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, 2019
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
Trading Symbol(s)
Name of Each Exchange On Which Registered
Common Stock, $0.001 par value
EPM
NYSE American
Securities registered pursuant to Section 12(g) of the Act:
None
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes:
No:
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes:
No:
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for
the past 90 days. Yes:
No:
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to
be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes:
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 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, 2018, the last business day of the registrant’s
most recently completed second fiscal quarter, based on the closing price on that date of $6.75 on the NYSE American was $158,319,105.
The number of shares outstanding of the registrant's common stock, par value $0.001, as of September 6, 2019, was 33,064,797.
Portions of the proxy statement related to the registrant's 2019 Annual Meeting of Stockholders to be filed within 120 days of the end of the fiscal year covered
by this report are incorporated by reference into Part III of this report.
DOCUMENTS INCORPORATED BY REFERENCE
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
2019 ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
Forward-Looking Statements
Glossary of Selected Petroleum Terms
PART I
Item 1.
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4.
Mine Safety Disclosures
PART II
Item 5.
Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Item 6.
Selected Financial Data
Item 7.
Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes In and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
PART III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11.
Executive Compensation
Item 12.
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14.
Principal Accounting Fees and Services
PART IV
Item 15.
Exhibits and Financial Statement Schedules
Item 16.
From 10-K Summary
Glossary of Selected Petroleum Terms
Signatures
Exhibit Index
ii
iii
1
13
21
21
21
21
22
22
25
26
34
36
62
62
62
63
63
63
63
63
63
64
64
64
iii
65
66
We use the terms, "EPM," "Company," "we," "us" and "our" to refer to Evolution Petroleum Corporation, and unless the
context otherwise requires, its wholly-owned subsidiaries.
i
FORWARD-LOOKING STATEMENTS
This Form 10-K and the information referenced herein contains forward-looking statements within the meaning of the
Private Securities Litigations Reform Act of 1995, Section 27A of the Securities Act of 1933 and Section 21E of the Securities
Exchange Act of 1934. The words “plan,” “expect,” “project,” “estimate,” “assume,” “believe,” “anticipate,” “intend,”
“budget,” “forecast,” “predict” and other similar expressions are intended to identify forward-looking statements. These
statements appear in a number of places and include statements regarding our plans, beliefs or current expectations, including
the plans, beliefs and expectations of our officers and directors. When considering any forward-looking statement, you should
keep in mind the risk factors that could cause our actual results to differ materially from those contained in any forward-looking
statement. Important factors that could cause actual results to differ materially from those in the forward-looking statements
herein include the timing and extent of changes in commodity prices for oil and natural gas, operating risks and other risk
factors as described in Part I, Item 1A, "Risk Factors" and elsewhere in this report and as also may be described from time to
time in our future reports we file with the Securities and Exchange Commission. You should read such information in
conjunction with our consolidated condensed financial statements and related notes and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" in this report. There also may be other factors that we cannot
anticipate or that are not described in this report, generally because we do not currently perceive them to be material. Such
factors could cause results to differ materially from our expectations.
Forward-looking statements speak only as of the date they are made, and we do not undertake to update these statements
other than as required by law. You are advised, however, to review any further disclosures we make on related subjects in our
periodic filings with the Securities and Exchange Commission.
ii
GLOSSARY OF SELECTED PETROLEUM TERMS
The following abbreviations and definitions are terms commonly used in the crude oil and natural gas industry and throughout this
form 10-K:
"BBL." A standard measure of volume for crude oil and liquid petroleum products; one barrel equals 42 U.S. gallons.
"BCF." Billion Cubic Feet of natural gas at standard temperature and pressure.
"BOE." Barrels of oil equivalent. BOE is calculated by converting 6 MCF of natural gas to 1 BBL of oil.
"BOPD." Barrels of oil per day.
"BTU" or "British Thermal Unit." The standard unit of measure of energy equal to the amount of heat required to raise the
temperature of one pound of water 1 degree Fahrenheit. One Bbl of crude is typically 5.8 MMBTU, and one standard MCF is typically
one MMBTU.
"CO2." Carbon dioxide, a gas that can be found in naturally occurring reservoirs, typically associated with ancient volcanoes, and
also is a major byproduct from manufacturing and power production also utilized in enhanced oil recovery through injection into an oil
reservoir.
"Developed Reserves." Reserves of any category that can be expected to be recovered (i) through existing wells with existing
equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well;
and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by
means not involving a well.
"EOR." Enhanced Oil Recovery projects involve injection of heat, miscible or immiscible gas, or chemicals into oil reservoirs,
typically following full primary and secondary waterflood recovery efforts, in order to gain incremental recovery of oil from the
reservoir.
"Field." An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geologic
structural feature and/or stratigraphic feature.*
"Farmout." Sale or transfer of all or part of the operating rights from the working interest owner (the assignor or farm-out party),
to an assignee (the farm-in party) who assumes all or some of the burden of development, in return for an interest in the property. The
assignor may retain an overriding royalty or any other type of interest. For Federal tax purposes, a farm-out may be structured as a sale
or lease, depending on the specific rights and carved out interests retained by the assignor.
"Gross Acres or Gross Wells." The total acres or number of wells participated in, regardless of the amount of working interest
owned.
"Horizontal Drilling." Involves drilling horizontally out from a vertical well bore, thereby potentially increasing the area and
reach of the well bore that is in contact with the reservoir.
"Hydraulic Fracturing." Involves pumping a fluid with or without particulates into a formation at high pressure, thereby creating
fractures in the rock and leaving the particulates in the fractures to ensure that the fractures remain open, thereby potentially increasing
the ability of the reservoir to produce oil or gas.
"LOE." Means lease operating expense(s), a current period expense incurred to operate a well.
"MBO." One thousand barrels of oil
"MBOE." One thousand barrels of oil equivalent.
"MCF." One thousand cubic feet of natural gas at standard conditions, being approximately sea level pressure and 60 degrees
Fahrenheit temperature. Standard pressure in the state of Louisiana is deemed to be 15.025 psi by regulation, but varies in other states.
"MMBOE." One million barrels of oil equivalent.
"MMBTU." One million British thermal units.
"MMCF." One million cubic feet of natural gas at standard temperature and pressure.
"Mineral Royalty Interest." A royalty interest that is retained by the owner of the minerals underlying a lease. See "Royalty
Interest".
"Net Acres or Net Wells." The sum of the fractional working interests owned in gross acres or gross wells.
iii
"NGL." Natural gas liquids, being the combination of ethane, propane, butane and natural gasoline that can be removed from
natural gas through processing, typically through refrigeration plants that utilize low temperatures, or through J-T plants that utilize
compression, temperature reduction and expansion to a lower pressure.
"NYMEX." New York Mercantile Exchange.
"OOIP." Original Oil in Place. An estimate of the barrels originally contained in a reservoir before any production therefrom.
"Operator." An oil and gas joint venture participant that manages the joint venture, pays venture costs and bills the venture's non-
operators for their share of venture costs. The operator is also responsible to market all oil and gas production, except for those non-
operators who take their production in-kind.
"Overriding Royalty Interest or ORRI." A royalty interest that is created out of the operating or working interest. Unlike a
royalty interest, an overriding royalty interest terminates with the operating interest from which it was created or carved out of. See
"Royalty Interest".
"Permeability." The measure of ease with which a fluid can move through a reservoir. The unit of measure is a darcy, or any
metric derivation thereof, such as a millidarcy, where one darcy equals 1,000 millidarcys. Extremely low permeability of 10 millidarcys,
or less, are often associated with source rocks, such as shale, making extraction of hydrocarbons more difficult, than say sandstone traps,
where permeability can be one to two darcys or more.
"Porosity." (of sand or sandstone). The relative volume of the pore space (or open area) compared to the total bulk volume of the
reservoir, stated in percent. Higher porosity rocks provide more storage space for hydrocarbon accumulations than lower porosity rocks
in a given cubic volume of reservoir.
“Possible Reserves.” Additional unproved reserves that analysis of geological and engineering data suggests are less likely to be
recoverable than Probable Reserves, but have at least a ten percent probability of being recovered.*
"Probable Developed Producing Reserves." Probable Reserves that are Developed and Producing.*
"Probable Reserves." Additional reserves that are less certain to be recovered than Proved Reserves but which, together with
Proved Reserves, are as likely as not to be recovered.*
"Producing Reserves." Any category of reserves that have been developed and production has been initiated.*
"Proved Developed Reserves." Proved Reserves that can be expected to be recovered (i) through existing wells with existing
equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well;
and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by
means not involving a well.
"Proved Developed Nonproducing Reserves ("PDNP")." Proved Reserves that have been developed and no material amount of
capital expenditures are required to bring on production, but production has not yet been initiated due to timing, markets, or lack of third
party completed connection to a gas sales pipeline.*
"Proved Developed Producing Reserves ("PDP")." Proved Reserves that have been developed and production has been
initiated.*
"Proved Reserves." Estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic, operating
methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates
that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to
extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a
reasonable time.*
"Proved Undeveloped Reserves ("PUD")." Proved Reserves that are expected to be recovered from new wells on undrilled
acreage, or from existing wells where a relatively major expenditure is required for recompletion.*
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain
of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic
producibility at greater distances.
(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating
that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of
fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual
projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology establishing reasonable certainty.
iv
"Present Value." When used with respect to oil and gas reserves, present value means the estimated future net revenues computed
by applying current prices of oil and gas reserves (with consideration of price changes only to the extent provided by contractual
arrangements) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet presented, less
estimated future expenditures (based on current costs to be incurred in developing and producing the proved reserves) computed using a
discount factor and assuming continuation of existing economic conditions.
"Productive Well." A well that is producing oil or gas or that is capable of production.
"PV-10." Means the present value, discounted at 10% per annum, of future net revenues (estimated future gross revenues less
estimated future costs of production, development, and asset retirement costs) associated with reserves and is not necessarily the same as
market value. PV-10 does not include estimated future income taxes. Unless otherwise noted, PV-10 is calculated using the pricing
scheme as required by the Securities and Exchange Commission ("SEC"). PV-10 of proved reserves is calculated the same as the
standardized measure of discounted future net cash flows, except that the standardized measure of discounted future net cash flows
includes future estimated income taxes discounted at 10% per annum. See the definition of standardized measure of discounted future
net cash flows.
"Royalty" or "Royalty Interest." 1) The mineral owner's share of oil or gas production (typically between 1/8 and 1/4), free of
costs, but subject to severance taxes unless the lessor is a government. In certain circumstances, the royalty owner bears a proportionate
share of the costs of making the natural gas saleable, such as processing, compression and gathering. 2) When a royalty interest is
coterminous with and carved out of an operating or working interest, it is an "Overriding Royalty Interest," which also may generically
be referred to as a Royalty.
"Shut-in Well." A well that is not on production, but has not yet been plugged and abandoned. Wells may be shut-in in anticipation
of future utility as a producing well, plugging and abandonment or other use.
"Standardized Measure." The standardized measure of discounted future net cash flows. The Standardized Measure is an
estimate of future net cash flows associated with proved reserves, discounted at 10% per annum. Future net cash flows is calculated by
reducing future net revenues by estimated future income tax expenses and discounting at 10% per annum. The Standardized Measure
and the PV-10 of proved reserves is calculated in the same exact fashion, except that the Standardized Measure includes future estimated
income taxes discounted at 10% per annum. The Standardized Measure is in accordance with accounting standards generally accepted in
the United States of America ("GAAP").
"Undeveloped Reserves." Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is required for recompletion.*
"Working Interest." The interest in the oil and gas in place which is burdened with the cost of development and operation of the
property. Also called the operating interest.
"Workover." A remedial operation on a completed well to restore, maintain or improve the well's production.
______________________________________________________________________________
*
This definition may be an abbreviated version of the complete definition as defined by the SEC in Rule 4-10(a) of Regulation S-X.
v
PART I
Item 1. Business
Note: See Glossary of Selected Petroleum Industry Terms starting on page
iii
General
Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its
shareholders through the ownership, management and development of producing oil and gas properties. The Company's long-
term goal is to build a diversified portfolio of oil and gas assets primarily through acquisition, while seeking opportunities to
maintain and increase production through selective development, production enhancement and other exploitation efforts on its
properties.
Our producing assets over the last three fiscal years consisted of our interests in the Delhi Holt-Bryant Unit in the Delhi
field (the "Unit") in Northeast Louisiana, a CO2 enhanced oil recovery project, and a de minimis overriding royalty interest
retained in a past divestiture. We have a combined net revenue interest in the Unit of 26.2% comprised of 7.2% of overriding
royalty interests that are in effect for the life of the Unit and mineral royalty interests and a 23.9% working interest with an
associated 19.0% net revenue interest.
Significant Activity in Fiscal 2019
• Delhi proved oil equivalent reserves at June 30, 2019 were 9.0 MMBOE, a 4% decrease from the previous year. The
Standardized Measure for proved reserves increased 7% to $127 million, reflecting a rise in realized commodity price
from $54.71 to $58.50 per BOE. Our proved reserves consist of 85% crude oil and 15% natural gas liquids.
• Delhi probable** reserves at June 30, 2019 were 4.8 MMBOE, a 7% increase over the previous year. 87% of these
reserves are incremental reserves associated with existing developed and producing locations. No additional capital
investment is required beyond what is captured in proved reserves.
• Delhi possible** reserves at June 30, 2019 were 4.3 MMBOE, a 7% decrease over the previous year. 91% of these
reserves are incremental reserves associated with existing developed and producing locations. No additional capital
investment is required beyond what is captured in proved reserves.
• The twelve well infill program, consisting of ten producer wells and two CO2 injector wells, was completed and on
production during fiscal 2019, converting 536 MBOE of proved undeveloped to proved developed reserves.
• Capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi
Phase V development is almost complete. The first pad commenced operations during fiscal 2019 and the second pad
is expected to begin injections during our second quarter of fiscal 2020.
Our Reserves: Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our independent petroleum engineering firm, DeGolyer & MacNaughton ("D&M"), assigned the estimated reserves net
to our interests at Delhi as of June 30, 2019. We had 9.0 million bbls of proved oil equivalent reserves, with a Standardized
Measure of $127 million, and PV-10* of $157 million. The following table summarizes the reserves assigned by D&M:
Reserves MBOE
% Developed
Liquids %
Standardized Measure ($MM)
PV-10* ($MM)
Reserves as of June 30, 2019
Proved
Probable**
Possible**
8,981
82%
100%
127
157
$
$
4,783
87%
100%
4,321
91%
100%
1
______________________________________________________________________________
*
**
PV-10 of proved reserves is a non-GAAP measure, reconciled to the Standardized Measure at "Estimated Oil and
Natural Gas Reserves and Estimated Future Net Revenues" below in Item 1. Business in this 10-K. Both the
Standardized Measure and PV-10 are based on the average first day of the month net commodity prices received at
the Delhi field in the twelve months ending June 30, 2019, which were $64.54 per barrel of oil and $23.83 per barrel
of natural gas liquids ("NGL"). Probable and possible reserves are not recognized under GAAP nor is there a
comparable GAAP measure for probable and possible reserves.
With respect to the above reserve numbers, and references to probable and possible reserves throughout this
document, estimates of probable and possible reserves are inherently imprecise. When producing an estimate of the
amount of oil and natural gas that is recoverable from a particular reservoir, probable reserves are those additional
reserves that are less certain to be recovered than proved reserves and there must be at least a 50% probability that the
actual quantities recovered will equal or exceed the proved plus probable reserve estimates. Possible reserves are
even less certain and there must be at least a 10% probability that the actual quantities recovered will equal or exceed
the sum of proved, probable and possible reserve estimates. All categories of reserves are continually subject to
revisions based on production history, results of additional exploration and development, price changes and other
factors. Estimates of probable and possible reserves are by their nature much more speculative than estimates of
proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is
subject to substantially greater risk. These three reserve categories have not been adjusted to different levels of
recovery risk among these categories and are therefore not comparable and are not meaningfully combined.
Development History of the Delhi Field - Enhanced Oil Recovery - Onshore Louisiana
Our working and royalty interests in the Delhi field are currently our primary producing assets. The Unit is
approximately 13,636 acres in size and has had a prolific production history totaling approximately 195 million bbls of oil
through primary and limited secondary recovery operations since its discovery in the mid-1940s. At the time of our purchase
of the field in 2003, the Unit had minimal production. We conveyed our working interest in the field to a subsidiary of
Denbury Resources, Inc. in May 2006 for $50 million for the purpose of installing an enhanced oil recovery ("EOR") project
in the field. We retained a 23.9% reversionary working interest upon payout of the project, as defined in the purchase and sale
agreements. Since EOR production began in March 2010, the Unit has produced over 20 million bbls of oil.
After the May 2006 conveyance, Denbury Resources, Inc., as the operator, originally planned six primary phases for the
installation of the CO2 flood in the Delhi field. Four of these phases have been completed as of June 30, 2017 and two remain
undeveloped. One of the remaining two phases (Phase V) is reflected as Proved undeveloped in our current reserves report and
the other was removed from proved reserves (Phase VI) as it was not deemed economic under current pricing guidelines for
SEC purposes.
Phase I began CO2 injection in November 2009. First oil production response occurred in March 2010 and production in
the field increased to approximately 1,000 gross barrels of oil per day by December 2010.
2
Implementation of Phase II, which was more than double the size of Phase I, commenced with incremental CO2
injection at the end of December 2010. First oil production response from Phase II occurred during March 2011, and field
gross production increased to more than 4,000 barrels of oil per day by June 2011.
Phase III was installed during calendar 2011, and was expanded twice during calendar 2011. Production subsequently
increased to more than 5,000 gross barrels of oil per day.
Phase IV was substantially installed during the first six months of calendar 2012. During early calendar 2013, the
operator intensified development in the previously redeveloped western side of the field based on production results and new
geological mapping that included the results of seismic data acquired over the last few years. Gross field production increased
to more than 7,500 gross barrels of oil per day.
In June 2013, following an adverse fluid release event that consisted of the uncontrolled release of CO2, water, natural
gas and a small amount of oil from a previously plugged well in the southwest part of the field, the operator suspended CO2
injection in most of the southwestern tip of the field. The operator has fully remediated the affected area, but has isolated that
part of the field with a water curtain, thus removing that area from the CO2 flood.
Construction began on the NGL extraction plant in February 2015. During fiscal 2017, the NGL extraction plant was
completed and began processing in December 2016. The plant extracts methane and NGL's from the CO2 recycle stream. The
methane and part of the ethane produced by the NGL plant are used to generate electrical power for the benefit and use in the
field. The extracted NGL's are sold at the field to a purchaser who transports them by truck to a plant for further processing. In
addition to the value of these hydrocarbon products, the increased purity of the CO2 stream re-injected into the field has
resulted in operational benefits to the CO2 flood. We have incurred a net capital cost of approximately $27 million for the
plant, including capital upgrades since its commissioning.
Subsequent to the reversion of our working interest to us in November 2014, the operator initiated work on the Phase V
expansion of the CO2 flood in the undeveloped eastern part of the field. These operations were suspended shortly after
reversion when the operator made significant cuts in its capital budget as a result of declining oil prices. Resumption of this
work has been electively delayed due to prevailing oil prices and the partners' allocation of capital to other Delhi projects,
primarily the large investment in the NGL plant together with the consensus that Phase V project economics would be
enhanced if it were implemented after completion of the NGL plant.
During fiscal 2019 the twelve well infill program, consisting of ten producing wells and two CO2 injection wells was
completed and on production. The program commenced in March 2018 to target productive oil zones in the developed areas of
the field that were not being swept effectively by the CO2 flood.
Also during the year, one pad of the six-well water curtain program was completed and commenced water injection
during the second half of fiscal 2019. The project began late in fiscal 2017 after completion of the NGL plant with the drilling
of one well followed by three wells in fiscal 2018. During fiscal 2019, we drilled the two remaining wells and proceeded with
completions and injection line work. In fiscal 2020, we expect to incur approximately $0.6 million of net capital expenditures
for completing the installation of the second three-well pad planned to begin injection in the second fiscal quarter.
Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues
The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies. These
rules require disclosure of oil and gas proved reserves by significant geographic area, using the trailing 12-month average
price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month
period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the
determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions
about reserve volumes. Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be
classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.
There are numerous uncertainties inherent in estimating quantities of proved reserves and estimates of reserves quantities
and values must be viewed as being subject to significant change as more data about the properties becomes available.
Estimates of probable and possible reserves are inherently imprecise. When producing an estimate of the amount of oil
and natural gas liquids that is recoverable from a particular reservoir, probable reserves are those additional reserves that are
less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered,
generally described as having a 50% probability that the actual quantities recovered will equal of exceed the proved plus
probable reserve estimates. Possible reserves are even less certain and generally require only a 10% or greater probability of
that actual quantities recovered will equal or exceed the sum of proved, probable and possible reserve estimates. All categories
of reserves are continually subject to revisions based on production history, results of additional exploration and development,
3
price changes and other factors. Estimates of probable and possible reserves are by their nature much more speculative than
estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those
reserves is subject to substantially greater risk. These three reserve categories have not been adjusted to different levels of
recovery risk among these categories and are therefore not comparable and are not meaningfully combined.
Information About the Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure") and pre-tax
PV-10 of Proved Reserves
Estimated pre-tax future net revenues from the production of proved reserves discounted at 10%, or PV-10, is a financial
measure that is not recognized by GAAP. We believe that the presentation of the non-GAAP financial measure of PV-10
provides useful information to investors because it is widely used by analysts and investors in evaluating oil and natural gas
companies, and that it is relevant and useful for evaluating the relative monetary significance of oil and natural gas properties.
Further, analysts and investors may utilize the measure as a basis for comparison of the relative size and value of our reserves
to other companies' reserves. We also use this pre-tax measure when assessing the potential return on investment related to oil
and natural gas properties and in evaluating acquisition opportunities. Because there are many unique factors that can impact
an individual company when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure
is valuable for evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it
intended to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in
isolation or as a substitute for the Standardized Measure as defined under GAAP, and reconciled herein. Refer to the
"Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows" below.
Summary of Oil & Gas Reserves for Fiscal Year Ended 2019
Our proved, probable and possible reserves at June 30, 2019, denominated in equivalent barrels using six MCF of gas
and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, were estimated by our independent petroleum
engineer, DeGolyer and MacNaughton ("D&M") which was formed in 1936, employs over 180 petroleum engineers,
geologists and other technical personnel, and operates domestically and around the world. D&M was selected to estimate
reserves for our interests in the Delhi field due to their expertise in CO2-EOR projects and to ensure consistency with the
operator of the Delhi field. The scope and results of their procedures are summarized in a letter from the firm, which is
included as exhibit 99.1 to this Annual Report on Form 10-K.
The following table sets forth our estimated proved, probable and possible reserves as of June 30, 2019. For additional
reserve information see Note 20 – Supplemental Disclosures about Oil and Natural Gas Producing Properties (Unaudited) of
the consolidated financial statements. The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month
price used to calculate estimated revenues was $61.62 per barrel of crude oil. The net price per barrel of natural gas liquids
was $23.83, which does not have any single comparable reference index price. The NGL price was based on historical prices
received. For periods for which no historical price information was available, we used comparable pricing in the area. Pricing
differentials were applied based on quality, processing, transportation, location and other pricing aspects for each individual
property and product.
4
Reserves as of June 30, 2019
Reserve Category
PROVED
Developed Producing (82% of Proved)
Undeveloped (18% of Proved)
TOTAL PROVED
Product Mix
PROBABLE
Developed Producing (87% of Probable)
Undeveloped (13% of Probable)
TOTAL PROBABLE
Product Mix
POSSIBLE
Developed Producing (91% of Possible)
Undeveloped (9% of Possible)
TOTAL POSSIBLE
Product Mix
Oil
(MBbls)
NGLs
(MBbls)
Total Reserves
(MBOE)*
6,274
1,342
7,616
1,124
241
1,365
7,398
1,583
8,981
85%
15%
100%
3,516
540
4,056
630
97
727
4,146
637
4,783
85%
15%
100%
3,323
341
3,664
596
61
657
3,919
402
4,321
85%
15%
100%
*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio.
5
The following tables present a reconciliation of changes in our proved, probable and possible reserves by major
property, on the basis of equivalent MBOE quantities.
Reconciliation of Changes in Proved Reserves by Major Property
Proved reserves, MBOE
June 30, 2018
Production
Revisions
Sales of minerals in place
Improved recovery, extensions and discoveries
June 30, 2019
Reconciliation of Changes in Probable Reserves by Major Property
Probable reserves, MBOE
June 30, 2018
Revisions
Sales of minerals in place
Improved recovery, extensions and discoveries
June 30, 2019
Reconciliation of Changes in Possible Reserves by Major Property
Possible reserves, MBOE
June 30, 2018
Revisions
Sales of minerals in place
Improved recovery, extensions, and discoveries
June 30, 2019
Delhi Field
Proved
Total
MBOE
9,368
(739)
352
—
—
8,981
Delhi Field
Probable
Total
MBOE
4,493
290
—
—
4,783
Delhi Field
Possible
Total
MBOE
4,570
(249)
—
—
4,321
Reconciliation of PV-10 to the Standardized Measure of Discounted Future Net Cash Flows
The following table provides a reconciliation of PV-10 (Non-GAAP) of our proved properties to the Standardized
Measure (GAAP) as shown in Note 20 – Supplemental Disclosures about Oil and Natural Gas Producing Properties
(Unaudited) of the consolidated financial statements.
Estimated future net revenues
10% annual discount for estimated timing of future cash flows
Estimated future net revenues discounted at 10% (PV-10)
Estimated future income tax expenses discounted at 10%
Standardized Measure
As of June 30,
2019
2018
$297,102,269
$ 270,842,377
140,489,586
124,798,505
156,612,683
(29,880,641)
$126,732,042
146,043,872
(27,085,458)
$ 118,958,414
Our primary proved producing assets as of June 30, 2019 and 2018 were our interests in the Delhi field.
6
Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the
Company's Overall Reserve Estimation Process
Our policies regarding internal controls over reserves estimates require such estimates to be prepared by an independent
petroleum engineering firm under the supervision of our Chairman of the Board and interim Chief Executive Officer and
Senior Vice President of Engineering and Business Development, a professional petroleum engineer. Such reserves estimates
are to be in compliance with generally accepted petroleum engineering and evaluation principles and definitions and
guidelines established by the SEC.
The reserves information in this filing is based on estimates prepared by DeGolyer and MacNaughton, our independent
petroleum engineering firm, which was formed in 1936, employs over 180 petroleum engineers, geologists and other technical
personnel, and operates domestically and around the world. The person responsible for preparing the reserves report with
D&M is a Registered Professional Engineer in the State of Texas and a Senior Vice President of the firm. He received a
Bachelor of Science degree in petroleum engineering from the University of Texas in 1984, has over 35 years of experience in
the energy industry and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation
Engineers.
Our Chairman of the Board and interim Chief Executive Officer holds B.S. and M.E. degrees from Rice University in
chemical engineering and earned an M.B.A. from Harvard University. He has over 30 years of experience in engineering,
energy transactions, operations and finance with small independents, larger independents and major integrated oil companies.
Our Senior Vice President of Engineering and Business Development received a Bachelor of Science degree in petroleum
engineering from the University of Oklahoma in 1979 and has over 39 years of experience in the energy industry with
upstream oil and gas companies. On July 10, 2019, Jason Brown was appointed President and Chief Executive Officer of the
Company and Mr. Herlin remained as Chairman of the Board of Directors. Mr. Brown has over 20 years of experience in the
energy industry and is a Registered Professional Engineer (Petroleum) in the State of Texas. He earned his B.S. degree in
chemical engineering from the University of Tulsa and his M.B.A. from the Mendoza School of Business at the University of
Notre Dame.
We provide our independent petroleum engineering firm with our property interests, production, current operating costs,
current production prices and other information. This information is reviewed by our Senior Vice President of Engineering and
Business Development and other members of management to ensure accuracy and completeness of the data prior to
submission to this firm. The scope and results of our independent petroleum engineering firm's procedures, as well as their
professional qualifications, are summarized in the letter included as exhibit 99.1 to this Annual Report on Form 10-K.
Proved Undeveloped Reserves
Our Proved undeveloped reserves were 1,583 MBOE at June 30, 2019, with associated future development costs of
approximately $8.6 million, which are associated with the Phase V development in the eastern portion of Delhi field.
During the year ended June 30, 2019 our proved undeveloped reserves changed as follows:
June 30, 2018
Revisions to previous estimates
Conversion to proved developed reserves
June 30, 2019
Oil
(MBbls)
NGLs
(MBbls)
Total Reserves
(MBOE)
1,798
7
(463)
1,342
284
30
(73)
241
2,082
37
(536)
1,583
Oil and NGL reserves were revised upward 7 MBbls and 29 MBOE, respectively, reflecting improved existing well and
NGL plant performance over the last year. The infill program, consisting of ten producer wells and two CO2 injection wells,
was completed during 2019 resulting in the conversion of 463 MBbls of oil and and 73 MBOE of NGLs from Proved
undeveloped reserves to proved developed reserves. Since the project's inception in March 2018, our infill project net capital
expenditures have totaled $4.6 million, of which $1.8 million was incurred during fiscal 2019.
The initial assignment of proved undeveloped reserves in the Delhi field was made on June 30, 2010, which
encompassed a large scale CO2 enhanced oil recovery project. The operator’s development plans for the field were to have
remained essentially unchanged and were originally scheduled to be completed by June 30, 2015, within five years from the
initial recording of such proved reserves. Developed reserves are approximately 82% of total Proved reserves as of June 30,
2019. However, as a result of the adverse fluid release event in the field in June 2013 and the resulting delay in reversion of
our working interest, development of the field has not proceeded as originally scheduled. Expansion of the CO2 flood to the
remaining undeveloped eastern portion of the field commenced subsequent to reversion of our working interest in late calendar
7
2014. We incurred $3.8 million of capital expenditures before the operator electively deferred this project as a result of a
reduction in its cash flows and capital spending from the significant drop in oil prices. This project was further electively
deferred as we began work on the NGL recovery plant field in February 2015. It was determined that the economics of
development of the remaining eastern portion of the field would be significantly improved after the NGL plant was completed.
During fiscal 2015, we authorized the NGL plant project and from late in that fiscal year until January 2017 when
production of NGLs began, we incurred $26.0 million of related capital expenditures. The NGL plant was completed in
December 2016 and we converted approximately 1,377 MBOE of proved undeveloped reserves to proved developed reserves
during fiscal 2017.
Since completion of the plant, we have resumed work that had been suspended in late 2014 and further deferred until the
NGL recovery plant was complete. Cumulatively, we have spent $3.1 million as of June 30, 2019, including $1.6 million in
fiscal 2019, on the six well water curtain program and related infrastructure required to precede the development of Phase V.
As of June 30, 2019 we had drilled all the wells, including four gross wells during fiscal 2019, and commenced operations for
one of the program's pads. The program was configured as two pads with each having two injector wells and one water source
well. The second pad is expected to begin operations in the second fiscal quarter of 2020 and we expect to incur
approximately $0.6 million net of capital expenditures to complete the program.
As of June 30, 2019, we have estimated total future net capital expenditures of approximately $8.6 million for remaining
curtain infrastructure and development of Phase V in the eastern part of the field, which we expect to commence in our fourth
fiscal quarter of 2020 based on our discussions with the operator. The timing of Phase V is dependent on the field operator's
available funds and capital spending plans and priorities within its portfolio of properties.
We believe this project is economic in the current oil price environment and we expect it to be completed within the next
two fiscal years. We have been continuously developing the Delhi field and have spent over $47 million subsequent to
reversion of our working interest in November 2014. Given the long-term nature of CO2 EOR development projects, we
believe that the remaining undeveloped reserves in the Delhi field satisfy the conditions to continue to be treated as proved
undeveloped reserves because (1) we initially established the development plan for the Delhi field in 2010 and continue to
follow that plan, as adjusted to incorporate the completion of the NGL plant in late 2016 and delays relating to the 2013
adverse fluid release event; (2) we have had significant ongoing development activities at this project that, as budgeted and
currently being expended, reflect a significant and sufficient portion of remaining capital expenditures to convert proved
undeveloped reserves to proved developed reserves; and (3) the operator has a historical record of completing the development
of comparable long-term projects.
As of June 30, 2019, no proved, probable or possible reserves were attributed to (a) the area beneath the inhabited
portion of the town of Delhi in the northeast and (b) the farthest east of the two remaining undeveloped sites in the eastern
portion of the field (Phase VI) due to the current economics and other technical aspects of our future development plans. In
addition, no probable reserves are currently attributed to three smaller reservoirs within the Unit in similar formations with
similar production history due to the lower oil price utilized in our reserves calculation. We also do not have proved or
probable reserves associated with out interests in the Mengel Sand, a separate interval within the Unit that is not currently
producing, but has produced oil in the past.
8
$
$
$
$
$
$
46.31
16.01
(0.25)
44.58
per BOE
13.52
13.80
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, 2019
Year Ended
June 30, 2018
Year Ended June 30, 2017
Volume
Price
Volume
Price
Volume
Price
626,879
112,013
459
738,968
$
$
$
$
65.05
21.87
2.64
58.50
651,931
93,366
$
$
— $
58.52
28.06
—
724,523
43,907
16
745,297
$
54.71
768,433
Production costs
Amount
per BOE
Amount
per BOE
Amount
Production costs, excluding ad
valorem and production taxes
$ 14,027,461
Total production costs, including
ad valorem and production taxes
$ 14,266,784
$
$
18.98
$ 11,497,759
19.31
$ 11,685,817
$
$
15.43
$ 10,390,041
15.68
$ 10,604,594
* BOE computed on units of production using a six to one conversion ratio of MCF's to barrels.
Drilling Activity
Our productive drilling activity during the past three fiscal years ended June 30, 2019, was limited to five gross (1.2 net)
producer wells drilled and completed in fiscal 2019 and another five (1.2 net) producer wells completed in fiscal 2018. We
completed one (0.239 net) CO2 injection well during fiscal 2019 and completed one (0.239 net) CO2 injection well during
fiscal 2018. There were no completions of productive wells in fiscal 2017. No dry wells were drilled in the past three fiscal
years.
In connection with establishing a six-well water curtain in advance of Phase V site development, during fiscal 2019 we
drilled two (0.48 net) wells and completed three (0.72 net) wells. In fiscal 2018, we had drilled three (0.72 net) wells and in
fiscal 2017 one (0.239 net) well was drilled. The three completed wells comprise the northern pad of the water curtain
program and commenced injection during fiscal 2019. A pad consists of one gross water source well and two gross water
injector wells.
Present Activities
As of June 30, 2019, we have three gross (0.72 net) water curtain wells remaining to be completed. We expect their
completions will conclude and the wells to be online by early in our second quarter of fiscal 2020. These wells comprise the
southern pad of the curtain program.
For further discussion, see "Highlights for our fiscal year 2019" and "Capital Budget" under Item 7. Management's
Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.
Delivery Commitments
As of June 30, 2019, we were not committed to provide a fixed and determinable quantity of oil, NGLs or gas under
existing agreements, nor do we currently intend to enter into any such agreements.
9
Productive Wells
The following table sets forth the number of productive oil and gas wells in which we owned a working interest as of
June 30, 2019.
Crude oil
Natural gas
Total
Acreage Data
Company Operated
Non-Operated
Total
Gross
Net
Gross
Net
Gross
Net
—
—
—
—
—
—
119
—
119
28.4
—
28.4
119
—
119
28.4
—
28.4
The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30,
2019. Developed acreage refers to acreage on which wells have been drilled or completed to a point that would permit
production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been
drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage
contains proved reserves.
Field
Developed Acreage
Undeveloped Acreage
Total
Delhi Field, Louisiana*
________________
Gross
9,126
Net
2,180
Gross
4,510
Net
Gross
1,077
13,636
Net
3,257
* This table excludes acreage attributable to small overriding royalty interests retained in various formations in the
Giddings Field area. Except for de minimis production that began on two leases during fiscal 2019, none of such
acreage is currently producing and our interests are subject to expiration if leases are not maintained by others or
commercial production is not established. It does not currently appear likely that we will obtain any significant value
from these interests and no reserves have been assigned to any of the Giddings interests.
When the Company acquired the Delhi field in 2003, the field had been fully developed through primary and secondary
recovery and all of such acreage was reflected as developed acreage. With the addition of a CO2-EOR project in the field,
certain acreage is now reflected as undeveloped using tertiary recovery operations. We estimate that our developed acreage
currently includes 9,126 gross (2,180 net) acres in the Delhi field, with approximately 4,510 gross (1,077 net) acres
attributable to the remaining undeveloped areas in the eastern part of the field. We own a 23.9% working interest in the field,
along with certain mineral and royalty interests. We are not the operator of the EOR project.
Our interests include all depths from the surface of the earth to the top of the Massive Anhydride, including the Delhi
Holt Bryant Unit, which is currently under CO2 flood, and the Mengel Sand Interval, which is within the boundary of the field,
but is currently not producing. As the Delhi field is unitized, all acreage, including any undeveloped, nonproductive or
undrilled acreage is held by existing production as long as continuous production is maintained in the unit.
For more complete information regarding current year activities, including crude oil and natural gas production, refer to
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations of this Form 10-K.
Markets and Customers
Our production is marketed to third parties in a manner consistent with industry practices. In the U.S. market where we
operate, crude oil and natural gas liquids are readily transportable and marketable. We do not currently market our share of
crude oil production from Delhi separately from the operator's share of production. Although we have the right to take our
working interest production in-kind, we are currently selling our oil under the Delhi operator's agreement with Plains
Marketing L.P. pursuant to the delivery and pricing terms thereunder. The oil from Delhi is currently transported from the field
by pipeline, which results in better net pricing than the alternative of transportation by truck. Delhi crude oil production sells at
Louisiana Light Sweet ("LLS") pricing which generally trades at a premium to West Texas Intermediate ("WTI") crude oil
pricing. The positive LLS Gulf Coast average price differential over WTI, as quoted daily on the New York Mercantile
Exchange ("NYMEX"), was approximately $6.89 per barrel during our fiscal year ended June 30, 2019. The differential has
increased from the prior year and we expect that a positive LLS price differential will continue, at least in the near future. Our
overall average net realized oil price, including the LLS premium and after all adjustments for transportation, marketing and
other price differentials, was $4.11 per barrel more than the average WTI NYMEX price for fiscal 2019.
10
Upon completion of the NGL plant in December 2016, we began selling natural gas liquids from the Delhi field to
American Midstream Gas Solutions, L.P. Title to these products is transferred to the purchaser at the field and they are
transported by truck to the purchaser's processing facility. We receive market prices, less transportation, processing and quality
differential fees for the net yield of the individual natural gas liquid components, consisting of propane, butanes, and C5+
(pentanes and heavier components). There is a small component of residual ethane, but the overall yield of products is a higher
value mix than is typical for natural gas liquids.
The following table sets forth purchasers of our oil and natural gas production for the years indicated:
Customer
Plains Marketing L.P. (Oil sales from Delhi)
American Midstream Gas Solutions. L.P. (NGL sales from Delhi)
All others
Total
Year Ended June 30,
2019
2018
94%
6%
—%
100%
92%
8%
—%
100%
The loss of a purchaser at the Delhi field or disruption to pipeline transportation from the field could adversely affect our
net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers would not be
expected to have a material adverse effect on our operations.
Market Conditions
Marketing of crude oil, natural gas, and natural gas liquids and the prices we receive are influenced by many factors that
are beyond our control, the exact effect of which is difficult to predict. These factors include changes in supply and demand,
market prices, government regulation and actions of major foreign producers.
Over the past 30 years, crude oil price fluctuations have been extremely volatile, with crude oil prices varying from less
than $10 to over $140 per barrel. More recently, the price of oil per barrel dropped dramatically, starting in the fourth quarter
of 2014 and continuing into 2017 before recovering somewhat in late calendar 2018 and then weakening again in 2019.
Worldwide factors such as geopolitical, international trade disruptions and tariffs, macroeconomic, supply and demand,
refining capacity, petrochemical production and derivatives trading, among others, influence prices for crude oil. Local factors
also influence prices for crude oil and include increasing or decreasing production trends, quality differences, regulation and
transportation issues unique to certain producing regions and reservoirs.
Also over the past 30 years, domestic natural gas prices have been extremely volatile, ranging from $1 to $15 per
MMBTU. The spot market for natural gas, changes in supply and demand, derivatives trading, pipeline availability, BTU
content of the natural gas and weather patterns, among others, cause natural gas prices to be subject to significant fluctuations.
Due to the practical difficulties in transporting natural gas, local and regional factors tend to influence product prices more for
natural gas than for crude oil.
Competition
The oil and natural gas industry is highly competitive for prospects, acreage and capital. Our competitors include major
integrated crude oil and natural gas companies and numerous independent crude oil and natural gas companies, individuals
and drilling and income programs. Many of our competitors are large, well-established companies with substantially larger
operating staffs and greater capital resources than ours. Competitors are national, regional or local in scope and compete on the
basis of financial resources, technical prowess or local knowledge. The principal competitive factors in our industry are
expertise in given geographical and geological areas and the abilities to efficiently conduct operations, achieve technological
advantages, identify, acquire economically producible reserves and obtain capital at rates which allow economic investments.
Government Regulation
Numerous federal and state laws and regulations govern the oil and gas industry, including environmental laws and
regulations. These laws and regulations are often changed in response to changes in the political or economic environment.
Compliance with this evolving regulatory burden is often difficult and costly, and substantial penalties may be incurred for
noncompliance. To the best of our knowledge, we are in compliance with all laws and regulations applicable to our operations
and we believe that continued compliance with existing requirements will not have a material adverse impact on us. The future
annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several
factors, including future changes to regulatory requirements which are unpredictable. However, we do not currently anticipate
that future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial
position or results of operations.
11
See "Government regulation and liability for environmental matters that may adversely affect our business and results of
operations" under Item 1A. Risk Factors of this Form 10-K, for additional information regarding government regulation.
Insurance
We maintain insurance on our oil and gas properties and operations for risks and in amounts customary in the industry.
Such insurance includes general liability, excess liability, control of well, operators extra expense, casualty, fraud and
directors & officer's liability coverage. Not all losses are insured, and we retain certain risks of loss through deductibles, limits
and self-retentions. We do not carry lost profits coverage and we do not have coverage for consequential damages.
Employment
At June 30, 2019, we had four full-time employees, not including contract personnel and outsourced service providers.
None of the Company’s employees are currently represented by a union, and the Company believes that it has excellent
relations with its employees. Our team is broadly experienced in oil and gas operations, development, acquisitions and
financing. We follow a strategy of outsourcing most of our property accounting, human resources, administrative and other
non-core functions. As a result of the retirement of Randy Keys, President and Chief Executive Officer on May 31, 2018, the
Board of Directors named Robert Herlin to act as Interim Chief Executive Officer and to commence a search for a permanent
Chief Executive Officer. A special Transition Services Committee of the board was created with one member, William Dozier,
to provide additional operational oversight to the Company during the transition to a new Chief Executive Officer. On July 10,
2019, Mr. Jason Brown was appointed by the Board of Directors to serve as President and Chief Executive Officer of the
Company. Robert Herlin, remained as Chairman of the Board.
Additional Information
We file Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports
with the Securities and Exchange Commission ("SEC") . Our reports filed with the SEC are available free of charge to the
general public through our website at www.evolutionpetroleum.com. These reports are accessible on our website as soon as
reasonably practicable after being filed with, or furnished to, the SEC. This Annual Report on Form 10-K and our other filings
can also be obtained by contacting: Corporate Secretary, 1155 Dairy Ashford Road, Suite 425, Houston, Texas 77079, or
calling (713) 935-0122. These reports are also available at the SEC Public Reference Room at 450 Fifth Street, N.W.,
Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the
SEC at 1-800-SEC-0330. The SEC also maintains a website at www.sec.gov that contains reports, proxy and information
statements and other information regarding issuers that file electronically with the SEC.
12
Item 1A. Risk Factors
Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Annual Report
on Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described
below are not the only ones facing us. Additional risks not presently known to us or which we currently consider to be
immaterial also may adversely affect us.
Risks related to the oil and gas industry and our Company
A substantial or extended decline in oil prices may adversely affect our business, financial condition or results of operations
and our ability to meet our capital expenditure obligations and financial commitments.
The price we receive for our oil significantly influences our revenue, profitability, access to capital and future rate of
growth. Oil is a commodity and its price is subject to wide fluctuations in response to relatively minor changes in supply and
demand. For example, average daily prices for WTI crude oil ranged from a high of $74 per barrel to a low of $27 per barrel
over the past four fiscal years ending June 30, 2019. Historically, the markets for oil and natural gas liquids have been volatile
and these markets will likely continue to be volatile in the future. The prices we receive for our production depend on numerous
factors beyond our control, including, but not limited to the following:
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;
• worldwide and regional economic conditions impacting the global supply and demand for oil and gas;
•
•
•
•
•
•
• weather conditions and natural disasters;
•
•
•
•
•
domestic and foreign governmental regulations;
speculation as to the future price of oil and the speculative trading of oil and natural gas futures contracts;
price and availability of competitors' supplies of oil and natural gas;
technological advances effecting energy consumption; and
the price and availability of alternative fuels.
Substantially all of our production is sold to purchasers under short-term (less than twelve-month) contracts at market-
based prices. A decline in oil and natural gas liquids prices will reduce our cash flows, borrowing ability, the present value of
our reserves and our ability to develop future reserves. We may be unable to obtain needed capital or financing on satisfactory
terms. Low oil and natural gas liquids prices may also reduce the amount of oil and natural gas liquids that we can produce
economically, which could lead to a decline in our oil and natural gas liquids reserves. Because approximately 85% of our
proved reserves at June 30, 2019 are crude oil reserves and 15% are natural gas liquids reserves, we are heavily impacted by
movements in crude oil prices, which also influence natural gas liquids prices. To the extent that we have not hedged our
production with derivative contracts or fixed-price contracts, any significant and extended decline in oil and natural gas liquids
prices may adversely affect our financial position.
Our revenues are concentrated in one asset and related declines in production or other events beyond our control could
have a material adverse effect on our results of operations and financial results.
Substantially all of our revenues come from our royalty, mineral and working interests in the Delhi field in Louisiana and
thus our current revenues are highly concentrated in this field. Any significant downturn in production, oil and NGL prices, or
other events beyond our control which impact the Delhi field could have a material adverse effect on our results of operations
and financial results. We are not the operator of the Delhi field, and our revenues and future growth are heavily dependent on
the success of operations, which we do not control.
Operating results from oil and natural gas production may decline; we may be unable to acquire and develop the additional
oil and natural gas reserves that are required in order to sustain our business operations.
In general, the volumes of production from crude oil and natural gas properties decline as reserves are depleted, with the
rate of decline depending on reservoir characteristics. Except to the extent we acquire additional properties containing proved
reserves or conduct successful development activities, or both, our proved reserves will decline. Our production is heavily
dependent on our interests in EOR production that began during March 2010 in the Delhi field. Environmental or operating
problems or lack of future investment at Delhi could cause our net production of oil and natural gas liquids to decline
significantly over time, which could have a material adverse effect on our financial condition.
13
We have limited control over the activities on properties we do not operate.
Substantially all of our property interests are not operated by the Company and also involve other third-party working
interest owners. As a result, we have limited ability to influence or control the operation or future development of such
properties, including compliance with environmental, safety and other regulations, or the amount of capital expenditures that
we will be required to fund with respect to such properties. Operators of these properties may act in ways that are not in our
best interest. Moreover, we are dependent on the other working interest owners of such projects to fund their contractual share
of the capital expenditures of such projects. These limitations and our dependence on the operator and other working interest
owners for these projects could cause us to incur unexpected future costs, result in lower production and materially and
adversely affect our financial conditions and results of operations.
We are materially dependent upon our operator with respect to the successful operation of our principal asset, which
consists of our interests the Delhi field. A materially negative change in our operator’s financial condition could negatively
affect operations (or timing thereof) in the Delhi field, and consequently our income (or timing thereof) from the field as
well as the value of our interests in the Delhi field.
Our royalty, mineral and working interests in the Delhi field, located in Northeast Louisiana, currently virtually represents
our sole producing asset. Over 99% of our revenues come from these interests and thus our current revenues are highly
concentrated in this field. Any significant downturn in production or other events beyond our control which impact the Delhi
field could have a material adverse effect on our results of operations and financial results (or timing thereof). We are not the
operator of the Delhi field. It is operated by a subsidiary of Denbury Resources Inc. (“DNR”), an independent oil and gas
company specializing in tertiary recovery with CO2. Our revenues and future growth are thus heavily dependent on the success
of operations which we do not control.
Further, our CO2 - Enhanced Oil Recovery (“CO2-EOR”) project in the Delhi field requires significant amounts of CO2
reserves and technical expertise, the sources of which have been committed by the operator. Additional capital remains to be
invested to fully develop this project, further increase production and maximize the value of this asset. The operator's failure to
manage these and other technical, environmental, operating, strategic, financial and logistical matters could cause ultimate
enhanced recoveries from the planned CO2 - EOR project to fall short of our expectations in volume and/or timing. Such
occurrences could have a material adverse effect on us, and our results of operations and financial condition.
Our economic success is thus materially dependent upon the Delhi field operator's ability to: (i) deliver sufficient
quantities of CO2 from its reserves in the Jackson Dome source, (ii) secure its share of capital necessary to fund development
and operating commitments with respect to the field and (iii) successfully manage related technical, operating, environmental,
strategic and logistical risks, among other things.
We are aware that DNR, which is publicly traded, has disclosed in its public SEC filings certain risks related to its current
level of indebtedness and the related financial covenants. They have stated, for example, that their level of indebtedness could
have important consequences, including, among others, requiring dedication of a substantial portion of DNR’s cash flow from
operations to servicing their indebtedness (so that such cash flows would not be available for capital expenditures or other
purposes). They noted that their ability to meet their obligations under their debt instruments will depend in part upon
prevailing economic conditions and commodity prices. DNR also noted that it has from time to time deferred development
spending for certain projects.
Given the current stress in the global commodity markets and oil and gas in particular, our operator could be materially
negatively impacted, which could in turn negatively affect the operator’s ability to operate the Delhi field as well as its financial
commitment to the CO2-EOR project in the field, and thus our interests in the Delhi field could be materially negatively
impacted.
The types of resources we focus on have substantial operational risks.
Our business plan focuses on the acquisition and development of known resources in partially depleted reservoirs,
naturally fractured or low permeability reservoirs. Our Delhi asset is productive from a relatively shallow reservoir but we may
pursue assets that produce from deeper reservoirs. Shallower reservoirs usually have lower pressure, which generally translates
into lower reserve volumes in place. Deeper reservoirs have higher pressures and usually more reserve volumes, but capturing
those reserves often comes at increased drilling and completion risk. Low permeability reservoirs require more wells and
substantial stimulation for development of commercial production. Naturally fractured reservoirs require penetration of
sufficient undepleted fractures to establish commercial production. Depleted reservoirs require successful application of newer
technology to unlock incremental reserves.
Our CO2-EOR project in the Delhi field, operated by a subsidiary of Denbury Resources Inc., requires significant
amounts of CO2 reserves, development capital and technical expertise, the sources of which to date have been committed by the
14
operator. Although initial CO2 injection began at Delhi in November 2009, initial oil production response began in March 2010
and a large part of the capital budget has already been expended, additional capital remains to be invested to fully develop the
EOR project, further increase production and maximize the value of the asset. The operator's failure to manage these and other
technical, environmental, operating, strategic, financial and logistical risks may cause ultimate enhanced recoveries from the
planned CO2-EOR project to fall short of our expectations in volume and/or timing. Such occurrences would have a material
adverse effect on the Company, its results of operations and financial condition.
Crude oil and natural gas development, re-completion of wells from one reservoir to another reservoir, restoring wells to
production and drilling and completing new wells are speculative activities and involve numerous risks and substantial
uncertain costs.
Our growth will be materially dependent upon the success of our future development program. Drilling for crude oil and
extracting natural gas liquids and re-working existing wells involve numerous risks, including the risk that no commercially
productive crude oil or natural gas reservoirs will be encountered. The cost of drilling, completing and operating wells is
substantial and uncertain, and drilling operations may be curtailed, delayed or canceled as a result of a variety of factors beyond
our control, including, but not limited to:
•
•
•
•
•
•
•
•
unexpected drilling conditions;
pressure fluctuations or irregularities in formations;
equipment failures or accidents;
environmental events;
inability to obtain or maintain leases on economic terms, where applicable;
adverse weather conditions;
compliance with governmental requirements; and
shortages or delays in the availability of drilling rigs or crews and the delivery of equipment.
Drilling or re-working is a highly speculative activity. Even when fully and correctly utilized, modern well completion
techniques such as horizontal drilling or CO2 injection or other injectants do not guarantee that we will find and produce crude
oil and/or natural gas in our wells in economic quantities. Our future drilling activities may not be successful and, if
unsuccessful, such failure would have an adverse effect on our future results of operations and financial condition. We cannot
assure you that our overall drilling success rate or our drilling success rate for activities within a particular geographic area will
not decline.
We may also identify and develop prospects through a number of methods, some of which may include horizontal drilling
or tertiary injectants, and some of which may be unproven. The drilling and results for these prospects may be particularly
uncertain. We cannot assure you that these projects can be successfully developed or that the wells discussed will, if drilled,
encounter reservoirs of commercially productive crude oil or natural gas.
The loss of a large single purchaser of our oil and natural gas could reduce the competition of our production.
For the year ended June 30, 2019, one purchaser accounted for 94% of our oil and natural gas liquid revenues. We do not
currently market our share of crude oil production from the Delhi field. Although we have the right to take our working interest
production in-kind, we are currently accepting terms under the Delhi operator's agreement with Plains Marketing L.P. for the
delivery and pricing of our oil at the field. The loss of such large single purchaser for our oil and natural gas production could
negatively impact the revenue we receive. We cannot assure you we could readily find other purchasers for our oil and natural
gas production. In addition, the crude oil production from the Delhi field is transported by pipeline and if this pipeline
transportation were disrupted and we were forced to use alternative transportation methods, our net realized pricing and
potentially our near-term production levels could be adversely affected.
Our crude oil and natural gas reserves are only estimates and may prove to be inaccurate.
There are numerous uncertainties inherent in estimating crude oil and natural gas reserves and their estimated values. Our
reserves are only estimates that may prove to be inaccurate because of these uncertainties. Reservoir engineering is a subjective
and inexact process of estimating underground accumulations of crude oil and natural gas that cannot be measured in an exact
manner. Estimates of economically recoverable crude oil and natural gas reserves depend upon a number of variable factors,
such as historical production from the area compared with production from other producing areas and assumptions concerning
effects of regulations by governmental agencies, future crude oil and natural gas product prices, future operating costs,
severance and excise taxes, development costs and work-over and remedial costs. Some or all of these assumptions may vary
considerably from actual results. For these reasons, estimates of the economically recoverable quantities of crude oil and
natural gas attributable to any particular group of properties, classifications of such reserves based on risk of recovery, and
estimates of the future net cash flows expected therefrom prepared by different engineers or by the same engineers but at
different times, may vary substantially.
15
Accordingly, reserve estimates may be subject to downward or upward adjustment. Actual production, revenue and
expenditures with respect to our reserves will likely vary from estimates, and such variances may be material. The information
regarding discounted future net cash flows included in this report should not be considered as the current market value of the
estimated crude oil and natural gas reserves attributable to our properties. The estimated discounted future net cash flows from
proved reserves are based on the 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-
the-month price for each month within the 12-month period prior to the end of the reporting period, and costs as of the date of
the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be
affected by factors such as the amount and timing of actual production, supply and demand for crude oil and natural gas,
increases or decreases in consumption, and changes in governmental regulations or taxation. In addition, the 10% discount
factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, is not
necessarily the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us
or the crude oil and natural gas industry in general. The Standardized Measure and PV-10 do not necessarily correspond to
market value.
Regulatory and accounting requirements may require substantial reductions in reporting proven reserves.
We review on a periodic basis the carrying value of our crude oil and natural gas properties under the applicable rules of
the various regulatory agencies, including the SEC. Under the full cost method of accounting that we use, the after-tax carrying
value of our oil and natural gas properties may not exceed the present value of estimated future net after-tax cash flows from
proved reserves, discounted at 10%. Application of this "ceiling" test requires pricing future revenues at the previous 12-month
average beginning-of-month price and requires a write down of the carrying value for accounting purposes if the ceiling is
exceeded. We may in the future be required to write down the carrying value of our crude oil and natural gas properties when
crude oil and natural gas prices are depressed or unusually volatile. Whether we will be required to take such a charge will
depend in part on the prices for crude oil and natural gas during the previous period and the effect of reserve additions or
revisions and capital expenditures during such period. If a write down is required, it would result in a current charge to our
earnings but would not impact our current cash flow from operating activities. A large write-down could adversely affect our
compliance with the current financial covenants under our credit facility and could limit our access to future borrowings under
that facility or require repayment of any amounts that might be outstanding at the time.
Our derivative activities could result in financial losses or could reduce our income.
To achieve more predictable cash flows and to reduce our exposure to adverse fluctuations in the prices of oil and natural
gas liquids, we have, and may in the future, enter into derivative arrangements for a portion of our oil and natural gas liquids
production, including costless collars and fixed-price swaps. We have not designated any of our derivative instruments as
hedges for accounting purposes and record all derivative instruments on our balance sheet at fair value. Changes in the fair
value of our derivative instruments are recognized in earnings. Accordingly, our earnings may fluctuate significantly as a result
of changes in the fair value of our derivative instruments. Derivative arrangements also expose us to the risk of financial loss in
some circumstances, including, but not limited to, if:
•
•
•
production is less than the volume covered by the derivative instruments;
the counterparty to the derivative instrument defaults on its contract obligations; or
there is a change in the expected differential between the underlying price in the derivative instrument and actual
price received.
In addition, some of these types of derivative arrangements limit the benefit we would receive from increases in the prices
for oil and natural gas liquids and may expose us to cash margin requirements.
We may have difficulty managing future growth and the related demands on our resources and may have difficulty in
achieving future growth.
Although we plan to experience growth through acquisitions and development activity, any such growth may place a
significant strain on our financial, technical, operational and administrative resources. Our ability to grow will depend upon a
number of factors, including, but not limited to the following:
•
•
•
•
•
•
•
•
our ability to identify and acquire new development projects;
our ability to develop new and existing properties;
our ability to continue to retain and attract skilled personnel;
the results of our development program and acquisition efforts;
the success of our technologies;
hydrocarbon prices;
drilling, completion and equipment prices;
our ability to successfully integrate new properties;
16
•
•
our access to capital; and
the Delhi field operator's ability to: (i) deliver sufficient quantities of CO2 from its reserves in the
Jackson Dome, (ii) secure all of the development capital necessary to fund its and our cost interests, and
further develop the Delhi field, such as advancement of Phase V development in the undeveloped
eastern part of the field, (iii) successfully manage technical, operating, environmental, strategic and
logistical development and operating risks, and (iv) maintain its own financial stability, among other
things.
We cannot assure you that we will be able to successfully grow or manage any such growth.
Our operations may require significant amounts of capital and additional financing may be necessary in order for us to
continue our exploitation activities, including meeting potential future drilling obligations.
Our cash flow from our reserves may not be sufficient to fund our ongoing activities at all times. From time to time, we
may require additional financing in order to carry out our oil and gas acquisitions, exploitation and development activities.
Certain of our undeveloped leasehold acreage may be subject to leases that will expire unless production is established. If our
revenues from our reserves decrease as a result of lower oil and natural gas prices or otherwise, it will affect our ability to
expend the necessary capital to replace our reserves or to maintain our current production. If our cash flow from operations is
not sufficient to satisfy our capital expenditure requirements, there can be no assurance that additional debt or equity financing
will be available to meet these requirements or available to us on favorable terms.
We may be subject to risks in connection with acquisitions because of uncertainties in evaluating recoverable reserves, well
performance and potential liabilities, as well as uncertainties in forecasting oil and gas prices and future development,
production and marketing costs, and the integration of significant acquisitions may be difficult.
We periodically evaluate acquisitions of reserves, properties, prospects and leaseholds and other strategic transactions that
appear to fit within our overall business strategy. The successful acquisition of producing properties requires an assessment of
several factors, including, but not limited to:
•
•
•
•
•
•
recoverable reserves
future oil and natural gas prices and their appropriate differentials;
development and operating costs;
potential for future drilling and production;
validity of the seller's title to properties, which may be less than expected at closing; and
potential environmental issues, litigation and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of
the subject properties that we believe to be generally consistent with industry practices. Our review will not reveal all existing
or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies
and potential recoverable reserves. Inspections may not always be performed on every well, and environmental problems are
not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be
unwilling or unable to provide effective contractual protection against all or part of the problems. Moreover, in the event of
such an acquisition, there is a risk that we could ultimately be liable for unknown obligations related to acquisitions, which
could materially adversely affect our financial condition, results of operations or cash flows.
Significant acquisitions and other strategic transactions may involve other risks, including, but not limited to:
•
•
•
•
•
our lean management team's capacity could be challenged by the demands of evaluating, negotiating and
integrating significant acquisitions and strategic transactions in concert with the Company's on going business
demands;
the challenge and cost of integrating acquired operations, information management and other technology systems
and business cultures with those of our operations while carrying on our ongoing business;
difficulty associated with coordinating geographically separate organizations;
an inability to secure, on acceptable terms, sufficient financing that my be required in connection with expanded
operations and unknown liabilities; and
the challenge of attracting and retaining personnel associated with acquired operations.
The process of integrating assets could cause an interruption of, or loss of momentum in, the activities of our business.
Members of our senior management may be required to devote considerable amounts of time to this integration process, which
will decrease the time they will have to manage our business. If our senior management is not able to effectively manage the
integration process, or if any significant business activities are interrupted as a result of the integration process, our business
could suffer. In addition, even if we successfully integrate the assets acquired in an acquisition, it may not be possible to realize
17
the full benefits we may expect in estimated proved reserves, production volumes, cost savings from operating synergies or
other benefits anticipated from an acquisition or realize these benefits within the expected time frame.
Government regulation and liability for oil and gas operations and environmental matters may adversely affect our business
and results of operations.
Crude oil and natural gas operations are subject to extensive federal, state and local government regulations, which may
be changed from time to time. Matters subject to regulation include discharge permits for drilling operations, drilling bonds,
reports concerning operations, the spacing of wells, unitization and pooling of properties and taxation. From time to time,
regulatory agencies have imposed price controls and limitations on production by restricting the rate of flow of crude oil and
natural gas wells below actual production capacity in order to conserve supplies of crude oil and natural gas. There are federal,
state and local laws and regulations primarily relating to protection of human health and the environment applicable to the
development, production, handling, storage, transportation and disposal of crude oil and natural gas, by-products thereof, the
emission of CO2 or other greenhouse gases, and other substances and materials produced or used in connection with crude oil
and natural gas operations. These laws and regulations may affect the costs, manner and feasibility of our operations and
require us to make significant expenditures in order to comply. In addition, we may inherit liability for environmental
damages, whether actual or not, caused by previous owners of property we purchase or lease or nearby properties. As a result,
failure to comply with these laws and regulations may result in substantial liabilities to third parties or governmental entities.
We are also subject to changing and extensive tax laws, the effects of which cannot be predicted. The implementation of new,
or the modification of existing, laws or regulations could have a material adverse effect on us, such as diminishing the demand
for our products through legislative enactment of proposed new penalties, fines and/or taxes on carbon that could have the
effect of raising prices to the end user.
Our business could be negatively affected by security threats. A cyber attack or similar incident could occur and result in
information theft, data corruption, operational disruption, damage to our reputation and/or financial loss.
The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain
exploration, development, production, processing and financial activities. We depend on digital technology to estimate
quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and
drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks,
seismic data, reserves information or other proprietary information, and those of our operator, vendors, suppliers, customers
and other business partners, may become the target of cyber attacks or information security breaches that could result in the
unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could
otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production
operations. Cyber attacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain
undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or
otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption
of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution
systems in the United States and abroad, which are necessary to transport our production to market. A cyber attack directed at
oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent
delivery of production to markets and make it difficult or impossible to accurately account for production and settle
transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be
specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not
be sufficient. Further, as cyber attacks continue to evolve, we may be required to expend significant additional resources to
continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber attacks.
Our insurance may not protect us against all of the operating risks to which our business is exposed.
The crude oil and natural gas business involves numerous operating hazards such as well blowouts, mechanical failures,
explosions, uncontrollable flows of crude oil, natural gas or well fluids, fires, formations with abnormal pressures, hurricanes,
flooding, pollution, releases of toxic gas and other environmental hazards and risks, which can result in (i) damage to or
destruction of wells and/or production facilities, (ii) damage to or destruction of formations, (iii) injury to persons, (iv) loss of
life, or (v) damage to property, the environment or natural resources. While we carry general liability, control of well, and
operator's extra expense coverage typical in our industry, we are not fully insured against all risks incidental to our business.
Environmental events similar to that experienced in the Delhi field in June 2013 could defer revenue, increase operating costs
and/or increase maintenance and repair capital expenditures.
The loss of key personnel could adversely affect us.
We depend to a large extent on the services of certain key management personnel, including our executive officers, the
loss of any of whom could have a material adverse effect on our operations. In particular, our future success is dependent upon
18
the abilities of Robert Herlin, our Chairman of the Board, Jason Brown, our President and Chief Executive Officer, and David
Joe, Senior Vice President, Chief Financial Officer, Treasurer and Corporate Secretary, to source, evaluate and close deals, raise
capital, and oversee our development activities and operations. Presently, the Company is not a beneficiary of any key man life
insurance.
Oil field service and materials' prices may increase, and the availability of such services and materials may be inadequate to
meet our needs.
Our business plan to develop or redevelop crude oil and natural gas resources requires third party oilfield service vendors
and various material providers, which we do not control. We also rely on third-party carriers for the transportation and
distribution of our production. As our production increases, so does our need for such services and materials. Generally, we do
not have long-term agreements with our service and materials providers. Accordingly, there is a risk that any of our service
providers could discontinue servicing our crude oil and natural gas fields for any reason or we may not be able to source the
materials we need. Any delay in locating, establishing relationships, and training our sources could result in production
shortages and maintenance problems, with a resulting loss of revenue to us. In addition, if costs for such services and materials
increase, it may render certain or all of our projects uneconomic, as compared to the earlier prices we may have assumed when
deciding to redevelop newly purchased or existing properties. Further adverse economic outcomes may result from the long
lead times often necessary to execute and complete our redevelop plans.
We cannot market the crude oil and natural gas that we produce without the assistance of third parties.
The marketability of the crude oil and natural gas that we produce depends upon the proximity of our reserves to, and the
capacity of, facilities and third-party services, including crude oil and natural gas gathering systems, pipelines, trucking or
terminal facilities, and processing facilities necessary to make the products marketable for end use. The unavailability or lack of
capacity of such services and facilities could result in the shut-in of producing wells or the delay or discontinuance of
development plans for properties. A shut-in or delay or discontinuance could adversely affect our financial condition.
We face strong competition from larger oil and gas companies.
Our competitors include major integrated crude oil and natural gas companies and numerous larger independent crude oil
and natural gas companies, individuals and drilling and income programs. Many of our competitors are large, well-established
companies with substantially larger operating staffs and greater capital resources than ours. We may not be able to successfully
conduct our operations, evaluate and select suitable properties and consummate transactions in this highly competitive
environment. Specifically, these larger competitors may be able to pay more for development projects and productive crude oil
and natural gas properties and may be able to define, evaluate, bid for and purchase a greater number of properties and
prospects than our financial or human resources permit. In addition, such companies may be able to expend greater resources
on hiring contract service providers, obtaining oilfield equipment and acquiring the existing and changing technologies that we
believe are and will be increasingly important to attaining success in our industry.
We have been, and in the future may become, involved in legal proceedings related to our Delhi interest or other properties
or operations and, as a result, may incur substantial costs in connection with those proceedings.
From time to time we may be a defendant or plaintiff in various lawsuits. The nature of our operations exposes us to
further possible litigation claims in the future. There is risk that any matter in litigation could be decided unfavorably against
us regardless of our belief, opinion, and position, which could have a material adverse effect on our financial condition, results
of operations, and cash flow. Litigation can be very costly, and the costs associated with defending litigation could also have a
material adverse effect on our financial condition. Adverse litigation decisions or rulings may damage our business reputation.
Ownership of our oil, gas and mineral production depends on good title to our property.
Good and clear title to our oil, gas and mineral properties is important to our business. Although title reviews will
generally be conducted prior to the purchase of most oil, gas and mineral producing properties or the commencement of drilling
wells, such reviews do not assure that an unforeseen defect in the chain of title will not arise to defeat our claim which could
result in a reduction or elimination of the revenue received by us from such properties.
19
Poor general economic, business, or industry conditions may have a material adverse effect on our results of operations,
liquidity, and financial condition.
During the last few years, concerns over inflation, energy costs, declining oil and gas prices, geopolitical issues, the
availability and cost of credit, the U.S. mortgage market, uncertainties with regard to European sovereign debt, the slowdown
in economic growth in large emerging and developing markets, such as China, regional or worldwide increases in tariffs or
other trade restrictions, and other issues have contributed to increased economic uncertainty and diminished expectations for
the global economy. Concerns about global economic conditions have had a significant adverse impact on domestic and
international financial markets and commodity prices. If uncertain or poor economic, business or industry conditions in the
United States or abroad remain prolonged, demand for petroleum products could diminish or stagnate, production costs could
increase, any of which could impact the price at which we can sell our oil, natural gas, and NGLs, affect our vendors', suppliers'
and customers' ability to continue operations, and ultimately adversely impact our results of operations, liquidity, and financial
condition.
Risks Associated with Our Stock
Our stock price has been and may continue to be volatile.
Our common stock has relatively low trading volume and the market price has been, and is likely to continue to be,
volatile. For example, during the fiscal year ending June 30, 2019, our stock price as traded on the NYSE American ranged
from $5.99 to $12.32. The variance in our stock price makes it difficult to forecast with certainty the stock price at which an
investor may be able to buy or sell shares of our common stock. The market price for our common stock could be subject to
fluctuations as a result of factors that are out of our control, such as:
•
•
•
•
•
•
actual or anticipated variations in our results of operations;
naked short selling of our common stock and stock price manipulation;
changes or fluctuations in the commodity prices of crude oil and natural gas;
general conditions and trends in the crude oil and natural gas industry;
redemption demands on institutional funds that hold our stock; and
general economic, political and market conditions.
Our executive officers, directors and affiliates may be able to control the election of our directors and all other matters
submitted to our stockholders for approval.
As of June 30, 2019 our executive officers and directors, in the aggregate, beneficially owned approximately 2.5 million
shares, or approximately 7.4% of our beneficial common stock base. Blackrock Fund Advisors, et al controlled approximately
3.5 million shares or approximately 10.6 % of our outstanding common stock, Renaissance Technologies, LLC controlled
approximately 2.2 million shares or approximately 6.7% of our outstanding common stock, and JVL Advisors, LLC controlled
approximately 2.1 million shares or approximately 6.5%. As a result, any of these holders could potentially exercise significant
influence over matters submitted to our stockholders for approval (including the election and removal of directors and any
merger, consolidation or sale of all or substantially all of our assets). This concentration of ownership may have the effect of
delaying, deferring or preventing a change in control of our company, impede a merger, consolidation, takeover or other
business combination involving our company or discourage a potential acquirer from making a tender offer or otherwise
attempting to obtain control of our company, which in turn could have an adverse effect on the market price of our common
stock.
The market for our common stock is limited and may not provide adequate liquidity.
Our common stock trades on the NYSE American. Our trading volumes increased in fiscal 2019 compared to fiscal 2018.
Trading volume in our common stock is relatively low compared to larger companies. During the fiscal year ended June 30,
2019, the daily trading volume in our common stock ranged from a low of 45,600 shares to a high of 1,079,500 shares, with
average daily trading volume of 180,353 shares compared to average daily volume of 112,015 in fiscal 2018. Our holders may
find it more difficult to sell their shares, should they desire to do so, based on the trading volume and price of our stock at that
time relative to the quantity of shares to be sold.
20
If securities or industry analysts do not publish research reports about our business, or if they downgrade our stock, the
price of our common stock could decline.
Small, relatively unknown companies can achieve visibility in the trading market through research and reports that
industry or securities analysts publish. To our knowledge there are three independent analysts that cover our company. The
limited number of published reports by independent securities analysts could limit the interest in our common stock and
negatively affect our stock price. We do not have any control over the research and reports these analysts publish or whether
they will be published at all. If any analyst who does cover us downgrades our stock, our stock price could decline. If any
analyst ceases coverage of our company or fails to regularly publish reports on us, we could lose visibility in the financial
markets, which in turn could cause our stock price to decline.
The issuance of additional common stock and preferred stock could dilute existing stockholders.
We currently have in place an effective registration statement which allows the company to publicly issue up to
$500 million of additional securities, including debt, common stock, preferred stock, and warrants. At any time we may make
private offerings of our securities. The shelf registration is intended to provide greater flexibility to the company in financing
growth or changing our capital structure. We are authorized to issue up to 100,000,000 shares of common stock. To the extent
of such authorization, our board of directors has the ability, without seeking stockholder approval, to issue additional shares of
common stock in the future for such consideration as our board may consider sufficient. The issuance of additional common
stock in the future would reduce the proportionate ownership and voting power of the common stock now outstanding. We are
also authorized to issue up to 5,000,000 shares of preferred stock, the rights and preferences of which may be designated in
series by our board of directors. Such designation of any new series of preferred stock may be made without stockholder
approval, and could create additional securities which would have dividend and liquidation preferences over the common stock
now outstanding. Preferred stockholders could adversely affect the rights of holders of common stock by:
•
•
•
•
exercising voting, redemption and conversion rights to the detriment of the holders of common stock;
receiving preferences over the holders of common stock regarding our surplus funds in the event of our
dissolution, liquidation or the payment of dividends to preferred stockholders;
delaying, deferring or preventing a change in control of our company; and
discouraging bids for our common stock.
Continued payment of dividends on our common stock could be impacted.
Our Board of Directors declared cash dividends on our common stock for the first time in December 2013 and we have
declared and paid quarterly cash dividends since that time. However, there is no certainty that dividends will be declared by the
Board of Directors in the future. Any payment of cash dividends on our common stock in the future will be dependent upon the
amount of funds legally available, our earnings, if any, our financial condition and business plan, restrictions contained in
current or future debt instruments, contractual covenants or arrangements we may enter into, our anticipated capital
requirements and other factors that our board of directors may think are relevant. Accordingly, there is no guarantee that we
will be able or choose to continue to pay cash dividends on our common stock.
Item 1B. Unresolved Staff Comments
None.
Item 2. Properties
Information regarding our properties is included in “Item 1. Business” above and in “Note 6. Property and Equipment” of
the Notes to our Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data,”which
information is incorporated herein by reference.
Item 3. Legal Proceedings
See Note 16 – Commitments and Contingencies under Item 8. Financial Statements for a description of legal
proceedings, which is incorporated herein by reference.
Item 4. Mine Safety Disclosures
Not Applicable.
21
PART II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
Securities
Common Stock
Our common stock is currently traded on the NYSE American under the ticker symbol "EPM". The following table
shows, for each quarter of the fiscal years ended June 30, 2019 and 2018, the high and low sales prices for EPM as reported by
the NYSE American.
NYSE American: EPM
2019:
Fourth quarter ended June 30, 2019
Third quarter ended March 31, 2019
Second quarter ended December 31, 2018
First quarter ended September 30, 2018
2018:
Fourth quarter ended June 30, 2018
Third quarter ended March 31, 2018
Second quarter ended December 31, 2017
First quarter ended September 30, 2017
Shares Outstanding and Holders
High
Low
$
$
$
$
$
$
$
$
7.40
8.11
12.83
12.00
High
10.50
8.30
7.63
8.70
$
$
$
$
$
$
$
$
5.99
6.44
6.17
9.60
7.75
6.70
6.35
6.35
Low
As of June 30, 2019, there were 33,183,730 shares of common stock issued and outstanding, held by approximately 250
holders of record. We estimate there are approximately 2,000 individuals and institutions that hold our stock through nominees.
Dividends
We began paying cash quarterly dividends on our common stock in December 2013. Over the last two fiscal years, the
Company made the following cash dividends per share:
Fourth quarter ended June 30,
Third quarter ended March 31,
Second quarter ended December 31,
First quarter ended September 30,
`
Years Ended June 30,
2019
$0.100
$0.100
$0.100
$0.100
2018
$0.100
$0.100
$0.075
$0.075
As of June 30, 2019, we had paid twenty-three consecutive quarterly dividends on our common stock. In August 2019, the
Company declared a $0.10 per share dividend payable on September 30, 2019. Any future determination with regard to the
payment of dividends will be at the discretion of the Board of Directors and will be dependent upon our future earnings,
financial condition, applicable dividend restrictions and capital requirements and other factors deemed relevant by the Board of
Directors. Under our current revolving credit facility, our ability to continue to pay common stock dividends is dependent on
compliance with certain financial covenants related to debt service coverage, as defined in the agreement.
Performance Graph
The following graph presents a comparison of the yearly percentage change in the cumulative total return on our
Common Stock over the period from June 30, 2014 to June 30, 2019 with the cumulative total return of the S&P 500 Index and
22
the S&P Oil & Gas Exploration and Production Index of publicly traded companies over the same period. The graph assumes
that $100 was invested on June 30, 2014 in our common stock at the closing market price at the beginning of this period and in
each of the other two indices and the reinvestment of all dividends, if any. The graph is presented in accordance with
requirements of the SEC. Shareholders are cautioned against drawing any conclusions from the data contained therein, as past
results are not necessarily indicative of future financial performance.
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)
— (1)
10,156
(1)
10,156
—
10,156
$
$
$
—
—
—
—
—
852,111
—
852,111
(1) As of June 30, 2019, all stock options had been exercised and no shares of common stock were issuable related to
outstanding stock options. The Amended and Restated 2004 Stock Plan (the "Plan") provided for the issuance of a
total of 6,500,000 common shares. Under the Plan as of June 30, 2019, 3,939,365 common shares had been issued
upon the exercise of stock options, 2,382,843 shares of restricted common stock had been issued (of which 42,833
23
were unvested as of June 30, 2019), contingent restricted stock grants of 145,646 shares had been reserved (of which
10,156 were unvested as of June 30, 2019) and 32,146 remaining reserved shares were released in December 2016 to
the Company's authorized but unissued and unreserved shares. The Plan was terminated upon the adoption of 2016
Equity Incentive Plan (the "2016 Plan"), which authorized the issuance of 1,100,000 shares of common stock. During
fiscal 2019, 110,982 awards were made under the 2016 Plan and 852,111 shares of common stock remain available for
future grants at June 30, 2019.
Issuer Purchases of Equity Securities
(a) Total Number of
Shares (or Units)
Purchased (1) (2)
(b) Average Price
Paid per Share (or
Units)
(c) Total Number of Shares
(or Units) Purchased as Part
of Publicly Announced Plans
or Programs
(d) Maximum Number (or
Approximate Dollar Value)
of Shares (or Units) that
May Yet Be Purchased
Under the Plans or
Programs
None
None
2,935
Not applicable
Not applicable
$3.4 million
Not applicable
Not applicable
$3.4 million
$6.19
266,192
$3.4 million
Period
April 1, 2019 to
April 30, 2019
May 1, 2019 to
May 31, 2019
June 1, 2019 to
June 30, 2019
(1) During the fourth quarter ended June 30, 2019, the Company received shares of common stock from certain of its
employees which were surrendered in exchange for their payroll tax liabilities arising from vestings of restricted stock and
contingent restricted stock. The acquisition cost per share reflects the weighted-average market price of the Company's
shares on the dates vested.
(2) On May 12, 2015, the Board of Directors approved a share repurchase program covering up to $5 million of the
Company's common stock. Under the program's terms, shares may be repurchased only on the open market and in
accordance with the requirements of the Securities and Exchange Commission. The timing and amount of repurchases will
depend upon several factors, including financial resources and market and business conditions. There is no fixed
termination date for this repurchase program, and the repurchase program may be suspended or discontinued at any time.
Such shares are initially recorded as treasury stock, then subsequently canceled. The Company repurchased 430 shares in
June 2019 at an average price of $6.07 per share. There were no other program purchases in fiscal 2019.
24
Item 6. Selected Financial Data
The selected consolidated financial data, set forth below should be read in conjunction with Item 7. "Management's
Discussion and Analysis of Financial Condition and Results of Operations" and with the consolidated financial statements and
notes to those consolidated financial statements included elsewhere in this report.
Income Statement Data
Revenues
Cost of revenues
Depreciation, depletion, and
amortization
General and administrative expense
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:
2019
2018
June 30,
2017
2016
2015
$ 43,229,621
$ 40,773,527
$ 34,253,681
$ 26,349,502
$ 27,841,265
14,266,784
11,685,817
10,604,594
9,133,111
9,355,613
6,253,083
5,072,931
—
17,636,823
1,222,604
3,482,361
6,102,288
6,773,781
—
16,211,641
(25,126)
(3,431,969)
5,779,069
4,985,408
4,488
12,880,122
5,214,174
9,079,597
1,257,433
1,665,187
4,855
32,565,954
4,840,664
9,570,779
3,650,603
6,256,783
(5,431)
8,583,697
(147,619)
3,444,221
$ 15,377,066
$ 19,618,484
$
8,044,313
$ 24,660,362
$
4,991,857
—
—
—
—
250,990
674,302
674,302
1,002,440
—
—
$ 15,377,066
$ 19,618,484
$
6,790,883
$ 23,986,060
$
4,317,555
Basic
Diluted
$
$
0.46
0.46
$
$
0.59
0.59
$
$
0.21
0.21
$
$
0.73
0.73
$
$
0.13
0.13
Balance Sheet Data
Total current assets
Total assets
Total current liabilities
Total liabilities
Stockholders' equity
Number of common shares outstanding
Working capital, net
2,752,694
15,635,986
80,125,858
33,183,730
32,426,233
Cash dividends to common stockholders
13,272,058
June 30, 2019
June 30, 2018
June 30, 2017
June 30, 2016
June 30, 2015
$ 35,178,927
$ 32,147,556
$ 26,142,527
$ 37,086,450
$ 23,693,048
95,761,844
93,662,544
88,268,668
97,451,051
69,882,727
4,430,214
16,373,065
77,289,479
33,080,543
27,717,342
11,594,541
2,718,894
19,798,813
68,469,855
33,087,308
23,423,633
8,432,435
8,528,908
21,129,901
76,321,150
32,907,863
28,557,542
6,565,823
9,329,257
21,306,150
48,576,577
32,845,205
14,363,791
9,833,642
25
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Executive Overview
Results of Operations
Liquidity and Capital Resources
Critical Accounting Policies
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. The Company's long-term goal is
to build a diversified portfolio of oil and gas assets primarily through acquisitions, while seeking opportunities to maintain and
increase production through selective development, production enhancement and other exploitation efforts on its properties.
Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a
CO2 enhanced oil recovery project, and a de minimis overriding royalty interest retained in a past divestiture.
By policy, every employee and director maintains a beneficial ownership position in our common stock. We believe this
ownership helps ensure that the interests of our employees and directors are aligned with our stockholders.
In May 2018, our then President and Chief Executive Officer elected to retire as of May 31, 2018. Robert Herlin, our
Chairman of the Board, founder and previous CEO, was appointed by the board to the position of Interim CEO. A special
Transition Services Committee of the board was created with one member, William Dozier, to provide additional operational
oversight to the Company during the transition to a new CEO. On July 10, 2019, Mr. Jason Brown, age 42, was appointed by
the Board of Directors to serve as President and Chief Executive Officer of the Company. Robert Herlin, remained as Chairman
of the Board.
Highlights for our 2019 Fiscal Year
• We recognized net income of $15.4 million, or $0.46 per diluted common share, our eighth consecutive year of
reporting net income
• We funded all operations, including $5.2 million of capital spending, from internal resources and remained debt free
• We returned $13.3 million to common shareholders in the form of cash dividends
• Oil and NGL revenues increased by $2.5 million to $43.2 million, an increase of 6%
• We increased working capital by 17% to $32.4 million at June 30, 2019, with cash on hand of $31.6 million. The
twelve well infill program, consisting of ten producer wells and two CO2 injector wells, was completed and on
production during fiscal 2019, converting 536 MBOE of proved undeveloped to proved developed reserves
• Capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi
Phase V development is almost complete. The first pad commenced operations during fiscal 2019 and the second pad
is expected to begin injections during our second quarter of fiscal 2020
Oil & Natural Gas Liquids Reserves (based on SEC average NYMEX WTI oil price of $61.62 per barrel at June 30, 2019)
• Delhi proved oil equivalent reserves at June 30, 2019 were 9.0 MMBOE, a 4% decrease from the previous year.
The Standardized Measure for proved reserves increased 7% to $127 million, reflecting a rise in realized commodity
prices from $54.71 to $58.50 per BOE. Our proved reserves are 85% crude oil and 15% natural gas liquids, and of
these proved reserves, 82% are classified as proved developed and producing and 18% are proved undeveloped.
• Delhi probable reserves at June 30, 2019 were 4.8 MMBOE, a 7% increase over the previous year. 87% of these
reserves are classified as probable developed and producing, as they are incremental reserves associated with existing
developed and producing locations. No additional capital investment is required beyond what is captured in proved
reserves.
26
• Delhi possible reserves at June 30, 2019 were 4.3 MMBOE, a 7% decrease over the previous year. 91% of these
reserves are classified as possible developed and producing, as they are incremental reserves associated with existing
developed and producing locations. No additional capital investment is required beyond what is captured in proved
reserves.
The following table is a summary of our proved, probable and possible reserves as of June 30, 2019 and 2018:
Proved
Probable
Possible
Reserves MMBOE
% Developed
Liquids %
2019
9.0
82%
2018
Change
2019
2018
Change
9.4
78%
(4)%
5 %
4.8
87%
4.5
80%
7%
9%
2019
4.3
91%
4.6
88%
2018
Change
100%
100% — %
100%
100%
—%
100%
100%
(7)%
3 %
— %
Standardized Measure ($MM) $ 127
PV-10* ($MM)
$ 157
$ 119
$ 146
7 %
8 %
____________________________________________________________________________
* PV-10 of proved reserves is a pre-tax non-GAAP measure. We have included a reconciliation of PV-10 to the
unaudited after-tax Standardized Measure of Discounted Future Net Cash Flows ("Standardized Measure"), which is
the most directly comparable financial measure calculated in accordance with GAAP, in Item 1. "Business - Estimated
Oil and Natural Gas Reserves and Estimated Future Net Revenues." We believe that the presentation of the non-
GAAP financial measure of PV-10 provides useful and relevant information to investors because of its wide use by
analysts and investors in evaluating oil and gas companies, and that it is relevant and useful in evaluating the relative
monetary significance of oil and natural gas properties. Further, analysts and investors may utilize the measure as a
basis for comparison of the relative size and value of our reserves to other companies’ reserves. We also use this pre-
tax measure when assessing the potential return on investment related to oil and natural gas properties and in
evaluating acquisition opportunities. Because there are many unique factors that can impact an individual company
when estimating the amount of future income taxes to be paid, we believe the use of a pre-tax measure is valuable for
evaluating our Company. PV-10 is not a measure of financial or operating performance under GAAP, nor is it intended
to represent the current market value of our estimated oil and natural gas reserves. PV-10 should not be considered in
isolation or as a substitute for the Standardized Measure as defined under GAAP, and is reconciled to the Standardized
Measure in Item 1. Business. Probable and possible reserves are not recognized as GAAP, nor is there a comparable
GAAP measure.
Additional property and project information is included under Item 1. Business, Item 8. Financial Statements - Notes to
the Financial Statements and Exhibit 99.1 of this Form 10-K.
Delhi Field
Our interests in the Delhi field consist of a 23.9% working interest (with associated 19.0% net revenue interest) and
separate overriding royalty and mineral interests of 7.2%. This yields a total net revenue interest of 26.2%. The Delhi field is
operated by Denbury Onshore, LLC (the "operator"), a subsidiary 100% owned by Denbury Resources Inc. .
Proved reserves volumes totaled 9.0 MMBOE with a Standardized Measure of $127 million and a PV-10* value of $157
million compared to the prior year's 9.4 MMBOE with a Standardized Measure of $119 million and a PV-10* value of $146
million. Improved performance of producing wells has led to a 0.152 MMBOE, or 2%, positive revision in proved oil reserves.
Performance from the NGL plant was improved via capitalized modifications resulting in a 0.199 MMBOE, or 16%, positive
revision to NGL reserves. Probable reserve volumes at Delhi were 4.8 MMBOE, an increase of 7% compared to 4.5 MMBOE
in the prior year. Possible reserves volumes at Delhi were 4.3 MMBOE, a decrease of 7% compared to 4.6 MMBOE in the
prior year. The reclassification to probable from possible are primarily the result of timing and recent performance.
Gross production at Delhi in the fourth quarter of fiscal 2019 was 7,843 BOEPD, a 2% increase compared to 7,687
BOEPD in the third fiscal quarter. Oil production was 6,364 BOPD, a 2% decrease from the third fiscal quarter’s 6,474 BOPD.
NGL production in the fourth quarter was 1,479 BOEPD, 22% higher than prior quarter production of 1,213 BOEPD. Oil
production was impacted by compressor downtime during the fourth quarter. Earlier in the year, the operator modified the flow
regime of the recycle facility which led to improved NGL production over the past two quarters. However, this modification
resulted in compressor issues causing the downtime in the fourth quarter. The compressor was repaired and oil production
recovered in July. We expect NGL production to be approximately 1,100 to 1,200 BOEPD over the next several months. The
27
operator is investigating solutions to recapture the NGL rates seen in the fourth quarter. All twelve wells in the infill program
initiated in fiscal 2018 have been completed, and consist of two CO2 injection wells and ten producer wells.
The average oil price realized by Evolution during the fourth quarter of fiscal 2019 was $64.77 compared to $59.12
during the previous quarter. The average NGL price realized by Evolution during the fourth quarter of fiscal 2019 was $15.27
per barrel compared to $16.37 during the previous quarter. Evolution continues to benefit from the premium that Delhi field oil
receives selling under Louisiana Light Sweet ("LLS") pricing, as compared to the more widely known West Texas Intermediate
("WTI") price, and the oil is shipped to market directly by pipeline, the most efficient means of transportation from the field.
Our received NGL price for royalty production is burdened by a capital recovery charge, which is mostly offset by our working
interest share of such capital recovery that is reflected as a reduction in lease operating expense.
Our overall lifting costs for the year were $19.31 per BOE increased 23% from $15.68 per BOE in the prior year. Gross
CO2 purchase volume rates for the fiscal 2019 averaged 85.2 MMcf per day, compared to 65.0 MMcf per day in the prior year,
a 31% increase. This increase together with an 8% higher price per mcf resulted in a 41% increase in CO2 cost compared to the
prior year. Our cost of purchased CO2, the largest single component of operating costs, is directly tied to the price of oil sold
from the Delhi field. Other lease operating expenses for the fiscal 2019 increased 9.1% compared to the prior year, primarily
due to higher fuel gas expense, labor and chemicals.
For fiscal 2019, our gross NGL production was 1,171 BOEPD, which sold at an average price of $21.87 per barrel,
compared to prior year gross production of 976 BOEPD for which we realized $28.06 per barrel. Production from the NGL
plant is transported by truck to a processing plant in East Texas, and therefore bears a material transportation charge. Plant
efficiencies have improved from the prior year and the higher realized price reflects both the impact of higher oil prices and
improvements in meeting the purchaser's specification requirements. Under the operator's marketing contract, we receive
market index pricing for each NGL component, based on the processed yield, less transportation, processing fees and other
deductions. Our current mix of products is very rich containing higher value NGL's, such as pentanes and butane. Market
pricing for our NGL's during the fourth quarter averaged approximately 36% of WTI prices (net realized price is after
deduction of transportation and fractionation charges). NGL prices have fallen significantly from a peak in late 2018 in
response to worldwide supply and demand. Historically, NGL demand has had a seasonal pattern with prices tending to be
higher in the cooler months of the year. Accordingly, the relationship between NGL prices and WTI has fluctuated over time
and we expect such volatility to continue.
The NGL plant includes an electric turbine to convert methane and part of the ethane processed by the plant to
electricity. This turbine is generating power for the NGL plant and supplies excess power to the CO2 recycle facility. The NGL
plant is accomplishing its primary objective of removing the lighter hydrocarbons (i.e. methane and ethane), thereby increasing
the purity of the CO2 recycle stream and improving the efficiency of the flood. Over time, it is expected to increase the
recovery of crude oil in the field. The plant is also providing feedstock to power the electric turbine and producing significant
quantities of higher value NGL's for sale.
Remaining estimated capital expenditures for our proved undeveloped reserves amount to approximately $6.00 per BOE
for Phase V. No remaining capital expenditures are required to develop our probable or possible reserves as these reserves
reflect incremental quantities associated with a greater percentage recovery of hydrocarbons in place than the recovery
quantities assumed for proved reserves. Looking forward, the timing of plans for continued development of the eastern part of
the Delhi field is dependent on the operator’s plans for capital allocation within their portfolio. Development of unquantified
volumes is dependent upon the timing of excess capacity within the processing plant and oil price. We continue to believe that
this high quality and economically viable project will be executed as planned, subject to oil price volatility.
28
Results of Operations
Years Ended June 30, 2019 and 2018
Revenues
Compared to the the prior fiscal year, fiscal 2019 revenues increased 6.0% due to 6.9% higher realized commodity prices
partially offset by a very slight decrease in production volumes. The following table summarizes total production volumes,
daily production volumes, average realized prices and revenues:
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.
Production Costs
Years Ended June 30,
2019
2018
Variance
Variance %
$
40,779,052
$
38,153,417
$
2,625,635
2,449,359
2,620,110
(170,751)
1,210
—
1,210
$
43,229,621
$
40,773,527
$
2,456,094
626,879
112,013
459
738,968
1,717
307
1
2,025
651,931
93,366
—
745,297
1,786
256
—
2,042
$
$
65.05
$
58.52
$
21.87
2.64
28.06
—
58.50
$
54.71
$
(25,052)
18,647
459
(6,329)
(69)
51
1
(17)
6.53
(6.19)
2.64
3.79
6.9 %
(6.5)%
n.m.
6.0 %
(3.8)%
20.0 %
n.m.
(0.8)%
(3.9)%
19.9 %
n.m
(0.8)%
11.2 %
(22.1)%
— %
6.9 %
The $2.6 million increase in production costs was due to a 41% increase in CO2 costs together with 9% higher 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,
2019
2018
Variance
Variance %
$
$
$
$
6,674,905
$
4,729,506
$ 1,945,399
7,591,879
6,956,311
635,568
14,266,784
$
11,685,817
$ 2,580,967
9.03
$
10.28
6.35
$
9.33
19.31
$
15.68
$
2.68
0.95
3.63
41.1%
9.1%
22.1%
42.2%
10.2%
23.2%
(a) Under our contract with the operator, purchased CO2 is priced at 1% of the realized oil price in the field per Mcf, plus sales taxes of approximately
8.5% and transportation costs of $0.20 per mcf. Transportation costs will decline effective January 1, 2020 as per contract terms.
29
CO2 costs per mcf
CO2 volumes (MMcf per day, gross)
Years Ended June 30,
2019
2018
Variance
Variance %
$
0.90
$
0.83
$
85.2
65.0
0.07
20.2
8.4%
31.1%
The $1.9 million increase in CO2 costs was due to a 31% increase in purchased volumes together with a 8.4% increase in price
per mcf reflecting the higher realized oil price. The increase in other production costs primarily consisted of higher costs of
$0.3 million for fuel gas expense, $0.2 million for labor, and $0.1 million for chemicals.
Depletion, Depreciation and Amortization ("DD&A")
DD&A expense was 2.5% higher compared to the same year-ago period principally due to a 3.4% higher oil and gas
DD&A rate as production volumes were virtually unchanged from fiscal 2018.
DD&A of proved oil and gas properties
$
6,122,515
$
5,980,307
$
142,208
2.4 %
Years Ended June 30,
2019
2018
Variance
Variance %
Depreciation of other property and equipment
Amortization of intangibles
Accretion of asset retirement obligations
Total DD&A
Oil and gas DD&A rate per BOE
General and Administrative Expenses
$
$
15,498
13,564
101,506
18,127
13,564
90,290
(2,629)
(14.5)%
—
11,216
— %
12.4 %
2.5 %
6,253,083
$
6,102,288
$
150,795
8.29
$
8.02
$
0.27
3.4 %
Expenses for the fiscal 2019 decreased $1.7 million, or 25.1%, to $5.1 million from the same year-ago period primarily
due to higher fiscal 2018 expenses such as $0.8 million of higher consulting and legal costs for acquisition pursuits, $0.6
million of litigation expense, $0.5 million of non-cash stock compensation expense and $0.3 million of compensation costs
associated with the retirement of the then Chief Executive Officer, partially offset by $0.3 million of increased Board expense
for fiscal 2019 during the search for a new Chief Executive Officer and $0.2 million of related executive search fees.
Other Income and Expenses
Other income and expense (net) increased due primarily to the $1.1 million breakup fee related to our Enduro stalking
horse bid received during August 2018, plus higher earned interest income due to increasing interest rates in fiscal 2019.
Enduro transaction breakup fee
Interest and other income
Interest expense
Total other income, net
n. m. Not meaningful.
Years Ended June 30,
2019
2018
Variance
Variance %
1,100,000
239,150
—
1,100,000
n.m.
85,654
153,496
179.2%
(116,546)
(110,780)
(5,766)
$
1,222,604
$
(25,126) $ 1,247,730
5.2%
n.m.
30
Net Income
Net income available to common stockholders for the year ended June 30, 2019 decreased $4.2 million, or 22%, to $15.4
million compared to the prior year primarily due to a non-recurring prior year deferred tax credit of $6.0 million, partially offset
by a $2.7 million, or 17% increase, in income before income taxes. This fiscal 2018 deferred tax benefit resulted from the
revaluation of our deferred income tax liabilities at December 31, 2017 to reflect the lower federal statutory rate under the Tax
Cut and Jobs Act.
Income before income taxes
Income tax provision (benefit)
Net income available to common stockholders
Income tax provision as a percentage of income before income
taxes
Years Ended June 30,
2019
2018
Variance
Variance %
18,859,427
16,186,515
3,482,361
(3,431,969)
2,672,912
6,914,330
$ 15,377,066
$19,618,484
$ (4,241,418)
16.5 %
(201.5)%
(22.0)%
19%
(37)%
Excluding the effect of the $6.1 million tax benefit from income taxes for the nine months ended March 31, 2018,
income tax as a percentage of income before income taxes would have been approximately 18%. For the years ended June 30,
2019 and 2018, our respective statutory federal tax rates were 21% and 27.55%, as we used a blended rate during our fiscal
2018 in which the Tax Cut and Jobs Act was enacted. The benefit of the lower statutory rate in the current year was partially
offset by a decreased benefit from depletion in excess of basis as much of our depletion carryover had been utilized by June 30,
2018.
Liquidity and Capital Resources
At June 30, 2019, we had $31.6 million in cash and cash equivalents (and no restricted cash) and $27.7 million of cash,
cash equivalents and restricted cash at June 30, 2018.
In addition, we have a senior secured reserve-based credit facility (the "Facility") with a maximum capacity of $50
million. The Facility had $40 million of undrawn elected borrowing base availability on June 30, 2019. Under the Facility the
borrowing base shall be determined semiannually as of May 15 and November 15. There have been no borrowings under the
Facility, which matures on April 11, 2021, and it is secured by substantially all of the Company’s assets.
During the current fiscal year, we amended the credit agreement to broaden the definition for Use of Proceeds to provide
funds, limited to an amount not in excess of 25% of the borrowing base, for investments into cash flow generating assets
complimentary to the production of oil and gas.
Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined
under the Facility, plus 1.0%. The Facility contains covenants that require the maintenance of (i) a total leverage ratio of not
more than 3.0 to 1.0, (ii) a debt service coverage ratio of not less than 1.1 to 1.0 and (iii) a consolidated tangible net worth of
not less than $50.0 million, each as defined in the Facility. The Facility also contains other customary affirmative and negative
covenants and events of default. As of June 30, 2019, the Company was in compliance with all covenants contained in the
Facility.
During the year ended June 30, 2019, we funded our operations, capital expenditures and cash dividends with cash
generated from operations resulting in an increase of $3.9 million in cash. As of June 30, 2019, our working capital was $32.4
million, an increase of $4.7 million over working capital of $27.7 million at June 30, 2018.
We have historically funded our operations through cash from operations and working capital. Our primary source of
cash is the sale of oil and natural gas liquids production. A portion of these cash flows are used to fund our capital expenditures.
While we expect to continue to expend capital to further develop the Delhi field, we and the operator have flexibility as to when
this capital is spent. The Company expects to manage future development activities in the Delhi field within the boundaries of
its operating cash flow and existing working capital.
We may choose to pursue new growth opportunities through acquisitions or other transactions. In addition to our cash on
hand, we have access to at least $40 million of undrawn elected borrowing base availability under our senior secured credit
facility. In addition we have an effective shelf registration statement with Securities and Exchange Commission under which we
may issue up to $500 million of new debt or equity securities. If we choose to pursue new growth opportunities, we would
expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be
31
advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to
issue additional equity at this time.
Our other significant use of cash is our on-going cash dividend program. The Board of Directors instituted a cash
dividend on our common stock in December 2013 and we have since paid twenty-three consecutive quarterly dividends.
Distribution of a large portion of free cash flow in excess of our operating and capital requirements through cash dividends and
potential repurchases of our common stock remains a priority of our financial strategy, and it is our long term goal to increase
our cash dividends over time as appropriate. On August 9, 2019, the Board declared the next quarterly common stock dividend
of $0.10 per share, which will be paid on September 30, 2019 to stockholders of record on September 13, 2019. The Board
reviews the quarterly dividend rate in view of our financial position and operations, forecasted results, including the outlook for
oil and NGL prices, the timing of further expansion of Delhi field development and other potential growth opportunities.
Capital Budget - Delhi Field
During the year ended June 30, 2019, we incurred $5.2 million of capital expenditures at Delhi. This spending included
$0.7 million for capital upgrades to the NGL plant, injection lines and facilities, $1.1 million for CO2 conformance projects and
capital maintenance, $1.6 million for Phase V infrastructure (i.e. water curtain wells) in the eastern portion of the field, and $1.8
million for the infill drilling program.
The twelve well infill drilling program in the Delhi field is complete and the wells are contributing. There are ten
producing oil wells and two CO2 injection wells. While we intended to drill four injection wells, two of the planned injectors
were completed as producers. These wells may be re-completed as injectors at a later date. The injectors and producers were
drilled and completed in areas needing additional support to sweep oil. Since the program's inception in fiscal 2018, our net
capital expenditures have totaled $4.6 million.
We expect to continue to perform conformance workover projects and will likely incur additional maintenance capital
expenditures. Such amounts are not known or approved yet but we expect them to run in the $1.0 to $2.0 million magnitude as
it has the past two fiscal years.
Our proved undeveloped reserves at June 30, 2019 included 1,583 MBOE of reserves and approximately $8.6 million of
future development costs associated with Phase V development in the eastern portion of the field. Such development requires
participation by both the operator and Evolution, and the operator has not yet finalized its capital expenditure budget for 2020.
Based our discussions with the operator, in fiscal 2020, we expect to spend about $0.6 million to complete the south water
curtain in preparation for the Phase V development, which is expected to commence late in fiscal 2020. In our last three fiscal
years we have incurred a total of $3.1 million on the water curtain program in advance of this development. The timing of
Phase V is also dependent, in part, on the field operator's available funds and capital spending plans and priorities within its
portfolio of properties.
Funding for our anticipated capital expenditures at Delhi over the next two fiscal years is expected to be met from cash
flows from operations and current working capital.
Overview of Cash Flow Activities
The table below compares a summary of our condensed consolidated statements of cash flows for year ended June 30,
2019 and 2018.
Increases (Decreases) in Cash:
2019
2018
Difference
June 30,
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
(In Millions)
24.1
$
20.5
$
(6.8)
(13.4)
(3.7)
(12.2)
3.9
$
4.6
$
$
$
3.6
(3.1)
(1.2)
(0.7)
Cash provided by operating activities in the current year increased $3.6 million compared to the fiscal 2018 due to a $5.8
million increase in cash provided by non-cash expenses and $2.1 million increase in cash provided from current operating
assets and liabilities partially offset by a $4.3 million decrease in cash provided by net income. Fiscal 2018 total non-cash
expenses were impacted by the one-time $6.0 million deferred income tax credit related to enactment of the Tax Cut and Jobs
Act.
32
Cash used in investing activities increased $3.1 million due to higher capital expenditure disbursements in the 2019
period.
Cash used in financing activities increased $1.2 million due to $1.6 million of higher cash dividends, reflecting a higher
quarterly dividend rate of $0.10 per share throughout fiscal 2019 compared to $0.075 per share during the first half of fiscal
2018 and $0.10 per share paid the subsequent two quarters, partially offset by $0.4 million of lower common share repurchases
related to stock-based awards vestings.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of June 30, 2019, we are obligated to make under
our contractual obligations and commitments. We expect to fund these contractual obligations with cash on hand and cash
generated from operations.
Payments Due by Period
Total
Less than
1 Year
1 - 3 Years
3 - 5 Years
More than 5
Years
Contractual Obligations
Purchase commitments in connection with
joint interest agreement
Operating lease
Other Obligations
$
861,674
$
861,674
$
— $
— $
182,208
34,322
147,886
—
—
1,560,601
—
—
Asset retirement obligations
1,610,845
50,244
—
Total Obligations
$
2,654,727
$
946,240
$
147,886
$
— $
1,560,601
Critical Accounting Policies and Estimates
The preparation of financial statements in accordance with accounting principles generally accepted in the United States
of America requires that we select certain accounting policies and make estimates and assumptions that affect the reported
amounts of the assets and liabilities and disclosures of contingent assets and liabilities as of the date of the balance sheet as well
as the reported amounts of revenues and expenses during the reporting period. These policies, together with our estimates have
a significant effect on our consolidated financial statements. Our significant accounting policies are included in Note 2 –
Summary of Significant Accounting Policies of the consolidated financial statements. Following is a discussion of our most
critical accounting estimates, judgments and uncertainties that are inherent in the preparation of our consolidated financial
statements.
Oil and Natural Gas Properties. Companies engaged in the production of oil and natural gas are required to follow
accounting rules that are unique to the oil and gas industry. We apply the full cost accounting method for our oil and natural gas
properties as prescribed by SEC Regulation S-X Rule 4-10. Under this method of accounting, the costs of unsuccessful, as well
as successful, exploration and development activities are capitalized as properties and equipment. This includes any internal
costs that are directly related to property acquisition, exploration and development activities but does not include any costs
related to production, general corporate overhead or similar activities. Gain or loss on the sale or other disposition of oil and
gas properties is not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and
proved reserves. Oil and natural gas properties include costs that are excluded from costs being depleted or amortized. Oil and
natural gas property costs excluded represent investments in unevaluated properties and include non-producing leasehold,
geological and geophysical costs associated with leasehold or drilling interests and exploration drilling costs. We exclude these
costs until the property has been evaluated. Costs are transferred to the full cost pool as the properties are evaluated. As of
June 30, 2019, we had no unevaluated properties costs.
Estimates of Proved Reserves. The estimated quantities of proved oil and natural gas reserves have a significant impact
on the underlying financial statements. The estimated quantities of proved reserves are used to calculate depletion expense, and
the estimated future net cash flows associated with those proved reserves is the basis in determining impairment under the
quarterly ceiling test calculation. The process of estimating oil and natural gas reserves is very complex, requiring significant
decisions in the evaluation of all available geological, geophysical, engineering and economic data. Estimated reserves are
often subject to future revisions, which could be substantial, based on the availability of additional information, including
reservoir performance, additional development activity, new geological and geophysical data, additional drilling, technological
advancements, price changes and other economic factors. As a result, material revisions to existing reserve estimates may occur
from time to time. Although every reasonable effort is made to ensure that the reported reserve estimates represent the most
33
accurate assessments possible, including the hiring of independent engineers to prepare our reserve estimates, the subjective
decisions and variances in available data for the properties make these estimates generally less precise than other estimates
included in our financial statements. Material revisions to reserve estimates and/or significant changes in commodity prices
could substantially affect our estimated future net cash flows of our proved reserves, affecting our quarterly ceiling test
calculation and could significantly affect our depletion rate. A 10% decrease in commodity prices used to determine our proved
reserves as of June 30, 2019 would not have resulted in an impairment of our oil and natural gas properties. Holding all other
factors constant, a reduction in the Company's proved reserve estimates at June 30, 2019 of 5%, 10% and 15% would affect
depreciation, depletion and amortization expense by approximately $313,000, $658,000 and $1,042,000, respectively.
On December 31, 2008, the SEC issued its final rule on the modernization of reporting oil and gas reserves. The rule
allows consideration of new technologies in evaluating reserves, generally limits the designation of proved reserves to those
projects forecast to be drilled five years from the initial recognition date of such reserves, allows companies to disclose their
probable and possible reserves to investors, requires reporting of oil and gas reserves using an average price based on the
previous 12-month unweighted arithmetic average first-day-of-the-month price rather than year-end prices, revises the
disclosure requirements for oil and gas operations, and revises accounting for the limitation on capitalized costs for full cost
companies.
Valuation of Deferred Tax Assets. We make certain estimates and judgments in determining our income tax expense for
financial reporting purposes. These estimates and judgments occur in the calculation of certain tax assets and liabilities that
arise from differences in the timing and recognition of revenue and expense for tax and financial reporting purposes. Our
federal and state income tax returns are generally not prepared or filed before the consolidated financial statements are prepared
or filed; therefore, we estimate the tax basis of our assets and liabilities at the end of each period as well as the effects of tax
rate changes, tax credits, and net operating loss carry backs and carry forwards. Adjustments related to these estimates are
recorded in our tax provision in the period in which we file our income tax returns. Further, we must assess the likelihood that
we will be able to recover or utilize our deferred tax assets (primarily our net operating loss). If recovery is not likely, we must
record a valuation allowance against such deferred tax assets for the amount we would not expect to recover, which would
result in an increase to our income tax expense. As of June 30, 2019, we have recorded a valuation allowance for the portion of
our net operating loss that is limited by IRS Section 382.
Management considers the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax
planning strategies in making the assessment of the ultimate realization of deferred tax assets. Based upon the level of historical
taxable income and projections for future taxable income over the periods for which the deferred tax assets are deductible, as of
end of the current fiscal year, we believe that it is more likely than not that the Company will realize the benefits of its net
deferred tax assets. If our estimates and judgments change regarding our ability to utilize our deferred tax assets, our tax
provision would increase in the period it is determined that recovery is not probable.
Stock-based Compensation. The fair value and expected vesting period of the Company's market-based awards were
determined using a Monte Carlo simulation. This technique uses a geometric Brownian motion model with defined variables
and randomly generates values for each variable through multiple trials. Variables include stock price volatility, expected term
of the award, the expected risk-free interest rate, and the expected dividend yield of the Company's stock. The risk-free interest
rate used is the U.S. Treasury yield for bonds matching the expected term of the award on the date of grant. Vesting of market-
based awards is based on the Company's total common stock return compared to a peer group of other companies in our
industry with comparable market capitalizations and, for certain awards, the Company's share price attaining a set target.
Recent Accounting Pronouncements. See Note 2 – Summary of Significant Accounting Policies to our Consolidated
Financial Statements for discussion of the recent accounting pronouncements issued by the Financial Accounting Standards
Board.
Off Balance Sheet Arrangements
The Company has no off-balance sheet arrangements as of June 30, 2019.
Item 7A. Quantitative and Qualitative Disclosures About Market Risks
Interest Rate Risk
We are exposed to changes in interest rates. Changes in interest rates affect the interest earned on our cash and cash
equivalents. Under our current policies, we do not use interest rate derivative instruments to manage exposure to interest rate
changes.
34
Commodity Price Risk
Our most significant market risk is the pricing for crude oil, natural gas and NGL's. We expect energy prices to remain
volatile and unpredictable. If energy prices decline significantly, revenues and cash flow would significantly decline. In
addition, a non-cash write-down of our oil and gas properties could be required under full cost accounting rules if future oil and
gas commodity prices sustained a significant decline. Prices also affect the amount of cash flow available for capital
expenditures and our ability to borrow and raise additional capital, as, if and when needed. We use derivative instruments to
manage our exposure to commodity price risk from time to time based on our assessment of such risk. We primarily utilize
swaps and costless collars to reduce the effect of price changes on a portion of our future oil production. We do not enter into
derivative instruments for trading purposes. The Company had no positions in derivative instruments at June 30, 2019.
35
Item 8. Financial Statements
Index to Consolidated Financial Statements
Reports of Independent Registered Public Accounting Firm
Consolidated Balance Sheets as of June 30, 2019 and 2018
Consolidated Statements of Operations for the Years ended June 30, 2019 and 2018
Consolidated Statements of Cash Flows for the Years ended June 30, 2019 and 2018
Consolidated Statements of Changes in Stockholders' Equity for the Years ended June 30, 2019 and 2018
Notes to Consolidated Financial Statements
37
39
40
41
42
43
36
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Evolution Petroleum Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Evolution Petroleum Corporation and Subsidiaries (the
“Company”) as of June 30, 2019 and 2018, the related consolidated statements of operations, cash flows and changes in stockholders’
equity for the years then ended, and the related notes (collectively referred to as the “consolidated financial statements”). In our
opinion, the consolidated financial statements present fairly, in all material respects, the consolidated financial position of the
Company as of June 30, 2019 and 2018, and the consolidated results of its operations and its cash flows for the years then ended,
in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the Company’s internal control over financial reporting as of June 30, 2019, based on criteria established in Internal
Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and
our report dated September 12, 2019 expressed an unqualified opinion on the Company’s internal control over financial reporting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an
opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with
the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws
and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether
due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated
financial statements, whether due to error or fraud, and performing procedures to respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits
also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the
overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ Moss Adams LLP
Houston, Texas
September 12, 2019
We have served as the Company’s auditor since 2017.
37
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Evolution Petroleum Corporation
Opinion on Internal Control over Financial Reporting
We have audited Evolution Petroleum Corporation and Subsidiaries’ (the “Company”) internal control over financial reporting as
of June 30, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of
Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of June 30, 2019, based on criteria established in Internal Control -
Integrated Framework (2013) issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(“PCAOB”), the consolidated balance sheets of Evolution Petroleum Corporation and Subsidiaries as of June 30, 2019 and 2018,
the related consolidated statements of operations, cash flows and changes in stockholders’ equity for the years then ended, and
the related notes (collectively referred to as the “consolidated financial statements”) and our report dated September 12, 2019
expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment
of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal
Control over Financial Reporting included in Item 9A. Our responsibility is to express an opinion on the Company’s internal
control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required
to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material
respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.
Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our
audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability
of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain
to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets
of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are
being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable
assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that
could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Moss Adams LLP
Houston, Texas
September 12, 2019
38
Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
Assets
Current assets
Cash and cash equivalents
Restricted cash
Receivables
Prepaid expenses and other current assets
Total current assets
June 30, 2019
June 30, 2018
$
31,552,533
$
24,929,844
—
3,168,116
458,278
2,751,289
3,941,916
524,507
35,178,927
32,147,556
Property and equipment, net of depreciation, depletion, and amortization
Oil and natural gas properties—full-cost method of accounting, of which none were excluded from amortization
60,346,466
61,239,746
Other property and equipment, net
Total property and equipment, net
Liabilities and Stockholders' Equity
Other assets, net
Total assets
Current liabilities
Accounts payable
Accrued liabilities and other
State and federal taxes payable
Total current liabilities
Long term liabilities
Deferred income taxes
Asset retirement obligations
Total liabilities
Commitments and contingencies (Note 16)
Stockholders' equity
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,183,730 and
33,080,543 shares as of June 30, 2019 and 2018, respectively
Additional paid-in capital
Retained earnings
Total stockholders' equity
Total liabilities and stockholders' equity
26,418
60,372,884
210,033
30,407
61,270,153
244,835
95,761,844
$
93,662,544
2,084,140
$
3,432,568
$
$
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
874,886
122,760
4,430,214
10,555,435
1,387,416
16,373,065
33,080
41,757,645
35,498,754
77,289,479
$
95,761,844
$
93,662,544
See accompanying notes to consolidated financial statements.
39
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
Revenues
Crude oil
Natural gas liquids
Natural gas
Total revenues
Operating costs
Production costs
Depreciation, depletion and amortization
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 attributable to common shareholders
Earnings per common share
Basic
Diluted
Weighted average number of common shares outstanding
Basic
Diluted
_______________________________________________________________________________
Years Ended June 30,
2019
2018
$
40,779,052
$
38,153,417
2,449,359
2,620,110
1,210
—
43,229,621
40,773,527
14,266,784
11,685,817
6,253,083
5,072,931
25,592,798
17,636,823
1,100,000
239,150
(116,546)
6,102,288
6,773,781
24,561,886
16,211,641
—
85,654
(110,780)
$
$
$
18,859,427
16,186,515
3,482,361
(3,431,969)
15,377,066
$
19,618,484
0.46
0.46
$
$
0.59
0.59
33,160,283
33,169,718
33,126,469
33,178,535
*
General and administrative expenses for the years ended June 30, 2019 and 2018 included non-cash stock-based compensation
expense of $888,162 and $1,366,764, respectively.
See accompanying notes to consolidated financial statements.
40
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
Deferred income taxes
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
Development of oil and natural gas properties
Capital expenditures for other property and equipment
Other assets
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 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
Years Ended June 30,
2019
2018
$
15,377,066
$
19,618,484
6,268,239
888,162
767,256
773,800
66,229
(90,891)
8,039
6,158,555
1,366,764
(5,270,856)
(1,215,214)
(136,835)
(107,081)
122,760
24,057,900
20,536,577
(6,746,142)
(3,690,845)
(11,509)
—
(7,846)
(19,282)
(6,757,651)
(3,717,973)
(156,791)
(571,083)
(13,272,058)
(11,594,541)
(13,428,849)
(12,165,624)
3,871,400
27,681,133
4,652,980
23,028,153
$
31,552,533
$
27,681,133
The following table provides a reconciliation of cash, cash equivalents and restricted cash reported within the statements of financial position
that sum to the totals of the such amounts shown in the statements of cash flows.
Cash and cash equivalents
Restricted cash included in current assets
Total cash, cash equivalents and restricted cash shown in the statements of cash flows
Years Ended June 30,
2019
31,552,533
—
31,552,533
$
$
2018
24,929,844
2,751,289
27,681,133
$
$
See accompanying notes to consolidated financial statements.
41
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
For the Years Ended June 30, 2019 and 2018
Balance, June 30, 2017
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, 2018
Issuance of restricted common 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
Common Stock
Shares
Par
Value
Additional
Paid-in
Capital
Retained
Earnings
Treasury
Stock
Total
Stockholders'
Equity
33,087,308
$ 33,087
$40,961,957
$ 27,474,811
$
— $
68,469,855
183,537
(117,094)
(73,208)
—
—
—
—
183
(117)
—
(73)
—
—
—
(183)
117
—
(571,010)
1,366,764
—
—
—
—
—
—
19,618,484
— (11,594,541)
33,080,543
33,080
41,757,645
35,498,754
121,611
(18,424)
—
—
—
—
122
—
(19)
—
—
—
(122)
—
(156,772)
888,162
—
—
—
—
—
15,377,066
— (13,272,058)
—
—
(571,083)
571,083
—
—
—
—
—
(156,791)
156,791
—
—
—
—
—
(571,083)
—
1,366,764
19,618,484
(11,594,541)
77,289,479
—
(156,791)
—
888,162
15,377,066
(13,272,058)
33,183,730
$ 33,183
$42,488,913
$ 37,603,762
$
— $
80,125,858
See accompanying notes to consolidated financial statements.
42
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 largest active investment is our interest in a CO2 enhanced oil recovery project in
Louisiana's Delhi field.
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.
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.
Accounts Receivable and Allowance for Doubtful Accounts. Accounts receivable consist accrued revenues due under
normal trade terms, generally requiring payment within 30 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. Collectibility is reviewed regularly and an allowance is established or adjusted, as necessary, using the specific
identification method. As of June 30, 2019 and 2018, 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,
43
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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; and 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, 2019 and 2018.
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, with an associated 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 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, restricted cash,
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.
44
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 single geographic location. 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 collectibility 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” in our consolidated balance sheets. As of June 30, 2019 and 2018 receivables from contracts with customers
were $3.2 million and $3.9 million, respectively.
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, office and computer equipment is depreciated as described above in Other Property and
Equipment.
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 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, based on the technical merits of the position and will 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) and 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 - Revenue Recognition
Effective July 1, 2018, the Company adopted ASU No. 2014-09, Revenue From Contracts With Customers (Topic 606)
(“ASC 606”) using the full retrospective method and has applied the standard to all existing contracts. ASC 606 supersedes
previous revenue recognition requirements in ASC 605 - Revenue Recognition (“ASC 605”) and includes a five-step revenue
recognition model to depict the transfer of goods or services to customers in an amount that reflects the consideration in
exchange for those goods or services. As a result of adopting ASC 606, the Company did not have a cumulative-effect
adjustment in retained earnings. The comparative information presented therein for the year ended June 30, 2018 reflects the
reclassification on our consolidated statement of operations of $507,685 from “Production Costs” to “Revenue - Natural Gas
Liquids” in conformance with ASC 606. These changes to revenue and production costs resulted from the conclusion that the
Company did not control the product throughout processing before transferring to the customer. Therefore, costs incurred after
the transfer of control are treated as reductions of revenue. Additionally, adoption of ASC 606 did not impact net income
45
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
attributable to common stockholders, current assets, total assets, current liabilities, total liabilities or stockholders’ equity and
the Company does not expect that it will do so in future periods.
Other Recently Adopted Accounting Pronouncements
In January 2016, the FASB issued ASU 2016-01, Financial Instruments - Overall: Recognition and Measurement of
Financial Assets and Financial Liabilities ("ASU 2016-01"). The pronouncement requires equity investments (except those
accounted for under the equity method of accounting, or those that result in consolidation of the investees) to be measured at
fair value with changes in fair value recognized in net income, requires public business entities to use the exit price notion when
measuring the fair value of financial instruments for disclosure purposes, requires separate presentation of financial assets and
financial liabilities by measurement category and form of financial asset, and eliminates the requirement for public business
entities to disclose the method(s) and significant assumptions used to estimate the fair value that is required to be disclosed for
financial instruments measured at amortized cost. Effective July 1, 2018, the Company prospectively adopted ASU 2016-01
without impact to its consolidated financial position or results of operations. Because its investment in Well Lift Inc. does not
have a readily determinable fair value, the Company elected to measure this investment 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 they were to occur.
Effective July 1, 2018, the Company retrospectively adopted ASU No. 2016-15, Statement of Cash Flows (Topic 230):
Classification of Certain Cash Receipts and Cash Payments, which is intended to reduce diversity in practice in how certain
transactions are classified in the statement of cash flows. The guidance addresses eight specific cash flow issues for which
current GAAP is either unclear or does not include specific guidance. Adoption had no effect on our current period and
comparative consolidated statements of cash flows.
Effective July 1, 2018, the Company prospectively adopted ASU No. 2017-01, Business Combinations (Topic 805):
Clarifying the Definition of a Business, which clarifies the definition of a business to assist entities with evaluating whether
transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The Company will apply the clarified
definition of business to future acquistions and divestitures.
Recently Issued Accounting Pronouncements
In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) (“ASU 2016-02”), which relates to the accounting
for leasing transactions. This standard requires a lessee to record on the balance sheet the assets and liabilities for the rights and
obligations created by leases with lease terms of more than twelve months. In addition, this standard requires both lessees and
lessors to disclose certain key information about lease transactions. This standard will be effective for fiscal years beginning
after December 15, 2018, including interim periods within those fiscal years. The Company will adopt ASU 2016-02 effective
July 1, 2019, using the modified retrospective approach. The Company will make certain elections allowing it to not reassess
contracts that commenced prior to adoption, not to recognize right of use ("ROU") assets or lease liabilities for short-term
leases, and will not separate lease components from non-lease components for specified asset classes. As of July 1, 2019, the
Company anticipates that the adoption of ASU 2016-02 will result in the recognition of ROU assets and lease liabilities on its
consolidated balance sheets of approximately $165,000 related to office space. Accordingly, the Company does not expect ASU
2016-02 to have a significant impact on its consolidated statements of operations or consolidated statements of cash flows. The
Company is finalizing its accounting policies, controls, processes, and disclosures that will change as a result of adopting the
new standard. As permitted by ASU No. 2018-11, Leases (Topic 842): Targeted Improvements, the Company does not expect to
adjust comparative-period financial statements.
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. The amendments in this ASU are effective for fiscal years beginning after December 15, 2019, and interim periods
within those fiscal years, and early adoption is permitted. Entities must adopt the amendment using a modified retrospective
approach to the first reporting period in which the guidance is effective. The adoption of ASU 2016-13 is currently not expected
to have a material effect on our consolidated financial statements.
46
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 3 – Enduro Purchase and Sale Agreement and "Stalking Horse" Bid
During the first quarter of fiscal 2019, The Company recorded a $1.1 million break-up fee upon the closing of a higher
bidder's purchase transaction. During May 2018, the Company had entered into a Purchase and Sale Agreement ("PSA"), 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. Contemporaneous with executing
the PSA, the Company made a $2.75 million deposit to an acquisition escrow account which, together with interest earned,
comprised the restricted cash balance on the Company's June 30, 2018 consolidated statement of financial position. Earlier 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.
The Company's initial and subsequent bids represented offers under Section 363 of the U.S. Bankruptcy Code in Enduro's
Chapter 11 proceeding. Such offers are commonly referred to as “stalking horse” bids and are subject to higher bids, in
accordance with the bidding procedures approved by the Bankruptcy Court. In connection with the PSA, the Company incurred
third party due diligence expenses of $0.4 million, which have been reflected in the Company's consolidated statement of
operations for the year ended June 30, 2018.
Note 4 – Receivables
As of June 30, 2019 and June 30, 2018 our receivables consisted of the following:
Receivables from oil and gas sales
Other
Total receivables
June 30,
2019
3,168,116
—
3,168,116
$
$
June 30,
2018
3,940,998
918
3,941,916
$
$
There were no losses from uncollectible accounts receivable, nor any allowance for doubtful accounts in any of the
periods presented in these financial statements.
Note 5 – Prepaid Expenses and Other Current Assets
As of June 30, 2019 and June 30, 2018 our prepaid expenses and other current assets consisted of the following:
Prepaid insurance
Prepaid federal and state income taxes
Retainers and deposits
Other prepaid expenses
Prepaid expenses and other current assets
June 30,
2019
206,198
121,679
8,019
122,382
458,278
June 30,
2018
198,558
231,920
11,089
82,940
524,507
$
$
$
$
47
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 6 – Property and Equipment
As of June 30, 2019 and June 30, 2018, our oil and natural gas properties and other property and equipment consisted of
the following:
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
June 30,
2019
June 30,
2018
$ 95,622,153
(35,275,687)
—
$ 90,392,918
(29,153,172)
—
60,346,466
61,239,746
154,731
(128,313)
26,418
$
143,223
(112,816)
30,407
$
As of June 30, 2019 and 2018, all oil and gas property costs were being amortized.
During the years ended June 30, 2019 and 2018, the Company incurred capital expenditures of $5.2 million and $5.4
million, respectively, in the Delhi field.
Note 7 – Other Assets
As of June 30, 2019 and June 30, 2018 our other assets consisted of the following:
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
Software license
Less: Accumulated amortization of software license
Other assets, net
June 30,
2019
108,512
(47,474)
108,750
168,972
(141,927)
20,662
(7,462)
210,033
$
June 30,
2018
108,512
(33,910)
108,750
168,972
(126,771)
20,662
(1,380)
244,835
$
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 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.
48
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 8 – Accrued Liabilities and Other
As of June 30, 2019 and June 30, 2018 our accrued liabilities and other consisted of the following:
Accrued incentive and other compensation
Accrued severance
Asset retirement obligations due within one year
Accrued royalties, including suspended accounts
Accrued franchise taxes
Accrued ad valorem taxes
Accrued liabilities and other
Note 9 – Asset Retirement Obligations
June 30,
2019
369,719
—
50,244
11,554
5,738
100,500
537,755
June 30,
2018
415,182
160,089
35,539
11,498
162,805
89,773
874,886
$
$
$
$
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, 2019 and 2018:
Asset retirement obligations — beginning of period
Liabilities incurred
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
2019
2018
$
1,422,955
$
1,288,743
31,268
101,506
55,116
1,610,845
(50,244)
1,560,601
$
$
44,700
90,290
(778)
1,422,955
(35,539)
1,387,416
49
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 10 – Stockholders' Equity
Common Stock
As of June 30, 2019, we had 33,183,730 shares of common stock outstanding.
The Company began paying quarterly cash dividends on common stock in December 2013. As of June 30, 2019, we have
cumulatively paid $59.4 million in cash dividends. We paid dividends of $13,272,058 and $11,594,541 from retained earnings
to our common shareholders during the years ended June 30, 2019 and 2018, 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
2019
$0.100
$0.100
$0.100
$0.100
2018
$0.100
$0.100
$0.075
$0.075
Repurchases of common shares are initially recorded as treasury stock, then subsequently canceled. On May 12, 2015, the
Board of Directors approved a share repurchase program covering up to $5 million of the Company's common stock. Since
commencement in June 2015, we have repurchased 266,192 shares at an average price of $6.05 per share, for total cost of
$1,611,620. The timing and amount of repurchases depends upon several factors, including financial resources, market and
business conditions. There is no fixed termination date for this repurchase program, and it may be suspended or discontinued at
any time. We have not repurchased any shares since December 2015 until June 2019 when 430 shares were repurchased at an
average price of $6.07 per share. Under the program's terms, shares are repurchased only on the open market and in accordance
with the requirements of the Securities and Exchange Commission.
The Company has also acquired treasury stock from holders of newly vested stock-based awards to fund the recipients'
payroll tax withholding obligations. The treasury shares were subsequently canceled. Such shares were valued at fair market
value on the date of vesting or date of share repurchase. The following summarizes all treasury stock purchases by fiscal year:
Number of treasury shares acquired
Average cost per share
Total cost of treasury shares acquired
Tax Treatment of Dividends to Recipients
Fiscal Year
2019
18,424
8.51
156,791
$
$
2018
73,208
7.80
571,083
$
$
Based on our current projections for the fiscal year ended June 30, 2019, we expect 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,
2018, all common stock dividends for that fiscal year were treated for tax purposes as qualified dividend income to the
recipients.
50
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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 and non-statutory stock options, stock
appreciation rights, restricted stock awards and restricted stock unit awards, performance share awards, performance cash
awards, and other forms of incentives valued in whole or in part by reference to, or otherwise based on, our common stock,
including its appreciation in value. As of June 30, 2019, 852,111 shares remained available for grant under the 2016 Plan.
All outstanding awards granted under the 2004 Plan continue to be subject to the terms and conditions as set forth in the
agreements evidencing such awards and the terms of the 2004 Plan. Under these agreements, we have outstanding grants of
restricted common stock awards ("Restricted Stock") and contingent restricted common stock awards ("Contingent Restricted
Stock") to employees and directors of the Company.
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 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.
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. During the year ended June 30, 2019, we granted 31,777 service-based Restricted Stock awards and 43,990
market-based awards to employees and 35,215 service-based awards to directors, which have a one-year vesting period. We did
not grant any performance-based nor any Contingent Restricted Stock awards, during this fiscal year.
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, 2019, there were no performance-based awards outstanding.
Market-based awards vest if their respective 2- or 3-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.
51
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Assumptions used in the Monte Carlo simulation valuations for the year ended June 30, 2019 follow below. There were
no market-based awards granted for the year ended June 30, 2018.
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, 2019 consisted of the following:
Award Type
Service-based awards
Market-based awards
Unvested at June 30, 2019
Year Ended
June 30,
2019
$
8.24
2.69%
2.82
41.8%
4.0%
Number of
Restricted
Shares
Weighted
Average
Grant-Date
Fair Value
112,381
64,302
176,683
$
$
8.52
7.35
8.09
The following table sets forth the Restricted Stock transactions for the year ended June 30, 2019:
Unvested at July 1, 2018
Service-based awards granted
Market-based awards granted
Vested
Unvested at June 30, 2019
Number of
Restricted
Shares
Weighted
Average
Grant-Date
Fair Value
199,477
$
66,992
43,990
(133,776)
176,683
$
6.83
9.17
8.24
6.80
8.09
The following is a summary of Restricted Stock vestings for the last two fiscal years:
Vesting-date intrinsic value of Restricted Stock
Grant-date fair value of vested Restricted Stock
Number of awards vesting
The following table summarizes Contingent Restricted Stock activity for fiscal 2019:
Weighted
Average
Remaining
Amortization
Period (Years)
Unamortized
Compensation
Expense at
June 30, 2019
$
—
$
848,262
1.75
Year Ended June 30,
$
$
2019
1,141,631
909,678
133,776
2018
$
$
1,622,937
1,427,498
211,960
Unvested at July 1, 2018
Expired
Vested
Unvested at June 30, 2019
Number of
Restricted
Stock Units
Weighted
Average
Grant-Date
Fair Value
Unamortized
Compensation
Expense at
June 30, 2019
Weighted
Average
Remaining
Amortization
Period (Years)
28,562
(7,777)
(10,629)
10,156
$
$
6.06
10.05
5.67
3.42
52
$
—
0
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
All of these outstanding awards at June 30, 2019 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 vesting
Stock-based Compensation Expense
Year Ended June 30,
2019
2018
$
$
$
$
105,227
60,266
10,629
347,852
155,744
46,630
For the years ended June 30, 2019, and 2018, we recognized stock-based compensation expense related to Restricted
Stock and Contingent Restricted Stock grants of $888,162 and $1,366,764.
Note 12 – Supplemental Disclosure of Cash Flow Information
Our supplemental disclosures of cash flow information for the years ended June 30, 2019 and 2018 are as follows:
Income taxes paid
Non-cash transactions:
June 30,
2019
2018
$
2,762,919
$
1,826,754
Increase (decrease) in accrued purchases of property and equipment
(1,603,290)
1,695,218
Oil and natural gas property costs attributable to the recognition of asset retirement
obligations
86,384
43,922
Note 13 – Income Taxes
We file a consolidated federal income tax return in the United States and various combined and separate filings in several
state and local jurisdictions.
There were no unrecognized tax benefits nor any accrued interest or penalties associated with unrecognized tax benefits
during the years ended June 30, 2019 and 2018. 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,
2015 through June 30, 2018 for federal tax purposes and for the years ended June 30, 2016 through June 30, 2018 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
Deferred:
Federal
State
Total deferred income tax provision (benefit)
53
June 30, 2019
June 30, 2018
$
2,343,512
$
1,186,649
371,593
2,715,105
652,238
1,838,887
387,541
379,715
767,256
$
3,482,361
$
(5,498,890)
228,034
(5,270,856)
(3,431,969)
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For the years ended June 30, 2019 and 2018, respectively, we recognized income tax expense of $3.5 million and an
income tax benefit of $(3.4) million reflecting corresponding effective tax rates of 18.5% and (21.2)%. The fiscal 2018 benefit
included a one-time $(6.1) million tax benefit, resulting from adjustments of our deferred income tax liabilities in fiscal 2018
due to the enactment of the Tax Cut and Jobs Act (the "Tax Act") during December of 2017. 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. For the years ended
June 30, 2019 and 2018, our respective statutory federal tax rates were 21% and 27.55%, as we used a blended rate in the prior
fiscal year when the Tax Act was enacted. Depletion in excess of basis had less of an impact on our effective rate in the current
year as we utilized all of our depletion carryover in fiscal 2018. 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.
% of
Income
Before
Income
Taxes
June 30, 2018
% of
Income
Before
Income
Taxes
June 30, 2019
Income tax provision (benefit) computed at the statutory federal rate:
$ 3,960,480
21.0 % $ 4,459,940
27.6 %
Reconciling items:
Adjustment of deferred income liability for the Tax Act's lower statutory federal
tax rate
Change in valuation allowance due to enactment of the Tax Act
Expiration of Section 382 tax loss carryforwards
Change in valuation allowance for Section 382 tax loss carryforwards
Depletion in excess of tax basis
State income taxes, net of federal tax benefit
Permanent differences related to stock-based compensation
Other
Income tax provision (benefit)
—
—
— %
— %
(5,949,389)
(36.8)%
(111,818)
(0.7)%
127,410
0.70 %
(127,410)
(0.70)%
—
—
— %
— %
(982,302)
593,533
(73,671)
(15,679)
(5.1)%
3.1 %
(0.4)%
(0.1)%
(2,433,530)
(14.9)%
718,337
(139,333)
23,824
4.4 %
(0.9)%
0.1 %
$ 3,482,361
18.5 % $ (3,431,969)
(21.2)%
54
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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
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, 2019
June 30, 2018
$
159,090
$
496,082
20,713
675,885
(53,218)
622,667
144,956
680,186
24,207
849,349
(180,628)
668,721
(11,945,358)
(11,224,156)
(11,945,358)
(11,224,156)
$ (11,322,691) $ (10,555,435)
As of June 30, 2019, we had a federal tax loss carryforward of approximately $0.6 million that we acquired through the
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.
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
June 30,
2019
2018
$ 15,377,066
$ 19,618,484
33,160,283
33,126,469
9,435
52,066
33,169,718
33,178,535
$
$
0.46
0.46
$
$
0.59
0.59
The following were reflected in the calculation of diluted earnings per share in their respective fiscal years:
Outstanding Potential Dilutive Securities
Contingent Restricted Stock grants
Outstanding Potential Dilutive Securities
Contingent Restricted Stock grants
55
Weighted
Average
Exercise Price
Outstanding at
June 30, 2019
$
—
10,156
Weighted
Average
Exercise Price
Outstanding at
June 30, 2018
$
—
28,562
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 15 – Credit Agreements
Senior Secured Credit Agreement
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.
As of June 30, 2019, the Company's elected commitment and borrowing base were $40 million, we were in compliance
with all financial covenants and there were no amounts outstanding under the Facility, which is secured by substantially all of
the Company’s assets.
Under the Facility the borrowing base shall be determined semiannually as of every May 15 and November 15 during the
term of the Facility. During the fourth fiscal quarter, the bank performed its periodic spring redetermination of the borrowing
base and confirmed our elected amount of $40 million.
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 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
$27,045 as of June 30, 2019.
Note 16 – Commitments and Contingencies
We are subject to various claims and contingencies in the normal course of business. In addition, 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. 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 and 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.
Lease Commitments. We have a non-cancelable office space whose term ends in November 2022. Future minimum
lease commitments as of June 30, 2019 under this operating lease is as follows:
For the Years Ended June 30,
2020
2021
2022
2023
Total
$
34,322
59,945
61,843
26,098
$
182,208
Rent expense for the years ended June 30, 2019 and 2018 was $73,289 and $76,666, respectively.
56
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 17 – Concentrations of Credit Risk
Major Customers. We market all of our oil and natural gas production from the properties we operate. We do not
currently market our share of crude oil or natural gas liquids production from Delhi. Although we have the right to take our
working interest production at Delhi in-kind, we are currently selling our oil under the Delhi operator's agreement with Plains
Marketing L.P. for the delivery of our oil to a pipeline at the field. 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, 2019 and 2018. The loss of our purchaser at the Delhi field or disruption to pipeline transportation from the field could
adversely affect our net realized pricing and potentially our near-term production levels. The loss of any of our other purchasers
would not be expected to have a material adverse effect on our operations.
Customer
Plains Marketing L.P. (Oil sales from Delhi)
American Midstream Gas Solutions. L.P. (NGL sales from Delhi)
All others
Total
Year Ended June 30,
2019
2018
94%
6%
—%
100%
92%
8%
—%
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 covers 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,
with Company contributions fully vested when made. Our matching contributions to the Plan totaled $52,809 and $43,134 for
the years ended June 30, 2019 and 2018, respectively.
57
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 19 – 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 is 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 Financial Instruments. The Company's other financial instruments consist of cash, cash equivalents, and
restricted cash, receivables and payables. The carrying amounts of cash and cash equivalents, receivables and payables
approximate fair value due to the highly liquid or short-term nature of these instruments.
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 20 – 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 and examining specific areas that are considered to have prospects containing oil and natural gas reserves,
including costs of drilling exploratory wells, geological and geophysical 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 $86,384 and $43,922 during the
years ended June 30, 2019 and 2018, respectively.
Oil and Natural Gas Activities
Property acquisition costs:
Proved property
Unproved property (a)
Exploration costs
Development costs
Total costs incurred for oil and natural gas activities
For the Years Ended June 30,
2019
2018
$
— $
—
—
—
—
—
5,229,235
5,429,985
$
5,229,235 $
5,429,985
Estimated Net Quantities of Proved Oil and Natural Gas Reserves
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
58
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
were determined under the method prescribed by the SEC for our fiscal years ended June 30, 2019 and 2018, which 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.
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 oil and natural gas reserves and changes in quantities of proved developed and
undeveloped reserves for each of the periods indicated were as follows:
Proved developed and undeveloped reserves:
June 30, 2017
Revisions of previous estimates (a)
Improved recovery, extensions and discoveries
Sales of minerals in place
Production (sales volumes)
June 30, 2018
Revisions of previous estimates (b)
Improved recovery, extensions and discoveries
Sales of minerals in place
Production (sales volumes)
June 30, 2019
Proved developed reserves:
June 30, 2017
June 30, 2018
June 30, 2019
Proved undeveloped reserves:
June 30, 2017
June 30, 2018
June 30, 2019
Crude Oil
(Bbls)
Natural Gas
Liquids
(Bbls)
Natural Gas
(Mcf)
BOE
8,372,150
369,971
—
—
(651,931)
8,090,190
152,420
—
—
(626,879)
7,615,731
6,617,389
6,291,850
6,273,907
1,754,761
1,798,340
1,341,824
1,686,228
(315,090)
—
—
(93,366)
1,277,772
199,078
—
—
(112,089)
1,364,761
1,332,803
993,741
1,124,302
353,425
284,031
240,459
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
10,058,378
54,881
—
—
(745,297)
9,367,962
351,498
—
—
(738,968)
8,980,492
7,950,192
7,285,591
7,398,209
2,108,186
2,082,371
1,582,283
(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) The positive crude oil and NGL revisions were the result of improvements in well and NGL plant performance
respectively.
Standardized Measure of Discounted Future Net Cash Flows
Future oil and natural gas sales and 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 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 asset retirement
59
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
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,
2019 and 2018 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,
2019
2018
$ 524,037,200
(208,539,679)
(18,395,252)
(55,881,997)
241,220,272
(114,488,230)
$ 126,732,042
$ 521,533,765
(228,478,119)
(22,213,269)
(50,810,883)
220,031,494
(101,073,080)
$ 118,958,414
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.
For the Years Ended June 30,
2019
2018
Oil
(Bbl)
Gas
(MMBtu)
Oil
(Bbl)
Gas
(MMBtu)
NYMEX prices used in determining future cash flows
$
61.62
n/a
$
57.50
n/a
There were no natural gas reserves in 2019 and 2018. 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.
60
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 sales 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
For the Years Ended June 30,
2019
2018
$ 118,958,414
$ 82,937,553
23,753,518
62,011,112
833,494
(28,962,837)
—
267,547
(29,087,710)
—
6,129,847
888,896
—
2,089,139
—
—
14,604,387
(2,795,183)
(7,878,737)
$ 126,732,042
11,089,455
871,540
(10,019,979)
$ 118,958,414
Note 21 – Selected Quarterly Financial Data (Unaudited)
The following table presents summarized quarterly financial information for the fiscal years ended June 30, 2019 and
2018:
2019
Revenues
Operating income
Net income available to common shareholders
Basic net income per share
Diluted net income per share
2018
Revenues
Operating income
Net income available to common shareholders
Basic net income per share
Diluted net income per share
First (1)
Second
Third
Fourth
$ 12,307,079
$ 11,048,118
5,994,927
5,795,801
0.18
0.17
$
$
$
4,733,747
3,904,565
0.12
0.12
$
$
$
$
9,501,028
$ 10,373,396
2,952,955
2,398,875
0.07
0.07
$
$
$
3,955,194
3,277,825
0.10
0.10
First
Second (2)
Third
Fourth
8,537,871
$ 11,066,911
$ 10,249,566
$ 11,426,864
2,536,459
2,140,532
0.06
0.06
$
$
$
4,829,252
9,876,848
0.30
0.30
$
$
$
3,663,267
3,068,354
0.09
0.09
$
$
$
5,182,663
4,532,750
0.14
0.14
$
$
$
$
$
$
$
(1) The first quarter of fiscal 2019 included other income of $1.1 million for the Enduro transaction breakup fee.
(2) The second quarter of fiscal 2018 was impacted by a $6 million tax benefit attributable to the Tax Cut and Jobs Act enacted
during December 2017.
61
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 and that such information is accumulated and communicated to this Company's
management, including our interim 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 interim 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 interim 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 and includes 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, 2019.
The effectiveness of our internal control over financial reporting at June 30, 2019 has been audited by Moss Adams LLP,
the independent registered public accounting firm that also audited our financial statements. Their report is included in Item 8.
"Financial Statements" of this Annual Report on form 10-K under the heading Report of Independent Registered Public
Accounting Firm on internal control over financial reporting.
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, 2019 that has materially affected, or is reasonably likely to materially affect, the Company's internal control over
financial reporting.
Item 9B. Other Information
None.
62
PART III
Item 10. Directors, Executive Officers And Corporate Governance
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 2019 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 2019 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 2019 fiscal year.
Item 13. Certain Relationships and Related Transactions, 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 2019 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 2019 fiscal year.
63
PART IV.
Item 15. Exhibits and Financial Statement Schedules
The following documents are filed as part of this report:
1. Financial Statements.
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.
64
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 12, 2019
By:
/s/ JASON E. BROWN
Jason E. Brown
President and Chief Executive Officer
(Principal Executive Officer)
Evolution Petroleum Corporation
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 12, 2019
/s/ ROBERT S. HERLIN
Robert S. Herlin
Chairman of the Board
September 12, 2019
September 12, 2019
September 12, 2019
/s/ JASON E. BROWN
Jason E. Brown
President and Chief Executive Officer
(Principal Executive Officer)
/s/ DAVID JOE
David Joe
Senior Vice President, Chief Financial Officer
and Treasurer (Principal Financial Officer)
/s/ R. STEVEN HICKS
R. Steven Hicks
Senior Vice President, Engineering and Business
Development
September 12, 2019
/s/ RODERICK SCHULTZ
Roderick Schultz
Vice President, Chief Accounting Officer
(Principal Accounting Officer)
September 12, 2019
/s/ EDWARD J. DIPAOLO
Edward J. DiPaolo
Lead Director
September 12, 2019
September 12, 2019
/s/ WILLIAM DOZIER
William Dozier
/s/ KELLY W. LOYD
Kelly W. Loyd
September 12, 2019
/s/ MARRAN J. OGILVIE
Marran J. Ogilvie
Director
Director
Director
65
INDEX OF EXHIBITS
MASTER EXHIBIT INDEX
DESCRIPTION
Articles of Incorporation (previously filed as an exhibit to Form 8-K on February 7, 2002)
Certificate of Amendment to Articles of Incorporation (previously filed as an exhibit to Form 8-K on
February 7, 2002)
Certificate of Amendment to Articles of Incorporation (previously filed as an exhibit to Form SB 2/A on
October 19, 2005)
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)
Amended Bylaws (previously filed as Exhibit 2.1 to Form 10KSB on March 31, 2004)
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 )
EXHIBIT
NUMBER
3.1
3.2
3.3
3.4
3.5
4.1
4.2
4.3
4.4
4.5
4.6
4.7
4.8
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
4.11
4.12
4.13
10.1
10.2
10.3
10.4
10.5
10.6
10.7
10.8
10.9
Form of Restricted Stock Agreement under 2016 Equity Incentive Plan (previously filed as an exhibit to Form
10-Q on February 8, 2018)
Form of Contingent Restricted Stock Agreement under 2016 Equity Incentive Plan (previously filed as an
exhibit to Form 10-Q on February 8, 2018)
Form of Restricted Stock Agreement under 2016 Equity Incentive Plan as Revised on July 9, 2019 (filed herein)
Form of Performance Share Unit Award Agreement under 2016 Equity Incentive Plan as Revised on July 9,
2019 (filed herein)
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)
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)
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)
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)
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)
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)
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)
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)
66
EXHIBIT
NUMBER
10.10
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)
DESCRIPTION
10.11
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 (filed herein)
14.1
21.1
23.1
23.2
31.1
31.2
32.1
32.2
99.1
Code of Business Conduct and Ethics (previously filed as an exhibit to Form 8-K on May 4, 2006)
List of Subsidiaries of Evolution Petroleum Corporation (filed herein)
Consent of Moss Adams LLP (filed herein)
Consent of DeGolyer & MacNaughton (filed herein)
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)
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)
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)
The summary of DeGolyer and MacNaughton's Report as of June 30, 2019, on oil and gas reserves (SEC Case)
dated August 2, 2019 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
67