Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
The following discussion and analysis should be read in conjunction with our Consolidated Financial Statements and Notes thereto included in Item 8, Financial Statements and Supplementary Data. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with Risk Factors under Item 1A of this Form 10-K, together with the statement of Forward-Looking Information at the beginning of this report for discussion of the risks and uncertainties that could cause our actual results to be materially different from our forward-looking statements. Certain dollar amounts and percentages in this Management’s Discussion and Analysis of Financial Condition and Results of Operations and other parts of this Annual Report on Form 10-K have been rounded for presentation, and certain amounts may not sum due to rounding.
Executive Overview
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 largest active investment is our interest in a CO
2
enhanced oil recovery project in Louisiana's Delhi field.
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 shareholders.
As a result of the retirement of Randy Keys, President and Chief Executive Officer on May 31, 2018, the Board of Directors immediately moved to name Robert Herlin to act as Interim Chief Executive Officer and to commence a search for a permanent Chief Executive Officer. Additionally, the Board of Directors created a temporary Transition Services Committee, consisting solely of Director William Dozier, to aid and assist management in primarily evaluating potential property acquisitions and operational matters. Both of these appointments are deemed temporary while the ongoing search for a permanent Chief Executive Officer is resolved.
We expect to fund our fiscal
2019
capital program from working capital and net cash flows from our properties.
Highlights for our fiscal year
2018
|
|
•
|
Our fiscal year 2018 net income was $19.6 million, or $0.59 per share, our seventh consecutive year of reporting net income.
|
|
|
•
|
We funded all operations, including $5.4 million of capital spending, from internal resources and remained debt free.
All of our capital expenditures and dividends were funded solely by cash flow from operations and working capital and we ended our fiscal year with no funded debt.
|
|
|
•
|
We returned $11.6 million to common shareholders in the form of cash dividends during fiscal 2018.
The annual dividend rate of $0.40 per share is an increase of 43% from a year ago. We remain committed to our dividend policy and rewarding our long-term shareholders.
|
|
|
•
|
We extended the maturity date of our senior secured bank credit facility to April 2021.
Our elected borrowing base is $40 million, and there are no outstanding borrowings as of September 1, 2018.
|
|
|
•
|
Oil and NGL revenues increased by $6.8 million, or 20%, in fiscal 2018, principally driven by 23% higher realized commodity prices, offset in part by a 3% decrease in production volumes.
Production was adversely impacted by factors including unusually cold weather and temporary reductions in CO
2
injections to support our infill drilling program.
|
|
|
•
|
The Delhi twelve-well infill drilling program is largely completed and only a few completions remain outstanding as of September 1, 2018.
We expect the remainder of the project to be completed by October 2018, and we expect to see an uplift in oil volumes in fiscal 2019.
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Oil & Gas Reserves (based on SEC oil price of $57.50 per barrel in effect as at June 30, 2018)
|
|
•
|
Delhi proved oil equivalent reserves at June 30, 2018 were 9.4 MMBOE
, a 7% decline from the previous year. The Standardized Measure for proved reserves increased 43% to $119 million, reflecting a rise in commodity price from
|
$44.88 to $55.39 per BOE. Proved reserves are 86% oil and 14% natural gas liquids, and 78% of these reserves are developed and producing.
|
|
•
|
Delhi probable reserves at June 30, 2018 were 4.5 MMBOE
, a 15% decrease over the previous year. 80% of these reserves are classified as developed and producing as such are incremental reserves associated with existing developed and producing locations.
|
|
|
•
|
Delhi possible reserves at June 30, 2018 were 4.6 MMBOE
, a 42% increase over the previous year. 88% of these reserves are classified as developed and producing as such are incremental reserves associated with existing developed and producing locations.
|
The following table is a summary of our proved, probable and possible reserves for fiscal year 2018 and 2017:
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|
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|
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Proved
|
|
|
|
Probable
|
|
|
|
Possible
|
|
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
|
2018
|
|
2017
|
|
Change
|
Reserves MMBOE
|
9.4
|
|
|
10.1
|
|
|
(7
|
)%
|
|
4.5
|
|
|
5.3
|
|
|
(15
|
)%
|
|
4.6
|
|
|
3.2
|
|
|
42
|
%
|
% Developed
|
78
|
%
|
|
79
|
%
|
|
(1
|
)%
|
|
80
|
%
|
|
82
|
%
|
|
(2
|
)%
|
|
88
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%
|
|
89
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%
|
|
(1
|
)%
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Liquids %
|
100
|
%
|
|
100
|
%
|
|
—
|
%
|
|
100
|
%
|
|
100
|
%
|
|
—
|
%
|
|
100
|
%
|
|
100
|
%
|
|
—
|
%
|
Standardized Measure ($MM)
|
$
|
119
|
|
|
$
|
83
|
|
|
43
|
%
|
|
|
|
|
|
|
|
|
|
|
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|
PV-10* ($MM)
|
$
|
146
|
|
|
$
|
111
|
|
|
32
|
%
|
|
|
|
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____________________________________________________________________________
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*
|
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 2. "Properties."
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 2. Properties
. 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 2. Properties, Item 8. Financial Statements - Notes to the Financial Statements
and
Exhibit 99.4
of this Form 10-K.
Delhi Field—Enhanced Oil Recovery Project
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, and subsidiary 100% owned by Denbury Resources, Inc. (the "operator").
Proved reserves volumes totaled 9.4 MMBOE with a Standardized Measure of $119 million and a PV-10* value of $146 million compared to the prior year's 10.1 MMBOE with a Standardized Measure of $83 million and a PV-10* value of $111 million. Transfers from probable oil reserves led to a 0.4 MMBO (4%) positive revision in proved oil reserves. Performance from the NGL plant was below our expectations, resulting in a 0.3 MMBO (19%) negative revision to NGL reserves. Combined, these revisions had a slight positive effect on equivalent reserves volumes. However, with NGL prices 67% the level of oil prices, the overall impact on value was more positive. Probable reserve volumes at Delhi were 4.5 MMBOE, a decrease of 15% compared to 5.3 MMBOE in the prior year. Possible reserves volumes at Delhi were 4.6 MMBOE, an increase of 42% compared to 3.2 MMBOE in the prior year.
Gross production at Delhi in the fourth quarter of fiscal 2018 was
7,545
BOEPD, a 5% increase compared to
7,187
BOEPD in the third fiscal quarter. Oil production was
6,530
barrels of oil per day (“BOPD”), a
2%
increase from the third
fiscal quarter’s
6,427
BOPD. NGL production in the fourth quarter was
1,015
BOEPD,
34%
higher than prior quarter production of
760
BOEPD. Production during the quarter was impacted by reduced volumes of CO
2
injected into the field due primarily to warmer temperatures, compressor downtime for repairs and reduced CO
2
injections near wells being drilled as part of the infill drilling program. July production is also expected to be similarly impacted. Production only included a small volume from the first three wells of the twelve infill well drilling program initiated in March 2018; the wells are expected to gradually begin materially impacting production over the next two to three quarters. The twelve-well infill program consists of eight producer wells and four CO
2
injection wells. Three producer wells and one CO
2
injection well went online at the end of the fourth quarter, and the remaining five producers and three CO
2
injection wells are expected to be completed and brought online by the end of October 2018. The infill program targets productive oil zones in the developed area of the field that the operator believes are not being swept effectively by the current CO
2
flood. This program is expected to both add production and increase ultimate recoveries above the current proved producing oil reserves.
The average oil price realized by Evolution during the fourth quarter of fiscal 2018 was $67.41 compared to $63.56 during the previous quarter. The average NGL price realized by Evolution during the fourth quarter of fiscal 2018 was $38.39 per barrel compared to $34.05 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 overall lifting costs for the year were
$16.36
per BOE increased
16%
from
$14.10
per BOE in the prior year. Our cost of purchased CO
2
in the Delhi field, the largest single component of operating costs, is directly tied to the price of oil sold from the field. This major operating cost increased
5.6%
due to the higher price of crude, partially offset by lower purchased volumes. Gross CO
2
injection rates for the year ended June 30, 2018 averaged
65.0
MMcf per day, a decline of
11%
compared to the 73.1 MMcf per day during fiscal 2017. Other lease operating expenses for the fiscal 2018 increased
17.4%
compared to the prior year , primarily due to workover expenses and the cost of the NGL plant, which commenced operations in December 2016, midway through our fiscal year 2017.
For fiscal 2018, our gross NGL production was
976
BOEPD, which sold at an average price of
$33.50
per barrel compared to prior year gross production of
459
BOEPD for which we realized
$21.28
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 contains a large percentage (~70%) of higher value NGL's, such as pentanes and butane, and almost no lower value ethane. Market pricing for our NGL's during the fourth quarter was favorable, with net realized NGL prices averaging approximately 57% of WTI prices (net realized price is after deduction of transportation and fractionation charges). NGL demand often has a seasonal pattern and prices tend to be higher during the cooler months of October through March. 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 CO
2
recycle facility, contributing to an 11% decline in electricity expense year over year. The NGL plant is accomplishing its primary objective of removing the lighter hydrocarbons (i.e. methane and ethane), thereby increasing the purity of the CO
2
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 $6.15 per BOE for the remainder of the infill drilling project and 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.
2017 Tax Cuts and Jobs Act
On December 22, 2017, the U.S. government enacted comprehensive tax legislation under the title of the Tax Cuts and Jobs Act ("Tax Act"). The Tax Act includes a permanent reduction in our federal corporate income tax rate from 34% to 21%. It also provides more favorable tax deductions associated with capital investments and other significant changes to tax law. The
Tax Act became effective upon passage, so our statutory rate for the current fiscal year ended June 30, 2018 is a blended rate of 27.55%. The permanent reduction in the federal corporate income tax rate resulted in a one-time non-cash income tax benefit of approximately
$6.1 million
related to the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. This benefit was recognized in the quarter ended December 31, 2017. The accounting for the effects of the rate change on the Company’s deferred tax balances was complete as of December 31, 2017 and no provisional amounts were recorded.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
2018
|
|
2017
|
|
2016
|
Income before income taxes
|
$
|
16,186,515
|
|
|
$
|
12,884,977
|
|
|
$
|
34,231,141
|
|
Income tax (benefit) provision
|
(3,431,969
|
)
|
(a)
|
4,840,664
|
|
|
9,570,779
|
|
Effective tax rate
|
(21
|
)%
|
(b)
|
38
|
%
|
|
28
|
%
|
(a) The income tax provision for the ended
June 30, 2018
includes a one-time non-cash benefit of approximately
$6.1 million
for the adjustment of our liability for deferred income taxes to the lower rate in the Tax Act. This discrete adjustment results in a negative tax rate (benefit) for this period.
(b) Income taxes are recorded in our financial statements based on our estimated annual effective income tax rate together with any discrete items. For the year ended
June 30, 2018
, the effective rate used in the calculation of our income tax expense was approximately
16%
. Applying this rate together with the
$6.1 million
discrete revaluation benefit resulted in the negative tax rate (benefit) of
(21)%
.
Compared to the year ended June 30, 2017, the effective tax rate for the year ended June 30, 2018, excluding the impact of the
$6.1 million
deferred tax adjustment, was lower than the prior year tax rate due principally to increased depletion in excess of basis.
Liquidity and Capital Resources
We had
$27.7 million
and
$23.4 million
of working capital at
June 30, 2018
and
June 30, 2017
, respectively.
In addition, we have a senior secured reserve-based credit facility (the "Facility") with a maximum borrowing capacity of $50.0 million. The Facility had $40.0 million of undrawn borrowing base availability on June 30, 2018. There have been no borrowings under the Facility, which is secured by substantially all of the Company’s assets. In February 2018, we elected to increase the borrowing base from $10.0 million to $40.0 million. Additionally, on May 28, 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 and amend certain financial covenants.
The borrowing base is subject to periodic redeterminations and further adjustments from time to time. The borrowing base will be redetermined semi-annually on May 15 and November 15 of each year. The borrowing base will also be reduced in certain circumstances such as the sale or disposition of certain oil and gas properties of the Company or its subsidiaries and changes to certain hedging positions. With volatility in commodity prices, our borrowing base and related commitments under the Facility could be reduced in the future. Any future borrowings bear interest, at the Company's option, at either LIBOR plus 2.75% or the Prime Rate, as defined in the Facility agreement, 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 agreement.
As of June 30, 2018, the Company was in compliance with all covenants under the Facility, and no amounts were outstanding under the Facility.
During our fiscal year ended
June 30, 2018
, we funded our operations and cash dividends with cash generated from operations; our cash balance and working capital increased
$1.9 million
and
$4.3 million
, respectively, from June 30, 2017.
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 evaluate and 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 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 advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.
Our other significant use of cash is our on-going dividend program. The Board of Directors instituted a cash dividend on our common stock in December 2013 and we have since paid twentieth consecutive quarterly dividends. Distribution 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 dividends over time as appropriate. In February 2018, the Board declared an increase in the quarterly common stock dividend from $0.075 per share to $0.10 per share, effective with the dividend payment in March 2018. In August 2018, the Board declared a $0.10 per share dividend payable on September 28, 2018. The amount of future dividends paid to Evolution Petroleum common stockholders is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board.
Cash Flows from Operating Activities
For the year ended
June 30, 2018
, cash flows provided by operating activities were
$20.5 million
, reflecting
$21.9 million
provided by operations before $1.4 million used by other working capital changes. Of the
$21.9 million
provided before working capital changes, approximately
$19.6 million
resulted from net income and
$2.3 million
was attributable to non-cash expenses and gains.
For the year ended June 30, 2017, cash flows provided by operating activities were $16.5 million, reflecting $19.0 million provided by operations before $2.5 million used by other working capital changes. Of the $19.0 million provided before working capital changes, approximately $8.0 million resulted from net income and $10.9 million was attributable to non-cash expenses and gains.
For the year ended June 30, 2016, cash flows provided by operating activities were $30.7 million, reflecting $28.9 million provided by operations before $1.8 million provided by other working capital changes. Of the $28.9 million provided before working capital changes, approximately $24.7 million resulted from net income and $4.2 million was attributable to non-cash expenses and gains.
Cash Flows from Investing Activities
For the year ended
June 30, 2018
, investing activities used
$3.7 million
of cash, consisting primarily of capital expenditures of approximately
$3.7 million
for the Delhi field.
For the year ended June 30, 2017, investing activities used $10.5 million of cash, consisting primarily of cash capital expenditures of approximately $10.2 million for the Delhi field, partially offset by $0.3 million of derivative settlements paid.
For the year ended June 30, 2016, investing activities used $17.6 million of cash, consisting primarily of cash capital expenditures of approximately $21.1 million for the Delhi field, partially offset by $3.6 million of derivative settlement payments received.
Oil and gas capital expenditures incurred, which includes accrued expenditures and other noncash items, were
$5.4 million
,
$7.6 million
, and
$19.7 million
, respectively, for the years ended
June 30, 2018
,
2017
, and
2016
. These amounts can be reconciled to cash capital expenditures on their respective cash flow statements by adjusting them for related non-cash items presented at Note 12 – Supplemental Cash Flow Information.
Cash Flows from Financing Activities
For the year ended June 30, 2018, financing activities used
$12.2 million
of cash, comprised of
$11.6 million
of common stock cash dividends, and
$0.6 million
of treasury stock acquired through the surrender of shares in satisfaction of payroll liabilities related to vestings of stock-based compensation awards.
For the year ended June 30, 2017, financing activities used $17.1 million of cash, comprised of $8.4 million of common stock cash dividends, $0.3 million of preferred dividends, $7.9 million for redemption of preferred stock in November 2016 and $0.5 million of treasury stock acquired through the surrender of shares in satisfaction of payroll liabilities related to vestings of stock-based compensation awards.
For the year ended June 30, 2016, financing activities provided $0.9 million of cash from $9.6 million of tax benefits related to stock-based compensation partially offset by $7.2 million of dividend payments to common and preferred shareholders and $1.4 million of treasury stock acquisitions, primarily attributable to the Company's share buyback program.
The tax benefits included a $1.5 million cash refund received from the State of Louisiana for carryback of stock-based compensation deductions to previously filed returns.
Capital Budget
During the year ended
June 30, 2018
, we incurred $5.4 million of capital expenditures at Delhi. This spending included $0.4 million for capital upgrades to the recycle plant, $1.1 million for CO
2
conformance projects and capital maintenance, $1.1 million for Test Site 5 infrastructure (i.e. water curtain wells) in the eastern portion of the field, and $2.8 million for the infill drilling program.
The twelve-well infill drilling program in the Delhi field commenced March 2018 and all twelve wells are expected to be drilled and completed by the end of September and on budget. The total project had an estimated net cost of $4.7 million, with approximately sixty percent of those costs incurred in fiscal year 2018, with the balance to be incurred in fiscal first quarter of 2019. All twelve wells are expected to be in operation by the end of October 2018 and the operator anticipates an uplift in oil volumes to be reported over the next few quarters. The program consists of four new CO
2
injection wells and eight new production wells and targeted productive oil zones which we believe were not being swept effectively by the current CO
2
flood, thereby adding incremental production.
We previously approved additional net capital expenditures totaling $2.8 million for water injection, flowlines and other infrastructure projects in preparation for the Test Site 5 development. Such development requires participation by both the operator and Evolution, and the operator has not yet finalized its capital expenditure budget for 2019. Approximately $1.1 million of these preparation costs have been incurred as of
June 30, 2018
. In addition, we expect to continue to perform conformance workover projects and will likely incur additional maintenance capital expenditures. Such amounts cannot be estimated accurately at this time, but are not expected to be material to our financial position.
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.
Liquidity Outlook
Our current liquidity position remains strong, with
$27.7 million
of working capital, which is significantly in excess of our expected capital needs at Delhi. We also expect positive cash flow in the future. Our future liquidity is dependent on the realized prices we receive for the oil and natural gas liquids we produce. Commodity prices are market driven and historically volatile, and they are likely to continue to be volatile. The Company may utilize derivative instruments to reduce its exposure to short term oil price volatility with the goal of achieving a more predictable level of cash flows to support the Company’s capital expenditure and dividend programs. From time to time, the Company has used both fixed price swap agreements and costless collars to manage its exposure to crude oil price risk. We have no derivative commitments at June 30, 2018. While the use of derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. Our future revenues, cash flow, profitability, access to capital and future rate of growth will be significantly impacted by the prices we receive for our production.
Funding for our anticipated capital expenditures over the next two fiscal years is expected to be met from cash flows from operations and current working capital. Our preference is to remain debt free under our current operating plans, but we have access to at least $40 million of availability under a senior secured credit facility if required. In addition, we have a maximum of $500 million authorized under an effective shelf registration statement with Securities and Exchange Commission under which we may sell new securities from time to time in one or more offerings. We may choose to evaluate and pursue new growth opportunities through acquisitions or other transactions. In that event, we would expect to use our internal resources of cash, working capital and borrowing capacity under our credit facility. It may also be advantageous for us to consider issuing additional equity as part of any potential transaction, but we have no specific plans to do so at this time.
The Board of Directors instituted a cash dividend on our common stock in December 2013 and have since paid twenty consecutive quarterly dividends and have declared the twenty-first dividend for payment on September 28, 2018. The amount of future dividends paid to Evolution common stockholders is determined by the Board on a quarterly basis and is based on the Company’s earnings, financial condition, capital requirements, the effect a dividend payment would have on the Company’s compliance with relevant financial covenants, and other factors deemed relevant by the Board.
In May 2015, we established a stock repurchase plan to allow us to acquire up to $5.0 million of our common stock over time. We have repurchased $1.6 million of common stock under the plan, but made no stock repurchases during fiscal 2017 or fiscal 2018. The timing and amount of repurchases will depend upon several factors, including financial resources and market conditions. In general, our share repurchase program is limited to discretionary funds and is of lesser importance than our primary objectives related to our development capital spending at Delhi and our common stock dividend program. There is no fixed termination date for the repurchase program, and the repurchase program may be suspended or discontinued at any time.
Results of Operations
The following table sets forth certain financial information with respect to our oil and natural gas operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year Ended June 30,
|
|
2018
|
|
2017
|
|
2016
|
Oil and gas production:
|
|
|
|
|
|
Crude oil revenues
|
$
|
38,153,417
|
|
|
$
|
33,550,698
|
|
|
$
|
26,130,762
|
|
NGL revenues
|
3,127,795
|
|
|
934,202
|
|
|
7,885
|
|
Natural gas revenues
|
—
|
|
|
(4
|
)
|
|
2,895
|
|
Total revenues
|
$
|
41,281,212
|
|
|
$
|
34,484,896
|
|
|
$
|
26,141,542
|
|
|
|
|
|
|
|
Crude oil volumes (Bbl)
|
651,931
|
|
|
724,523
|
|
|
658,041
|
|
NGL volumes (Bbl)
|
93,366
|
|
|
43,907
|
|
|
491
|
|
Natural gas volumes (Mcf)
|
—
|
|
|
16
|
|
|
1,620
|
|
Equivalent volumes (BOE)
|
745,297
|
|
|
768,433
|
|
|
658,802
|
|
|
|
|
|
|
|
Crude oil (BOPD, net)
|
1,786
|
|
|
1,985
|
|
|
1,798
|
|
NGLs (BOEPD, net)
|
256
|
|
|
120
|
|
|
1
|
|
Natural gas (BOEPD, net)
|
—
|
|
|
—
|
|
|
1
|
|
Equivalent volumes (BOEPD, net)
|
2,042
|
|
|
2,105
|
|
|
1,800
|
|
|
|
|
|
|
|
Crude oil price per Bbl
|
$
|
58.52
|
|
|
$
|
46.31
|
|
|
$
|
39.71
|
|
NGL price per Bbl
|
33.50
|
|
|
21.28
|
|
|
16.06
|
|
Natural gas price per Mcf
|
—
|
|
|
(0.25
|
)
|
|
1.79
|
|
Equivalent price per BOE
|
$
|
55.39
|
|
|
$
|
44.88
|
|
|
$
|
39.68
|
|
|
|
|
|
|
|
CO
2
costs
|
$
|
4,729,506
|
|
|
$
|
4,477,866
|
|
|
$
|
4,090,938
|
|
All other lease operating expenses (a)
|
7,463,996
|
|
|
6,357,943
|
|
|
4,971,241
|
|
Production costs
|
$
|
12,193,502
|
|
|
$
|
10,835,809
|
|
|
$
|
9,062,179
|
|
Production costs per BOE
|
$
|
16.36
|
|
|
$
|
14.10
|
|
|
$
|
13.76
|
|
|
|
|
|
|
|
CO
2
volumes (MMcf per day, gross)
|
65.0
|
|
|
73.1
|
|
|
73.8
|
|
|
|
|
|
|
|
Oil and gas DD&A (b)
|
$
|
5,980,307
|
|
|
$
|
5,687,903
|
|
|
$
|
4,906,123
|
|
Oil and gas DD&A per BOE
|
$
|
8.02
|
|
|
$
|
7.40
|
|
|
$
|
7.45
|
|
|
|
|
|
|
|
Artificial lift technology services:
|
|
|
|
|
|
Services revenues
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
207,960
|
|
Cost of service
|
—
|
|
|
—
|
|
|
70,932
|
|
Depreciation and amortization expense
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
238,475
|
|
(a) Includes ad valorem and production taxes of
$188,058
,
$214,553
, and
$294,689
for the years ended
June 30, 2018
,
2017
, and
2016
, respectively.
(b) Excludes depreciation and amortization expense of artificial lift technology services below and excludes non-operating asset depreciation of
$31,691
,
$31,502
, and
$20,522
for the years ended
June 30, 2018
,
2017
, and
2016
, respectively.
Year ended June 30, 2018 compared with the Year ended June 30, 2017
Net Income Attributable to Common Shareholders.
For the year ended June 30, 2018, we generated net income of
$19.6 million
, or
$0.59
per diluted share, on total revenues of
$41.3 million
. This compares to net income of
$6.8 million
, or
$0.21
per diluted share, on total revenues of
$34.5 million
for the corresponding year-ago period. The
$12.8 million
earnings increase reflects
$6.8 million
of higher revenue, a
$8.3 million
income tax decrease attributable to the 2017 Tax Cuts and Jobs Act and a $1.2 million decrease in earnings allocated to preferred stock because of its redemption, partially offset by
$3.5 million
of higher operating expenses, primarily production costs and general and administrative expense.
Oil and Gas Production.
Revenues increased
20%
to
$41.3 million
primarily due to a
23%
increase in realized prices from
$44.88
per equivalent barrel to
$55.39
per equivalent barrel on lower
(3.0)%
in equivalent barrels. All of our revenues in the current fiscal year came from the Delhi field, as did all of our revenues from the prior year. Net Delhi oil production volumes of
1,786
BOPD at an average price of
$58.52
decreased
199
BOPD from the prior year period primarily due to the abnormal sub-freezing temperatures that disrupted operations in January, plant scheduled maintenance later in our third quarter and reduced CO
2
injections in the fourth quarter due to compressor maintenance and infill drilling activities. Net NGL production averaged
256
BOEPD, at an average price of
$33.50
per barrel, an increase of
136
BOEPD compared to the year-ago period as NGL plant production began in January 2017, representing only a partial year of production.
Production Costs
. Production costs for the year ended June 30, 2018 were
$12.2 million
, a
13%
increase from the prior year primarily due to higher CO
2
costs and the incremental operating costs of the NGL plant that commenced operations in January 2017. CO
2
costs increased
$0.3 million
, or
6%
, due to higher purchased CO
2
costs per Mcf, which correlates to the
26%
increase in realized oil price from the prior year, partially offset by a
11.0%
decrease in purchase volumes. Average gross purchased CO
2
volumes decreased from
73.1
MMcf per day in the year-ago period to
65.0
MMcf per day for the current year. Other production costs, which include incremental costs of the NGL plant, power, chemicals, workovers, repairs and maintenance, labor and overhead, increased $1.1 million, or 17%, from the year-ago period. Approximately $0.9 million of this increase were due to higher NGL plant-related expenses. Total production costs per equivalent barrel in the current period were
$16.36
per BOE on total production volumes, compared to
$14.10
in the prior year period.
General and Administrative Expenses (“G&A”).
G&A expenses increased
$1.8 million
, or
36%
, from the prior year, to
$6.8 million
for the year ended June 30, 2018. The expense increase reflected increases of $0.4 million of litigation and non-recurring settlement expenses, $0.2 million of non-cash stock-based compensation expense, $0.2 million of severance, $0.2 million of board expenses, and $0.7 million of due diligence costs associated with property acquisitions evaluations. In early fiscal 2019, we received a $1.1 million break-up fee related to our Enduro stalking horse bid thereby recovering $0.4 million of acquisition expenses incurred in fiscal 2018. See Note 3 – Enduro Purchase and Sale Agreement and Related Subsequent Events.
Depreciation, Depletion & Amortization Expense (“DD&A”).
DD&A increased
$0.3 million
, or
5%
, to
$6 million
for the year ended June 30, 2018 compared to the prior year, primarily due to increased full cost amortization from a higher amortization rate of
$8.02
per BOE compared to
$7.40
per BOE in the year ago period, partially offset by the
3.0%
decrease in production volumes. The higher rate was principally due to increased development costs at Delhi field.
Year ended June 30, 2017 ("Fiscal 2017") compared with the Year ended June 30, 2016 ("Previous Year")
Net Income Attributable to Common Shareholders.
For the year ended June 30, 2017, we generated net income of $6.8 million, or $0.21 per diluted share, on total revenues of $34.5 million. This compares to net income of $24.0 million, or $0.73 per diluted share, on total revenues of $26.1 million for the previous year. The $17.2 million earnings decrease principally resulted from a decrease of $32.6 million in other income, reflecting a $28.1 million previous year litigation settlement, a $3.4 million decrease in derivative instrument gains, and a $1.1 million prior year insurance settlement together with a $0.6 million increase in allocated net income to holders of called preferred shares, partially offset by $8.1 million of higher revenue, $3.1 million of decreased operating costs, and $4.7 million of lower income taxes.
Oil and Gas Production.
Revenues increased 31.9% to $34.5 million primarily as a result of a 16.6% increase in production volumes from the previous year together with a 13.1% increase in realized prices from $39.68 per equivalent barrel to $44.88 per barrel in Fiscal 2017. Delhi production and revenues comprise virtually all of our revenues. Net Delhi oil production of 1,985 BOPD was 10.4% higher compared to the Previous Year as a result of production enhancement and conformance operations in the field. In addition $0.9 million of initial plant NGL sales commenced at the beginning of our third fiscal quarter and averaged 120 BOEPD over the entire fiscal year.
Production Costs
. Production costs for the year ended June 30, 2017 were $10.8 million, a 19.6% increase from the previous year. CO
2
costs for the Fiscal 2017 year were $4.5 million, or 9.5% higher than the Previous Year, due to a higher CO
2
price partially offset by a 1.2% decrease in purchase volumes as a result of operational efficiencies. The Fiscal 2017 year average
gross CO
2
injection rate was 73.1 MMcf per day, compared to 73.8 MMcf per day in the Previous Year. For the Fiscal 2017 year, production costs were $14.10 per barrel on total production volumes, compared to $13.76 per BOE in the Previous Year. Calculated solely on our Delhi working interest volumes, production costs were $19.01 per barrel of which $8.03 per barrel was CO
2
cost. These latter production costs per barrel exclude production volumes from our royalty interests in the Delhi field as they bear only certain allocated NGL production costs, and are therefore higher than the rates per barrel on our total production volumes.
General and Administrative Expenses (“G&A”).
G&A expenses decreased $4.1 million, or 45%, from the previous year, to $5.0 million for the year ended June 30, 2017, primarily due to a $2.6 million decrease in litigation costs, a $0.6 million decrease in stock-based compensation, $0.5 million of lower bonus expense, and $0.5 million of lower salary and benefit expenses.
Other Income and Expenses
. For the year ended June 30, 2017, aggregate other items decreased $32.6 million from the previous year due to the $28.1 million Delhi field litigation settlement in the previous year, a $3.4 million decrease in derivative gains and a $1.1 million insurance recovery in the previous year.
Depreciation, Depletion & Amortization Expense (“DD&A”).
DD&A increased $0.6 million, or 11%, to $5.7 million for the year ended June 30, 2017 compared to the previous year, due to an increase of $0.8 million in full cost pool depletion, partially offset by a $0.2 million decrease in fixed asset depreciation, which was impacted by the previous year impairment of artificial lift equipment. Compared to the previous year, the increase in full cost pool amortization reflects a 16.6% production increase to 0.8 million BOE, partially offset by a small 0.7% decrease in the amortization rate to $7.40 per BOE.
Other Economic Factors
Inflation
. Although the general inflation rate in the United States, as measured by the Consumer Price Index and the Producer Price Index, has been relatively low in recent years, the oil and gas industry has experienced unusually volatile price movements in commodity prices, vendor goods and oilfield services. Prices for drilling and oilfield services, oilfield equipment, tubulars, labor, expertise and other services impact our lease operating expenses and our capital expenditures. During fiscal 2018 to date, we have seen a firming of prices for operating and capital costs as a result of improving demand and a closer balance with the supply of goods and services in the industry. Product prices, operating costs and development costs may not always move in tandem.
Known Trends and Uncertainties
. General worldwide economic conditions, as well as economic conditions for the oil and gas industry specifically, continue to be uncertain and volatile. Regional and worldwide market factors, such as tariffs or trade restrictions, may also increase production costs. Concerns over uncertain future economic growth are affecting numerous industries and companies, as well as consumers, which impact demand for crude oil and natural gas. If the supply of crude oil and natural gas exceeds demand in the future, it may put downward pressure on crude oil and natural gas prices, thereby lowering our revenues, profits, cash flow and working capital going forward. While we realized higher average oil prices in the current quarter than any period since the quarter ended December 31, 2014, there can be no assurance that such prices will continue to prevail or trend upward.
Seasonality
. Our business is generally not directly seasonal, except for instances when weather conditions may adversely affect access to our properties or delivery of our petroleum products. Although we do not generally modify our production for changes in market demand, we do occasionally experience seasonality in the product prices we receive, driven by summer cooling and driving, winter heating, and extremes in seasonal weather, including hurricanes. We have also experienced adverse impacts on our production from very high summer temperatures and extremely cold winter weather.
Contractual Obligations and Other Commitments
The table below provides estimates of the timing of future payments that, as of
June 30, 2018
, 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
|
$
|
2,879,545
|
|
|
$
|
2,879,545
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Operating lease
|
66,984
|
|
|
66,984
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Other Obligations
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations
|
1,422,955
|
|
|
35,539
|
|
|
—
|
|
|
—
|
|
|
1,387,416
|
|
Total obligations
|
$
|
4,369,484
|
|
|
$
|
2,982,068
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
1,387,416
|
|
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, 2018, 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 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, 2018 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, 2018 of 5%, 10% and 15% would affect depreciation, depletion and amortization expense by approximately $306,000, $646,000 and $1,026,000, 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 commenced within five years of the end of the period, 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, 2018, 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 based on the historical volatility of our total common stock return compared to the historical volatilities of the other companies in the index. 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. We estimate the fair value of stock option awards on the date of grant using the Black-Scholes option pricing model. This valuation method requires the input of certain assumptions, including expected 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 option on the date of grant. Because of our limited trading experience of our common stock and limited exercise history of our stock option awards, estimating the volatility and expected term is very subjective. We base our estimate of our expected future volatility on peer companies whose common stock has been trading longer than ours, along with our own limited trading history while operating as an oil and natural gas producer. Future estimates of our stock volatility could be substantially different from our current estimate, which could significantly affect the amount of expense we recognize for our stock-based compensation awards.
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, 2018
.
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.
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, 2018.
Item 8. Financial Statements
Index to Consolidated Financial Statements
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 sheet of Evolution Petroleum Corporation and Subsidiaries (the “Company”) as of June 30, 2018, the related consolidated statements of operations, cash flows and changes in stockholders’ equity for the year ended June 30, 2018, 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, 2018, and the consolidated results of its operations and its cash flows for the year ended June 30, 2018, 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, 2018, 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 10, 2018
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 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 the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audit 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 audit 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 audit provides a reasonable basis for our opinion.
/s/
Moss Adams LLP
Houston, Texas
September 10, 2018
We have served as the Company’s auditor since 2017.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders
Evolution Petroleum Corporation
We have audited the accompanying consolidated balance sheet of Evolution Petroleum Corporation and subsidiaries (the “Company”) as of June 30, 2017, and the related consolidated statements of operations, cash flows, and changes in stockholders' equity for each of the two years in the period ended June 30, 2017. These consolidated financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Evolution Petroleum Corporation and subsidiaries as of June 30, 2017, and the results of their operations and their cash flows for each of the two years in the period ended June 30, 2017, in conformity with U.S. generally accepted accounting principles.
/s/ Hein & Associates LLP
Houston, Texas
September 15, 2017
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, 2018, 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 control over financial reporting as of June 30, 2018, 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 sheet of Evolution Petroleum Corporation
and Subsidiaries
as of June 30, 2018, the related consolidated statements of operations, cash flows and changes in stockholders’ equity for the year ended June 30, 2018, and the related notes (collectively referred to as the “consolidated financial statements”) and our report dated
September 10, 2018
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 10, 2018
Evolution Petroleum Corporation and Subsidiaries
Consolidated Balance Sheets
|
|
|
|
|
|
|
|
|
|
June 30, 2018
|
|
June 30, 2017
|
Assets
|
|
|
|
Current assets
|
|
|
|
Cash and cash equivalents
|
$
|
24,929,844
|
|
|
$
|
23,028,153
|
|
Restricted cash
|
2,751,289
|
|
|
—
|
|
Receivables
|
3,941,916
|
|
|
2,726,702
|
|
Prepaid expenses and other current assets
|
524,507
|
|
|
387,672
|
|
Total current assets
|
32,147,556
|
|
|
26,142,527
|
|
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
|
61,239,746
|
|
|
61,790,068
|
|
Other property and equipment, net
|
30,407
|
|
|
40,689
|
|
Total property and equipment, net
|
61,270,153
|
|
|
61,830,757
|
|
Other assets, net
|
244,835
|
|
|
295,384
|
|
Total assets
|
$
|
93,662,544
|
|
|
$
|
88,268,668
|
|
Liabilities and Stockholders' Equity
|
|
|
|
Current liabilities
|
|
|
|
Accounts payable
|
$
|
3,432,568
|
|
|
$
|
1,994,255
|
|
Accrued liabilities and other
|
874,886
|
|
|
724,639
|
|
State and federal taxes payable
|
122,760
|
|
|
—
|
|
Total current liabilities
|
4,430,214
|
|
|
2,718,894
|
|
Long term liabilities
|
|
|
|
Deferred income taxes
|
10,555,435
|
|
|
15,826,291
|
|
Asset retirement obligations
|
1,387,416
|
|
|
1,253,628
|
|
Total liabilities
|
16,373,065
|
|
|
19,798,813
|
|
Commitments and contingencies (Note 16)
|
|
|
|
Stockholders' equity
|
|
|
|
Common stock; par value $0.001; 100,000,000 shares authorized: issued and outstanding 33,080,543 and 33,087,308 shares as of June 30, 2018 and 2017, respectively
|
33,080
|
|
|
33,087
|
|
Additional paid-in capital
|
41,757,645
|
|
|
40,961,957
|
|
Retained earnings
|
35,498,754
|
|
|
27,474,811
|
|
Total stockholders' equity
|
77,289,479
|
|
|
68,469,855
|
|
Total liabilities and stockholders' equity
|
$
|
93,662,544
|
|
|
$
|
88,268,668
|
|
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30,
|
|
2018
|
|
2017
|
|
2016
|
Revenues
|
|
|
|
|
|
Crude oil
|
$
|
38,153,417
|
|
|
$
|
33,550,698
|
|
|
$
|
26,130,762
|
|
Natural gas liquids
|
3,127,795
|
|
|
934,202
|
|
|
7,885
|
|
Natural gas
|
—
|
|
|
(4
|
)
|
|
2,895
|
|
Artificial lift technology services
|
—
|
|
|
—
|
|
|
207,960
|
|
Total revenues
|
41,281,212
|
|
|
34,484,896
|
|
|
26,349,502
|
|
Operating costs
|
|
|
|
|
|
Production costs
|
12,193,502
|
|
|
10,835,809
|
|
|
9,062,179
|
|
Cost of artificial lift technology services
|
—
|
|
|
—
|
|
|
70,932
|
|
Depreciation, depletion and amortization
|
6,011,998
|
|
|
5,719,405
|
|
|
5,165,120
|
|
Accretion of discount on asset retirement obligations
|
90,290
|
|
|
59,664
|
|
|
49,054
|
|
General and administrative expenses*
|
6,773,781
|
|
|
4,985,408
|
|
|
9,079,597
|
|
Restructuring charges
|
—
|
|
|
4,488
|
|
|
1,257,433
|
|
Total operating costs
|
25,069,571
|
|
|
21,604,774
|
|
|
24,684,315
|
|
Income from operations
|
16,211,641
|
|
|
12,880,122
|
|
|
1,665,187
|
|
Other
|
|
|
|
|
|
Gain on settled derivative instruments, net
|
—
|
|
|
43,890
|
|
|
3,315,123
|
|
Gain (loss) on unsettled derivative instruments, net
|
—
|
|
|
(14,132
|
)
|
|
124,106
|
|
Delhi field litigation settlement
|
—
|
|
|
—
|
|
|
28,096,500
|
|
Delhi field insurance recovery related to pre-reversion event
|
—
|
|
|
—
|
|
|
1,074,957
|
|
Interest and other income
|
85,654
|
|
|
56,855
|
|
|
26,211
|
|
Interest (expense)
|
(110,780
|
)
|
|
(81,758
|
)
|
|
(70,943
|
)
|
Income before income tax provision
|
16,186,515
|
|
|
12,884,977
|
|
|
34,231,141
|
|
Income tax provision (benefit)
|
(3,431,969
|
)
|
|
4,840,664
|
|
|
9,570,779
|
|
Net income attributable to the Company
|
19,618,484
|
|
|
8,044,313
|
|
|
24,660,362
|
|
Dividends on preferred stock
|
—
|
|
|
250,990
|
|
|
674,302
|
|
Deemed dividend on redeemed preferred shares
|
—
|
|
|
1,002,440
|
|
|
—
|
|
Net income attributable to common shareholders
|
$
|
19,618,484
|
|
|
$
|
6,790,883
|
|
|
$
|
23,986,060
|
|
Earnings per common share
|
|
|
|
|
|
Basic
|
$
|
0.59
|
|
|
$
|
0.21
|
|
|
$
|
0.73
|
|
Diluted
|
$
|
0.59
|
|
|
$
|
0.21
|
|
|
$
|
0.73
|
|
Weighted average number of common shares outstanding
|
|
|
|
|
|
Basic
|
33,126,469
|
|
|
33,034,480
|
|
|
32,810,375
|
|
Diluted
|
33,178,535
|
|
|
33,110,560
|
|
|
32,861,231
|
|
_______________________________________________________________________________
|
|
*
|
General and administrative expenses for the years ended June 30, 2018, 2017 and 2016 included non-cash stock-based compensation expense of
$1,366,764
,
$1,180,618
, and
$1,750,209
, respectively.
|
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Cash Flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30,
|
|
2018
|
|
2017
|
|
2016
|
Cash flows from operating activities
|
|
|
|
|
|
Net income attributable to the Company
|
$
|
19,618,484
|
|
|
$
|
8,044,313
|
|
|
$
|
24,660,362
|
|
Adjustments to reconcile net income to net cash provided by operating activities:
|
|
|
|
|
|
Depreciation, depletion and amortization
|
6,068,265
|
|
|
5,775,946
|
|
|
5,211,494
|
|
Impairments included in restructuring charge
|
—
|
|
|
—
|
|
|
569,228
|
|
Stock-based compensation
|
1,366,764
|
|
|
1,180,618
|
|
|
1,809,548
|
|
Accretion of discount on asset retirement obligations
|
90,290
|
|
|
59,664
|
|
|
49,054
|
|
Settlement of asset retirement obligations
|
—
|
|
|
(157,910
|
)
|
|
—
|
|
Deferred income taxes
|
(5,270,856
|
)
|
|
4,090,919
|
|
|
575,235
|
|
Gain on derivative instruments, net
|
—
|
|
|
(29,758
|
)
|
|
(3,439,229
|
)
|
Noncash gain on Delhi field litigation settlement
|
—
|
|
|
—
|
|
|
(596,500
|
)
|
Write-off of deferred loan costs
|
—
|
|
|
—
|
|
|
50,414
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
Receivables
|
(1,215,214
|
)
|
|
(88,514
|
)
|
|
484,285
|
|
Prepaid expenses and other current assets
|
(136,835
|
)
|
|
(135,923
|
)
|
|
24,754
|
|
Accounts payable and accrued expenses
|
(107,081
|
)
|
|
(1,626,648
|
)
|
|
822,730
|
|
Income taxes payable
|
122,760
|
|
|
(621,850
|
)
|
|
431,818
|
|
Net cash provided by operating activities
|
20,536,577
|
|
|
16,490,857
|
|
|
30,653,193
|
|
Cash flows from investing activities
|
|
|
|
|
|
Derivative settlements received (paid)
|
—
|
|
|
(272,318
|
)
|
|
3,633,831
|
|
Development of oil and natural gas properties
|
(3,690,845
|
)
|
|
(10,158,960
|
)
|
|
(21,095,901
|
)
|
Capital expenditures for other property and equipment
|
(7,846
|
)
|
|
(32,260
|
)
|
|
(6,883
|
)
|
Other assets
|
(19,282
|
)
|
|
—
|
|
|
(161,345
|
)
|
Net cash used by investing activities
|
(3,717,973
|
)
|
|
(10,463,538
|
)
|
|
(17,630,298
|
)
|
Cash flows from financing activities
|
|
|
|
|
|
Proceeds from the exercise of stock options
|
—
|
|
|
—
|
|
|
51,000
|
|
Common share repurchases, including shares surrendered for tax withholding
|
(571,083
|
)
|
|
(459,858
|
)
|
|
(1,357,185
|
)
|
Common stock dividends paid
|
(11,594,541
|
)
|
|
(8,432,435
|
)
|
|
(6,565,823
|
)
|
Preferred stock dividends paid
|
—
|
|
|
(250,990
|
)
|
|
(674,302
|
)
|
Redemption of preferred shares
|
—
|
|
|
(7,932,975
|
)
|
|
—
|
|
Deferred loan costs
|
—
|
|
|
—
|
|
|
(168,972
|
)
|
Tax benefits related to stock-based compensation
|
—
|
|
|
—
|
|
|
9,650,657
|
|
Other
|
—
|
|
|
32
|
|
|
33
|
|
Net cash provided (used) by financing activities
|
(12,165,624
|
)
|
|
(17,076,226
|
)
|
|
935,408
|
|
Net increase (decrease) in cash, cash equivalents and restricted cash
|
4,652,980
|
|
|
(11,048,907
|
)
|
|
13,958,303
|
|
Cash, cash equivalents and restricted cash, beginning of year
|
23,028,153
|
|
|
34,077,060
|
|
|
20,118,757
|
|
Cash, cash equivalents and restricted cash, end of year
|
$
|
27,681,133
|
|
|
$
|
23,028,153
|
|
|
$
|
34,077,060
|
|
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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Years Ended June 30,
|
|
2018
|
|
2017
|
|
2016
|
Cash and cash equivalents
|
$
|
24,929,844
|
|
|
$
|
23,028,153
|
|
|
$
|
34,077,060
|
|
Restricted cash included in current assets
|
2,751,289
|
|
|
—
|
|
|
—
|
|
Total cash, cash equivalents and restricted cash shown in the statements of cash flows
|
$
|
27,681,133
|
|
|
$
|
23,028,153
|
|
|
$
|
34,077,060
|
|
See accompanying notes to consolidated financial statements.
Evolution Petroleum Corporation and Subsidiaries
Consolidated Statements of Changes in Stockholders' Equity
For the Years Ended
June 30, 2018
,
2017
and
2016
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred
|
|
Common Stock
|
|
|
|
|
|
|
|
|
|
Additional
Paid-in
Capital
|
|
Retained
Earnings
|
|
Treasury
Stock
|
|
Total
Stockholders'
Equity
|
|
Shares
|
|
Par Value
|
|
Shares
|
|
Par Value
|
|
Balance, June 30, 2015
|
317,319
|
|
|
$
|
317
|
|
|
32,845,205
|
|
|
$
|
32,845
|
|
|
$
|
36,847,289
|
|
|
$
|
11,696,126
|
|
|
$
|
—
|
|
|
$
|
48,576,577
|
|
Issuance of restricted common stock
|
—
|
|
|
—
|
|
|
272,098
|
|
|
272
|
|
|
(239
|
)
|
|
—
|
|
|
—
|
|
|
33
|
|
Exercise of stock options
|
—
|
|
|
—
|
|
|
50,000
|
|
|
50
|
|
|
127,450
|
|
|
—
|
|
|
—
|
|
|
127,500
|
|
Forfeitures of restricted stock
|
—
|
|
|
—
|
|
|
(40,758
|
)
|
|
(41
|
)
|
|
41
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Common share repurchases, including shares surrendered for tax withholding
|
—
|
|
|
—
|
|
|
(218,682
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(1,263,402
|
)
|
|
(1,263,402
|
)
|
Retirements of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(219
|
)
|
|
(1,263,183
|
)
|
|
—
|
|
|
1,263,402
|
|
|
—
|
|
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,809,548
|
|
|
—
|
|
|
—
|
|
|
1,809,548
|
|
Tax benefits related to stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
9,650,657
|
|
|
—
|
|
|
—
|
|
|
9,650,657
|
|
Net income attributable to the Company
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
24,660,362
|
|
|
—
|
|
|
24,660,362
|
|
Common stock cash dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(6,565,823
|
)
|
|
—
|
|
|
(6,565,823
|
)
|
Preferred stock cash dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(674,302
|
)
|
|
—
|
|
|
(674,302
|
)
|
Balance, June 30, 2016
|
317,319
|
|
|
317
|
|
|
32,907,863
|
|
|
32,907
|
|
|
47,171,563
|
|
|
29,116,363
|
|
|
—
|
|
|
76,321,150
|
|
Issuance of restricted common stock
|
—
|
|
|
—
|
|
|
227,889
|
|
|
228
|
|
|
(196
|
)
|
|
—
|
|
|
—
|
|
|
32
|
|
Exercise of stock options
|
—
|
|
|
—
|
|
|
35,231
|
|
|
35
|
|
|
77,121
|
|
|
—
|
|
|
—
|
|
|
77,156
|
|
Common share repurchases, including shares surrendered for tax withholding
|
—
|
|
|
—
|
|
|
(83,675
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(537,014
|
)
|
|
(537,014
|
)
|
Retirements of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(83
|
)
|
|
(536,931
|
)
|
|
—
|
|
|
537,014
|
|
|
—
|
|
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,180,618
|
|
|
—
|
|
|
—
|
|
|
1,180,618
|
|
Redemption of preferred shares
|
(317,319
|
)
|
|
(317
|
)
|
|
—
|
|
|
—
|
|
|
(6,930,218
|
)
|
|
(1,002,440
|
)
|
|
—
|
|
|
(7,932,975
|
)
|
Net income attributable to the Company
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
8,044,313
|
|
|
—
|
|
|
8,044,313
|
|
Common stock cash dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(8,432,435
|
)
|
|
—
|
|
|
(8,432,435
|
)
|
Preferred stock cash dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(250,990
|
)
|
|
—
|
|
|
(250,990
|
)
|
Balance, June 30, 2017
|
—
|
|
|
—
|
|
|
33,087,308
|
|
|
33,087
|
|
|
40,961,957
|
|
|
27,474,811
|
|
|
—
|
|
|
68,469,855
|
|
Issuance of restricted common stock
|
—
|
|
|
—
|
|
|
183,537
|
|
|
183
|
|
|
(183
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
Forfeitures of restricted stock
|
—
|
|
|
—
|
|
|
(117,094
|
)
|
|
(117
|
)
|
|
117
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Common share repurchases, including shares surrendered for tax withholding
|
—
|
|
|
—
|
|
|
(73,208
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(571,083
|
)
|
|
(571,083
|
)
|
Retirements of treasury stock
|
—
|
|
|
—
|
|
|
—
|
|
|
(73
|
)
|
|
(571,010
|
)
|
|
—
|
|
|
571,083
|
|
|
—
|
|
Stock-based compensation
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
1,366,764
|
|
|
—
|
|
|
—
|
|
|
1,366,764
|
|
Net income attributable to the Company
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
19,618,484
|
|
|
—
|
|
|
19,618,484
|
|
Common stock cash dividends
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(11,594,541
|
)
|
|
—
|
|
|
(11,594,541
|
)
|
Balance, June 30, 2018
|
—
|
|
|
$
|
—
|
|
|
33,080,543
|
|
|
$
|
33,080
|
|
|
$
|
41,757,645
|
|
|
$
|
35,498,754
|
|
|
$
|
—
|
|
|
$
|
77,289,479
|
|
See accompanying notes to consolidated financial statements.
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 CO
2
enhanced oil recovery project in Louisiana's Delhi field.
Principles of Consolidation and Reporting.
Our consolidated financial statements include the accounts of EPM 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,
2018
and
2017
, 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,
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, 2018
,
2017
or
2016
.
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 based on 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. We use the Black-Scholes option-pricing model to determine grant date fair value of any Stock Option or Incentive Warrant awards. 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.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Revenue Recognition - Oil and Gas.
We recognize oil and natural gas revenue from our interests in producing wells at the time that title passes to the purchaser. As a result, we accrue revenues related to production sold for which we have not received payment.
Revenue Recognition - Artificial Lift Technology.
Our artificial lift technology operations have generated revenues under contractual arrangements. Under these contracts, we were required to bear part or all of the incremental installation and capital costs for the technology. We evaluated the substance of each contractual arrangement and recognized revenues over the life of the contract as the earnings process is determined to be complete. We likewise charge our costs, including both capital expenditures and operating expenses, to operating costs in a manner which either matches these costs to the timing of expected revenues, where appropriate, or charges these costs to the accounting period in which they were incurred where it is not appropriate to capitalize or defer them to match with revenues.
Derivative Instruments.
The Company has used and may continue to use derivative transactions to reduce its exposure to oil, natural gas or NGL price volatility. All derivative instruments are recorded on the consolidated balance sheet as either an asset or liability measured at fair value. The Company nets its fair value amounts for derivative instruments executed with the same counterparty, where such transactions are covered by an ISDA master agreement that provides for net settlement over the term of the contract and in the event of default or termination of the contract. Although the derivative instruments are intended to provide an economic hedge of the Company’s exposure to commodity price volatility, the Company has not attempted to qualify its derivative instruments for hedge accounting treatment. As a result, changes in the fair value of derivative instruments are recognized as gains or losses in the consolidated statements of operations in the period in which the changes occur. The net cash flows resulting from the payments to and receipts from counterparties as a result of derivative settlements are classified as cash flows from investing activities rather than operating activities. The Company does not intend to enter into derivative instruments for speculative or trading purposes.
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.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Recently Adopted Accounting Pronouncements.
In November 2016, the FASB issued ASU 2016-18, Statement of Cash Flows (Topic 230) (“ASU 2016-18”). ASU 2016-18 addresses the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows, and requires that a statement of cash flows explain the change in total cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, entities will no longer present transfers between cash and cash equivalents and restricted cash and restricted cash equivalents in the statement of cash flows. This guidance is effective for fiscal years beginning after December 15, 2017, including interim periods within the year of adoption, with early adoption permitted. The Company retrospectively early adopted this guidance on April 1, 2018. ASU 2016-18 had no impact on the consolidated statements of cash flows for the previously reported interim periods of our current fiscal year and for prior fiscal year consolidated statements of cash flows presented in this annual report on Form 10-K.
New Accounting Pronouncements Not Yet Adopted.
In May 2014, the FASB issued ASU No. 2014-09, Revenue from Contracts with Customers (Topic 606), which will supersede most of the existing revenue recognition standards and will require entities to recognize revenue at an amount that reflects the consideration to which it expects to be entitled in exchange for transferring goods or services to a customer. The new standard also requires disclosures that are sufficient to enable users to understand an entity’s nature, amount, timing, and uncertainty of revenue and cash flows arising from contracts with customers.
In March 2016, the FASB issued ASU 2016-08, Revenue from Contracts with Customers (Topic 606): Principal versus Agent Considerations (Reporting Revenue Gross versus Net). This update provides clarifications in the assessment of principal versus agent considerations in the new revenue standard. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow Scope Improvements and Practical Expedients. The update reduces the potential for diversity in practice at initial application of Topic 606 and the cost and complexity of applying Topic 606. In December 2016, the FASB issued ASU 2016-20, Technical Corrections and Improvements to Topic 606, Revenue from Contracts with Customers. The update was issued to increase stakeholders’ awareness of the proposals for technical corrections and to expedite improvements.
The Company will adopt these updates effective July 1, 2018, using the full retrospective approach, meaning any cumulative effect of initially applying the standard is recognized in the earliest period presented in the financial statements. The Company has finalized the detailed analysis of its contracts and of the impact of the standard on its contracts and found that there was no significant impact on its financial position or results of operations. Upon adoption of this standard, the Company will not be required to record a cumulative effect adjustment as the new standard does not have a quantitative impact on net income compared to existing generally accepted accounting principles. Also, upon adoption of the standard, the Company will not be required to alter its existing information technology and internal controls outside of ongoing contract review processes to identify impacts of future revenue contracts entered into by the Company. The Company does not anticipate the disclosure requirements under the new updates will have a material change on how it presents information regarding its revenue streams as compared to existing generally accepted accounting principles although certain revenue streams under the new standard will be presented on a net rather than gross basis.
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. These changes become effective for fiscal years beginning after December 15, 2018. The expected adoption method of ASU 2016-01 is being evaluated by the Company and the adoption is not expected to have a significant impact on the Company’s consolidated financial position or results of operations.
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. We are evaluating the impact the adoption of ASU 2016-02 will have on our consolidated financial statements.
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”), 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. The Company will retrospectively adopt ASU 2016-15 on July 1, 2018, and does not expect its adoption to have a material effect on its consolidated statements of cash flows.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”), 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 adopt ASU 2017-01 effective July 1, 2018 on a prospective basis.
Note 3 – Enduro Purchase and Sale Agreement and Related Subsequent Events
As previously disclosed, the Company entered into a Purchase and Sale Agreement ("PSA") on May 15, 2018, 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 is reflected in restricted cash together with earned interest on the Company's
June 30, 2018
statement of financial position. On July 20, 2018, the Company was repaid its deposit together with related earned interest as a higher bidder emerged in the Chapter 11 bidding process.
The Company's initial and subsequent bids represented offers under Section 363 of the U.S. Bankruptcy Code in connection with the Chapter 11 filing of Enduro and certain of its affiliates. 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. The PSA provided the Company with certain important protections in this process, including return of the escrowed deposit and payment to the Company of a
$1.1 million
break-up fee upon the closing of a higher bidder's purchase transaction. In connection with the PSA, the Company incurred third party due diligence expenses of
$0.4 million
, which were reflected in the Company's consolidated statement of operations for the year ended June 30, 2018. The full amount of the break-up fee was paid in late August 2018.
Note 4 – Receivables
As of
June 30, 2018
and
June 30, 2017
our receivables consisted of the following:
|
|
|
|
|
|
|
|
|
|
June 30,
2018
|
|
June 30,
2017
|
Receivables from oil and gas sales
|
$
|
3,940,998
|
|
|
$
|
2,722,880
|
|
Other
|
918
|
|
|
3,822
|
|
Total receivables
|
$
|
3,941,916
|
|
|
$
|
2,726,702
|
|
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, 2018
and
June 30, 2017
our prepaid expenses and other current assets consisted of the following:
|
|
|
|
|
|
|
|
|
|
June 30,
2018
|
|
June 30,
2017
|
Prepaid insurance
|
$
|
198,558
|
|
|
$
|
169,416
|
|
Prepaid federal and state income taxes
|
231,920
|
|
|
121,232
|
|
Retainers and deposits
|
11,089
|
|
|
7,553
|
|
Other prepaid expenses
|
82,940
|
|
|
89,471
|
|
Prepaid expenses and other current assets
|
$
|
524,507
|
|
|
$
|
387,672
|
|
EVOLUTION PETROLEUM CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 6 – Property and Equipment
As of
June 30, 2018
and
June 30, 2017
, our oil and natural gas properties and other property and equipment consisted of the following:
|
|
|
|
|
|
|
|
|
|
June 30,
2018
|
|
June 30,
2017
|
Oil and natural gas properties:
|
|
|
|
Property costs subject to amortization
|
$
|
90,392,918
|
|
|
$
|
84,962,933
|
|
Less: Accumulated depreciation, depletion, and amortization
|
(29,153,172
|
)
|
|
(23,172,865
|
)
|
Unproved properties not subject to amortization
|
—
|
|
|
—
|
|
Oil and natural gas properties, net
|
61,239,746
|
|
|
61,790,068
|
|
Other property and equipment:
|
|
|
|
Furniture, fixtures and office equipment, at cost
|
143,223
|
|
|
135,377
|
|
Less: Accumulated depreciation
|
(112,816
|
)
|
|
(94,688
|
)
|
Other property and equipment, net
|
$
|
30,407
|
|
|
$
|
40,689
|
|