of discounted future net cash flows. The Standardized Measure is an estimate of future net cash
flows associated with proved reserves, discounted at 10% per annum. Future net cash flows are calculated by reducing
future net revenues by estimated future income tax expenses and discounting at 10% per annum. The Standardized
Measure and the PV-10 of proved reserves is calculated in the same exact fashion, except that the Standardized Measure
includes future estimated income taxes discounted at 10% per annum. The Standardized Measure is in accordance with
accounting standards generally accepted in the United States of America ("GAAP").
iv
Table of Contents
Undeveloped Reserves
Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from
existing wells where a relatively major expenditure is required for recompletion.*
Working Interest
The interest in the oil and gas in place which is burdened with the cost of development and operation of the
property. Also called the operating interest.
Workover
A remedial operation on a completed well to restore, maintain or improve the well's production.
* This definition may be an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X.
v
Table of Contents
Item 1. Business
Note: See Glossary of Selected Petroleum Industry Terms starting on page
iii
General
PART I
Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management and development of producing
oil and gas properties. The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisition, while seeking opportunities to maintain and increase
production through selective development, production enhancement and other exploitation efforts on its properties.
Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, and our interests in the Hamilton Dome field
located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, and overriding royalty interests in two onshore Texas wells.
Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue
interest of 26.2%. The field is operated by Denbury Onshore LLC ("Denbury"), a subsidiary of Denbury Resources, Inc.
On November 1, 2019, the Company acquired non-operated working interests in the Hamilton Dome field consisting of a 23.5% working interest, with an associated 19.7% revenue interest (inclusive
of a small overriding royalty interest). The field is operated by Merit Energy Company ("Merit"), a private oil and gas company, who owns the vast majority of the remaining working interest in
Hamilton Dome field. Our acquired interest in Hamilton Dome aligned with the Company's strategy of adding long lived, low decline reserves expected to be supportive of our dividend over the
long-term.
Significant Activity in Fiscal 2020
•
Proved oil equivalent reserves at June 30, 2020 were 10.2 MMBOE, a 13% increase from the previous year primarily due to the acquisition of the Hamilton Dome field in November 2019.
The Standardized Measure for proved reserves decreased 51% to $62 million, as the acquisition of the Hamilton Dome field was offset by the decrease in the average first day of the month
net oil price from $64.54 per barrel of oil and $23.83 per barrel of natural gas liquids at June 30, 2019 to $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids at June 30, 2020.
Our proved reserves consist of 80% crude oil and 20% natural gas liquids, 82% are classified as proved developed producing and 18% are proved undeveloped.
• We recognized net income of $5.9 million, or $0.18 per diluted common share, our ninth consecutive year of reporting net income.
•
•
•
•
Returned to shareholders $10.7 million in cash dividends and $2.5 million in stock repurchases in fiscal 2020. The Company has paid out to shareholders more than $70 million in cash
dividends since inception of the dividend program in December 2013.
Closed the acquisition of non-operating working interest in the Hamilton Dome field on November 1, 2019 which included total proved reserves of 1.47 MMBOE as of June 30, 2020 as
estimated by DeGolyer & MacNaughton ("D&M"), an independent reservoir engineering firm.
Reported $12.4 million of cash flows from operations for the fiscal year ended June 30, 2020. We funded all operations, including $11.8 million of capital spending inclusive of our $9.3
million acquisition of our interest in the Hamilton Dome Field, from internal resources and remain debt free at June 30, 2020.
In order to mitigate the impact of the growing global COVID-19 pandemic on our employees, we continue to follow local stay-at-home orders and remotely work from home with minimal
disruptions to our business operations.
• We entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel,
recording a loss of $1.4 million at June 30, 2020. Of this amount, $1.9 million were non-cash, unrealized mark-to-market losses as commodity prices improved from those existing at fiscal
year-end, offset in part by $0.5 million in realized gains during the fiscal fourth quarter.
1
Table of Contents
• We completed remaining capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi Phase V development, which was delayed by the
operator until our fiscal fourth quarter of 2021.
•
In July 2020, Denbury Resources announced that it had entered into a restructuring support agreement with certain of its debt holders and filed a pre-packaged voluntary petition for
reorganization under Chapter 11 of the Bankruptcy Code in Texas. Denbury Resources is seeking to eliminate $2.1 billion of debt. Denbury subsequently announced on September 3, 2020
that its plan to eliminate $2.1 billion of its bond debt has been confirmed by the court which will substantially reduce its debt and strengthen its balance sheet.
Our Reserves: Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our independent reservoir engineering firm, D&M, assigned the estimated reserves net to our interests at Delhi as of June 30, 2020; we had 8.7 million bbls of total proved oil equivalent reserves.
The following table summarizes the reserves assigned by D&M:
Reserves MBOE
% Developed
Liquids %
Reserves as of June 30, 2020
Proved
8,746
79%
100%
Development History of the Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our working and royalty interests in the Delhi field is currently our largest producing asset. The Holt-Bryant Unit ("Unit") is approximately 13,636 acres in size and has had a prolific production
history totaling approximately 195 million bbls of oil through primary and limited secondary recovery operations since its discovery in the mid-1940s. At the time of our purchase of the field in 2003,
the Unit had minimal production. We conveyed our working interest in the field to Denbury in May 2006 for $50 million for the purpose of installing an enhanced oil recovery ("EOR") project in the
field. We retained a 23.9% reversionary working interest upon payout of the project, as defined in the purchase and sale agreements. Since EOR production began in March 2010, the Unit has
produced over 21.5 million bbls of oil.
After the May 2006 conveyance, Denbury as the operator, originally planned six primary phases for the installation of the CO2 flood in the Delhi field. Four of these six phases have been completed
as of June 30, 2020 and two remain undeveloped. One of the remaining two phases (Phase V) is reflected as proved undeveloped in our current reserves report and the other (Phase VI) was removed
from proved reserves as it was not deemed economic under current pricing guidelines for SEC purposes.
Phase I began CO2 injection in November 2009. First oil production response occurred in March 2010 and production in the field increased to approximately 1,000 gross barrels of oil per day by
December 2010.
2
Table of Contents
Implementation of Phase II, which was more than double the size of Phase I, commenced with incremental CO2 injection at the end of December 2010. First oil production response from Phase II
occurred during March 2011, and field gross production increased to more than 4,000 barrels of oil per day by June 2011.
Phase III was initially installed and subsequently expanded during calendar 2011. First oil production response from Phase III occurred during June 2011, and field gross production subsequently
increased to more than 5,000 gross barrels of oil per day by December 2011.
Phase IV was installed during the first six months of calendar 2012. During early calendar 2013, the operator intensified development in the previously redeveloped western side of the field based on
production results and new geological mapping that included the results of seismic data acquired over the last few years. First oil production response from Phase IV occurred during August 2012,
and field gross production increased to more than 7,500 gross barrels of oil per day by February 2013.
In June 2013, following an adverse fluid release event that consisted of the uncontrolled release of CO2, water, natural gas and a small amount of oil from a previously plugged well in the southwest
part of the field, the operator suspended CO2 injection in most of the southwestern tip of the field. The operator has fully remediated the affected area, has isolated that part of the field with a water
curtain, thus removing the area from the CO2 flood.
Construction began on the NGL extraction plant in February 2015 and was completed and began processing in December 2016. The plant extracts methane and NGL's from the CO2 recycle stream.
The methane and part of the ethane produced by the NGL extraction plant are used to generate electrical power for use in the field. The extracted NGL's are sold at the field to a purchaser who
transports them by truck to a plant for further processing. In addition to the value of these hydrocarbon products, the increased purity of the CO2 stream re-injected into the field has resulted in
operational benefits to the CO2 flood. To date, we have incurred a net capital cost of approximately $27.4 million for the plant, including capital upgrades since its commissioning.
Subsequent to the reversion of our working interest to us in November 2014, the operator initiated work on the Phase V expansion of the CO2 flood in the undeveloped eastern part of the field. These
operations were suspended shortly after reversion when the operator significantly reduced capital spending as a result of declining oil prices. Resumption of this work has been delayed due to low
prevailing oil prices and the operator's allocation of capital to other Delhi projects, primarily the large investment in the NGL plant together with the consensus that Phase V project economics would
be enhanced if it were implemented after completion of the NGL plant.
An infill drilling program commenced in March 2018 to target productive oil zones in the developed areas of the field that were not being swept efficiently by the CO2 flood.During fiscal 2019 the 12
well infill program, consisting of 10 producing wells and two CO2 injection wells, was completed. Proved undeveloped reserves of 536 MBOE were converted to proved developed reserves.
Additionally during fiscal 2019, one pad of the six-well water curtain program was completed and commenced water injection during the second half of fiscal 2019. The project began late in fiscal
2017 after completion of the NGL plant with the drilling of one injection well followed by three injection wells in fiscal 2018. During fiscal 2019, the operator drilled the two remaining injection
wells and proceeded with completions and injection line work. The first pad commenced operations during fiscal 2019 and the second pad began injections during our second quarter of fiscal 2020.
At June 30, 2020, we had total proved reserves of 8.7 MMBOE at Delhi, which was comprised of 6.7 MMBOE of oil and 2.0 MMBOE of NGLs as estimated by our independent petroleum
engineering firm. The following table sets forth our estimated proved reserves as of June 30, 2020. For additional reserve information see Note 21 to our consolidated financial statements in Item 8.
Reserve Category
PROVED
Developed Producing (79% of Proved)
Undeveloped (21% of Proved)
TOTAL PROVED
Product Mix
Oil
(MBbls)
NGLs
(MBbls)
Total Reserves
(MBOE)*
5,105
1,648
6,753
1,777
216
1,993
77%
23%
6,882
1,864
8,746
100%
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and
NGL prices per barrel often differ significantly from the equivalent amount of oil.
3
Table of Contents
For fiscal 2020, average gross daily oil production at Delhi was 5,632 BOPD and 1,106 bbls NGLs per day (6,738 BOEPD). The total gross purchased CO2 volume was 19 BCF for fiscal 2020. In
February 2020, the CO2 purchase line to Delhi was shut-in by the pipeline operator for extensive repairs. No CO2 was purchased from the shut-in date through June 2020. The recycle facilities
continue to operate as usual providing approximately 80% of the injected CO2 volumes to Delhi with production somewhat reduced due to lower injection volumes. Per communications with
Denbury, the CO2 line is currently being repaired and is projected to be completed early in the second quarter of our fiscal 2021.
Our Reserves: Hamilton Dome - Hot Springs County, Wyoming
Our independent reservoir engineering firm, D&M, assigned the estimated reserves net to our interests at Hamilton Dome as of June 30, 2020; we had 1.5 million bbls of total proved oil equivalent
reserves. The following table summarizes the reserves assigned by D&M:
Reserves MBOE
% Developed
Liquids %
Reserves as of June 30, 2020
Proved
1,473
100%
100%
On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field. The
Hamilton Dome field is located in the southwest part of the Big Horn Basin in northwest Wyoming about twenty miles northwest of Thermopolis in Hot Springs County.
4
Table of Contents
Our interest includes a 23.5% working interest and an associated 19.7% revenue interest (inclusive of a small overriding royalty interest). The Hamilton Dome field has produced over 160 MMBO
over the last 100 years; Merit has operated the field over the last 25 years. Production from this field is 100% oil and is currently averaging low single-digit decline rates.
Development History of the Hamilton Dome Field - Hot Springs County, Wyoming
Oil was first discovered at the Hamilton Dome field within the Big Horn Basin in September 1918 in the Curtis/Chugwater reservoir by New York Oil Company via surface mapping. Shortly
thereafter, the Phosphoria and Tensleep formations were discovered in 1919 and 1929, respectively. The field is part of an anticlinal fold with a southerly bounding fault with approximately 4,500-
5,000 feet of displacement, thus providing a structural trap. The two major producing formations are the Tensleep (sandstone) and Phospohoria (limestone) reservoirs. Additional present day and
historical production exists from the Curtis/Chugwater (sandstone), Amsden (sandstone), Madison (limestone), and Big Horn (dolomite) formations. These formations produce from depths ranging
approximately 1,500 to 3,600 feet and have historically produced at rates of greater than 25,000 gross BOPD. The productive surface area of the field spans approximately 2,500 acres. The original
oil in place of the six producing reservoirs is estimated to be at least 500 million barrels. Over the last 100 years, more than 160 million barrels have been produced from the field.
Although the Tensleep reservoir was discovered in 1929, it remained largely undeveloped until World War II. Active development of the Tensleep reservoir occurred between 1944 and 1960. The
Madison and Darwin reservoirs were discovered in 1948 and 1959, respectively. These two reservoirs were developed sporadically from 1950 through the 1970’s. In 1970, 52 years after the field’s
discovery, a waterflood was implemented in the Curtis/Chugwater reservoir. In 1973, the Phosphoria reservoir was unitized in order to implement a waterflood of the reservoir, this unit is still in place
and is approximately 3,160 acres. In the early 1970’s, Tensleep production was down spaced to 5 acres and in the late 1970’s an isolated Tensleep waterflood was implemented. By 1981, the Tensleep
reservoir had produced more than 147 million bbls. The last active development of the Curtis/Chugwater reservoir occurred in 1978 when the waterflood was ended. The Madison reservoir was
further developed in the early 1990’s.
Merit Energy purchased the field in 1995 and has operated the field for 25 years; the field was unitized in 1996. The Phosphoria and Tensleep reservoirs were permitted for unlimited commingling in
1996 as well. In 1997, Merit began a capital workover program to downspace the Phosphoria reservoir to 10 acres in addition to improving the Tensleep and Phosphoria waterfloods and eliminating
commingled production.
Under Merit’s operations, the wells in the Hamilton Dome field are produced via electric submersible pumps (ESP) and rod pumps. Typical workovers in the field include rod repair, ESP repair,
injector acid jobs, and wellbore cleanouts.
At June 30, 2020, EPM has total net proved reserves of 1.47 MMBOE at Hamilton Dome which was entirely comprised of oil as estimated by our independent reservoir engineering firm. The
following table sets forth our estimated proved reserves as of June 30, 2020 for our Hamilton Dome field. For additional reserve information see Note 21 to our consolidated financial statements in
Item 8.
Reserve Category
PROVED
Developed Producing (100% of Proved)
Undeveloped (0% of Proved)
TOTAL PROVED
Product Mix
Oil
(MBbls)
NGLs
(MBbls)
Total Reserves
(MBOE)*
1,473
—
1,473
100%
—
—
—
—%
1,473
—
1,473
100%
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and
NGL prices per barrel often differ significantly from the equivalent amount of oil.
Following acquisition in November 2019, average gross daily production was 2,048 BOPD through the end of fiscal 2020. From March to June 2020, the production rate was negatively impacted by
an estimated 870 gross BOPD, or approximately 38%, due to the shut-in of 61 wells as a result of the drop in oil prices.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues
The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These rules require disclosure of oil and gas proved reserves by significant geographic
area, using the trailing 12-month average price,
5
Table of Contents
calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and
allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes. Subject to
limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled
within five years.
There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities and values must be viewed as being subject to significant change as more
data about the properties becomes available.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2020
Our proved reserves at June 30, 2020, denominated in equivalent barrels using six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, were estimated by our
independent reservoir engineer, DeGolyer and MacNaughton which was formed in 1936. D&M has completed more than 23,000 projects in more than 100 countries. D&M was selected to estimate
reserves primarily due to their expertise in CO2-EOR projects and to ensure consistency with the operator of the Delhi field. The scope and results of their procedures are summarized in a letter from
the firm, which is included as Exhibit 99.1 to this Annual Report on Form 10-K.
The following table sets forth our estimated proved reserves as of June 30, 2020. For additional reserve information see Note 21 to our consolidated financial statements in Item 8. The NYMEX
previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $47.37 per barrel of crude oil. The net price per barrel of NGLs was $9.00,
which does not have any single comparable reference index price. The NGL price was based on historical prices received. For periods for which no historical price information was available, we used
comparable pricing in the geographic area. Pricing differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual property and product.
Reserves as of June 30, 2020
Reserve Category
PROVED
Developed Producing (82% of Proved)
Undeveloped (18% of Proved)
TOTAL PROVED
Product Mix
Oil
(MBbls)
NGLs
(MBbls)
Total Reserves
(MBOE)*
6,578
1,648
8,226
1,777
216
1,993
8,355
1,864
10,219
80%
20%
100%
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and
NGL prices per barrel often differ significantly from the equivalent amount of oil.
.
6
Table of Contents
The following table presents a reconciliation of changes in our proved reserves by major property, on the basis of equivalent MBOE quantities.
Reconciliation of Changes in Proved Reserves by Major Property
Proved reserves, MBOE
June 30, 2019
Purchases
Production
Revisions (a)
Sales of minerals in place
Improved recovery, extensions and discoveries
June 30, 2020
Delhi Field Proved
Total
MBOE
8,981
—
(647)
412
—
—
8,746
(a) Positive revisions of 412 MBOE at Delhi field reflect adjusted methodology of forecasting NGLs independently from the oil production forecast by our independent reservoir engineering firm.
Proved reserves, MBOE
June 30, 2019
Purchases
Production
Revisions (a)
Sales of minerals in place
Improved recovery, extensions and discoveries
June 30, 2020
Hamilton Dome Field Proved
Total
MBOE
—
3,427
(98)
(1,856)
—
—
1,473
(a) Negative revisions of 1,856 MBOE were due to the impacts of lower oil prices since the field’s November 2019 acquisition and to subsequent reduced rates of production. Responding to lower oil
prices, in March, the operator shut in wells that were not economic to optimize the field's cash flow. Although some returned to production as prices improved, as of June 30, 2020, approximately
25% of the wells remained shut-in. The lowered historical production curve and lower SEC average price, resulted in the field reaching its economic limit sooner than it had when proved reserves
were estimated at the acquisition date.
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company's Overall Reserve Estimation Process
Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent petroleum engineering firm under the supervision of our President and Chief
Executive Officer, Jason Brown, who has over 20 years of experience in the energy industry and is a Registered Professional Engineer (Petroleum) in the State of Texas. He earned his B.S. degree in
chemical engineering from the University of Tulsa and his M.B.A. from the Mendoza School of Business at the University of Notre Dame. Such reserves estimates are in compliance with generally
accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.
The reserves information in this filing is based on estimates prepared by D&M, our independent petroleum engineering firm, which was formed in 1936 and has completed more than 23,000 projects
in more than 100 countries. The person responsible for preparing the reserves report with D&M is a Registered Professional Engineer in the State of Texas and a Vice President of the firm. He
received a Bachelor of Science degree in petroleum engineering from the University of Texas in 1984, has over 35 years of experience in the energy industry and is a member of the Society of
Petroleum Engineers and the Society of Petroleum Evaluation Engineers.
7
Table of Contents
We provide D&M with our property interests, production, current operating costs, current production prices and other information in order to prepare the reserve estimates. This information is
reviewed by our President and Chief Executive Officer, designated operations personnel, and other members of management to ensure accuracy and completeness of the data prior to submission to
D&M. The scope and results of D&M's procedures, as well as their professional qualifications, are summarized in the letter included as Exhibit 99.1 to this Annual Report on Form 10-K.
Proved Undeveloped Reserves
Our proved undeveloped reserves were 1,864 MBOE at June 30, 2020, with associated future development costs of approximately $8.6 million, which are associated with the Phase V development of
Delhi field. The Company does not have any proved undeveloped reserves associated with its Hamilton Dome field acquired in November of 2019.
During the year ended June 30, 2020 our proved undeveloped reserves changed as follows:
June 30, 2019
Revisions to previous estimates
Conversion to proved developed reserves
June 30, 2020
Oil
(MBbls)
NGLs
(MBbls)
Total Reserves
(MBOE)
1,342
306
—
1,648
241
(25)
—
216
1,583
281
—
1,864
Price declines resulted in a reclassification of a small volume of oil reserves from PDP to PUD at June 30, 2020. The decline in price led to currently producing wells becoming uneconomic at an
earlier point in time than previously estimated. However, when forecasted in conjunction with the PUD reserves the overall economic life of the field is extended. Due to the EOR unit nature of
Delhi, this PDP reduction shifts those reserves to our PUD oil reserves as they are considered proved and expected to be recovered as a result of the development of our Phase V. NGL reserves were
revised downward 25 MBbls primarily due to the adjusted methodology of projecting NGL volumes independent of oil production, shifting them into developed NGL volumes. The infill program,
consisting of ten producer wells and two CO2 injection wells, was completed during 2019 resulting in the conversion of 463 MBbls of oil and and 73 MBOE of NGLs from proved undeveloped
reserves to proved developed reserves. Since this project's inception in March 2018, its net capital expenditures have totaled $4.6 million.
The initial assignment of proved undeveloped reserves in the Delhi field was made on June 30, 2010, which encompassed a large scale CO2 enhanced oil recovery project. The operator’s
development plans for the field have remained essentially unchanged and were originally scheduled to be completed by June 30, 2015, within five years from the initial recording of such proved
reserves. However, as a result of the adverse fluid release event in the field in June 2013 and the resulting delay in reversion of our working interest, development of the field has not proceeded as
originally scheduled. Expansion of the CO2 flood to the remaining undeveloped eastern portion of the field commenced subsequent to reversion of our working interest in late calendar 2014. We
incurred $3.8 million of capital expenditures before the operator electively deferred this project as a result of a reduction in its cash flows and capital spending from the significant drop in oil prices.
This project was further electively deferred as we began work on the NGL recovery plant field in February 2015. It was determined that the economics of development of the remaining eastern
portion of the field would be significantly improved after the NGL plant was completed.
During fiscal 2015, we authorized the NGL plant project and from late in that fiscal year until January 2017 when production of NGLs began, we incurred $26.0 million of related capital
expenditures. The NGL plant was completed in December 2016 and we converted approximately 1,377 MBOE of proved undeveloped reserves to proved developed reserves during fiscal 2017.
Since completion of the plant, we have resumed work that had been suspended in late 2014 and further deferred until the NGL recovery plant was complete. Cumulatively, we have spent $3.7 million
as of June 30, 2020, including $0.6 million and $1.6 million in fiscal years 2020 and 2019, respectively, on the six well water curtain program and related infrastructure required to precede the
development of Phase V. As of June 30, 2020 we had drilled all the injection wells, including four gross injection wells during fiscal 2019, and commenced operations for one of the program's pads.
The program was configured as two pads, each having two injection wells and one water source well. The second pad was completed during fiscal 2020 and began injections during our second
quarter of fiscal 2020.
As of June 30, 2020, we have estimated total future net capital expenditures of approximately $8.6 million for remaining curtain infrastructure and development of Phase V in the eastern part of the
field, which we expect to commence in May 2021 based on our discussions with the operator. The timing of Phase V development is dependent on the field operator's available funds and capital
spending plans and priorities within its portfolio of properties.
8
Table of Contents
We believe this project is economic in the current oil price environment and we expect it to be completed within the next four fiscal years. We have been continuously developing the Delhi field and
have spent over $48 million subsequent to reversion of our working interest in November 2014. Given the long-term nature of CO2 EOR development projects, we believe that the remaining
undeveloped reserves in the Delhi field satisfy the conditions to continue to be treated as proved undeveloped reserves because (1) we initially established the development plan for the Delhi field in
2010 and continue to follow that plan, as adjusted to incorporate the completion of the NGL plant in late 2016 and delays relating to the 2013 adverse fluid release event; (2) we have had significant
ongoing development activities at this project that, as budgeted and currently being expended, reflect a significant and sufficient portion of remaining capital expenditures to convert proved
undeveloped reserves to proved developed reserves; and (3) the operator has a historical record of completing the development of comparable long-term projects.
As of June 30, 2020, no proved reserves were attributed to (a) the area beneath the inhabited portion of the town of Delhi in the northeast and (b) the farthest east of the two remaining undeveloped
sites in the eastern portion of the field (Phase VI) due to the current economics and other technical aspects of our future development plans. In addition, no proved reserves are currently attributed to
three smaller reservoirs within the Unit in similar formations with similar production history due to the lower oil price utilized in our reserves calculation. We also do not have any proved reserves
associated with our interests in the Mengel Sand, a separate interval within the Unit that is not currently producing, but has produced oil in the past.
Sales Volumes, Average Sales Prices and Average Production Costs
The following table shows the Company's sales volumes and average sales prices received for crude oil, natural gas liquids, and natural gas for the periods indicated:
Product
Crude oil (Bbls)
Natural gas liquids (Bbls)
Natural gas (Mcf)
Average price per BOE*
Year Ended
June 30, 2020
Year Ended
June 30, 2019
Year Ended
June 30, 2018
Volume
Price
Volume
Price
Volume
Price
638,464 $
106,159 $
1,087 $
744,804 $
44.76
9.59
1.90
39.74
626,879 $
112,013 $
459 $
738,968 $
65.05
21.87
2.64
58.50
651,931 $
93,366 $
— $
745,297 $
58.52
28.06
—
54.71
Production costs
Production costs, excluding ad valorem and
production taxes
Total production costs, including ad valorem and
production taxes
$
$
Amount
per BOE
Amount
per BOE
Amount
per BOE
12,966,923 $
17.41 $
14,027,461 $
18.98 $
11,497,759 $
13,505,502 $
18.13 $
14,266,784 $
19.31 $
11,685,817 $
15.43
15.68
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence. Gas prices per MCF and
NGL prices per barrel often differ significantly from the equivalent amount of oil.
Drilling Activity
Our productive drilling activity during the past three fiscal years at Delhi field ended June 30, 2020, and was limited to five gross (1.2 net) producer wells drilled and completed in fiscal 2019 and
another five (1.2 net) producer wells completed in fiscal 2018. We completed one (0.239 net) CO2 injection well during fiscal 2019 and completed one (0.239 net) CO2 injection well during fiscal
2018. No dry wells were drilled in the past three fiscal years.
In connection with establishing a six-well water curtain in advance of Phase V site development, during fiscal 2019 we drilled two (0.48 net) wells and completed three (0.72 net) wells. In fiscal
2018, we drilled three (0.72 net) wells and in fiscal 2017 one (0.239 net) well was drilled. A pad consists of one gross water source well and two gross water injector wells. The three completed wells
comprise the northern pad of the water curtain program which commenced injection during fiscal 2019. The southern pad became fully operational late in the second quarter of fiscal 2020 when
capital expenditures for completion work concluded.
Hamilton Dome field is considered fully developed. No wells were drilled in fiscal 2020 and there are no plans to drill wells in fiscal 2021.
9
Table of Contents
Present Activities
The operator is completing a SCADA (supervisory control and data acquisition) well monitoring capital project at present which will improve the flow of information and assist in the real-time
management of the Delhi field. There are no significant drilling plans until Phase V development, expected to commence in the fourth quarter of fiscal 2021.
For further discussion, see "Highlights for our fiscal year 2020" and "Capital Expenditures" within Item 7.
Delivery Commitments
As of June 30, 2020, we were not committed to provide a fixed and determinable quantity of oil, NGLs or gas under existing agreements, nor do we currently intend to enter into any such agreements.
If the price of oil remains above $32.00, we have a financial commitment as we entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020
through December 2020 at a fixed swap price of $32.00 per barrel.
Productive Wells
The following table sets forth the number of productive oil and gas wells in which we own a working interest as of June 30, 2020.
Crude oil
Natural gas
Total
Acreage Data
Company Operated
Non-Operated
Total
Gross
Net
Gross
Net
Gross
Net
—
—
—
—
—
—
315
—
315
74.5
—
74.5
315
—
315
74.5
—
74.5
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2020. Developed acreage refers to acreage on which wells have been drilled
or completed to a point that would allow production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that
would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves.
Field (1)
Developed Acreage
Undeveloped Acreage
Total
Delhi Field, Louisiana (2)
Hamilton Dome Field, Wyoming
Total
Gross
Net
Gross
Net
Gross
Net
9,126
5,908
15,034
2,180
1,389
3,569
4,510
—
4,510
1,077
—
1,077
13,636
5,908
19,544
3,257
1,389
4,646
(1) All acreage, including any undeveloped, nonproductive or undrilled acreage, is held by existing production as long as continuous production is maintained in the unit.
(2) This table excludes acreage attributable to small overriding royalty interests retained in various formations in the Texas Giddings Field area. Except for de minimis production that began on
two leases during later fiscal 2019, none of such acreage is currently producing and our interests are subject to expiration if leases are not maintained by others or commercial production is not
established. It does not currently appear likely that we will obtain any significant value from these interests and no reserves have been assigned to any of the Giddings interests.
When the Company acquired the Delhi field in 2003, the field had been fully developed through primary and secondary recovery and all of such acreage was reflected as developed acreage. With the
addition of a CO2-EOR project in the field, certain acreage is now reflected as undeveloped using tertiary recovery operations. We estimate that our developed acreage currently includes 9,126 gross
(2,180 net) acres in the Delhi field, with approximately 4,510 gross (1,077 net) acres attributable to the remaining undeveloped areas in the eastern part of the field. We own a 23.9% working interest
in the field, along with certain mineral and royalty interests. We are not the operator of the EOR project.
10
Table of Contents
Our interests include all depths from the surface of the earth to the top of the Massive Anhydride, including the Delhi Holt Bryant Unit, which is currently under CO2 flood, and the Mengel Sand
Interval, which is within the boundary of the field, but is currently not producing. As the Delhi field is unitized per the State of Louisiana Department of Conservation order number 96-G-5, all
acreage, including any undeveloped, nonproductive or undrilled acreage is held by existing production as long as continuous production is maintained in the unit.
When the Company acquired Hamilton Dome field on November, 1 2019, the field had been fully developed through primary recovery and all acreage is reflected as developed acreage. The Tensleep
and Phosphoria were permitted for commingling and unitized in 1996 following purchase of the field by Merit Energy. The Company estimates that our developed acreage includes 5,908 gross
(1,389 net) acres in the Hamilton Dome field, with no acres attributable as undeveloped. We own 23.5% working interest in the field, along with a small overriding royalty interest. As Hamilton
Dome is unitized, all acreage is held by existing production as long as continuous production is maintained in the unit. We are not operators of Hamilton Dome field.
For more complete information regarding current year activities, including crude oil and natural gas production, refer to Item 7.
Markets and Customers
Our production is marketed to third parties in a manner consistent with industry practices. In the United States of America market, where we operate, crude oil and natural gas liquids are readily
transportable and marketable. We do not currently market our share of crude oil production from Delhi nor from Hamilton Dome separately from the operators' shares of production. Although we
have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts.
Under such arrangements we typically do not know the identity of the buyers of production except in the case of the Delhi field where there is a sole buyer for oil and another for NGL's.
The oil from Delhi is currently transported from the field by pipeline, which results in better net pricing than the alternative of transportation by truck. Delhi crude oil production sells at Louisiana
Light Sweet ("LLS") pricing which generally trades at a premium to West Texas Intermediate ("WTI") crude oil pricing. The positive LLS Gulf Coast average price differential over WTI, as quoted
daily on the New York Mercantile Exchange ("NYMEX"), was approximately $0.77 per barrel during our fiscal year ended June 30, 2020, compared to $4.11 per barrel for the prior year. In the
current fiscal year, the differential was impacted by market conditions over the second half of the fiscal year and trucking charges that were incurred for several months while the sales pipeline
underwent repair. NGL production is sold to a midstream processing company which fractionates the stream and sells the resulting hydrocarbons.
On November 1, 2019, Evolution acquired a non-operated interest in the Hamilton Dome field in Wyoming. All the field’s production is sour heavy crude oil which is the sole component of the
field’s reserves. Crude oil is transported by pipeline primarily to purchasers in Casper, Wyoming. As a result of transportation differentials, the high sulfur content and low API gravity, this crude
trades at a discount to WTI, averaging $17.62 lower over the last eight months. Although we have the option of taking our production in kind, we have elected to have the operator market our share of
production. Our realized price is net of transportation and marketing costs.
The following table sets forth purchasers of our oil and natural gas liquid production for the years indicated:
Customer
Plains Marketing L.P. (Delhi field oil)
Merit Energy Company (Hamilton Dome field oil)
Third Coast Midstream (Delhi field NGLs)
All others
Total
Year Ended June 30,
2020
2019
87%
10%
3%
—%
100%
94%
—%
6%
—%
100%
The loss of a purchaser at either the Delhi or Hamilton Dome fields or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-
term production levels.
11
Table of Contents
Market Conditions
Marketing of crude oil, natural gas, and natural gas liquids and the prices we receive are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict. These
factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.
Oil prices over the past few years have fluctuated and been extremely volatile. For example, average daily prices for WTI crude oil ranged from a high of $74 per barrel to a low of a negative $38 per
barrel over our past few fiscal years. Starting in the fourth quarter of 2014, the price of oil per barrel dropped dramatically and continuing into 2017 before recovering somewhat in late calendar 2018,
then weakening again in 2019 and dropping substantially in 2020 as a result of the impact of the COVID-19 pandemic and geopolitical factors. Worldwide factors such as global health pandemics,
geopolitical, international trade disruptions and tariffs, macroeconomic, supply and demand, refining capacity, petrochemical production and derivatives trading, among others, influence prices for
crude oil. Local factors also influence prices for crude oil and include increasing or decreasing production trends, quality differences, regulation and transportation issues unique to certain producing
regions and reservoirs.
Competition
The oil and natural gas industry is highly competitive for prospects, acreage and capital. Our competitors include major integrated crude oil and natural gas companies, numerous independent crude
oil and natural gas companies, individuals, and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger operating staffs and greater
capital resources. Competitors are national, regional or local in scope and compete on the basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our
industry are expertise in given geographical areas and geological systems and the abilities to efficiently conduct operations, achieve technological advantages, identify, and acquire economically
producible reserves and obtain capital at rates which allow economic investments.
Risk Management
Derivative instruments are occasionally utilized to hedge our exposure to price fluctuations and reduce the variability in our cash flows associated with anticipated sales of future oil and natural gas
production. We have designed a risk management policy to use derivative instruments from time to time during periods of extraordinary price volatility and when such instruments are needed to
ensure the Company can meet its current dividend policy, fund its capital expenditures commitments and maintain liquidity. We determine the duration of derivative positions to approximate the
anticipated period of volatility and the percentage of our production to be hedged, based on our view of current and future market conditions. We do not enter into derivative contracts for speculative
trading purposes.
While there are many different types of derivatives available, we typically use fixed-price swap and costless collars to attempt to manage price risk. The fixed-price swap agreements call for
payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under
the fixed-price swap agreement. Costless collar agreements are put and call options used to establish floor and ceiling commodity prices for a fixed volume of production during a certain time period.
All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under
the agreement is below the floor.
We entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel. In the
future we may add additional swaps or other derivative positions covering a variable portion of our anticipated future production during subsequent periods.
It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers. As of June
30, 2020, we did not post collateral under any of our derivative contracts as they are uncollateralized trades. We will continue to evaluate the benefit of employing derivatives in the future. See
Item 7A and Note 19 to our consolidated financial statements in Item 8 for additional information.
Government Regulation
Numerous federal and state laws and regulations govern the oil and gas industry, including environmental laws and regulations. These laws and regulations are often changed in response to changes
in the political or economic environment. Compliance with this evolving regulatory environment is often difficult and costly; substantial penalties may be incurred for noncompliance. To the best of
our knowledge, we are in compliance with all federal and state-level laws and regulations applicable to our operations. The future annual capital cost of complying with the regulations applicable to
our operations is
12
Table of Contents
uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable. We do not currently anticipate that continued and future compliance
with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.
See discussion captioned "Government regulation and liability for oil and gas operations and environmental matters may adversely affect our business and results of operations" in Item 1A.
Insurance
We maintain insurance on our oil and gas properties and operations for risks and in amounts customary in the industry. Such insurance includes general liability, excess liability, control of well,
operators extra expense, casualty, fraud and directors and officer's liability coverage. Not all losses are insured, and we retain certain risks of loss through deductibles, limits and self-retentions. We
do not carry lost profits coverage and we do not have coverage for consequential damages.
Employment
At June 30, 2020, we had four full-time employees, not including contract personnel and outsourced service providers. None of the Company’s employees are currently represented by a union, and
the Company believes that it has excellent relations with its employees. Our team is broadly experienced in oil and gas operations, development, acquisitions and financing. We follow a strategy of
outsourcing most of our property accounting, human resources, administrative and other non-core functions.
Additional Information
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports with the Securities and Exchange Commission ("SEC") . Our reports filed
with the SEC are available free of charge to the general public through our website at www.evolutionpetroleum.com. These reports are accessible on our website as soon as reasonably practicable
after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425,
Houston, Texas 77079, or calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W., Washington, D.C. 20549. The public may obtain
information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information
statements and other information regarding issuers that file electronically with the SEC.
13
Table of Contents
Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report on Form 10-K, actually occurs, our business, financial condition or
results of operations could suffer. The risks described below are not the only ones facing us. Additional risks not presently known to us or which we currently consider to be immaterial also may
adversely affect us.
Risks related to the oil and gas industry and our Company
A substantial or extended decline in oil prices may adversely affect our business, financial condition or results of operations and our ability to meet our capital expenditure obligations and
financial commitments.
The price we receive for our oil significantly influences our revenue, profitability, access to capital, and future rate of growth. Oil is a commodity and its price is subject to wide fluctuations in
response to relatively minor changes in supply and demand. For example, average daily prices for WTI crude oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel over our
past few fiscal years. Historically, the markets for oil and natural gas liquids have been volatile and these markets will likely continue to be volatile in the future. The prices we receive for our
production depend on numerous factors beyond our control, including, but not limited to the following:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
changes in global supply and demand for oil and natural gas, which has recently been negatively affected by concerns about the impact of COVID-19;
worldwide and regional economic conditions impacting the global supply and demand for oil and gas;
actions of OPEC or other groups of oil producing nations;
the price and quantity of imports of foreign oil and natural gas;
political conditions in or affecting other oil-producing and natural gas-producing countries;
the level of global oil and natural gas exploration and production;
the level of global oil and natural gas inventories;
localized supply and demand fundamentals of regional, domestic and international transportation availability;
weather conditions and natural disasters;
domestic and foreign governmental regulations;
speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
price and availability of competitors' supplies of oil and natural gas;
technological advances affecting energy consumption; and
the price and availability of alternative fuels.
Substantially all of our production is sold to purchasers under short-term (less than 12-month) contracts at market-based prices. A decline in oil and natural gas liquids prices will reduce our cash
flows, borrowing ability, the present value of our reserves, and our ability to develop future reserves. We may be unable to obtain needed capital or financing on satisfactory terms. Low oil and natural
gas liquids prices may also reduce the amount of oil and natural gas liquids that we can produce economically, which could lead to a decline in our oil and natural gas liquids reserves. Because
approximately 80% of our proved reserves at June 30, 2020 are crude oil reserves and 20% are natural gas liquids reserves, we are heavily impacted by movements in crude oil prices, which also
influence natural gas liquids prices. To the extent that we have not hedged our production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas
liquids prices may adversely affect our financial position.
Our revenues are concentrated in two assets and related declines in production or other events beyond our control could have a material adverse effect on our results of operations and financial
results.
Our revenues come from our royalty, mineral and working interests in the Delhi field in Louisiana and the Hamilton Dome field in Wyoming and thus our current revenues are highly concentrated in
these fields. Any significant downturn in production, oil and NGL prices, or other events beyond our control which impact these fields could have a material adverse effect on our results of operations
and financial results. We are not the operator of these fields, and our revenues and future growth are heavily dependent on the success of operations, which we do not control.
Operating results from oil and natural gas production may decline; we may be unable to acquire and develop the additional oil and natural gas reserves that are required in order to sustain our
business operations.
In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted, with the rate of decline depending on reservoir characteristics. Except to the extent we
acquire additional properties containing proved reserves or conduct successful development activities, or both, our proved reserves will decline. Our production is heavily dependent on our interests
in EOR production that began during March 2010 in the Delhi field and our newly acquired interests in the
14
Table of Contents
Hamilton Dome field in Wyoming. Environmental or operating problems or lack of extended future investment in either of these fields could cause our net production of oil and natural gas liquids to
decline significantly over time, which could have a material adverse effect on our financial condition. In fiscal 2020, our production was impacted by the operators of both fields. Delhi production
volumes were negatively impacted as a result of the financial strain Denbury was under and their lack of investment in projects in the field, including the delay of our Phase V, in addition to the
purchased CO2 line being shut in for repairs. In the Hamilton Dome field Merit temporarily shut in a portion of the production as it was uneconomic at the historically low prices. As of June 30, 2020,
a number of these wells have returned to production and we continue to monitor their performance; however, there is no guarantee that prolonged periods of being shut in or lack of investment would
not negatively impact future production.
We have limited control over the activities on properties we do not operate.
Substantially, all of our property interests are not operated by the Company and also involve other third-party working interest owners. As a result, we have limited ability to influence or control the
operation or future development of such properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that we will be required to fund with
respect to such properties. Operators of these properties may act in ways that are not in our best interest. Moreover, we are dependent on the other working interest owners of such projects to fund
their contractual share of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest owners for these projects could cause us to incur
unexpected future costs, result in lower production, and materially and adversely affect our financial conditions and results of operations.
We are materially dependent upon our operators with respect to the successful operation of our principal assets, which consists of our interests Delhi and Hamilton Dome fields. A materially
negative change in our operator’s financial condition could negatively affect operations (or timing thereof) in these fields, and consequently our income (or timing thereof) from these fields as
well as the value of our interests in these fields.
Our royalty, mineral and working interests in the Delhi field, located in Northeast Louisiana are our primary producing assets. Approximately 90% of our revenues come from the Delhi interests and
thus our current revenues are highly concentrated in this field. Any significant downturn in production or other events beyond our control which impact the Delhi field could have a material adverse
effect on our results of operations and financial results (or timing thereof). We are not the operator of the Delhi field. It is operated by a subsidiary of Denbury Resources Inc. (“DNR”), an
independent oil and gas company specializing in tertiary recovery with CO2. Our revenues and future growth are thus heavily dependent on the success of operations which we do not control.
Further, our CO2 - Enhanced Oil Recovery (“CO2-EOR”) project in the Delhi field requires significant amounts of CO2 reserves and technical expertise, the sources of which have been committed by
the operator. Additional capital remains to be invested to fully develop this project, further increase production, and maximize the value of this asset. The operator's failure to manage these and other
technical, environmental, operating, strategic, financial and logistical matters could cause ultimate enhanced recoveries from the planned CO2 - EOR project to fall short of our expectations in volume
and/or timing. Such occurrences could have a material adverse effect on us, and our results of operations and financial condition.
On February 22, 2020, DNR experienced a pressure loss in its CO2 purchase pipeline resulting in an immediate shut down. DNR cut out a section of the failed pipeline and sent it out for analysis on
the cause of the failure and remediation procedures. Analysis results, with the consultation the government regulating agency, recommended repairing the damaged section of pipeline. DNR has
informed the Company that preparations for this project are underway and the CO2 purchases line should be back in operation October 1, 2020.
Our economic success is thus materially dependent upon the Delhi field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome source, (ii) secure its share
of capital necessary to fund development and operating commitments with respect to the field and (iii) successfully manage related technical, operating, environmental, strategic, and logistical risks,
among other things.
In July 2020, Denbury announced that it had entered into a Restructuring Support Agreement (the “RSA”) with holders of 100% of revolving credit facility loans, approximately 67.2% of second lien
notes and approximately 70.8% of convertible notes for a “pre-packaged” plan to eliminate $2.1 billion of bond debt and subsequently filed for voluntarily filed petitions for reorganization under
Chapter 11 of the Bankruptcy Code in the U.S. Bankruptcy Court for the Southern District of Texas. Denbury subsequently announced on September 3rd that its plan to eliminate $2.1 billion of its
bond debt has been confirmed by the court which will substantially reduce its debt, strengthen its balance sheet, and position Denbury to free up capital for investment in properties such as Delhi
again.
15
Table of Contents
The types of resources we focus on have substantial operational risks.
Our business plan focuses on the acquisition and development of known resources in partially depleted reservoirs, naturally fractured, or low permeability reservoirs. Our Delhi and Hamilton Dome
assets are productive from relatively shallow reservoirs; we may pursue assets that produce from deeper reservoirs in the future. Shallower reservoirs usually have lower pressure, which generally
translates into lower reserve volumes in place. Deeper reservoirs have higher pressures and usually more reserve volumes, but capturing those reserves often comes at increased drilling and
completion cost and risk. Low permeability reservoirs require more wells and substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of
sufficient undepleted fractures to establish commercial production. Depleted reservoirs require successful application of newer technology to produce incremental reserves.
Our CO2-EOR project in the Delhi field, operated by a subsidiary of Denbury Resources Inc., requires significant amounts of CO2 reserves, development capital and technical expertise, the sources of
which to date have been committed by the operator. Although initial CO2 injection began at Delhi in November 2009, initial oil production response began in March 2010 and a large part of the
capital budget has already been expended. Additional capital remains to be invested to fully develop the EOR project, further increase production, and maximize the value of the asset. The operator's
failure to manage these and other technical, environmental, operating, strategic, financial, and logistical risks may cause ultimate enhanced recoveries from the planned CO2-EOR project to fall short
of our expectations in volume and/or timing. Such occurrences would have a material adverse effect on the Company, its results of operations and financial condition.
Crude oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to production, and drilling and completing new wells are speculative
activities which involve numerous risks and substantial uncertain costs.
Our growth will be materially dependent upon the success of our future development program. Drilling for crude oil and extracting natural gas liquids and re-working existing wells involve numerous
risks. The risk that no commercially productive crude oil or natural gas reservoirs will be encountered is paramount. The cost of drilling, completing and operating wells is substantial and uncertain;
drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond our control, including, but not limited to:
•
•
•
•
•
•
•
•
unexpected drilling conditions;
pressure fluctuations or irregularities in reservoir formations;
equipment failures or accidents;
regulatory climate;
inability to obtain or maintain leases on economic terms, where applicable;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.
Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion techniques such as horizontal drilling or CO2 injection, do not guarantee that
we will find and produce crude oil and/or natural gas in our wells in economic quantities. Our future drilling activities may not be successful and, if unsuccessful, such failure would have an adverse
effect on our future results of operations and financial condition. We cannot guarantee that our overall drilling success rate will not decline.
We may also identify and develop prospects through a number of methods, some of which may include horizontal drilling or tertiary injectants, and some of which may be unproven. The drilling and
results for these prospects may be particularly uncertain. We cannot assure you that these projects can be successfully developed or that the wells discussed will, if drilled, encounter reservoirs of
commercially productive crude oil or natural gas.
The loss of a large single purchaser of our oil and natural gas could reduce the competition of our production.
For the year ended June 30, 2020, one purchaser accounted for approximately 87% of our total oil revenues. We do not currently market our share of crude oil production from the Delhi or Hamilton
Dome fields. Although we have the right to take our working interest production in-kind, we are currently accepting terms under the operators' agreements for the delivery and pricing of our oil. The
loss of a large purchaser for our oil production could negatively impact the revenue we receive. We cannot guarantee that we could readily find other purchasers for our oil and natural gas production.
In addition, the crude oil production from the Delhi and Hamilton Dome fields is transported by pipeline; if either of these pipelines were disrupted and we were forced to use alternative
transportation methods, our net realized pricing and potentially our near-term production levels could be adversely affected.
16
Table of Contents
Our crude oil and natural gas reserves are only estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. Our reserves are only estimates that may prove to be inaccurate because of these
inherent uncertainties. Reservoir engineering is a subjective process of estimating underground accumulations of crude oil and natural gas that cannot always be measured in an exact manner.
Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors. These factors include historical production from the area compared with
production from other comparable producing areas, assumptions concerning effects of regulations by governmental agencies, future crude oil and natural gas product prices, future operating costs,
severance and excise taxes, development costs, work-over costs, and remedial costs. Some or all of these assumptions utilized in estimating reserve volumes may vary considerably from actual
results. For these reasons, estimates of the economically recoverable quantities of reserves, classifications of such reserves based on risk of recovery, and estimates of the future net cash flows
expected from reserves may vary substantially depending on the timing ang and different engineers preparing reserves estimates.
Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue, and expenditures with respect to our reserves will likely vary from estimates; such
variances may be material. The information regarding discounted future net cash flows included in this report should not be considered as the current market value of the estimated crude oil and
natural gas reserves attributable to our properties. The estimated discounted future net cash flows from proved reserves are based on the 12-month average price, calculated as the unweighted
arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of the estimate, while actual future
prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as the amount and timing of actual production, supply and demand for crude oil
and natural gas, increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount factor, which is required by the SEC to be used in
calculating discounted future net cash flows for reporting purposes, is not necessarily the most appropriate discount factor. Interest rates in effect vary from time to time based on risks associated with
us or the oil and natural gas industry in general. The Standardized Measure does not necessarily correspond to market value.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
On a periodic basis we review the carrying value of our crude oil and natural gas properties under the applicable rules of various regulatory agencies, including the SEC. Under the full cost method of
accounting that we use, the after-tax carrying value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from proved reserves, discounted
at 10%. Application of this "ceiling" test requires pricing future revenues at the previous 12-month average beginning-of-month price and requires a write down of the carrying value for accounting
purposes if the ceiling is exceeded. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when crude oil and natural gas prices are depressed or
unusually volatile. Whether we will be required to take such a charge will depend in part on the prices of crude oil and natural gas during the previous period and the effect of reserve additions or
revisions and capital expenditures during such period. If a write down is required, it would result in a current charge to our earnings but would not impact our current cash flow from operating
activities. A large write-down could adversely affect our compliance with the current financial covenants under our credit facility, could limit our access to future borrowings under that facility, or
require repayment of any amounts that might be outstanding at the time.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural gas liquids, we have, and may in the future, enter into derivative
arrangements for a portion of our oil and natural gas liquids production. Derivative arrangements may include costless collars and fixed-price swaps. We have not designated any of our derivative
instruments as hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair value of our derivative instruments are recognized in
earnings. Accordingly, our earnings may fluctuate significantly as a result of changes in the fair value of our derivative instruments. Derivative arrangements also expose us to the risk of financial loss
in some circumstances, including, but not limited to, if:
•
•
•
production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contract obligations; or
there is a change in the expected differential between the underlying price in the derivative instrument and actual price received.
17
Table of Contents
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices for oil and natural gas liquids and may expose us to cash margin
requirements.
We may have difficulty managing future growth and the related demands on our resources and may have difficulty in achieving future growth.
Although we plan to experience growth through acquisitions and development activity, any such growth may place a significant strain on our financial, technical, operational, and administrative
resources. Our ability to grow will depend upon a number of factors, including, but not limited to the following:
•
•
•
•
•
•
•
•
•
•
our ability to identify and acquire new development projects;
our ability to develop new and existing properties;
our ability to continue to retain and attract skilled personnel;
the results of our development program and acquisition efforts;
the success of our technologies;
hydrocarbon prices;
drilling, completion, and equipment prices;
our ability to successfully integrate new properties;
our access to capital; and
the Delhi field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the Jackson Dome, (ii) secure all of the development capital necessary to fund its
and our cost interests, and further develop the Delhi field, such as advancement of Phase V development in the undeveloped eastern part of the field, (iii) successfully manage
technical, operating, environmental, strategic and logistical development and operating risks, and (iv) maintain its own financial stability.
We cannot assure you that we will be able to successfully grow or manage any such growth.
Our operations may require significant amounts of capital and additional financing may be necessary in order for us to continue our exploitation activities, including meeting potential future
drilling obligations.
Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we may require additional financing in order to carry out our oil and gas
acquisitions, exploitation and development activities. Certain portions of our undeveloped leasehold acreage may be subject to expiration unless production is established. If our revenues from our
reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to expend the necessary capital to replace our reserves or to maintain our current production. If
our cash flow from operations is not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing will be available to meet these
requirements or available to us on favorable terms.
We will be subject to risks in connection with acquisitions, and the integration of significant acquisitions may be difficult and may involve unexpected costs or delays.
We periodically evaluate acquisitions of reserves, properties, prospects, leaseholds and other strategic transactions that appear to fit within our overall business strategy. The successful acquisition of
producing properties requires an assessment of several factors, including, but not limited to:
•
•
•
•
•
•
recoverable reserves;
future oil and natural gas prices and their appropriate differentials;
development and operating costs;
potential for future drilling and production;
validity of the seller's title to properties, which may be less than expected at closing; and
potential environmental issues, litigation and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry
practices. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and potential
recoverable reserves. Inspections may not always be performed on every well, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when
problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. Moreover, in the event of such an acquisition, there is a
risk that we could ultimately be liable for unknown obligations related to acquisitions, which could materially adversely affect our financial condition, results of operations, or cash flows.
18
Table of Contents
Significant acquisitions and other strategic transactions may involve other risks, including, but not limited to:
•
•
•
•
•
our lean management team's capacity could be challenged by the demands of evaluating, negotiating, integrating significant acquisitions, and strategic transactions in concert with the
Company's ongoing business demands;
the challenge and cost of integrating acquired operations, information management, other technology systems, and business cultures with those of our operations while carrying on our
ongoing business;
difficulty associated with coordinating geographically separate organizations;
an inability to secure, on acceptable terms, sufficient financing that may be required in connection with expanded operations and unknown liabilities; and
the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business. Members of our senior management may be required to devote considerable
amounts of time to this integration process, which will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the integration process, or
if any significant business activities are interrupted as a result of the integration process, our business could suffer. In addition, even if we successfully integrate the assets acquired in an acquisition, it
may not be possible to realize the full benefits we may expect in estimated proved reserves, production volumes, cost savings from operating synergies, other benefits anticipated from an acquisition,
or realize these benefits within the expected time frame.
Government regulation and liability for oil and gas operations and environmental matters may adversely affect our business and results of operations.
Crude oil and natural gas operations are subject to extensive federal, state, and local government regulations, which may be changed from time to time. Matters subject to regulation include discharge
permits for drilling operations, drilling bonds, reports concerning operations, the spacing of wells, unitization and pooling of properties, and taxation. From time to time, regulatory agencies have
imposed price controls and limitations on production by restricting the rate of flow of crude oil and natural gas from wells below actual production capacity in order to conserve supplies of crude oil
and natural gas. There are federal, state, and local laws and regulations primarily relating to protection of human health and the environment applicable to the development, production, handling,
storage, transportation, and disposal of crude oil and natural gas, by-products thereof, the emission of CO2 or other greenhouse gases, and other substances and materials produced or used in
connection with crude oil and natural gas operations. These laws and regulations may affect the costs, manner and feasibility of our operations and require us to make significant expenditures in order
to comply. In addition, we may inherit liability for environmental damages, whether actual or not, caused by previous owners of property we purchase or lease or from nearby properties. As a result,
failure to comply with these laws and regulations may result in substantial liabilities to third parties or governmental entities. We are also subject to changing and extensive tax laws, the effects of
which cannot be predicted. The implementation of new, or the modification of existing, laws or regulations could have a material adverse effect on us, such as diminishing the demand for our
products through legislative enactment of proposed new penalties, fines and/or taxes on carbon that could have the effect of raising prices to the end user.
Our business could be negatively affected by security threats. A cyber attack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to
our reputation, and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing, and financial activities. We depend on
digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with
our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information, or other proprietary information, and those of our operators, vendors, suppliers,
customers and other business partners may become the target of cyber attacks or information security breaches. Cyber attacks or information security breaches could result in the unauthorized release,
gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our
exploration or production operations. Cyber attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to
disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business,
disruption of operations, damage to our reputation, or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States of America and abroad.
Computers are necessary to transport our oil and gas production to market. A cyber attack directed at oil and gas distribution systems could damage critical distribution and storage assets or the
environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and
the United States of America government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against
cybersecurity risks may not be sufficient. Further, as cyber
19
Table of Contents
attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to
cyber attacks.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures, explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires,
formations with abnormal pressures, hurricanes, flooding, pollution, releases of toxic gas and other environmental hazards and risks, which can result in (i) damage to or destruction of wells and/or
production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of life, or (v) damage to property, the environment or natural resources. While we carry general
liability, control of well, and operator's extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our business. Environmental events similar to that
experienced in the Delhi field in June 2013 could defer revenue, increase operating costs and/or increase maintenance and repair capital expenditures.
The loss of key personnel could adversely affect us.
We depend to a large extent on the services of certain key management personnel, including our executive officers. The loss of one or more key personnel could have a material adverse effect on our
operations. In particular, our future success is dependent upon the abilities of Robert Herlin, our Chairman of the Board, Jason Brown, our President and Chief Executive Officer, and David Joe,
Senior Vice President, Chief Financial Officer, Treasurer and Corporate Secretary, to source, evaluate and close deals, raise capital, and oversee our development activities and operations. Presently,
the Company is not a beneficiary of any key man life insurance.
Oil field service and materials prices may increase, and the availability of such services and materials may be inadequate to meet our needs.
Our business plan to develop or redevelop crude oil and natural gas resources requires third party oilfield service vendors and various material providers, which we do not control. We also rely on
third-party carriers for the transportation and distribution of our oil and gas production. As our production increases, so does our need for such services and materials. Generally, we do not have long-
term agreements with our service and materials providers. Accordingly, there is a risk that any of our service providers could discontinue servicing our crude oil and natural gas fields for any reason
or we may not be able to source the materials we need. Any delay in locating, establishing relationships, and training our sources could result in production shortages and maintenance problems,
resulting in loss of revenue to us. In addition, if costs for such services and materials increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have
assumed when deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long lead times often necessary to execute and complete our
redevelopment plans.
We cannot market the crude oil and natural gas that we produce without the assistance of third parties.
The marketability of the crude oil and natural gas that we produce depends upon the proximity of our reserves to, and the capacity of, facilities and third-party services, including crude oil and natural
gas gathering systems, pipelines, trucking or terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of capacity of such services
and facilities could result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. A shut-in, delay, or discontinuance could adversely affect our financial
condition.
We face strong competition from larger oil and gas companies.
Our competitors include major integrated crude oil and natural gas companies, numerous larger independent crude oil and natural gas companies, individuals, and drilling and income programs. Many
of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources. We may not be able to successfully conduct our operations, evaluate
and select suitable properties, or consummate transactions in this highly competitive environment. Specifically, these larger competitors may be able to pay more for development projects and
productive crude oil and natural gas properties and may be able to define, evaluate, bid for, and purchase a greater number of properties and prospects than our financial or human resources permit. In
addition, such companies may be able to expend greater resources on hiring contract service providers, obtaining oilfield equipment, and acquiring the existing and changing technologies that we
believe are and will be increasingly important to attaining success in our industry.
20
Table of Contents
We have been, and in the future may become, involved in legal proceedings related to our Delhi interest or other properties or operations and, as a result, may incur substantial costs in
connection with those proceedings.
From time to time we may be a defendant or plaintiff in various lawsuits. The nature of our operations exposes us to further possible litigation claims in the future. There is risk that any matter in
litigation could be decided unfavorably against us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results of operations, and cash
flow. Litigation can be very costly, and the costs associated with defending litigation could also have a material adverse effect on our financial condition. Adverse litigation decisions or rulings may
damage our business reputation.
Ownership of our oil, gas and mineral production depends on good title to our property.
Good and clear title to our oil, gas, and mineral properties is important to our business. Although title reviews will generally be conducted prior to the purchase of most oil, gas, and mineral producing
properties or the commencement of drilling wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim. This could result in a reduction or
elimination of the revenue received by us from such properties.
Events outside of our control, including a pandemic or broad outbreak of an infectious disease, such as the ongoing global outbreak of a novel strain of the coronavirus identified in late 2019
(“COVID-19”), may materially adversely affect our business.
We face risks related to pandemics, outbreaks, or other public health events that are outside of our control and could significantly disrupt our operations and adversely affect out financial condition. In
December 2019, a novel strain of a coronavirus, COVID-19, was identified in Wuhan, China. This virus continues to spread globally including in the United States of America. These and other
actions could, among other things, impact the ability of our employees and contractors to perform their duties, cause increased technology and security risk due to extended and company-wide
telecommuting and lead to disruptions in our permitting activities and critical business relationships.Additionally, the COVID-19 outbreak and governmental restrictions have significantly impacted
economic activity and markets and have dramatically reduced current and anticipated demand for oil and natural gas, adversely impacting the prices we receive for our production. The severity and
duration of the current COVID-19 outbreak and the potential for future outbreaks are uncertain and difficult to predict.
The extent to which COVID-19 impacts our business will depend on future developments, which are highly uncertain and cannot be predicted, including new information which may emerge
concerning the severity of the coronavirus and the actions to contain the coronavirus or treat its impact, among others. We are unable to predict the ultimate adverse impact of COVID-19 on our
business, which will depend on numerous evolving factors and future developments, including the length of time that the pandemic continues, its ongoing effect on the demand for oil and natural gas
and the response of the overall economy and the financial markets after governmental restrictions are eased.
Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations, liquidity, and financial condition.
During the last few years, concerns over inflation, energy costs, declining oil and gas prices, geopolitical issues, the availability and cost of credit, the United States of America mortgage market,
uncertainties with regard to European sovereign debt, the slowdown in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or other
trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for the global economy. Concerns about global economic conditions have had a
significant adverse impact on domestic and international financial markets and commodity prices. If uncertain or poor economic, business, or industry conditions in the United States of America or
abroad remain prolonged, demand for petroleum products could diminish or stagnate, and production costs could increase. These situations could impact the price at which we can sell our oil, natural
gas, and NGLs, affect our vendors', suppliers', and customers' ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial condition.
Risks Associated with Our Stock
Our stock price has been and may continue to be volatile.
Our common stock has relatively low trading volume and the market price has been, and is likely to continue to be, volatile. For example, during the fiscal year ending June 30, 2020, our stock price
as traded on the NYSE American ranged from $2.16 to $7.05. The variance in our stock price makes it difficult to forecast with certainty the stock price at which an investor may be able to buy or sell
shares of our common stock. The market price for our common stock could be subject to fluctuations as a result of factors that are out of our control, such as:
•
actual or anticipated variations in our results of operations;
21
Table of Contents
•
•
•
•
•
naked short selling of our common stock and stock price manipulation;
changes or fluctuations in the commodity prices of crude oil and natural gas;
general conditions and trends in the crude oil and natural gas industry;
redemption demands on institutional funds that hold our stock; and
general economic, political and market conditions.
Significant ownership of our common stock is concentrated in a small number of shareholders who may be able to affect the outcome of the election of our directors and all other matters
submitted to our stockholders for approval.
As of June 30, 2020 our executive officers and directors, in the aggregate, beneficially owned approximately 2.7 million shares, or approximately 8.2% of our beneficial common stock base.
Blackrock Fund Advisors, et al controlled approximately 3.4 million shares or approximately 10.2% of our outstanding common stock, Arrowmark Colorado Holdings, LLC controlled approximately
2.6 million shares or approximately 7.8% of our outstanding common stock, Renaissance Technologies, LLC controlled approximately 2.4 million shares or approximately 7.3% of our outstanding
common stock, Advisory Research, Inc controlled approximately 1.5 million shares or approximately 4.5% of our outstanding common stock and JVL Advisors, LLC controlled approximately 1.5
million shares or approximately 4.5% of our outstanding common stock. As a result, any of these holders could potentially exercise significant influence over matters submitted to our stockholders
for approval (including the election and removal of directors and any merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of
delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover, or other business combination involving our company or discourage a potential
acquirer from making a tender offer or otherwise attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common stock.
The market for our common stock is limited and may not provide adequate liquidity.
Our common stock trades on the NYSE American. Our trading volumes decreased slightly in fiscal 2020 compared to fiscal 2019. Trading volume in our common stock is relatively low compared to
larger companies. During the fiscal year ended June 30, 2020, the daily trading volume in our common stock ranged from a low of 42,300 shares to a high of 931,500 shares, with average daily
trading volume of 155,610 shares compared to average daily volume of 180,353 in fiscal 2019. Our holders may find it more difficult to sell their shares, should they desire to do so, based on the
trading volume and price of our stock at that time relative to the quantity of shares to be sold.
If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the price of our common stock could decline.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that industry or securities analysts publish. To our knowledge there are three
independent analysts that cover our company. The limited number of published reports by independent securities analysts could limit the interest in our common stock and negatively affect our stock
price. We do not have any control over the research and reports these analysts publish or whether they will be published at all. If any analyst who does cover us downgrades our stock, our stock price
could decline. If any analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial markets, which in turn could cause our stock price to
decline.
The issuance of additional common stock and preferred stock could dilute existing stockholders.
We currently have in place an effective registration statement which allows the company to publicly issue up to $500 million of additional securities, including debt, common stock, preferred stock,
and warrants. At any time we may make private offerings of our securities. The shelf registration is intended to provide greater flexibility to the company in financing growth or changing our capital
structure. We are authorized to issue up to 100,000,000 shares of common stock. To the extent of such authorization, our board of directors has the ability, without seeking stockholder approval, to
issue additional shares of common stock in the future for such consideration as our board may consider sufficient. The issuance of additional common stock in the future would reduce the
proportionate ownership and voting power of the common stock now outstanding. We are also authorized to issue up to 5,000,000 shares of preferred stock, the rights and preferences of which may
be designated in series by our board of directors. Such designation of any new series of preferred stock may be made without stockholder approval and could create additional securities which would
have dividend and liquidation preferences over the common stock now outstanding. Preferred stockholders could adversely affect the rights of holders of common stock by:
•
•
•
exercising voting, redemption and conversion rights to the detriment of the holders of common stock;
receiving preferences over the holders of common stock regarding our surplus funds in the event of our dissolution, liquidation, or the payment of dividends to preferred
stockholders;
delaying, deferring, or preventing a change in control of our company; and
22
Table of Contents
•
discouraging bids for our common stock.
Payment of dividends on our common stock has been in the past, and could be in the future, reduced or eliminated.
Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have declared and paid quarterly cash dividends since that time. However, there is
no certainty that dividends will be declared by the Board of Directors in the future. Any payment of cash dividends on our common stock in the future will be dependent upon the amount of funds
legally available, our earnings, if any, our financial condition, our business plan, restrictions contained in current or future debt instruments, contractual covenants or arrangements we may enter into,
our anticipated capital requirements, and other factors that our board of directors may think are relevant. Although it is our intent to maintain a steady dividend for our shareholders, there is no
guarantee that we will be able to do so. For example, during the 3rd quarter of fiscal 2020, we reduced our quarterly dividend from $0.10 per common share to $0.025 per common share.
Accordingly, there is no guarantee that we will be able or choose to continue to pay cash dividends on our common stock.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding our properties is included in Item 1 above and in Note 6 to our consolidated financial statements in Item 8, which information is incorporated herein by reference.
Item 3. Legal Proceedings
See Note 16 to our consolidated financial statements in Item 8 for a description of any legal proceedings, which is incorporated herein by reference.
Item 4. Mine Safety Disclosures
Not Applicable.
23
Table of Contents
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock
PART II
Our common stock is currently traded on the NYSE American under the ticker symbol "EPM". The following table shows, for each quarter of the fiscal years ended June 30, 2020 and 2019, the high
and low sales prices for EPM as reported by the NYSE American.
NYSE American: EPM
2020:
Fourth quarter ended June 30, 2020
Third quarter ended March 31, 2020
Second quarter ended December 31, 2019
First quarter ended September 30, 2019
2019:
Fourth quarter ended June 30, 2019
Third quarter ended March 31, 2019
Second quarter ended December 31, 2018
First quarter ended September 30, 2018
Shares Outstanding and Holders
$
$
$
$
$
$
$
$
High
Low
3.20 $
5.62 $
5.86 $
7.05 $
High
Low
7.40 $
8.11 $
12.83 $
12.00 $
2.23
2.16
5.08
5.55
5.99
6.44
6.17
9.60
As of June 30, 2020, there were 32,956,469 shares of common stock issued and outstanding. As of September 1, 2020, there were approximately 213 registered shareholders of our common stock.
Dividends
We began paying cash quarterly dividends on our common stock in December 2013. Over the last two fiscal years, the Company made the following cash dividends per share:
Fourth quarter ended June 30,
Third quarter ended March 31,
Second quarter ended December 31,
First quarter ended September 30,
`
Years Ended June 30,
2020
$0.025
$0.100
$0.100
$0.100
2019
$0.100
$0.100
$0.100
$0.100
As of June 30, 2020, we have paid 27 consecutive quarterly dividends on our common stock. In August 2020, the Company declared a $0.025 per share dividend payable on September 30, 2020. Any
future determination with regard to the payment of dividends will be at the discretion of the Board of Directors and will be dependent upon our future earnings, financial condition, results of
operations, applicable dividend restrictions, capital requirements, and other factors deemed relevant by the Board of Directors. Under our current revolving credit facility, our ability to continue to pay
common stock dividends is dependent on compliance with certain financial covenants related to debt service coverage, as defined in the agreement.
Performance Graph
The following graph presents a comparison of the yearly percentage change in the cumulative total return on our Common Stock over the period from June 30, 2015 to June 30, 2020 with the
cumulative total return of the S&P 500 Index and the S&P
24
Table of Contents
Oil & Gas Exploration and Production Index of publicly traded companies over the same period. The graph assumes that $100 was invested on June 30, 2015 in our common stock at the closing
market price at the beginning of this period and in each of the other two indices and the reinvestment of all dividends, if any. The graph is presented in accordance with requirements of the SEC.
Shareholders are cautioned against drawing any conclusions from the data contained therein, as past results are not necessarily indicative of future financial performance.
Securities Authorized For Issuance Under Equity Compensation Plans
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
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)
—
200,000
(1)
200,000
—
200,000
$
$
$
—
—
—
—
—
390,489
—
390,489
(1) In December 2016, the Company adopted the Equity Incentive Plan (the "2016 Plan"), which authorized the issuance of 1,100,000 shares of common stock. As of June 30, 2020, the Company
has granted 709,511 awards under the 2016 Plan and 390,489 shares of common stock remain available for future grants.
25
Table of Contents
Issuer Purchases of Equity Securities
During the fourth quarter ended June 30, 2020, the Company did not purchase any common stock in the open market under the previously announced share repurchase program and no shares of
common stock were surrendered by its employees to pay their share of payroll taxes arising from vesting of restricted stock.
Item 6. Selected Financial Data
The selected consolidated financial data, set forth below should be read in conjunction with Item 7 and Item 8.
Income Statement Data
Revenues
Cost of revenues
Depreciation, depletion and amortization
General and administrative expenses
Net loss on derivative contracts
Restructuring charges
Income from operations
Other income (expense)
Income tax provision (benefit)
Net income attributable to the Company
Dividends on preferred stock
Deemed dividend on preferred shares called for redemption
Net income attributable to common shareholders
Earnings per common share:
Basic
Diluted
Balance Sheet Data
Total current assets
Total assets
Total current liabilities
Total liabilities
Total stockholders' equity
Number of common shares outstanding
Working capital
Cash dividends to common shareholders
2020
2019
June 30,
2018
2017
2016
$
29,599,296 $
43,229,621 $
40,773,527 $
34,253,681 $
13,505,502
5,761,498
5,259,659
1,383,204
—
3,689,433
66,643
(2,180,996)
5,937,072
—
—
14,266,784
6,253,083
5,072,931
—
—
17,636,823
1,222,604
3,482,361
15,377,066
—
—
11,685,817
6,102,288
6,773,781
—
—
16,211,641
(25,126)
(3,431,969)
19,618,484
—
—
10,604,594
5,779,069
4,985,408
—
4,488
12,880,122
4,855
4,840,664
8,044,313
250,990
1,002,440
26,349,502
9,133,111
5,214,174
9,079,597
—
1,257,433
1,665,187
32,565,954
9,570,779
24,660,362
674,302
—
$
$
$
$
5,937,072 $
15,377,066
$
19,618,484 $
6,790,883 $
23,986,060
0.18 $
0.18 $
0.46 $
0.46 $
0.59 $
0.59 $
0.21 $
0.21 $
0.73
0.73
June 30, 2020
June 30, 2019
June 30, 2018
June 30, 2017
June 30, 2016
25,316,698 $
35,178,927 $
32,147,556 $
26,142,527 $
92,138,236
4,278,859
18,013,754
74,124,482
32,956,469
21,037,839
10,740,754
95,761,844
2,752,694
15,635,986
80,125,858
33,183,730
32,426,233
13,272,058
26
93,662,544
4,430,214
16,373,065
77,289,479
33,080,543
27,717,342
11,594,541
88,268,668
2,718,894
19,798,813
68,469,855
33,087,308
23,423,633
8,432,435
37,086,450
97,451,051
8,528,908
21,129,901
76,321,150
32,907,863
28,557,542
6,565,823
Table of Contents
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
General
Executive Overview
Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its stockholders through the ownership, management, and development of oil and gas
properties. In support of that objective, the Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisitions, while seeking opportunities to maintain
and increase production through selective development, production enhancements, and other exploitation efforts on its properties.
Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, and our interests in the Hamilton Dome field
located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, and overriding royalty interests in two onshore Texas wells.
Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue
interest of 26.2%. The field is operated by Denbury.
On November 1, 2019, the Company acquired mineral interests in the Hamilton Dome field consisting of a 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small
overriding royalty interest). The field is operated by Merit, a private oil and gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field. Our acquired interest
in this field aligned with the Company's strategy of adding long-lived, low decline reserves expected to be supportive of our dividend over the long-term.
Highlights for our Fiscal Year 2020 and Operations Update
•
Proved oil equivalent reserves at June 30, 2020 were 10.2 MMBOE, a 13% increase from the previous year primarily due to the acquisition of the Hamilton Dome field in November 2019.
The Standardized Measure for proved reserves decreased 51% to $62 million, as the acquisition of the Hamilton Dome field was offset by the decrease in the average first day of the month
net oil price from $64.54 per barrel of oil and $23.83 per barrel of natural gas liquids at June 30, 2019 to $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids at June 30, 2020.
Our proved reserves consist of 80% crude oil and 20% natural gas liquids, 82% are classified as proved developed producing and 18% are proved undeveloped.
• We recognized net income of $5.9 million, or $0.18 per diluted common share, our ninth consecutive year of reporting net income.
•
•
•
Returned to shareholders $10.7 million in cash dividends and invested $2.5 million in stock repurchases in fiscal 2020. The Company has paid out to shareholders more than $70 million in
cash dividends since inception of the dividend program in December 2013.
Closed the acquisition of non-operated working interest in Hamilton Dome field on November 1, 2019 which included total proved reserves of 1.47 MMBOE as of June 30, 2020 as
estimated by D&M, an independent reservoir engineering firm.
Reported $12.4 million of cash flows from operations for the fiscal year ended June 30, 2020. We funded all operations, including $11.8 million of capital spending inclusive of our $9.3
million acquisition of our interest in the Hamilton Dome Field, from internal resources and remain debt free at June 30, 2020.
27
Table of Contents
•
In order to mitigate the impact of the growing global COVID-19 pandemic on our employees, we continue to follow local stay-at-home orders and remotely work from home with minimal
disruptions to our business operations.
• We entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel,
recording a loss of $1.4 million at June 30, 2020. Of this amount, $1.9 million were non-cash, unrealized mark-to-market losses as commodity prices improved from those existing at fiscal
year-end, offset in part by $0.5 million in realized gains during the fiscal fourth quarter.
• We completed remaining capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi Phase V development, which was delayed by the
operator until the fourth quarter of 2021.
•
In July 2020, Denbury Resources announced that it had entered into a restructuring support agreement with certain of its debt holders and filed a pre-packaged voluntary petition for
reorganization under Chapter 11 of the Bankruptcy Code in Texas. Denbury Resources is seeking to eliminate $2.1 billion of debt. Denbury subsequently announced on September 3, 2020
that its plan to eliminate $2.1 billion of its bond debt has been confirmed by the court which will substantially reduce its debt and strengthen its balance sheet.
Oil & Natural Gas Liquids Reserves (based on SEC average NYMEX WTI oil price of $47.37 per barrel at June 30, 2020)
•
Proved oil equivalent reserves at June 30, 2020 were 10.2 MMBOE, a 13% increase from the previous year primarily due to the acquisition of the Hamilton Dome field in November
2019. The Standardized Measure for proved reserves decreased 51% to $62 million, reflecting the decrease in the average first day of the month net oil price from $64.54 per barrel of oil and
$23.83 per barrel of natural gas liquids at June 30, 2019 to $47.37 per barrel of oil and $9.00 per barrel of natural gas liquids at June 30, 2020. Price decreases are partially offset by the
acquisition of the Hamilton Dome field in November 2019. Our proved reserves are 80% crude oil and 20% natural gas liquids, and of these proved reserves, 82% are classified as proved
developed and producing and 18% are proved undeveloped.
The following table is a summary of our proved reserves as of June 30, 2020 and 2019:
Reserves MMBOE
% Developed
Liquids %
Standardized Measure ($MM)
Proved
2020
2019
Change
10.2
82%
100%
$
62
$
9.0
82%
100%
127
13.3 %
— %
— %
(51)%
Additional property and project information is included under Item 1 and in Note 6 and Note 21 to our consolidated financial statements in Item 8, and in Exhibit 99.1 of this Form 10-K.
Delhi Field
Proved reserves volumes totaled 8.7 MMBOE compared to the prior year's 9.0 MMBOE. Year over year, decreased oil prices and temporary curtailment of CO2 purchases since February 2020 has led
to a 0.2 MMBOE, or a 2% negative revision in proved oil reserves. Adjustment of projecting NGL reserves independent of oil production resulted in a 0.6 MMBOE, or 46% positive revision to NGL
reserves.
Gross production at Delhi in the fourth quarter of fiscal 2020 was 6,082 BOEPD, an 8% decrease compared to 6,597 BOEPD in the third fiscal quarter. Oil production was 4,985 BOPD, an 9%
decrease from the third fiscal quarter’s 5,499 BOPD. NGL fourth quarter production of 1,097 BOEPD was virtually flat compared to prior quarter production. Oil production was significantly
impacted by materially lower CO2 purchases when the CO2 purchase pipeline, upstream of Delhi field, was shut-in for repairs in late February throughout the end of fiscal 2020. The operator has
commenced repairs to the pipeline and expects an in service date of October 2020. The loss of CO2 purchases, coupled with the decline in oil prices, led to the operator electing to freeze non-essential
capital projects through the end of fiscal 2020.
The average oil price realized by Evolution during the fourth quarter of fiscal 2020 was $23.74 compared to $47.27 during the previous quarter, a decrease of 50%. The average NGL price realized by
Evolution during the fourth quarter of fiscal 2020 was $2.11 per barrel compared to $9.56 during the previous quarter, a decrease of 78%. The decline was attributable to the decrease in all realized
commodity prices in fiscal fourth quarter. The COVID-19 pandemic, combined with a market share competition between certain members of the OPEC+ member nations, continued to adversely
impact demand for commodity products,
28
Table of Contents
which caused a global supply/demand imbalance for oil that resulted in extreme volatility in benchmark oil prices, with prices ranging from a low of a negative price of $37.63 per Bbl to a high of
$40.46 per Bbl during our fiscal fourth quarter.
Although we historically benefit from the premium that Delhi field oil receives selling under Louisiana Light Sweet ("LLS") pricing, as compared to the more widely known West Texas Intermediate
("WTI") price, in the fiscal fourth quarter, the field realized a discount to WTI of $4.26. Oil produced from Delhi field is shipped to market directly by pipeline, the most efficient means of
transportation from the field. Our received NGL price for royalty production is burdened by a capital recovery charge, which is mostly offset by our working interest share that is reflected as a
reduction in lease operating expense.
Our overall lifting costs for the year were $16.50 per BOE, which decreased 14.6% from $19.31 per BOE in the prior year. Gross CO2 purchase volume rates for the fiscal 2020 averaged 51.9 MMcf
per day, compared to 85.2 MMcf per day in the prior year, a 39% decrease due to the Delhi CO2 purchase pipeline shut-in for repairs. This decrease together with a 14% lower price per mcf resulted
in a 48% decrease in CO2 cost compared to the prior year. Our cost of purchased CO2, the largest single component of operating costs at Delhi, is directly tied to the price of oil sold from the Delhi
field. Other lease operating expenses for fiscal 2020 decreased 5.6% compared to the prior year, primarily due to lower fuel gas, parts and workover expenses.
For fiscal 2020, our gross NGL production was 1,106 BOEPD, which sold at an average price of $9.59 per barrel, compared to prior year gross production of 1,171 BOEPD for which we realized
$21.87 per barrel. Production from the NGL plant is transported by truck to a processing plant in East Texas, and therefore bears a material transportation charge. Our current mix of products is very
rich containing higher value NGLs, such as pentanes and butane. NGL prices have fallen significantly from a peak in late 2018 in response to worldwide supply and demand. Historically, NGL
demand has had a seasonal pattern with prices tending to be higher in the cooler months of the year. Accordingly, the relationship between NGL prices and WTI has fluctuated over time and we
expect such volatility to continue in the future.
The NGL plant includes an electric turbine that converts methane and part of the ethane processed by the plant into electricity. This turbine generates power primarily for the NGL plant and supplies
excess power to the CO2 recycle facility. The NGL plant is accomplishing its primary objective of removing the lighter, smaller chain hydrocarbons (i.e. methane and ethane), thereby increasing the
purity of the CO2 recycle stream and improving the efficiency of the CO2 flood throughout the field. Over time, the NGL plant is expected to increase and enhance the recovery of crude oil in the
field. The NGL plant is not only providing feedstock to power the electric turbine, it is also producing significant quantities of higher value NGLs to sell to market.
Remaining estimated capital expenditures for our proved undeveloped reserves amount to approximately $6.38 per BOE for Phase V. Looking forward, the timing of plans for continued development
of the eastern part of the Delhi field are dependent on the operator’s schedule for capital allocation within their portfolio. Development of unquantified volumes is dependent upon the timing of
excess capacity within the processing plant and oil price. We continue to believe that this high quality and economically viable project will be executed as planned, subject to oil price volatility.
Hamilton Dome
At June 30, 2020, we had total proved reserves of 1.5 MMBOE which was entirely comprised of oil as estimated by our independent petroleum engineering firm D&M.
Gross oil production at Hamilton Dome in the fourth quarter of fiscal 2020 was 1,642 BOPD, a 29% decrease compared to 2,328 BOPD in the third fiscal quarter quarter primarily due to the operator
shutting in uneconomic wells at the extremely low oil price. There were limited capital expenditures in the field during fiscal 2020 due primarily to the decrease in oil prices. Most projects focused on
maintenance, but in March 2020, a larger, and more efficient, ESP was installed in the Step Scale 117 which resulted in an increase in average production since completion of 5 BOPD. The average
oil price realized by Evolution during the fourth quarter was $16.12 compared to $30.23 during the previous quarter, a decrease of 47%. Production from this field is transported by pipeline to
customers in the Western Canadian Select market; prices are discounted from WTI. In the fourth quarter our realized price reflected a $11.88 per barrel discount from the WTI price. For this fiscal
year, subsequent to our acquisition, our lifting costs at Hamilton Dome have averaged $28.93 per barrel.
29
Table of Contents
Impact of Geopolitical Factors and the COVID-19 Pandemic
On March 11, 2020, the World Health Organization declared COVID-19 a pandemic, and on March 13, 2020, the United States of America declared a national emergency with respect to COVID-19.
The virus has continued to spread in the United States of America and abroad. National, state, and local authorities have recommended social distancing, imposed quarantine and isolation measures,
as well as mandatory business closures on large portions of the population. These measures, while intended to protect human life, are expected to have serious adverse impacts on domestic and
foreign economies of uncertain severity and duration. The effectiveness of economic stabilization efforts, including government payments to affected citizens and industries, is uncertain.
The nature of the COVID-19 pandemic makes it extremely difficult to predict the impact on the Company’s business and operations. However, the likely overall economic impact of the pandemic is
viewed as highly negative to the general economy, especially the oil and natural gas industry. During the six months ended June 30, 2020, primarily driven by the COVID-19 pandemic and actions
taken by OPEC+, the benchmark price of WTI dropped significantly. Although global outputs can be adjusted to support commodity pricing levels, the Company expects the price of crude oil to
remain volatile in the near term. Uncertainty regarding the future actions of foreign oil producers, such as Saudi Arabia and Russia, and the risk that they take actions that will prolong or exacerbate
the current over-supply of crude oil is also contributing to the recent decline in oil prices.
Currently, all of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, the Company has limited ability to influence or
control the operation or future development of such properties. In light of the current price and economic environment, the Company continues to be proactive with its third-party operators to review
spending and alter plans as appropriate.
The Company is focused on maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home.
The Company was able to transition the operation of its business with minimal disruption and to maintain its system of internal controls and procedures.
Liquidity and Capital Resources
At June 30, 2020, we had $19.7 million in cash and cash equivalents, primarily impacted by the $9.3 million purchase of certain mineral interests in Hamilton Dome field in November 2019,
compared to $31.6 million of cash and cash equivalents at June 30, 2019.
In addition, the Company has a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50 million subject to a borrowing base determined by the lender based on the
value of our oil and gas properties. The Facility had a $27 million borrowing base on June 30, 2020. However, our ability to access the borrowing base is also limited by our compliance with certain
financial covenants, including a debt service ratio covenant, described below. As a consequence of declining oil prices adversely impacting our EBITDA upon which the debt service ratio is
calculated, at June 30, 2020 our borrowings would have been limited to approximately $8 million. There are no borrowings outstanding under the Facility, which matures on April 11, 2021. The
Facility is secured by substantially all of the reserves associated with the Delhi field.
Any future borrowings bear interest, at the Company's option, at either the London Interbank Offered Rate ("LIBOR") plus 2.75% or the Prime Rate, as defined under the Facility, plus 1.0%. The
Facility contains covenants requiring the maintenance of (i) a total leverage ratio of not more than 3.0 to 1.0, (ii) a debt service coverage ratio of not less than 1.1 to 1.0 and (iii) a consolidated
tangible net worth of not less than $50.0 million, each as defined in the Facility. The Facility also contains other customary affirmative and negative covenants and events of default. As of June 30,
2020, the Company was in compliance with all covenants contained in the Facility.
The Company has historically funded operations through cash from operations and working capital. The primary source of cash is the sale of produced oil and natural gas liquids. A portion of these
cash flows is used to fund capital expenditures. The Company expects to manage future development activities in the Delhi field and the limited capital maintenance requirements of the Hamilton
Dome field within the boundaries of its operating cash flow and existing working capital.
The Company is pursuing new growth opportunities through acquisitions and other transactions. In addition to cash on hand, the Company has limited access to an undrawn borrowing base available
under its senior secured credit facility, The Company also has an effective shelf registration statement with the SEC under which the Company may issue up to $500 million of new debt or equity
securities.
30
Table of Contents
During the fiscal year ended June 30, 2020, the Company funded operations, capital expenditures and cash dividends with cash generated from operations resulting in a decrease of $11.9 million in
cash. Uses of cash included the acquisition of the Hamilton Dome field ($9.3 million), cash dividends on common shares ($10.7 million) and repurchasing shares under the buyback program ($2.5
million). As of June 30, 2020, working capital was $21.0 million, a decrease of $9.3 million over working capital of $32.4 million at June 30, 2019.
The Board of Directors instituted a cash dividend payable on shares of our common stock in December 2013. The Company has since paid 27 consecutive quarterly dividends. Distribution of a
substantial portion of cash flow in excess of operating and capital requirements through cash dividends is a priority of the Company’s financial strategy. However, due to current depressed price
environment and a desire to preserve cash to potentially pursue opportunities that will grow dividends over time, the Board of Directors believed it was in the best interest of the Company to reduce
its quarterly dividend rate from $0.10 per share to $0.025 per share, effective in the quarter ending June 30, 2020. The reduced dividend rate will continue to reward shareholders with a yield of
approximately 3% at current stock price levels. The Company intends to grow dividend levels as appropriate.
In May 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the Company’s common stock. The Company monitors its stock price and looks to
opportunistically purchase its common stock when market conditions are deemed to be appropriate. During the year ended June 30, 2020, the Company purchased 440,666 shares at an average cost of
$5.51 per share bringing its total to $4.0 million to purchase 706,858 common shares at an average price of $5.72 per share.
In early March 2020, oil prices declined rapidly. As a consequence of unprecedented commodity price volatility and uncertainty on April 6, 2020, the Company elected to enter into NYMEX WTI oil
swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020, at a fixed swap price of $32.00 per barrel. The fixed price swap contracts will
significantly reduce volatility in the Company's near-term realized oil price and resulting revenues, thus supporting its current business plans and objectives. The Company expects to have sufficient
liquidity to meet all its identified cash requirements for at least the next 12 months.
Capital Expenditures
For the year ended June 30, 2020, we incurred $11.8 million on capital projects consisting of $9.3 million for the acquisition of Hamilton Dome field, $0.9 million for a non-cash asset addition related
to Hamilton Dome asset retirement obligations, $1.5 million at the Delhi field (primarily for the NGL plant and completion of the water curtain) and $0.1 million for capital workovers at Hamilton
Dome.
Based on discussions with the Delhi and Hamilton Dome operators, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital
expenditures, primarily at the Delhi field. Such amounts are not known or approved but we expect such expenditures to be in the range of $0.75 million to $1.0 million over the next 12 months. In
addition, we have planned for Delhi Phase V development expenditures of approximately $1.9 million to be incurred in the fourth quarter of our fiscal 2021. Phase V development expenditures are
expected to total $8.6 million with $3.7 million to be incurred in fiscal 2022 and the remainder over the next two years.
Our proved undeveloped reserves at June 30, 2020 included 1.86 MMBOE of reserves and approximately $8.6 million of future development costs associated with Phase V development in the
eastern portion of the field. Such development requires participation by both the operator and the Company. Based on our discussions with the operator, we expect drilling to commence in fiscal
2022, but the timing of Phase V is also dependent, in part, on the field operator's available funds and capital spending plans and priorities within its portfolio of properties.
Funding for our anticipated capital expenditures over the next 24 months is expected to be met from cash flows from operations and current working capital.
Full Cost Pool Ceiling Test
At the year ended June 30, 2020, our capitalized costs of oil and gas properties were below the full cost valuation ceiling; however, we could experience an impairment if current price levels persist or
worsen. The trend of lower oil prices reduced the excess, or cushion, of our valuation ceiling over our capitalized costs in the current quarter and may adversely impact our ceiling tests in future
quarters. We cannot give assurance that a write-down of capitalized oil and gas properties will not be required in the future. Under the full cost method of accounting, capitalized costs of oil and gas
properties, net of accumulated DD&A and related deferred taxes, are limited to the estimated future net cash flows from proved oil and gas reserves, discounted at 10%, plus the lower of cost or fair
value of unproved properties, as adjusted for related income tax effects (the valuation “ceiling”). If capitalized costs exceed the full cost ceiling, the excess would be charged to expense as a write-
down of oil and gas properties in the quarter in which the excess occurred. The quarterly ceiling test calculation requires that we use the
31
Table of Contents
average first day of the month price for our petroleum products during the 12-month period ending with the balance sheet date. The prices used in calculating our ceiling test at June 30, 2020 were
$47.37 per barrel of oil and $9.00 per barrel of natural gas liquids. A significant decline from these prices would likely result in a ceiling test impairment charge.
Overview of Cash Flow Activities
The table below compares a summary of our consolidated statements of cash flows for year ended June 30, 2020 and 2019.
Increases (Decreases) in Cash:
Net cash provided by operating activities
Net cash used in investing activities
Net cash used in financing activities
Change in cash, cash equivalents and restricted cash
June 30,
2020
12.4
$
(11.1)
(13.2)
(11.9)
$
$
$
2019
(In Millions)
Difference
24.1 $
(6.8)
(13.4)
3.9 $
(11.7)
(4.3)
0.2
(15.8)
Cash provided by operating activities in the current year decreased $11.7 million compared to fiscal 2019. The difference is primarily as the result of decrease in net income of $9.4 million due to
lower realized commodity prices together with a $3.2 million increase in cash used by operating assets and liabilities. Enhanced Oil Recovery credits claimed on income tax returns for fiscal 2019,
2018 and 2017 resulted in an income tax refund receivable that contributed to the use of cash by operating activities.
Cash used in investing activities decreased $4.3 million primarily due to the acquisition of the Hamilton Dome field in November 2019. The decrease is partially offset by a reduction in capital
expenditures in fiscal 2020 due to the decrease in realized commodity prices.
Cash used in financing activities remained relatively flat year over year as the reduction in cash used for cash dividends was offset by the Company's common share repurchase program in fiscal
2020. The Company reduced its quarterly dividend rate from $0.10 per share to $0.025 per share for the fourth quarter of fiscal year 2020. The Company spent a total of $2.5 million to purchase
440,666 shares of its common stock at an average price of $5.51.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2020, we are obligated to make under our contractual obligations and commitments. We expect to fund these
contractual obligations with cash on hand and cash generated from operations.
Total
Less than
1 Year
1 - 3 Years
3 - 5 Years
More than 5 Years
Payments Due by Period
Contractual Obligations
AFE purchase commitments in connection with joint interest
agreements
Operating lease
Other Obligations
Asset retirement obligations
Total Obligations
$
$
201,104 $
139,268
2,588,894
2,929,266 $
201,104 $
54,290
—
255,394 $
— $
84,978
65,163
150,141 $
— $
—
—
—
43,442
43,442 $
2,480,289
2,480,289
32
Table of Contents
Revenues
Results of Operations
Years Ended June 30, 2020 and 2019
Compared to the prior fiscal year, fiscal 2020 revenues decreased 31.5% due to 32.1% lower realized commodity prices. The decrease is partially offset by a very slight increase in production
volumes. The following table summarizes total production volumes, daily production volumes, average realized prices and revenues:
Oil and gas production
Crude oil revenues
NGL revenues
Natural gas revenues
Total revenues
Crude oil volumes (Bbl)
NGL volumes (Bbl)
Natural gas volumes (Mcf)
Equivalent volumes (BOE)
Crude oil (BOPD, net)
NGLs (BOEPD, net)
Natural gas (BOEPD, net)
Equivalent volumes (BOEPD, net)
Crude oil price per Bbl
NGL price per Bbl
Natural gas price per Mcf
Equivalent price per BOE
n. m. Not meaningful.
Years Ended June 30,
2020
2019
Variance
Variance %
28,578,879 $
1,018,349
2,068
40,779,052 $
2,449,359
1,210
(12,200,173)
(1,431,010)
858
29,599,296 $
43,229,621 $
(13,630,325)
638,464
106,159
1,087
744,804
1,744
290
—
2,034
44.76
$
9.59
1.90
39.74
$
626,879
112,013
459
738,968
1,717
307
1
2,025
65.05 $
21.87
2.64
58.50 $
11,585
(5,854)
628
5,836
27
(17)
(1)
9
(20.29)
(12.28)
(0.74)
(18.76)
(29.9)%
(58.4)%
70.9 %
(31.5)%
1.8 %
(5.2)%
136.8 %
0.8 %
1.6 %
(5.5)%
n.m
0.4 %
(31.2)%
(56.1)%
(28.0)%
(32.1)%
$
$
$
$
33
Table of Contents
(Gain) Loss on Derivative Contracts
Periodically, we utilize commodity derivative financial instruments to reduce our exposure to fluctuations in crude oil prices. This amount represents the (i) (gain) loss related to fair value adjustments
on our open, or unrealized, derivative contracts and (ii) (gains) losses on settlements of derivative contracts for positions that have settled or been realized.
Oil Derivative Contracts
Realized (gain) loss on derivatives, net
Unrealized (gain) loss on derivatives
Loss on derivatives
Crude oil price per Bbl (including impact of realized derivatives)
n. m. Not meaningful.
Production Costs
Years Ended June 30,
2020
2019
Variance
Variance %
$
$
$
(528,139)
$
1,911,343
1,383,204
$
45.59
— $
—
— $
(528,139)
1,911,343
1,383,204
n.m.
n.m.
n.m.
Production costs (also referred to as lease operating expenses) are presented in two components: (i) CO2 costs for the Delhi field and (ii) other production costs for both the Delhi and Hamilton Dome
fields. The $0.8 million decrease in total production costs was due to a 47.5% decrease in CO2 costs. The decrease is partially offset by a 31.8% increase in other production costs.
CO2 costs (a)
Other production costs
Total production costs
CO2 costs per BOE
All other production costs per BOE
Production costs per BOE
Years Ended June 30,
2020
2019
Variance
Variance %
$
$
$
$
3,501,507
$
10,003,995
13,505,502
$
6,674,905 $
7,591,879
14,266,784 $
(3,173,398)
2,412,116
(761,282)
4.70
$
13.43
18.13
$
9.03 $
10.28
19.31 $
(4.33)
3.15
(1.18)
(47.5)%
31.8 %
(5.3)%
(48.0)%
30.6 %
(6.1)%
(a) Under our contract with the operator, purchased CO2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes and transportation costs as per contract terms.
CO2 costs per mcf
CO2 volumes (MMcf per day, gross)
Years Ended June 30,
2020
2019
Variance
Variance %
$
0.77 $
51.9
0.90 $
85.2
(0.13)
(33.3)
(14.4)%
(39.1)%
The $3.2 million decrease in CO2 costs was due to a 39.1% decrease in rate of purchased volumes together with a 14.4% decrease in price per Mcf associated with the lower realized oil price. The
upstream pipeline that supplies CO2 to the Delhi field was shut-in on February 22, 2020, when a pressure loss was detected. CO2 purchases were temporarily suspended through our fiscal year-end.
CO2 purchases provide approximately 20% of the injected volumes in the field and the field’s recycle facilities provide the other 80%. The recycle facilities continued to operate as usual during the
purchase pipeline suspension. The pipeline is owned and operated by Denbury Resources, and the Company does not have any ownership in the portion of the pipeline under repair. The operator
expects the pipeline to be back in service in October 2020.
Compared to fiscal 2019, "Other production costs" increased 31.8% primarily due to the acquisition of the Hamilton Dome field in November 2019. The Delhi field's "Other production costs"
decreased slightly by 5.6% impacted by cost control measures as a result of lower oil prices.
Compared to fiscal 2019, Delhi field costs decreased 15% to $16.50 per BOE of Delhi current year production primarily due to lower CO2 costs, as discussed above.
34
Table of Contents
For fiscal 2020, Hamilton Dome field costs per BOE were $28.93.
Depletion, Depreciation and Amortization ("DD&A")
Total DD&A expense was 7.9% lower compared to the same one year-ago period due to an 8.7% decrease in the oil and gas DD&A amortization rate; the volume change between the two periods was
very slight. The integration of the Hamilton Dome asset contributed to an overall lower composite DD&A per BOE rate.
DD&A of proved oil and gas properties
Depreciation of other property and equipment
Amortization of intangibles
Accretion of asset retirement obligations
Total DD&A
Oil and gas DD&A per BOE
General and Administrative Expenses
Years Ended June 30,
2020
2019
Variance
Variance %
5,592,651 $
6,122,515 $
8,779
13,564
146,504
15,498
13,564
101,506
5,761,498 $
6,253,083 $
(529,864)
(6,719)
—
44,998
(491,585)
(8.7)%
(43.4)%
— %
44.3 %
(7.9)%
7.51 $
8.29 $
(0.78)
(9.4)%
$
$
$
Total general and administrative expenses for fiscal 2020 increased $0.2 million, or 3.7%, to $5.3 million from the same year-ago period. The increase is primarily due to higher non-cash stock-based
compensation of $0.4 million related to new grants associated with the hiring of a new executive officer and increased consulting expense of $0.1 million, partially offset by a decrease of $0.3 million
in bonus expense.
35
Table of Contents
Other Income and Expenses
Other income and expenses (net) decreased due primarily to the non-recurring Enduro transaction breakup fee income received during fiscal 2019. During May 2018, the Company entered into a
Purchase and Sale Agreement to acquire, as the "stalking horse" bidder, certain oil and gas assets from an affiliate of Enduro Resource Partners LLC ("Enduro") for a purchase price of $27.5 million,
subject to the outcome of Enduro's Chapter 11 process. In the first quarter of 2019, the Company was repaid its deposit together with related earned interest when a higher bidder first emerged in the
bidding process. Interest income is lower due to lower invested balances together with declining interest rates.
Enduro transaction breakup fee
Interest and other income
Interest expense
Total other income, net
Net Income
Years Ended June 30,
2020
2019
Variance
Variance %
—
177,418
(110,775)
1,100,000
239,150
(116,546)
(1,100,000)
(61,732)
5,771
$
66,643 $
1,222,604 $
(1,155,961)
(100.0)%
(25.8)%
(5.0)%
(94.5)%
Net income available to common stockholders for the year ended June 30, 2020 decreased $9.4 million, or 61%, to $5.9 million compared to the last fiscal year. Pre-tax income decreased due to the
aforementioned revenue and expense variances. Our income tax provision decreased primarily due to lower pre-tax income as our effective income tax rate was relatively unchanged from the year-
ago period. During the current period, we recorded a $2.8 million income tax benefit related to Enhanced Oil Recovery credits claimed on income tax returns for fiscal 2019, 2018 and 2017 .
Income before income taxes
Income tax provision (benefit)
Net income available to common stockholders
Income tax provision (benefit) as a percentage of income before income taxes
Years Ended June 30,
2020
3,756,076
(2,180,996)
2019
18,859,427
3,482,361
$
5,937,072
$
15,377,066
$
(58)%
18%
Variance
Variance %
(15,103,351)
(5,663,357)
(9,439,994)
(80.1)%
(162.6)%
(61.4)%
36
Table of Contents
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires that we select certain accounting policies and make
estimates and assumptions that affect the reported amounts of the assets, liabilities, and disclosures of contingent assets and liabilities as of the date of the balance sheet as well as the reported
amounts of revenues and expenses during the reporting period. These policies, together with our estimates, have a significant effect on our consolidated financial statements. Our significant
accounting policies are included in Note 2 to our consolidated statements in Item 8. Following is a discussion of our most critical accounting estimates, judgments, and uncertainties that are inherent
in the preparation of our consolidated financial statements.
Oil and Natural Gas Properties. Companies engaged in the production of oil and natural gas are required to follow accounting rules that are unique to the oil and gas industry. We apply the full cost
accounting method for our oil and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful and successful, exploration and
development activities are capitalized as properties and equipment. This includes any internal costs that are directly related to property acquisition, exploration, and development activities but does
not include any costs related to production, general corporate overhead, or similar activities. Gain or loss on the sale or other disposition of oil and gas properties is not recognized unless the gain or
loss would significantly alter the relationship between capitalized costs and proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil
and natural gas property costs excluded represent investments in unevaluated properties. We exclude these costs until the property has been evaluated. Costs are transferred to the full cost pool as the
properties are evaluated. As of June 30, 2020, we had no unevaluated property costs. Oil and natural gas property costs included represent non-producing leasehold, geological and geophysical costs
associated with leasehold or drilling interests and exploration drilling costs. .
Estimates of Proved Reserves. The estimated quantities of proved oil and natural gas reserves have a significant impact on the underlying financial statements. The estimated quantities of proved
reserves are used to calculate depletion expense and the estimated future net cash flows associated with those proved reserves is the basis for determining impairment under the quarterly ceiling test
calculation. The process of estimating oil and natural gas reserves is very complex and requires significant decisions in the evaluation of all available geological, geophysical, engineering, and
economic data. Estimated reserves are often subject to future revisions, which could be substantial, based on the availability of additional information; this includes reservoir performance, additional
development activity, new geological and geophysical data, additional drilling, technological advancements, price changes, and other economic factors. As a result, material revisions to existing
reserve estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates prepared by our third party independent engineers represent the
most accurate assessments possible, the subjective decisions and variances in available data for the properties make these estimates generally less precise than other estimates included in our financial
statements. Material revisions to reserve estimates and/or significant changes in commodity prices could substantially affect our estimated future net cash flows of our proved reserves. These changes
could affect our quarterly ceiling test calculation and could significantly affect our depletion rate. A 10% decrease in commodity prices used to determine our proved reserves as of June 30, 2020
would not have resulted in an impairment of our oil and natural gas properties. Holding all other factors constant, a reduction in the Company's proved reserve estimates at June 30, 2020 of 5%, 10%
and 15% would affect depreciation, depletion, and amortization expense by approximately $290,000, $612,000, and $970,000, respectively.
On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and gas reserves. The rule allows consideration of new technologies in evaluating reserves, generally limits
the designation of proved reserves to those projects forecast to be drilled five years from the initial recognition date of such reserves, allows companies to disclose their probable and possible reserves
to investors, requires reporting of oil and gas reserves using an average price based on the previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices,
revises the disclosure requirements for oil and gas operations, and revises accounting for the limitation on capitalized costs for full cost companies.
Valuation of Deferred Tax Assets. We make certain estimates and judgments in determining our income tax expense for financial reporting purposes. These estimates and judgments occur in the
calculation of certain tax assets and liabilities that arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our federal and state income
tax returns are generally not prepared or filed before the consolidated financial statements are prepared or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each
period as well as the effects of tax rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are recorded in our tax provision in the
period in which we file our income tax returns. Further, we must assess the likelihood that we will be able to recover or utilize our deferred tax assets (primarily our net operating loss). If recovery is
not likely, we must record a valuation allowance against such deferred tax assets for the amount we would not expect to recover; this would result in an increase to our income tax expense. As of
June 30, 2020, we have recorded a valuation allowance for the portion of our net operating loss that is limited by IRS Section 382.
37
Table of Contents
Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making the assessment of the ultimate realization of deferred
tax assets. Based upon the level of historical taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible, we believe that it is more likely
than not that the Company will realize the benefits of its net deferred tax assets at the time of this report. If our estimates and judgments change regarding our ability to utilize our deferred tax assets,
our tax provision would increase in the period it is determined that recovery is not probable.
Stock-based Compensation. The fair value and expected vesting period of the Company's market-based awards were determined using a Monte Carlo simulation. This technique uses a geometric
Brownian motion model with defined variables and randomly generates values for each variable through multiple trials. Variables include stock price volatility, expected term of the award, the
expected risk-free interest rate, and the expected dividend yield of the Company's stock. The risk-free interest rate used is the U.S. Treasury yield for bonds matching the expected term of the award
on the date of grant. Vesting of market-based awards is based on the Company's total common stock return compared to a peer group of other companies in our industry with comparable market
capitalizations and, for certain awards, the Company's share price attaining a set target.
Recent Accounting Pronouncements. Refer to Note 2 to our consolidated financial statements in Item 8. Consolidated Financial Statements and Supplementary Data for discussion of the recent
accounting pronouncements issued by the Financial Accounting Standards Board.
Off Balance Sheet Arrangements
The Company has no off-balance sheet arrangements as of June 30, 2020.
Item 7A. Quantitative and Qualitative Disclosures About Market Risks
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash equivalents. Under our current policies, we do not use interest rate derivative
instruments to manage exposure to interest rate changes.
Derivative Instruments and Hedging Activity
We are exposed to various risks, including energy commodity price risk, such as price differentials between the NYMEX commodity price and the index price at the location where our production is
sold. When oil, natural gas, and natural gas liquids prices decline significantly, our ability to finance our capital budget and operations may be adversely impacted. We expect energy prices to remain
volatile and unpredictable, therefore we monitor commodity prices to identify the potential need for the use of derivative financial instruments to provide partial protection against declines in oil
prices.We do not enter into derivative contracts for speculative trading purposes. In early March 2020, oil prices declined rapidly. As a consequence of unprecedented commodity price volatility and
uncertainty on April 6, 2020, we elected to enter into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020, at a fixed swap
price of $32.00 per barrel. The fixed price swap contracts will significantly reduce volatility in our near-term realized oil price and resulting revenues, thus supporting our current business plans and
objectives.
We are exposed to market risk on our open derivative contracts related to potential non-performance by our counterparties. It is our policy to enter into derivative contracts only with counterparties
that are creditworthy institutions deemed by management as competitive market makers. As of June 30, 2020, we did not post collateral under our derivative contract as it is an uncollateralized trade.
We account for our derivative activities under the provisions of ASC 815, Derivatives and Hedging, ("ASC 815"). ASC 815 establishes accounting and reporting that every derivative instrument be
recorded on the balance sheet as either an asset or liability measured at fair value. See Note 20 to our consolidated financial statements for more details.
38
Table of Contents
Item 8. Consolidated Financial Statements and Supplementary Data
Index to Consolidated Financial Statements
Report of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of June 30, 2020 and 2019
Consolidated Statements of Operations for the Years ended June 30, 2020 and 2019
Consolidated Statements of Cash Flows for the Years ended June 30, 2020 and 2019
Consolidated Statements of Changes in Stockholders' Equity for the Years ended June 30, 2020 and 2019
Notes to Consolidated Financial Statements
40
41
42
43
44
45
39
Table of Contents
To the Board of Directors and Stockholders
Evolution Petroleum Corporation
Opinion on the Financial Statements
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and Subsidiaries (the “Company”) as of June 30, 2020 and 2019, the related consolidated
statements of operations, cash flows and changes in stockholders’ equity for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our
opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the Company as of June 30, 2020 and 2019, and the consolidated results of
its operations and its cash flows for the years then ended, in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on
our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (“PCAOB”) and are required to be independent with respect to the
Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated
financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over
financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of
the Company’s internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures to respond to
those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the
accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a
reasonable basis for our opinion.
/s/ Moss Adams LLP
Houston, Texas
September 10, 2020
We have served as the Company’s auditor since 2017.
40
Table of Contents
Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
Assets
June 30, 2020
June 30, 2019
Current assets
Cash and cash equivalents
Receivables from oil and gas sales
Receivables for federal and state income tax refunds
Prepaid expenses and other current assets
Total current assets
Property and equipment, net of depreciation, depletion, and amortization
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization
Liabilities and Stockholders' Equity
Other property and equipment, net
Total property and equipment, net
Other assets, net
Total assets
Current liabilities
Accounts payable
Accrued liabilities and other
Derivative contract liabilities
State and federal taxes payable
Total current liabilities
Long term liabilities
Deferred income taxes
Asset retirement obligations
Operating lease liability
Total liabilities
Commitments and contingencies (Note 16)
Stockholders' equity
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 32,956,469 and 33,183,730 shares as of June 30, 2020 and 2019, respectively
Additional paid-in capital
Retained earnings
Total stockholders' equity
Total liabilities and stockholders' equity
See accompanying notes to consolidated financial statements.
41
$
$
$
$
$
19,662,528
1,919,213
3,243,271
491,686
25,316,698
66,512,281
17,639
66,529,920
291,618
92,138,236
$
1,471,679
$
716,648
1,911,343
179,189
4,278,859
11,061,023
2,588,894
84,978
18,013,754
32,956
41,291,446
32,800,080
74,124,482
$
92,138,236
$
31,552,533
3,168,116
—
458,278
35,178,927
60,346,466
26,418
60,372,884
210,033
95,761,844
2,084,140
537,755
—
130,799
2,752,694
11,322,691
1,560,601
—
15,635,986
33,183
42,488,913
37,603,762
80,125,858
95,761,844
Table of Contents
Revenues
Crude oil
Natural gas liquids
Natural gas
Total revenues
Operating costs
Production costs
Depreciation, depletion, and amortization
Net loss on derivative contracts
General and administrative expenses*
Total operating costs
Income from operations
Other
Enduro transaction breakup fee
Interest and other income
Interest (expense)
Income before income tax provision
Income tax provision (benefit)
Net income (loss) attributable to common shareholders
Earnings per common share
Basic
Diluted
Weighted average number of common shares outstanding
Basic
Diluted
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
Years Ended June 30,
2020
2019
$
28,578,879
$
1,018,349
2,068
29,599,296
13,505,502
5,761,498
1,383,204
5,259,659
25,909,863
3,689,433
—
177,418
(110,775)
3,756,076
(2,180,996)
5,937,072
$
0.18
0.18
$
$
33,031,149
33,033,091
$
$
$
40,779,052
2,449,359
1,210
43,229,621
14,266,784
6,253,083
—
5,072,931
25,592,798
17,636,823
1,100,000
239,150
(116,546)
18,859,427
3,482,361
15,377,066
0.46
0.46
33,160,283
33,169,718
*
General and administrative expenses for the years ended June 30, 2020 and 2019 included non-cash stock-based compensation expense of $1,285,663 and $888,162, respectively.
See accompanying notes to consolidated financial statements.
42
Table of Contents
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
Cash flows from operating activities
Net income attributable to the Company
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion, and amortization
Stock-based compensation
Settlement of asset retirement obligations
Deferred income taxes
Net loss on derivative contracts
Payments received for derivative settlements
Other
Changes in operating assets and liabilities:
Receivables
Prepaid expenses and other current assets
Accounts payable and accrued expenses
Income taxes payable
Net cash provided by operating activities
Cash flows from investing activities
Acquisition of oil and gas properties
Development of oil and natural gas properties
Capital expenditures for other property and equipment
Net cash used by investing activities
Cash flows from financing activities
Common share repurchases, including shares surrendered for tax withholding
Common stock dividends paid
Net cash provided by (used in) financing activities
Net increase (decrease) in cash, cash equivalents, and restricted cash
Cash, cash equivalents, and restricted cash, beginning of year
Cash, cash equivalents, and restricted cash, end of year *
* Neither annual period had any restricted cash balances.
See accompanying notes to consolidated financial statements.
43
Years Ended June 30,
2020
2019
$
5,937,072
$
15,377,066
5,761,498
1,285,663
(76,832)
(261,668)
1,383,204
793,327
39,783
(1,994,368)
(33,408)
(486,010)
48,390
12,396,651
(9,337,716)
(1,724,829)
—
(11,062,545)
(2,483,357)
(10,740,754)
(13,224,111)
(11,890,005)
31,552,533
$
19,662,528
$
6,253,083
888,162
—
767,256
—
—
15,156
773,800
66,229
(90,891)
8,039
24,057,900
—
(6,746,142)
(11,509)
(6,757,651)
(156,791)
(13,272,058)
(13,428,849)
3,871,400
27,681,133
31,552,533
Table of Contents
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
For the Years Ended June 30, 2020 and 2019
Balance, June 30, 2018
Issuance of restricted common stock
Forfeitures of restricted stock
Common share repurchases, including shares surrendered for tax withholding
Retirements of treasury stock
Stock-based compensation
Net income attributable to the Company
Common stock cash dividends
Balance, June 30, 2019
Issuance of restricted common stock
Forfeitures of restricted stock
Common share repurchases, including shares surrendered for tax withholding
Retirements of treasury stock
Stock-based compensation
Net income attributable to the Company
Common stock cash dividends
Balance, June 30, 2020
Common Stock
Shares
Par Value
Additional
Paid-in
Capital
Retained
Earnings
Treasury
Stock
Total
Stockholders'
Equity
33,080,543
$
33,080
$
41,757,645
$
35,498,754
$
121,611
—
(18,424)
—
—
—
—
33,183,730
271,778
(49,118)
—
(449,921)
—
—
—
122
—
—
(19)
—
—
—
33,183
272
(49)
—
(450)
—
—
—
(122)
—
—
(156,772)
888,162
—
—
42,488,913
(272)
49
—
(2,482,907)
1,285,663
—
—
—
—
—
15,377,066
(13,272,058)
37,603,762
—
—
—
—
—
—
—
5,937,072
(10,740,754)
32,956,469
$
32,956
$
41,291,446
$
32,800,080
$
— $
—
—
(156,791)
156,791
—
—
—
—
—
—
(2,483,357)
2,483,357
—
—
—
— $
77,289,479
—
—
(156,791)
—
888,162
15,377,066
(13,272,058)
80,125,858
—
—
(2,483,357)
—
1,285,663
5,937,072
(10,740,754)
74,124,482
See accompanying notes to consolidated financial statements.
44
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Organization and Basis of Preparation
Nature of Operations. Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management, and
development of producing oil and gas properties. The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisition, while seeking opportunities to
maintain and increase production through selective development, production enhancement, and other exploitation efforts on its properties.
Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO2 enhanced oil recovery project, our interests in the Hamilton Dome field
located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, and overriding royalty interests in two onshore Texas wells.
Principles of Consolidation and Reporting. Our consolidated financial statements include the accounts of the Company and its wholly-owned subsidiaries. All significant intercompany
transactions have been eliminated in consolidation. The consolidated financial statements of prior periods include certain reclassifications that were made to conform to the current presentation. Such
reclassifications have no impact on previously reported net income or stockholders' equity.
Risk and Uncertainties. The Company is continuously monitoring the current and potential impacts of the COVID-19 pandemic on its business, including how it has and may continue to impact its
financial results, liquidity, employees and the operations of the Delhi and Hamilton Dome fields in which we hold non-operated interests. During the six months ended June 30, 2020, primarily driven
by the COVID-19 pandemic and actions taken by OPEC+, the benchmark price of WTI has declined to levels that have adversely impacted our earnings and reduced the maximum amount we could
borrow under our senior secured facility.
In response to the pandemic, both of our operators have taken actions such as reducing operating and capital expenditures. At Hamilton Dome the operator has also temporarily shut-in some
producing wells. In addition to the above, we also believe the pandemic has slowed the repair schedule of the Delhi CO2 supply pipeline which together with the foregoing have negatively impacted
our production. All of the Company’s property interests are not operated by the Company and involve other third-party working interest owners. As a result, we have limited ability to influence or
control the operation or future development of such properties. However, the Company has been proactive with its third-party operators to review spend and alter plans as appropriate.
The Company is focused on maintaining its operations and system of controls remotely and has implemented its business continuity plans in order to allow its employees to securely work from home.
The Company was able to transition the operation of its business with minimal disruption and to maintain its system of internal controls and procedures.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the
dates of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Significant estimates include (a) reserve quantities and estimated future cash flows
associated with proved reserves, which 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 assets and liabilities, (e) income taxes and the valuation of deferred tax assets, and (f) commitments and contingencies. We analyze our estimates based on
historical experience and various other assumptions that we believe to be reasonable. While we believe that our estimates and assumptions used in preparation of the consolidated financial statements
are appropriate, actual results could differ from those estimates.
Note 2 – Summary of Significant Accounting Policies
Cash and Cash Equivalents. We consider all highly liquid investments, with original maturities of 90 days or less when purchased, to be cash and cash equivalents.
Restricted Cash. Funds legally designated for a specified purpose are classified as restricted cash. Such a balance is classified on the statement of financial position as either current or non-current
depending on its expected use. At June 30, 2020 and 2019, we had no such balances.
45
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 miscellaneous receivables. No interest is charged on past-due balances. Payments made on accounts receivable are applied to the earliest unpaid items. We establish
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, 2020 and 2019, no allowance for doubtful accounts was considered necessary.
Oil and Natural Gas Properties. We use the full-cost method of accounting for our 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.
Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Excluded costs represent investments in unproved and unevaluated properties and include non-
producing leasehold, geological and geophysical costs associated with leasehold or drilling interests, and exploration drilling costs. We exclude these costs until the project is evaluated and proved
reserves are established or impairment is determined. Excluded costs are reviewed at least quarterly to determine if impairment has occurred. The amount of any evaluated or impaired oil and natural
gas properties is transferred to capitalized costs being amortized.
Limitation on Capitalized Costs. Under the full-cost method of accounting, we are required, at the end of each fiscal quarter, to perform a test to determine the limit on the book value of our oil and
natural gas properties (the "Ceiling Test"). If the capitalized costs of our oil and natural gas properties, net of accumulated amortization and related deferred income taxes, exceed the "Ceiling", this
excess or impairment is charged to expense and reflected as additional accumulated depreciation, depletion, and amortization or as a credit to oil and natural gas properties. The expense may not be
reversed in future periods, even though higher oil and natural gas prices may subsequently increase the Ceiling. The Ceiling is defined as the sum of: (a) the present value, discounted at 10 percent
and assuming continuation of existing economic conditions, of 1) estimated future gross revenues from proved reserves, which is computed using oil and natural gas prices determined 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 (with consideration of price changes only to the
extent provided by contractual arrangements including hedging arrangements pursuant to SAB 103), less 2) estimated future expenditures (based on current costs) to be incurred in developing and
producing the proved reserves; plus (b) the cost of properties not being amortized (pursuant to Reg. S-X Rule 4-10 (c)(3)(ii)); plus (c) the lower of cost or estimated fair value of unproven properties
included in the costs being amortized; net of (d) the related tax effects related to the difference between the book and tax basis of our oil and natural gas properties. Our Ceiling Tests did not result in
an impairment of our oil and natural gas properties during the years ended June 30, 2020 and 2019.
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. Repairs
and maintenance costs are expensed in the period incurred.
Deferred Financing Costs. The Company capitalizes costs incurred in connection with obtaining financing. These costs are included in other assets on the Company's consolidated balance sheet and
are amortized over the term of the related financing using the straight-line method, which approximates the effective interest method.
Asset Retirement Obligations. An asset retirement obligation 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, our 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
46
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 our 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 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. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable, and derivative instruments. Except for derivatives, the
carrying amounts of these approximate fair value due to the highly liquid nature of these short-term instruments. 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 gas, discount rates, and volatility factors.
Stock-based Compensation. We estimate the fair value of stock-based compensation awards on the grant date to provide the basis for future compensation expense. Service-based and performance-
based Restricted Stock and Contingent Restricted Stock awards are valued using the market price of our common stock on the grant date. Market-based awards 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 we compare our performance. This Monte Carlo simulation also provides an expected vesting period. For service-based awards, stock-based compensation is recognized ratably over the
service period. For performance-based awards, stock-based compensation is recognized ratably over the expected vesting period when it is deemed probable, for accounting purposes, that the
performance goal will be achieved. The expected vesting period may be shorter than the remaining term. For market-based awards, stock-based compensation expense is recognized ratably over the
expected vesting period, so long as the award holder remains an employee of the Company. Total compensation expense is independent of vesting or expiration of the awards, except for termination
of service.
Revenue Recognition - Oil and Gas. Our revenues are comprised solely of revenues from customers from the sale of crude oil, NGLs and natural gas. The Company believes that the disaggregation
of revenue on its consolidated statements of operations into these three major product types appropriately depicts how the nature, amount, timing, and uncertainty of revenue and cash flows are
affected by economic factors based on our geographic locations. Crude oil, NGL, and natural gas revenues are recognized at a point in time when production is sold to a purchaser at an index-based,
determinable price, delivery has occurred, control has transferred and collectability of the revenue is probable. The transaction price used to recognize revenue is a function of the contract billing
terms which reference index price sources used by the industry. Revenue is invoiced by calendar month based on volumes at contractually based rates with payment typically required within 30 days
for crude oil and 60 days for NGLs after the end of the production month. At the end of each month when the performance obligations have been satisfied, the consideration can be reasonably
estimated and amounts due from customers are accrued in “Receivables from oil and gas sales” in our consolidated balance sheets. As of June 30, 2020 and 2019 receivables from contracts with
customers were $1.9 million and $3.2 million, respectively.
Derivative Instruments. The Company follows ASC 815, Derivatives and Hedging ("ASC 815"). From time to time, in accordance with the Company’s policy, it may hedge a portion of its forecasted
oil and natural gas liquids 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 ISDA master agreement; 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 instruments” on the consolidated statements of operations.
Depreciation, Depletion, and Amortization ("DD&A"). The depreciable base for oil and natural gas properties includes the sum of all capitalized costs net of DD&A, 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. Other property, consisting of leasehold building improvements and office and computer equipment, is depreciated as
described above in Other Property and Equipment.
47
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Taxes. We recognize deferred tax assets and liabilities based on the differences between the tax basis of assets and liabilities and their reported amounts in the financial statements that may
result in taxable or deductible amounts in future years. The measurement of deferred 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 tax assets will not be realizable. We recognize 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. We record 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. Basic earnings (loss) per share ("EPS") is computed by dividing earnings or loss available to common stockholders 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. Potentially dilutive common shares are our outstanding stock options and contingent restricted common
stock. We use the treasury stock method to determine the effect of potentially dilutive common shares on diluted EPS, unless the effect would be anti-dilutive. Under this method, exercise of stock
options and, under certain conditions, contingent restricted common stock is assumed to have occurred at the beginning of the period (or at time of issuance, if later); common shares are assumed to
have been issued. The proceeds from exercise of stock options and unamortized stock compensation expense related to restricted common stock are assumed to be used to repurchase 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. Contingent restricted stock is 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 Adopted Accounting Pronouncements - Leases
Effective July 1, 2019, the Company adopted the new standard using a modified retrospective approach and elected to use the optional transition methodology whereby reporting periods prior to
adoption continue to be presented in accordance with legacy accounting guidance, Accounting Standard Codification 840 - Leases. Upon transition, we recognized a right of use ("ROU") asset (or
operating lease right-of-use asset) and an operating lease liability with no retained earnings impact. We 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).
Adoption of the new standard did not impact our consolidated statements of operations, cash flows or stockholders’ equity. At adoption we recorded our operating lease as follows:
Asset (Liability)
Balance June 30, 2019
Adjustment at Adoption July 1,
2019
Operating lease right-of-use asset
Accrued liabilities and other:
Deferred rent
Operating lease liability
Operating lease liabilities - long-term
$
$
$
$
— $
(4,338)
$
— $
— $
161,125
4,338
(26,194)
(139,269)
48
Table of Contents
Recently Issued Accounting Pronouncements
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 Accounting Standards Update 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 adoption of ASU 2016-13 is currently not expected to have a material effect on our
consolidated financial statements.
In December 2019, the FASB issued ASU No. 2019-12, Income Taxes ("Topic 740") - Simplifying the Accounting for Income Taxes. ASU 2019-12 is intended to simplify accounting for income
taxes. It removes certain exceptions to the general principles in Topic 740 and amends existing guidance to improve consistent application. ASU 2019-12 is effective for annual periods, including
interim periods within those annual periods, beginning after December 15, 2020. Early adoption is permitted. We are currently evaluating the impact of ASU 2019-12 on our consolidated financial
statements.
Note 3 – Revenue Recognition
Our revenue is primarily generated from our interests in the Delhi field in Northeast Louisiana and, our interests in the Hamilton Dome field in Wyoming. Additionally, an overriding royalty interest
retained in a past divestiture of Texas properties provided de minimis revenue:
Revenues
Crude oil
Natural gas liquids
Natural gas
Total revenues
June 30,
2020
2019
$
$
28,578,879 $
1,018,349
2,068
29,599,296 $
40,779,052
2,449,359
1,210
43,229,621
We are a non-operator and presently do not take production in kind and do not negotiate contracts with customers. We recognize crude oil, natural gas liquids, and natural gas production revenue at
the point in time when custody and title (“control”) of the product transfers to the customer. Transfer of control drives the presentation of post-production expenses such as transportation, gathering,
and processing deductions within the accompanying statements of operations. Fees and other deductions incurred prior to control transfer are recorded within the production costs line item on the
accompanying consolidated statements of operations, while fees and other deductions incurred subsequent to control transfer are embedded in the price and effectively recorded as a reduction of
crude oil, natural gas liquids, and natural gas production revenue.
Judgments made in applying the guidance in Accounting Standards Codification Topic 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 at a point in time upon control transferring to a customer at a specified delivery point. Consideration is allocated to satisfied 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 one to two months after production has occurred, which is typical in the 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. Estimated revenue due to the Company is recorded within the receivables line item on the accompanying consolidated balance
sheets until payment is
49
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
received. The accounts receivable balances from contracts with customers as of June 30, 2020 and 2019, as presented on our respective consolidated balance sheets, were $1.9 million and $3.2
million, respectively. To estimate accounts receivable from operators' contracts with customers, the Company uses knowledge of its properties, historical performance, contractual arrangements, index
pricing, quality and transportation differentials, and other factors. Differences between estimates and actual amounts received for product sales are recorded in the month that payment is received
from the purchaser. Revenue recognized during the fiscal year ended June 30, 2020 and 2019 related to performance obligations satisfied in prior reporting periods, was immaterial.
Note 4 – Leases
Operating leases are reflected as an operating lease ROU asset included in “Other assets, net”, and as a ROU liability in “Accrued liabilities and other” and “Operating lease liability” on our
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. 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 in recent years and having adequate liquidity, the Company has generally not entered into lease transactions. Presently, our only operating lease is for corporate office space in
Houston, Texas, effective May 1, 2019 and which expires November 30, 2022. Presently we have one operating lease for office space, no finance leases and no short-term leases.
The Company makes certain assumptions and judgments when evaluating a contract that meets the definition of a lease under Topic 842. At adoption, July 1, 2019, as our lease did not provide an
implicit rate, we used our prime-rate-based borrowing rate under our senior secured credit facility as our incremental borrowing as the term facility was based on a similar term and is appropriately
risk-adjusted. We determined lease term by considering any option available to extend or to early terminate the lease which we believed was reasonably certain to be exercised.
At June 30, 2020, maturities of our operating lease liability are as follows:
Fiscal Year
2021
2022
2023
Total lease payments
Less imputed interest
Total lease liability
50
Operating Lease Liability
59,945
61,843
26,098
147,886
(8,617)
139,269
$
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Supplemental cash flow, balance sheet, and other disclosures information related to our operating leases are as follows:
Cash Flow:
Cash paid for amounts included in the measurement of lease liabilities
ROU asset added in exchange for lease obligation at adoption
Balance Sheet:
Operating lease ROU asset (included in other assets)
Accrued liabilities - current
Operating lease liability - long-term
Other:
Weighted average remaining lease term in years
Weighted average discount rate
Note 5 – Prepaid Expenses and Other Current Assets
Prepaid insurance
Prepaid federal and state income taxes
Prepaid investor relations and other
Prepaid expenses and other current assets
Note 6 – Property and Equipment
Oil and natural gas properties:
Property costs subject to amortization
Less: Accumulated depreciation, depletion, and amortization
Unproved properties not subject to amortization
Oil and natural gas properties, net
Other property and equipment:
Furniture, fixtures and office equipment, at cost
Less: Accumulated depreciation
Other property and equipment, net
As of and For the Year
Ended June 30, 2020
$
4,903
161,125
117,193
54,290
84,978
2.66
5.15%
June 30,
2020
June 30,
2019
289,999 $
86,208
115,479
491,686 $
206,198
121,679
130,401
458,278
$
$
June 30,
2020
June 30,
2019
$
107,390,379 $
(40,878,098)
—
66,512,281
154,731
(137,092)
$
17,639 $
95,622,153
(35,275,687)
—
60,346,466
154,731
(128,313)
26,418
As of June 30, 2020 and 2019, all oil and gas property costs were being amortized.
During the years ended June 30, 2020 and 2019, the Company incurred capital expenditures of $1.5 million and $5.2 million, respectively.
Hamilton Dome Acquisition
On November 1, 2019, and effective as of October 1, 2019, our wholly-owned subsidiary, Evolution Petroleum West, Inc., a Delaware corporation, purchased a 23.5% non-operated working interest
and a 19.7% revenue interest in the Hamilton Dome unitized field located in Hot Springs County, Wyoming, from entities owned or controlled by Merit Energy Company ("Merit") of Dallas, Texas.
At closing on November 1, 2019, we paid a cash purchase price of $9.5 million subject to customary purchase
51
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
price adjustments, which were settled in December 2019 upon our receipt of a $0.2 million cash payment made by Merit. Given the effective date of the transaction, the purchase price adjustment
consisted of our interest's share of sales proceeds from October sales net of our share of operating expenses. Commencing November 1, 2019, we began recording our share of Hamilton Dome
revenues, related expenses, and capital costs. In connection with this acquisition, the Company recorded a $0.9 million non-cash addition of asset retirement obligations of wells and related assets.
The unit includes producing and water injection wells and associated facilities producing crude oil from proved developed reserves. There were no proved undeveloped reserves. We accounted for
this acquisition transaction as an asset purchase.
Note 7 – Other Assets
Royalty rights
Less: Accumulated amortization of royalty rights
Investment in Well Lift Inc., at cost
Deferred loan costs
Less: Accumulated amortization of deferred loan costs
Right of use asset under operating lease
Less: Accumulated amortization of right of use asset
Software license
Less: Accumulated amortization of software license
Other assets, net
June 30,
2020
June 30,
2019
108,512
(61,037)
108,750
168,972
(157,084)
161,125
(43,932)
20,662
(14,350)
$
291,618 $
108,512
(47,474)
108,750
168,972
(141,927)
—
—
20,662
(7,462)
210,033
Our royalty rights and investment in Well Lift, Inc. ("WLI") resulted from the separation of our artificial lift technology operations in December 2015. We conveyed our patents and other intellectual
property to WLI and retained a 5% royalty on future gross revenues associated with the technology. We own 17.5% of the common stock of WLI and account for our investment in this private
company at cost less impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions for the identical or a similar investment of the same issuer, if such were
to occur. The Company evaluates the investment for impairment when it identifies any events or changes in circumstances that might have a significant adverse effect on the fair value of the
investment.
Note 8 – Accrued Liabilities and Other
Accrued incentive and other compensation
Asset retirement obligations due within one year
Accrued franchise taxes
Accrued ad valorem taxes
Payable for settled derivatives
Operating lease liability, current
Accrued - other
Accrued liabilities and other
June 30,
2020
June 30,
2019
176,636 $
—
100,978
108,000
265,188
54,290
11,556
716,648 $
369,719
50,244
5,738
100,500
—
—
11,554
537,755
$
$
52
Table of Contents
Note 9 – Asset Retirement Obligations
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Our asset retirement obligations represent the estimated present value of the amount we will incur to plug, abandon, and remediate our producing properties at the end of their productive lives in
accordance with applicable laws. The following is a reconciliation of the beginning and ending asset retirement obligations for the years ended June 30, 2020 and 2019:
Asset retirement obligations — beginning of period
Liabilities incurred
Liabilities settled
Accretion of discount
Revisions to previous estimates
Asset retirement obligations — end of period
Less: current asset retirement obligations
Long-term portion of asset retirement obligations
Years Ended
2020
2019
$
1,610,845
$
1,422,955
(a)
(b)
944,278
(86,592)
146,504
(26,141)
2,588,894
—
$
2,588,894
$
31,268
—
101,506
55,116
1,610,845
(50,244)
1,560,601
(a) Liabilities incurred in fiscal 2020 included $0.9 million from our acquisition of our Hamilton Dome interest and remainder related to facilities at the Delhi field.
(b) We abandoned one well in the Delhi field and four wells in the Hamilton Dome field.
Note 10 – Stockholders' Equity
Common Stock
As of June 30, 2020, we had 32,956,469 shares of common stock outstanding.
The Company began paying quarterly cash dividends on common stock in December 2013. As of June 30, 2020, we have cumulatively paid $70.2 million in cash dividends. We paid dividends of
$10,740,754 and $13,272,058 from retained earnings to our common shareholders during the years ended June 30, 2020 and 2019, respectively. The following table reflects the dividends paid per
common share in each quarter within the respective two fiscal years:
Fourth quarter ended June 30,
Third quarter ended March 31,
Second quarter ended December 31,
First quarter ended September 30,
Fiscal Year
2020
$0.025
$0.100
$0.100
$0.100
2019
$0.100
$0.100
$0.100
$0.100
In May 2015, the Board of Directors approved a share repurchase program covering up to 5 million of the Company's common stock. Since inception of the program through June 30, 2020, the
Company has spent $4.0 million to repurchase 706,858 common shares at an average price of $5.72 per share. Under the program's terms, shares are repurchased only on the open market and in
accordance with the requirements of the SEC. Such shares are initially recorded as treasury stock, then subsequently canceled. The timing and amount of repurchases depends upon several factors,
including financial resources and market and business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at any time.
The Company has also acquired treasury stock from holders of newly vested stock-based awards to fund the recipients' payroll tax withholding obligations. Such shares were valued at fair market
value on the date of vesting.
53
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The treasury shares were subsequently canceled. The following summarized the Company's treasury stock purchases in its last two fiscal years.
Year Ended June 30, 2020:
Shares surrendered for tax withholding upon vesting
Share repurchase program
Total
Year Ended June 30, 2019:
Shares surrendered for tax withholding upon vesting
Share repurchase program
Total
Tax Treatment of Dividends to Recipients
Common Shares Acquired
Average Price per
Share
Treasury Stock Purchases
9,255
440,666
449,921
17,994
430
18,424
$5.90
$5.51
$5.52
$8.57
$6.07
$8.51
$
$
$
$
54,565
2,428,792
2,483,357
154,179
2,612
156,791
Based on our current projections for the fiscal year ended June 30, 2020, we expect that all common stock dividends for this fiscal year will be treated for tax purposes as qualified dividend income to
the recipients. For the fiscal year ended June 30, 2019, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the recipients.
Note 11—Stock-Based Incentive Plan
At the December 8, 2016 annual meeting, the stockholders approved the adoption of the Evolution Petroleum Corporation 2016 Equity Incentive Plan (the “2016 Plan”), which replaced the Evolution
Petroleum Corporation Amended and Restated 2004 Stock Plan (the "2004 Plan"). The 2016 Plan authorizes the issuance of 1,100,000 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, non-
statutory stock options, stock appreciation rights, restricted stock awards, 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, our common stock, including its appreciation in value. As of June 30, 2020, 390,489 shares remained available for grant under the 2016 Plan.
All remaining outstanding awards granted under the 2004 Plan have vested during the year ended June 30, 2020.
Restricted Stock and Contingent Restricted Stock
The Company may award grants of both Restricted Stock and Contingent Restricted Stock as part of its long-term incentive plan. Such grants, which expire after a maximum of four years if unvested,
contain service-based, performance-based, and market-based vesting provisions. The common shares underlying the Restricted Stock grants are issued on the date of grant. Contingent Restricted
Stock grants vest only upon the attainment of typically higher performance-based or market-based vesting thresholds and are issued only upon vesting. Shares underlying Contingent Restricted Stock
awards are reserved from the Plan under which they were granted under.
In July 2019, the new chief executive officer upon his employment received 48,872 shares of serviced-based restricted common stock which vest in three equal amounts on June 30, 2020, 2021 and
2022. He was also awarded a total of 200,000 market-based restricted stock units consisting of four equal tranches, each of which may vest only if its respective stock price requirement is met before
the award term expires. Each tranche has a separate stated price requirement and respective vesting will occur only if, before July 1, 2023, the ninety-day trailing average Company stock share price
equals or exceeds its tranche price requirement.
During the year ended June 30, 2020, we also granted 52,119 service-based and 104,236 market-based Restricted Stock awards to our employees as well as 56,395 service-based awards to the
Company's directors.
54
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Service-based awards vest with continuous employment by the Company, generally in annual installments over a three- or four-year period. Certain awards may contain other vesting periods,
including quarterly installments and one-year vesting. Restricted Stock grants, which vest based on service, are valued at the fair market value on the date of grant and amortized over the service
period.
Performance-based grants vest upon the attainment of earnings, revenue, and other operational goals and require that the recipient remain an employee or director of the Company through the vesting
date. The Company recognizes compensation expense for performance-based awards ratably over the expected vesting period based on the grant date fair value when it is deemed probable, for
accounting purposes, that the performance criteria will be achieved. The expected vesting period may be deemed to be shorter than the term of the award. As of June 30, 2020, there were no
performance-based awards outstanding.
Market-based awards vest if their respective two- or three-year trailing total returns on the Company’s common stock exceed the corresponding total returns of various quartiles of indices consisting
of either peer companies or a broad market index of companies in our industry. More recent market-based awards vest if the average of the Company's closing stock prices over defined quarterly
measurement periods together with accumulated paid dividends exceeds a defined value. The fair values and expected vesting periods of these awards are determined using a Monte Carlo simulation
based on the historical volatility of the Company's total return compared to the historical volatilities of the other companies in the index. Compensation expense for market-based awards is recognized
over the expected vesting period using the straight-line method, so long as the holder remains an employee or director of the Company. Total compensation expense is based on the fair value of the
awards at the date of grant and is independent of vesting or expiration of the awards, except for termination of service.
Assumptions used in the Monte Carlo simulation valuations for the years ended June 30, 2020 and 2019 were:
Weighted average fair value of market-based awards granted
Risk-free interest rate
Expected life in years
Expected volatility
Dividend yield
Unvested Restricted Stock awards at June 30, 2020 consisted of the following:
Service-based awards
Market-based awards
Unvested at June 30, 2020
Award Type
55
Year Ended June 30,
2020
2019
$
3.79 $
1.65% to 1.87%
1.35 to 2.56
38.6% to 43.7%
6% to 7.2%
8.24
2.69%
2.82
41.8%
4.0%
Number of
Restricted
Shares
Weighted
Average
Grant-Date
Fair Value
155,318 $
129,710
285,028 $
5.88
5.10
5.53
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table sets forth the Restricted Stock transactions for the year ended June 30, 2020:
Unvested at July 1, 2019
Service-based shares granted
Market-based shares granted
Vested
Forfeited
Unvested at June 30, 2020
The following is a summary of Restricted Stock that vested during the last two fiscal years:
Vesting-date intrinsic value of Restricted Stock
Grant-date fair value of vested Restricted Stock
Number of awards that vested
The following table summarizes Contingent Restricted Stock activity for the year ended June 30, 2020:
Unvested at July 1, 2019
Market-based awards granted
Vested
Unvested at June 30, 2020
All of these outstanding awards at June 30, 2020 are market-based awards.
The following is a summary of Contingent Restricted Stock vestings for the last two fiscal years:
Vest-date intrinsic value of Contingent Restricted Stock
Grant-date fair value of vested Contingent Restricted Stock
Number of awards that vested
Stock-based Compensation Expense
Number of
Restricted
Shares
Weighted
Average
Grant-Date
Fair Value
Unamortized
Compensation Expense
at June 30, 2020
Weighted Average
Remaining Amortization
Period (Years)
176,683 $
8.09 $
—
157,386
104,236
(104,159)
(49,118)
5.73
4.34
7.19
9.35
285,028 $
5.53 $
1,001,477
1.74
Year Ended June 30,
2020
2019
$
$
477,647 $
748,893 $
104,159
1,141,631
909,678
133,776
Number of
Restricted
Stock Units
Weighted
Average
Grant-Date
Fair Value
Unamortized
Compensation Expense at
June 30, 2020
Weighted Average
Remaining Amortization
Period (Years)
10,156 $
200,000
(10,156)
200,000 $
3.42
3.50
3.42
3.50 $
156,591
0.52
Year Ended June 30,
2020
2019
$
$
60,225 $
34,734 $
10,156
105,227
60,266
10,629
For the years ended June 30, 2020, and 2019, we recognized stock-based compensation expense related to Restricted Stock and Contingent Restricted Stock grants of $1,285,663 and $888,162,
respectively.
56
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 12 – Supplemental Disclosure of Cash Flow Information
Income taxes paid
Non-cash transactions:
Decrease in accrued purchases of property and equipment
Oil and natural gas property costs attributable to the recognition of asset retirement obligations
Note 13 – Income Taxes
June 30,
2020
2019
$
1,241,538 $
2,762,919
(212,456)
918,137
(1,603,290)
86,384
We file a consolidated federal income tax return in the United States of America in addition to 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, 2020 and 2019. We believe that we have
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 our 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 years ended June 30, 2016 through June 30, 2019 for federal tax purposes and for the years ended June 30, 2015 through June 30, 2019 for state tax purposes. To the extent we
utilize net operating losses generated in earlier years, such earlier years may also be subject to audit.
The components of our income tax provision (benefit) are as follows:
Current:
Federal
State
Total current income tax provision (benefit)
Deferred:
Federal
State
Total deferred income tax provision (benefit)
Total income tax provision (benefit)
June 30, 2020
June 30, 2019
$
(2,264,850) $
345,522
(1,919,328)
(266,482)
4,814
(261,668)
$
(2,180,996) $
2,343,512
371,593
2,715,105
387,541
379,715
767,256
3,482,361
For the years ended June 30, 2020 and 2019, respectively, we recognized income tax benefit of $(2.2) million and an income tax expense of $3.5 million reflecting corresponding effective tax rates of
(58.1)% and 18.5%, respectively. During the current year we undertook a project to seek potential cash tax savings opportunities identifying available Enhanced Oil Recovery credits (“EOR credits”)
related to our interests in the Delhi field. To take advantage of the EOR credits, we amended federal and state tax returns for the years ended June 30, 2017 and 2018 and incorporated the associated
impacts into our 2019 tax returns. Principally as a result of the EOR credits, the Company recorded a net tax benefit of $2.8 million during the current year. Relative to the foregoing, the Company
has a $3.2 million receivable for income tax refunds at June 30, 2020.
57
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Our effective tax rate will typically differ from the statutory federal rate as a result of state income taxes, primarily in the State of Louisiana, and differences related to percentage depletion in excess
of basis, stock-based compensation, and other permanent differences. The following table presents the reconciliation of our income taxes calculated at the statutory federal tax rate to the income tax
provision (benefit) in our financial statements.
June 30, 2020
% of Income
Before Income
Taxes
June 30, 2019
% of Income
Before Income
Taxes
Income tax provision (benefit) computed at the statutory federal rate:
$
788,776
21.0 % $
3,960,480
Reconciling items:
Return to provision adjustments including returns amended for EOR credits
Depletion in excess of tax basis
State income taxes, net of federal tax benefit
Permanent differences related to stock-based compensation and other
Expiration of Section 382 tax loss carryforwards
Change in valuation allowance for Section 382 tax loss carryforwards
Other
Income tax provision (benefit)
(2,823,527)
(412,215)
272,962
22,408
—
—
(29,400)
(75.2)%
(11.0)%
7.3 %
0.6 %
— %
— %
(0.8)%
—
(982,302)
593,533
(73,671)
127,410
(127,410)
(15,679)
$
(2,180,996)
(58.1)% $
3,482,361
21.0 %
— %
(5.1)%
3.1 %
(0.4)%
0.7 %
(0.7)%
(0.1)%
18.5 %
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.
Deferred tax assets:
Non-qualified stock-based compensation
Net operating loss carry-forwards
Derivative losses
Other
Gross deferred tax assets
Valuation allowance
Total deferred tax assets
Deferred tax liability:
Oil and natural gas properties
Total deferred tax liability
Net deferred tax liability
Asset (Liability)
June 30, 2020
June 30, 2019
$
234,559
$
78,197
401,382
53,159
767,297
(53,218)
714,079
159,090
496,082
—
20,713
675,885
(53,218)
622,667
(11,775,102)
(11,775,102)
$
(11,061,023)
$
(11,945,358)
(11,945,358)
(11,322,691)
As of June 30, 2020, we had a federal tax loss carryforward of approximately $0.6 million that we acquired through a reverse merger in May 2004. The majority of the tax loss carryforwards from the
reverse merger expired without being utilized. We will be able to utilize a maximum of $0.2 million of these carryforwards in equal annual amounts of $39,648 through 2023 and the balance is not
able to be utilized based on the provisions of IRC Section 382. We have recorded a valuation allowance for the portion of our net operating loss that is limited by IRC Section 382.
58
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 14 – Net Income Per Share
The following table sets forth the computation of basic and diluted net income per share:
Numerator
Net income attributable to common shareholders
Denominator
Weighted average number of common shares – Basic
Effect of dilutive securities:
Contingent restricted stock grants
Weighted average number of common shares and dilutive potential common shares used in diluted EPS
Net income per common share – Basic
Net income per common share – Diluted
Outstanding Potential Dilutive Securities
Contingent Restricted Stock grants
Outstanding Potential Dilutive Securities
Contingent Restricted Stock grants
Note 15 – Senior Secured Credit Agreement
June 30,
2020
2019
5,937,072 $
15,377,066
33,031,149
33,160,283
1,942
33,033,091
0.18 $
0.18 $
9,435
33,169,718
0.46
0.46
$
$
$
Weighted
Average
Exercise Price
Outstanding at
June 30, 2020
$
—
200,000
Weighted
Average
Exercise Price
Outstanding at
June 30, 2019
$
—
10,156
On April 11, 2016, the Company entered into a three-year, senior secured reserve-based credit facility ("Facility") in an amount up to $50 million. On May 25, 2018, we entered into the third
amendment to our credit agreement governing the revolving credit facility to, among other things, extend the maturity date to April 11, 2021. On December 31, 2018, we entered into the fourth
amendment to our credit agreement governing the revolving credit facility to broaden the definition for the Use of Proceeds.
On April 27, 2020, the Company completed its spring redetermination of the Facility resulting in a decrease of the borrowing base to $27 million. The Company's ability to access the borrowing base
is also limited by its compliance with certain financial covenants, including a debt service ratio covenant, described below. As a consequence of declining oil prices adversely impacting the
Company's EBITDA upon which the debt service ratio is calculated, at June 30, 2020 the Company's borrowings would have been limited to approximately $8 million. There are no borrowings
outstanding under the Facility, which matures on April 11, 2021. The Facility is secured by substantially all of the reserves associated with the Delhi field.
As of June 30, 2020, the Company was in compliance with all financial covenants and there were no amounts outstanding under the Facility.
Under the Facility the borrowing base shall be determined semiannually as of every May 15 and November 15 during the term of the Facility.
Borrowings from the Facility may be used for the acquisition and development of oil and gas properties, investments in cash flow generating assets complimentary to the production of oil and gas,
and for letters of credit and other general corporate purposes.
The Facility carries a commitment fee of 0.25% per annum on the undrawn portion of the borrowing base. Any borrowings under the Facility will bear interest, at the Company’s option, at either
Libor plus 2.75% or the Prime Rate, as defined, plus
59
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
1.00%. The Facility contains financial covenants including a requirement that the Company maintain, as of the last day of each fiscal quarter, (a) a maximum total leverage ratio of not more than 3.00
to 1.00, (b) a debt service coverage ratio of not less than 1.10 to 1.00, and (c) a consolidated tangible net worth of not less than $50 million, all as defined under the Facility.
In connection with this agreement, the Company incurred $168,972 of debt issuance costs. Such costs were capitalized in Other Assets and are being amortized to expense. The unamortized balance
in debt issuance costs related to the Facility was $11,888 as of June 30, 2020.
Note 16 – Commitments and Contingencies
We are subject to various claims and contingencies in the normal course of business. From time to time, we receive communications from government or regulatory agencies concerning
investigations or allegations of noncompliance with laws or regulations in jurisdictions in which we operate our business. At a minimum, we disclose such matters if we believe it is reasonably
possible that a future event or events will confirm a loss through impairment of an asset or the incurrence of a liability. We accrue a loss if we believe it is probable that a future event or events will
confirm a loss, we can reasonably estimate such loss, and we do not accrue future legal costs related to that loss. Furthermore, we will disclose any matter that is unasserted if we consider it probable
that a claim will be asserted and there is a reasonable possibility that the outcome will be unfavorable. We expense legal defense costs as they are incurred.
Note 17 – Concentrations of Credit Risk
Major Customers. As a non-operator, we presently market our production through the field operators. The majority of our operated gas, oil and condensate production is sold to purchasers under
short-term (less than 12 months) contracts at market-based prices. The following table identifies customers from whom we derived 10 percent or more of our net oil and natural gas revenues during
the years ended June 30, 2020 and 2019. The loss of either one of our oil purchasers or disruption to their respective pipelines could adversely affect our net realized pricing and potentially our near-
term production levels. The loss of our NGL purchaser, who trucks NGLs from the field, would not be expected to have a material adverse effect on our operations.
Customer
Plains Marketing L.P. (Delhi field oil)
Merit Energy Company (Hamilton Dome field oil)
Third Coast Midstream (Delhi field NGLs)
Total
Year Ended June 30,
2020
2019
87%
10%
3%
100%
94%
—%
6%
100%
Accounts Receivable. Substantially all of our accounts receivable result from oil and natural gas sales to third parties in the oil and natural gas industry. Our concentration of customers in this
industry may impact our overall credit risk.
Cash and Cash Equivalents. We are subject to concentrations of credit risk with respect to our cash and cash equivalents, which we attempt to minimize by maintaining our cash and cash equivalents
in high quality money market funds. At times, cash balances may exceed limits federally insured by the Federal Deposit Insurance Corporation ("FDIC").
Note 18 – Retirement Plan
We have a Company sponsored 401(k) Retirement Plan ("Plan") which is available to all full-time employees. We currently match 100% of employees' contributions to the Plan, to a maximum of the
first 6% of each participant's eligible compensation, subject to IRS limits, with Company contributions fully vested when made. Our matching contributions to the Plan totaled $41,127 and $52,809
for the years ended June 30, 2020 and 2019, respectively.
Note 19 – Derivatives
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, 2020, the Company did not post collateral under its one open derivative contract as trades were uncollateralized.
60
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company may utilize fixed-price swaps or costless put/call collars to hedge a portion of its anticipated future production. 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. 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. 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.
Realized (gain) loss
Unrealized (gain) loss
Net (gain) loss on derivative contracts
Years Ended June 30,
2020
2019
$
$
(528,139)
$
1,911,343
1,383,204
$
—
—
—
The Company’s derivative contract is recorded at fair market value and is included in the consolidated balance sheets as an asset or a liability. Refer to Note 20 – Fair Value Measurement for the table
summarizing the location and fair value amounts of the Company’s open derivative contract in the consolidated balance sheet as of June 30, 2020. The Company did not have any open positions as of
June 30, 2019.
The following sets forth a summary of the Company’s open crude oil derivative positions as of June 30, 2020.
Period
July 2020 to December 2020
Type of Contract
Fixed-Price Swap
Volumes in Barrels
Price / Price Range
Weighted Average Floor
Price per Bbl.
Weighted Average Ceiling
Price per Bbl.
257,600
$32
$32
$—
The Company presents the fair value of its derivative contracts at the gross amounts in the consolidated balance sheets. The Company enters into an International Swap Dealers Association Master
Agreement ("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 20 – 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.
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 (exit price). ASC 820 – Fair Value Measurement ("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
61
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 the 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; this 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 in this report. The table below sets forth the Company’s derivative assets and liabilities whose
fair value measurements all reflect Level 2 inputs as of June 30, 2020. The Company did not have any open positions at June 30, 2019.
Asset (Liability)
Current derivative assets
Current derivative contract liabilities
Total
Gross Amounts
Recognized
$
—
1,911,343
$
1,911,343
June 30, 2020
Gross Amounts
Offset in the
Consolidated
Balance Sheet
Net Amounts
Presented in the
Consolidated
Balance Sheets
—
— $
—
1,911,343
— $
1,911,343
Other Fair Value Measurements. The initial measurement and any subsequent revision of asset retirement obligations at fair value are calculated using discounted future cash flows of internally
estimated costs. Significant Level 3 inputs used in the calculation of asset retirement obligations 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.
Note 21 – Supplemental Disclosures about Oil and Natural Gas Producing Properties (unaudited)
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. 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, geological 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. Exploration and development costs also include amounts incurred due to the recognition
of asset retirement obligations of $918,137 and $86,384 during the years ended June 30, 2020 and 2019, respectively.
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
For the Years Ended June 30,
2020
2019
$
$
9,337,716 $
—
—
—
—
—
2,430,510
11,768,226 $
5,229,235
5,229,235
The following estimates of the net proved oil and natural gas reserves of our oil and gas properties located entirely within the United States of America are based on evaluations prepared by third-
party reservoir engineers. Reserve volumes and values were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2020 and 2019, SEC methodology requires the
application of the previous 12 months 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.
62
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Proved oil and natural gas reserves are estimated quantities of crude oil, natural gas, and natural gas liquids that geological 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 crude oil, natural gas liquids , and natural gas reserves and changes in quantities of proved developed and undeveloped reserves for each of the periods indicated are as
follows:
Crude Oil
(Bbls)
Natural Gas
Liquids
(Bbls)
Natural Gas
(Mcf)
BOE
Proved developed and undeveloped reserves:
June 30, 2018
Revisions of previous estimates (a)
Improved recovery, extensions and discoveries
Sales of minerals in place
Production (sales volumes)
June 30, 2019
Revisions of previous estimates (b)
Improved recovery, extensions and discoveries
Purchase of reserves in place (c)
Sales of minerals in place
Production (sales volumes)
June 30, 2020
Proved developed reserves:
June 30, 2018
June 30, 2019
June 30, 2020
Proved undeveloped reserves:
June 30, 2018
June 30, 2019
June 30, 2020
8,090,190
152,420
—
—
(626,879)
7,615,731
(2,177,787)
—
3,426,756
—
(638,464)
8,226,236
6,291,850
6,273,907
6,577,731
1,798,340
1,341,824
1,648,505
1,277,772
199,078
—
—
(112,089)
1,364,761
734,169
—
—
—
(106,340)
1,992,590
993,741
1,124,302
1,777,236
284,031
240,459
215,354
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9,367,962
351,498
—
—
(738,968)
8,980,492
(1,443,618)
—
3,426,756
—
(744,804)
10,218,826
7,285,591
7,398,209
8,354,967
2,082,371
1,582,283
1,863,859
(a) The positive crude oil revision resulted from better production performance during fiscal 2018. The negative NGL revision results primarily from lower expectations for ultimate NGL
recoveries from the plant based on production data subsequent to the commencement of plant production.
(b) Primarily due to negative revisions at Hamilton Dome field reflecting the impact of pricing on future economic production. In March 2020 when the oil price decreased, the operator began
to shut-in wells that were not economic at those lower prices to try and keep the field cash flow positive. The use of an SEC price deck for our reserves at June 30, 2020, precludes volumes that
are uneconomic at such prices. Positive NGL revisions at Delhi field reflect adjusted methodology of forecasting NGLs independently from the oil production as forecasted by our independent
reservoir engineering firm.
(c) On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field.
Standardized Measure of Discounted Future Net Cash Flows
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 requires that net
63
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 our 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 relating to our 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
our proved reserves.
The standardized measure of discounted future net cash flows related to proved oil and natural gas reserves as of June 30, 2020 and 2019 are as follows:
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
As of June 30,
2020
399,358,481 $
(240,399,715)
(24,623,426)
(21,982,469)
112,352,871
(49,862,035)
62,490,836 $
2019
524,037,200
(208,539,679)
(18,395,252)
(55,881,997)
241,220,272
(114,488,230)
126,732,042
$
$
Future cash inflows represent expected revenues from production of period-end quantities of proved reserves based on the previous 12 months 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
$
47.37
n/a $
61.62
n/a
There were no natural gas reserves in 2020 and 2019. The NGL prices utilized for future cash inflows were based on historical prices received, where available. For the Delhi NGL plant, we utilized
historical prices for the expected mix and net pricing of natural gas liquid products projected to be produced by the plant.
For the Years Ended June 30,
2020
2019
Oil
(Bbl)
Gas
(MMBtu)
Oil
(Bbl)
Gas
(MMBtu)
64
Table of Contents
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
A summary of the changes in the standardized measure of discounted future net cash flows applicable to proved crude oil, natural gas liquids, and natural gas reserves is as follows:
Balance, beginning of the fiscal year
Net changes in sales prices and production costs related to future production
Changes in estimated future development costs
Sales of oil and gas produced during the period, 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
Development costs incurred during the period
Accretion of discount
Net change in discounted income taxes
Net changes in timing of production and other
Balance, end of the fiscal year
Note 22 – Selected Quarterly Financial Data (Unaudited)
2020
Revenues
Income (loss) from operations
Net income (loss) attributable to common shareholders
Basic earnings (loss) per common share
Diluted earnings (loss) per common share
2019
Revenues
Income from operations
Net income attributable to common shareholders
Basic earnings per common share
Diluted earnings per common share
For the Years Ended June 30,
$
2020
126,732,042 $
(83,857,342)
(4,099,792)
(16,093,794)
—
(6,746,316)
10,364,875
1,431,444
16,266,663
17,078,591
1,414,465
2019
118,958,414
23,753,518
833,494
(28,962,837)
—
6,129,847
—
2,089,139
14,604,387
(2,795,183)
(7,878,737)
$
62,490,836 $
126,732,042
First
Second
Third (1)
Fourth
9,152,215 $
3,274,019 $
2,792,820 $
0.08 $
0.08 $
9,381,615 $
2,249,764 $
1,764,918 $
0.05 $
0.05 $
7,712,619 $
951,814 $
3,710,159 $
0.11 $
0.11 $
3,352,847
(2,786,164)
(2,330,825)
(0.07)
(0.07)
First (2)
Second
Third
Fourth
12,307,079 $
5,994,927 $
5,795,801 $
0.18 $
0.17 $
11,048,118 $
4,733,747 $
3,904,565 $
0.12 $
0.12 $
9,501,028 $
2,952,955 $
2,398,875 $
0.07 $
0.07 $
10,373,396
3,955,194
3,277,825
0.10
0.10
$
$
$
$
$
$
$
$
$
$
(1) The third quarter of fiscal 2020 was impacted by a $2.8 million tax benefit attributable to the EOR tax credits.
(2) The first quarter of fiscal 2019 included other income of $1.1 million for the Enduro transaction breakup fee.
65
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 this Company's management, including our
Chief Executive Officer and Chief 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 the Company's management, including our
Chief Executive Officer and Chief 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 Chief Executive Officer and Chief 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 Report on Internal Control Over Financial Reporting
The Company's 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, the company's principal executive and principal financial officers and effected by the Company's 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 Chief Executive Officer and the Chief Financial Officer, an evaluation was conducted on the effectiveness of the Company's 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 the
Company maintained effective internal control over financial reporting as of June 30, 2020.
Effective April 27, 2020, the SEC adopted certain amendments to the accelerated filer and large accelerated filer definitions to more appropriately tailor the types of issuers that are included in the
categories of accelerated and large accelerated filers and to promote capital formation, preserve capital, and reduce unnecessary burdens for certain smaller issuers while maintaining investor
protections. As a result of the amendments, certain low-revenue issuers will remain obligated, among other things, to establish and maintain internal control over financial reporting and have
management assess the effectiveness of its internal control over financial reporting, but they will not be required to have their management’s assessment of the effectiveness of internal controls over
financial reporting attested to and reported on by an independent auditor. As a result, the effectiveness of our internal control over financial reporting at June 30, 2020 has not been audited by Moss
Adams LLP, the independent registered public accounting firm that also audited our financial statements.
66
Table of Contents
Changes in Internal Control Over Financial Reporting
There has been no change in the Company's internal control over financial reporting during the fourth quarter ended June 30, 2020 that has materially affected, or is reasonably likely to materially
affect, the Company's internal control over financial reporting.
Item 9B. Other Information
None.
67
Table of Contents
Item 10. Directors, Executive Officers, and Corporate Governance
PART III
Incorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's 2020 fiscal year.
Item 11. Executive Compensation
Incorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's 2020 fiscal year.
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Incorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's 2020 fiscal year.
Item 13. Certain Relationships and Related Transactions, and Director Independence
Incorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's 2020 fiscal year.
Item 14. Principal Accountant Fees and Services
Incorporated by reference to the Company's Proxy Statement to be filed with the Commission pursuant to Regulation 14A within 120 days of the end of the Company's 2020 fiscal year.
68
Table of Contents
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as part of this report:
1. Financial Statements.
PART IV.
Our consolidated financial statements are included in Part II, Item 8 of this report:
Reports of Independent Registered Public Accounting Firm
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
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 Master 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.
69
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.
Date: September 10, 2020
Evolution Petroleum Corporation
By:
/s/ JASON E. BROWN
Jason E. Brown
President and Chief Executive Officer
(Principal Executive Officer)
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 10, 2020
September 10, 2020
September 10, 2020
September 10, 2020
September 10, 2020
September 10, 2020
September 10, 2020
September 10, 2020
/s/ ROBERT S. HERLIN
Robert S. Herlin
/s/ JASON E. BROWN
Jason E. Brown
/s/ DAVID JOE
David Joe
/s/ RODERICK SCHULTZ
Roderick Schultz
/s/ EDWARD J. DIPAOLO
Edward J. DiPaolo
/s/ WILLIAM DOZIER
William Dozier
/s/ KELLY W. LOYD
Kelly W. Loyd
/s/ MARRAN H. OGILVIE
Marran H. Ogilvie
70
Chairman of the Board
President and Chief Executive Officer
(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President, Chief Accounting Officer (Principal Accounting Officer)
Lead Director
Director
Director
Director
Table of Contents
EXHIBIT INDEX
EXHIBIT
NUMBER
MASTER EXHIBIT INDEX
DESCRIPTION
3.1 Articles of Incorporation (previously filed as an exhibit to Form 8-K on February 7, 2002)
3.2 Certificate of Amendment to Articles of Incorporation (previously filed as an exhibit to Form 8-K on February 7, 2002)
3.3 Certificate of Amendment to Articles of Incorporation (previously filed as an exhibit to Form SB 2/A on October 19, 2005)
3.4 Certificate of Designation of Rights and Preferences for 8.5% Series A Cumulative Preferred Stock (previously filed as an exhibit to Form 8-K on June 29, 2011)
3.5 Amended Bylaws (previously filed as Exhibit 2.1 to Form 10KSB on March 31, 2004)
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
Specimen form of the Company's Common Stock Certificate (previously filed as an exhibit to Form S-3 on June 19, 2013)
2004 Stock Plan (previously filed as an exhibit to the Company's Definitive Information Statement on Schedule 14C on August 9, 2004)
Amended and Restated 2004 Stock Plan, adopted December 4, 2007 (previously filed as Annex A to the Company's Definitive Information Statement on Schedule 14A on
October 29, 2007)
Amendment to Amended and Restated 2004 Stock Plan, adopted December 5, 2011 (previously filed as Annex A to the Company's Definitive Information Statement on
Schedule 14A on October 28, 2011)
Form of Stock Option Agreement for the Natural Gas Systems 2004 Stock Plan (previously filed as an exhibit to Form 8-K on April 8, 2005)
Form of Restricted Stock Agreement (previously filed as an exhibit to Form SC TO-I on May 15, 2009)
Form of Contingent Performance Stock Grant under the Amended and Restated 2004 Stock Plan (previously filed as an exhibit to Form 10-Q on November 7, 2014 )
2016 Equity Incentive Plan (previously filed as an exhibit to the Company's Form 10-Q on February 8, 2017)
4.9 Majority Voting Policy for Directors (previously filed as an exhibit to the Company's Current Report on Form 8-K on October 31, 2012)
4.10
Form of Restricted Stock Agreement under 2016 Equity Incentive Plan (previously filed as an exhibit to Form 10-Q on February 8, 2018)
4.11
Form of Contingent Restricted Stock Agreement under 2016 Equity Incentive Plan (previously filed as an exhibit to Form 10-Q on February 8, 2018)
4.12
Form of Restricted Stock Agreement under 2016 Equity Incentive Plan as Revised on July 9, 2019 (previously filed as an exhibit to Form 10-K on September 13, 2019)
4.13
Form of Performance Share Unit Award Agreement under 2016 Equity Incentive Plan as Revised on July 9, 2019 (previously filed as an exhibit to Form 10-K on September 13,
2019)
10.1
Purchase and Sale Agreement I, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006 (previously filed as an exhibit to Form 8-K on June 16, 2006)
10.2
Purchase and Sale Agreement II, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006 (previously filed as an exhibit to Form 8-K on June 16, 2006)
10.3 Unit Operating Agreement, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006 (previously filed as an exhibit to Form 8-K on June 16, 2006)
10.4
10.5
Conveyance, Assignment and Bill of Sale Agreement, by and between NGS Sub Corp. and Denbury Onshore, LLC, dated May 8, 2006 (previously filed as an exhibit to
Form 8-K on June 16, 2006)
Settlement Agreement, dated June 24, 2016, by and among Denbury Onshore, LLC, Denbury Resources Inc., NGS Sub Corp., Tertiaire Resources Company, and the Company
(previously filed as an exhibit to Form 10-K on September 9, 2016)
10.6
Form of Indemnification Agreement for Officers and Directors, as adopted on September 20, 2006 (previously filed as an exhibit to Form 8-K on September 22, 2006)
10.7 Credit Agreement dated April 11, 2016 between Evolution Petroleum Corporation and MidFirst Bank (previously filed as an exhibit to Form 8-K on April 15, 2016)
10.8
First Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation and Midfirst Bank effective October 18, 2016 (previously filed as an
exhibit to Form 10-Q on November 9, 2016)
71
Table of Contents
EXHIBIT
NUMBER
10.9
10.10
10.11
DESCRIPTION
Second Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation and Midfirst Bank effective February 1, 2018 (previously filed as an
exhibit to Form 10-Q on February 8, 2018)
Third Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation and Midfirst Bank effective May 25, 2018 (previously filed on
September 10, 2018 as an exhibit to Form 10-K)
Fourth Amendment to Credit Agreement dated April 11, 2016, between Evolution Petroleum Corporation and Midfirst Bank effective December 31, 2018 (previously filed on
February 8, 2019 as an exhibit to Form 10-Q)
10.12
Employment Offer Letter to Jason E. Brown dated July 8, 2019 (previously filed as an exhibit to Form 10-K on September 13, 2019)
14.1 Code of Business Conduct and Ethics (previously filed as an exhibit to Form 8-K on May 4, 2006)
21.1
List of Subsidiaries of Evolution Petroleum Corporation (filed herein)
23.1 Consent of Moss Adams LLP (filed herein)
23.2 Consent of DeGolyer & MacNaughton (filed herein)
31.1
31.2
Certification of Chief 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 (filed herein)
Certification of President and Chief 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 (filed herein)
32.1 Certification of Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herein)
32.2 Certification of President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (filed herein)
99.1
The summary of DeGolyer and MacNaughton's Report as of June 30, 2020, on oil and gas reserves (SEC Case) dated August 10, 2020 and certificate of qualification (filed
herein)
101.INS XBRL Instance Document
101.SCH XBRL Taxonomy Extension Schema Document
101.CAL XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF XBRL Taxonomy Extension Definition Linkbase Document
101.LAB XBRL Taxonomy Extension Label Linkbase Document
101.PRE XBRL Taxonomy Extension Presentation Linkbase Document
72
List of Subsidiaries of Evolution Petroleum Corporation
Name of Subsidiary
Jurisdiction of Incorporation or
Organization
Exhibit 21.1
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.)
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Texas
Louisiana
Texas
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statements (Form S-3/A No. 333-231412, Form S-3 No. 333-193899, Form S-8 Nos. 333‑152136, 333‑140182,
333‑183746 and 333‑216098) of Evolution Petroleum Corporation of our report dated September 10, 2020, relating to the consolidated financial statements of Evolution Petroleum
Corporation, which report appears in the Form 10-K of Evolution Petroleum Corporation for the year ended June 30, 2020 (and expresses an unqualified opinion), and to the
reference to our firm under the heading “Experts” in the Prospectuses, which are part of those Registration Statements.
Exhibit 23.1
/s/ Moss Adams LLP
Houston, Texas
September 10, 2020
EXHIBIT 23.2
DEGOLYER AND MACNAUGHTON
500 I SPRING ALLEY ROAD
SUITE 800 EAST
DALLAS, TEXAS 75244
September 10, 2020
Evolution Petroleum Corporation 1155 Dairy Ashford, Suite 425
Houston, Texas 77079
Ladies and 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 10, 2020, and to the inclusion of information taken from our report entitled "Report as of June 30, 2020 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, 2020. 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. 333-152136, 333-140182,
333-183746, and 333-216098), 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
EXHIBIT 31.1
CERTIFICATION
I, Jason E. Brown, President and Chief Executive Officer 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)
b)
c)
d)
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;
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;
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
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)
b)
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
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 10, 2020
/s/ JASON E. BROWN
Jason E. Brown
President and Chief Executive Officer
EXHIBIT 31.2
I, David Joe, Chief Financial Officer of Evolution Petroleum Corporation, certify that:
1.
I have reviewed this annual report on Form 10-K of Evolution Petroleum Corporation;
CERTIFICATION
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 10, 2020
/s/ DAVID JOE
David Joe
Chief Financial Officer
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, Jason E. Brown, President and Chief Executive Officer 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, 2020 (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 10, 2020.
/s/ JASON E. BROWN
Jason E. Brown
President and Chief Executive Officer
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, David Joe, Chief Financial Officer 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, 2020 (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 10, 2020.
/s/ DAVID JOE
David Joe
Chief Financial Officer
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 DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 August 10, 2020 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, 2020, of the extent and value of the estimated net proved oil, natural gas liquids (NGL), and gas reserves of the Delhi field in Louisiana and the proved developed producing oil and gas reserves in 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. This evaluation was completed on August 10, 2020. Evolution has represented that these properties account for 100 percent on a net equivalent barrel basis of Evolution’s net proved reserves as of June 30, 2020. 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 Securities and Exchange Commission (SEC) of the United States. 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, 2020. 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 of the estimated net reserves. Future net revenue is calculated by
deducting production taxes, ad valorem taxes, operating expenses, capital costs, and
2 DeGolyer and MacNaughton 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 nominal discount rate of 10 percent per year compounded monthly 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 prices and costs consistent with the effective date of this report, including consideration of
3 DeGolyer and MacNaughton changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: 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:
4 DeGolyer and MacNaughton (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.
5 DeGolyer and MacNaughton (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.” 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 analyses 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 constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses,
6 DeGolyer and MacNaughton 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. 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, 2020, 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 through June 30, 2020. Cumulative production, as of June 30, 2020, was deducted from the estimated gross ultimate recovery to estimate gross reserves. Oil 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 and NGL reserves included in this report are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United States gallons. 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 reserves are located. Gas quantities included in this report are expressed in millions of
7 DeGolyer and MacNaughton cubic feet (MMcf). All of the produced gas is consumed as fuel or lost in processing, so sales gas reserves were estimated herein to be zero. 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 are associated 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 and NGL Prices Evolution has represented that the oil and NGL prices were based on West Texas Intermediate (WTI) pricing, 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. The oil and NGL prices were calculated using differentials furnished by Evolution to the reference price of $47.37 per barrel and held constant thereafter. The volume-weighted average prices attributable to the estimated proved reserves over the lives of the properties were $46.37 per barrel of oil and $9.00 per barrel of NGL. 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 Delh
carbon dioxide flood has been qualified as a tertiary recovery project and that no oil production
8 DeGolyer and MacNaughton 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. Operating Expenses, Capital Costs, and Abandonment Costs 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 2020 values, 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, 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.
9 DeGolyer and MacNaughton 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. Summary of Conclusions The estimated net proved reserves, as of June 30, 2020, 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, 2020 Oil NGL Sales Gas (Mbbl) (Mbbl) (MMcf) Proved Developed 6,578 1,777 0 Undeveloped 1,648 216 0 Total Proved 8,226 1,993 0
10 DeGolyer and MacNaughton The estimated future revenue to be derived from the production and sale of the net proved reserves, as of June 30, 2020, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$): Proved Proved Total Developed Undeveloped Proved (M$) (M$) (M$) Future Gross Revenue 316,610 82,748 399,358 Production Taxes 2,899 34 2,933 Ad Valorem Taxes 5,258 662 5,920 Operating Expenses 189,074 42,473 231,547 Capital Costs 6,292 8,600 14,892 Abandonment Costs 9,054 677 9,731 Future Net Revenue 104,033 30,302 134,335 Present Worth at 10 Percent 67,264 8,029 75,293 Note: Future income taxes have not 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, 2020, 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 /s/ Gregory K. Graves Gregory K. Graves, P.E. {SEAL} Vice President DeGolyer and MacNaughton
DeGolyer and MacNaughton CERTIFICATE of QUALIFICATION I, Gregory K. Graves, 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 a Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Evolution Petroleum Corporation dated August 10, 2020, and that I, as Vice President, was responsible for the preparation of this report of third party. 2. That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations. /s/ Gregory K. Graves Gregory K. Graves, P.E. {SEAL} Vice President DeGolyer and MacNaughton