Executive Overview



  Liquidity and Capital Resources

  Results of Operations

  Critical Accounting Policies

                               Executive Overview

General

Evolution Petroleum Corporation is an independent energy company focused on
maximizing total returns to its shareholders through the ownership of and
investment in onshore oil and natural gas properties in the United States. In
support of that objective, our long-term goal is to maximize total shareholder
return from a diversified portfolio of long-life oil and natural gas properties
built through acquisitions and through selective development opportunities,
production enhancements, and other exploitation efforts on our oil and natural
gas properties.

Our oil and natural gas properties consist of non-operated interests in the
Delhi Holt-Bryant Unit in the Delhi Field in Northeast Louisiana, a CO2 enhanced
oil recovery ("EOR") project; non-operated interests in the Hamilton Dome Field
located in Hot Springs County, Wyoming, a secondary recovery field utilizing
water injection wells to pressurize the reservoir; non-operated interests in the
Barnett Shale located in North Texas, a natural gas producing property;
non-operated interests in the Williston Basin in North Dakota, a producing oil
and natural gas property; non-operated interests in the Jonah Field in Sublette
County, Wyoming, a natural gas producing field; and small overriding royalty
interests in four onshore central Texas wells.

Our non-operated interests in the Delhi Field, a CO2-EOR project, consist of
approximately 24% average net working interest, with an associated 19% revenue
interest and separate overriding royalty and mineral interests of approximately
7% yielding a total average net revenue interest of approximately 26%. The field
is operated by Denbury Onshore LLC ("Denbury"). The Delhi Field is located in
northeast Louisiana in Franklin, Madison, and Richland Parishes and encompasses
approximately 14,000 gross unitized acres, or approximately 3,200 net acres.

Our non-operated interests in the Hamilton Dome Field, a secondary recovery
field utilizing water injection wells to pressurize the reservoir, consists of
approximately 24% average net working interest, with an associated 20% average
net revenue interest (inclusive of a small overriding royalty interest). The
approximately 5,900 gross acre unitized field, of which we hold approximately
1,400 net acres, is operated by Merit Energy Company ("Merit"), who owns the
vast majority of the remaining working interest in the Hamilton Dome Field. The
Hamilton Dome Field is located in the southwest region of the Big Horn Basin in
northwest Wyoming.

Our non-operated interests in the Barnett Shale, a natural gas producing shale
reservoir, consists of approximately 17% average net working interest with an
associated 14% average net revenue interest (inclusive of small overriding
royalty interests). The approximately 21,000 net acres are held by production
across nine North Texas counties. The oil and natural gas properties are
primarily operated by Diversified Energy Company with approximately 10% of wells
operated by seven other operators.

On January 14, 2022, we acquired non-operated working interests in 73 producing
wells in the Williston Basin with an average net working interest of
approximately 39% and average net revenue interest of approximately 33% located
on approximately 45,000 net acres (approximately 90% held by production) across
Billings, Golden Valley, and McKenzie Counties in North Dakota (the "Williston
Basin Acquisition"). After taking into account customary closing adjustments and
an effective date of June 1, 2021, cash consideration was $25.2 million which
includes $0.3 million of transaction costs related to the acquisition. The
properties are operated by Foundation Energy Management ("Foundation"), an
established operator in the geographic region.

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On April 1, 2022, we acquired non-operated working interests in the Jonah Field
in Sublette County, Wyoming (the "Jonah Field Acquisition"). After taking into
account the deposit on the acquisition, customary closing adjustments and an
effective date of February 1, 2022, cash consideration at closing was $26.4
million (including $0.2 million of transaction costs). The acquired properties
include an average net working interest of approximately 20% and an average net
revenue interest of approximately 15% in 595 producing wells and 950 net acres.
The properties are operated by Jonah ("Jonah"), an established operator in

the
geographic region.

Recent Developments

Dividend Declaration and Share Repurchase Program


On September 12, 2022, Evolution's Board of Directors approved and declared a
quarterly dividend of $0.12 per common share payable September 30, 2022. This
represents a 20% increase over the $0.10 per common share dividend paid in the
fourth quarter of fiscal year 2022. Also, on September 8, 2022, the Board of
Directors authorized a share repurchase program, under which we are approved to
repurchase up to $25 million of our common stock through December 31, 2024. We
intend to fund repurchases from available working capital and cash provided by
operating activities. As we continue to focus on our goal of maximizing total
shareholder return, the Board of Directors along with the management team
believe that a share repurchase program is complimentary to the existing
dividend policy and is a tax efficient means to further improve shareholder
return. The shares may be repurchased from time to time in open market
transactions, through privately negotiated transactions or by other means in
accordance with federal securities laws. The timing, as well as the number and
value of shares repurchased under the program, will depend on a variety of
factors, including management's assessment of the intrinsic value of our shares,
the market price of our common stock, general market and economic conditions,
and applicable legal requirements. The value of shares authorized for repurchase
by our Board of Directors does not require us to repurchase such shares or
guarantee that such shares will be repurchased, and the program may be
suspended, modified, or discontinued at any time without prior notice.

Highlights for our Fiscal Year 2022 and Operations Update

? Generated revenue of $108.9 million and net income of $32.6 million.

? Production averaged 5,953 net BOEPD.

Returned to shareholders $11.8 million in cash dividends. We have paid out to

? shareholders more than $86.3 million in cash dividends since inception of the

dividend program in December 2013.

? Funded all operations, development capital expenditures, and dividends out of

operating cash flow.

Closed the Jonah Field Acquisition on April 1, 2022 and the Williston Basin

Acquisition on January 14, 2022, which included total proved reserves of 7.1

? MMBOE and 6.1 MMBOE, respectively, as of June 30, 2022 as estimated by

Netherland, Sewell & Associates, Inc. ("NSAI") an independent reservoir

engineering firm.

Increased proved reserves 55% since prior year-end primarily due to the

? acquisitions of the Jonah Field properties in April 2022 and Williston Basin

properties in January 2022.

? Maintained a strong financial position with low leverage.

Proved Reserves



Proved oil equivalent reserves as of June 30, 2022 were 36.2 MMBOE, a 55%
increase from the previous year primarily due to the acquisitions of properties
in the Williston Basin and Jonah Field in January 2022 and April 2022,
respectively. The Standardized Measure for proved reserves increased 259% to
$314.8 million, primarily due to the acquisitions of

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properties in the Williston Basin and Jonah Field and an increase in the SEC
mandated trailing 12-month average first day of the month prices for oil and
natural gas. Prices increased from $49.72 per barrel of oil, $2.46 per MMBtu of
natural gas and $19.81 per barrel of NGLs at June 30, 2021 to $85.82 per barrel
of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs at June 30,
2022. Our proved reserves consist of 32% oil, 49% natural gas, and 19% NGLs; 90%
are classified as proved developed producing and 10% are proved undeveloped.

The following table is a summary of our proved reserves as of June 30, 2022 and
2021:

                                Proved Reserves
                                2022         2021      Change
Reserves MMBOE                     36.2       23.4        55 %
% Developed                          90 %       92 %     (2) %
Liquids %                            51 %       65 %    (14) %
Standardized Measure ($MM)    $   314.8     $ 87.6       259 %


Additional property and project information is included under Item 1. Business
and in Note 5, "Property and Equipment" and our Supplemental Disclosure about
Oil and Natural Gas Properties (unaudited) to our consolidated financial
statements in Item 8. Financial Statements and Supplementary Data, and in
Exhibit 99.1 and 99.2 of this Form 10-K.

At June 30, 2022, we had total net proved reserves of 36.2 MMBOE, a 12.8 MMBOE
increase from the previous year of 23.4 MMBOE. The net increase in total proved
reserves was the result of acquisitions of 9.3 MMBOE, additions and extensions
of 3.6 MMBOE and net positive revisions of 2.1 MMBOE, partially offset by
production of 2.2 MMBOE. Net positive revisions of 2.1 MMBOE increased primarily
due to improvement in SEC trailing 12-month pricing partially offset by the
removal of 1.8 MMBOE of PUDs related to Test Site V and 0.7 MMBOE of PDP at our
Delhi Field property.

Impact of the COVID-19 Pandemic and Geopolitical factors

The global economy has been deeply impacted by the effects of the novel coronavirus ("COVID-19") pandemic and related efforts to mitigate the spread of the disease. These events led to crude oil prices falling to historic lows during the second quarter of 2020 and remaining depressed through much of 2020.


In 2021, the demand for oil and natural gas began to recover primarily as a
result of the roll-out of the COVID-19 vaccine and lessening of pandemic related
government restrictions on individuals and businesses. In addition, the recent
special military operation of Russia into Ukraine and the subsequent sanctions
imposed on Russia and other actions have created significant market
uncertainties, including uncertainties around potential supply disruptions for
oil and natural gas, which has further enhanced volatility in global commodity
prices in the first half of 2022. Given the dynamic nature of these events, we
cannot reasonably estimate the period of time that these market conditions will
persist.

Currently, none of our oil and natural gas properties are operated by us. As a
result, in the past we have had limited ability to influence or control the
operation or future development of such properties. Despite these uncertainties,
we remain focused on our long-term objectives and continue to be proactive with
our third-party operators to review capital expenditures and alter plans as
appropriate to increase shareholder value.

                        Liquidity and Capital Resources

As of June 30, 2022, we had $8.3 million in cash and cash equivalents compared
to $5.3 million at June 30, 2021. Our primary sources of liquidity and capital
resources during the year ended June 30, 2022 were cash provided by operations
as well as net borrowings under our Senior Secured Credit Facility. Our primary
uses of liquidity and capital resources for the year ended June 30, 2022 were
acquisitions of oil and natural gas properties and cash dividend payments to our
common stockholders. As of June 30, 2022, working capital was $6.1 million, a
decrease of $5.4 million from working capital of $11.5 million as of June 30,
2021.

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The Senior Secured Credit Facility has a maximum capacity of $50.0 million
subject to a borrowing base determined by the lender based on the value of our
oil and natural gas properties. The Senior Secured Credit Facility has a current
borrowing base of $50.0 million, with $21.3 million drawn as of June 30, 2022.
Since year-end, we have paid down another $9.0 million under our Senior Secured
Credit Facility and as of August 31, 2022, we have $12.3 million outstanding.
The Senior Secured Credit Facility is secured by substantially all of our
reserves associated with our oil and natural gas properties and matures on
April 9, 2024.

Any future borrowings bear interest, at our option, at either the London
Interbank Offered Rate ("LIBOR") plus 2.75% or the Prime Rate, as defined under
the Senior Secured Credit Facility, plus 1.0%. The Senior Secured Credit
Facility contains covenants requiring the maintenance of (i) a total leverage
ratio of not more than 3.00 to 1.00, (ii) a current ratio of not less than 1.00
to 1.00, and (iii) a consolidated tangible net worth of not less than $40.0
million, each as defined in the Senior Secured Credit Facility. It also contains
other customary affirmative and negative covenants and events of default. As of
June 30, 2022, we were in compliance with all covenants under the Senior Secured
Credit Facility.

We are currently working on our annual redetermination with MidFirst Bank. We
expect that our borrowing base will remain at $50.0 million and the Margined
Collateral Value, as defined in the Ninth Amendment to the Senior Secured Credit
Facility, will be set at $125.0 million. We are required to enter into hedges on
a rolling 12-month basis when the borrowings under the Senior Secured Credit
Facility exceed 25% of the Margined Collateral Value. Based on the current
amount outstanding, the utilization percentage under the required hedging
covenant is below the minimum utilization threshold of 25% and as a result we
are not required to enter into additional hedges at this time. At each
redetermination, our Margined Collateral Value takes into account the estimated
value of our oil and natural gas properties, proved developed reserves, total
indebtedness, and other relevant factors consistent with customary oil and
natural gas lending criteria.

On February 7, 2022, we entered into the Ninth Amendment to the Senior Secured
Credit Facility. This amendment, among other things, modified the definition of
utilization percentage related to the required hedging covenant such that for
the purposes of determining the amount of future production to hedge, the
utilization of the Senior Secured Credit Facility will be based on the Margined
Collateral Value, as defined in the agreement, to the extent it exceeds the
borrowing base then in effect. This amendment also required us to enter into
hedges for the next 12-month period ending February 2023, covering 25% of
expected oil and natural gas production over that period.

On November 9, 2021, we entered into the Eighth Amendment to the Senior Secured
Credit Facility. This amendment, among other things, increased the borrowing
base to $50.0 million and added a hedging covenant whereby we must hedge a
certain amount of our future production on a rolling 12-month basis when 25% or
more of the borrowing base is utilized. The hedging covenant was amended in the
Ninth Amendment, as discussed above.

On August 5, 2021, we entered into the Seventh Amendment of our Senior Secured
Credit Facility which, among other things, added definitions for the terms
"Acquired Entity or Mineral Interests" and "Acquired Entity or Mineral Interests
EBITDA Adjustment." Additionally, the consolidated tangible net worth covenant
level was reduced to $40.0 million from $50.0 million.

We have historically funded operations through cash from operations and working
capital. The primary source of cash is the sale of produced crude oil, natural
gas, and NGLs. A portion of these cash flows is used to fund capital
expenditures and pay cash dividends to shareholders. We expect to manage
near-future development activities for our properties with cash flows from
operating activities and existing working capital.

We are pursuing new growth opportunities through acquisitions and other
transactions. In addition to cash on hand, we have access to the undrawn portion
of the borrowing base available under our Senior Secured Credit Facility. We
also have an effective shelf registration statement with the SEC under which we
may issue up to $500.0 million of new debt or equity securities.

The Board of Directors instituted a cash dividend on common stock in December 2013. We have since paid 35 consecutive quarterly dividends. Distribution of a substantial portion of free cash flow in excess of operating and capital requirements through cash dividends remains a priority of our financial strategy, and it is our long-term goal to increase



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dividends over time, as appropriate. During the industry downturn primarily due
to COVID-19, effective in the quarter ended June 30, 2020, the Board of
Directors adjusted the quarterly dividend rate from $0.10 per share to $0.025
per share. The reduction in the dividend rate at that time allowed us to
conserve cash for additional financial flexibility while continuing to reward
shareholders with a yield of approximately 3% at the then current stock price
levels. In light of our improving financial performance and industry outlook,
the Board of Directors has since increased the dividend rate, with the most
recent increase occurring on September 12, 2022, when the Board of Directors
declared a dividend of $0.12 per share payable on September 30, 2022.

Also, on September 8, 2022, our Board of Directors authorized a share repurchase
program, under which we are approved to repurchase up to $25 million of our
common stock through December 31, 2024. We intend to fund any repurchases from
working capital and cash provided by operating activities. As we continue to
focus on our goal of maximizing total shareholder return, the Board of Directors
along with the management team believe that a share repurchase program is
complimentary to the existing dividend policy and is a tax efficient means to
further improve shareholder return. Refer to Note 15, "Subsequent Events," for a
further discussion of our share repurchase program.

Capital Expenditures



For the year ended June 30, 2022, we incurred $2.6 million on development
capital expenditures, $26.4 million for the Jonah Field Acquisition (net of
customary purchase price adjustments, excluding $3.0 million in non-cash asset
retirement obligations), and $25.2 million for the Williston Basin Acquisition
(net of customary purchase price adjustments, excluding $2.4 million in non-cash
asset retirement obligations) and less than $0.1 million at the Delhi Field and
Hamilton Dome Field, for plugging and abandoning costs.

Based on discussions with our operators, we expect capital workover projects to
continue in all the fields. At Delhi Field, we anticipate capital costs for a
NGL plant heat exchanger project which is currently underway. Overall, for
fiscal year 2023, we expect budgeted capital expenditures to be in the range of
$6.5 million to $9.5 million, which excludes any potential acquisitions. Our
expected capital expenditures for the next 12 months include Foundation, the
operator of our Williston Basin properties, drilling two sidetrack locations
targeting the Birdbear formation. Our fiscal year 2023 budget does not include
any capital expenditures for drilling at our Pronghorn and Three Forks
locations.

As of June 30, 2022, our PUD reserves included 3.6 MMBOE of reserves and approximately $61.7 million of future development costs associated with the Williston Basin properties.



Funding for our anticipated capital expenditures over the near-term is expected
to be met from cash flows from operations and current working capital, as well
as borrowings under our Senior Secured Credit Facility as needed for future
acquisitions or development of PUD reserves at our Pronghorn and Three Forks
locations.

Full Cost Pool Ceiling Test

As of June 30, 2022, our capitalized costs of oil and natural gas properties
were below the full cost valuation ceiling; however, we could experience an
impairment if commodity price levels were to substantially decline. Lower
commodity prices would reduce the excess, or cushion, of our valuation ceiling
over our capitalized costs and may adversely impact our ceiling tests in future
quarters. We cannot give assurance that a write-down of capitalized oil and
natural gas properties will not be required in the future. Under the full cost
method of accounting, capitalized costs of oil and natural gas properties, net
of accumulated depletion, depreciation, and amortization and related deferred
taxes, are limited to the estimated future net cash flows from proved oil and
natural gas reserves, discounted at 10%, plus the lower of cost or fair value of
unproved properties, as adjusted for related income tax effects (the valuation
"ceiling"). If capitalized costs exceed the full cost ceiling, the excess would
be charged to expense as a write-down of oil and natural gas properties in the
quarter in which the excess occurred. The quarterly ceiling test calculation
requires that we use the average first day of the month price for our petroleum
products during the 12-month period ending with the balance sheet date. The
prices used in calculating our ceiling test as of June 30, 2022 were $85.82 per
barrel of oil, $5.19 per MMBtu of natural gas and $44.24 per barrel of NGLs. At
December 31, 2020 and September 30, 2020, we recorded ceiling test impairment
charges of $15.2 million and $9.6 million, respectively. The ceiling test
impairments were driven by decreases in the first-day-of-the-month average price
for oil used in the ceiling test calculation. At June 30, 2022, a 10% decrease
in commodity

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prices used to determine our proved reserves would not have resulted in an impairment of our oil and natural gas properties.



                                      Twelve-Month Period Ended:
                6/30/2021      9/30/2021      12/31/2021      3/31/2022      6/30/2022
Crude Oil      $     49.72    $     57.64    $      66.55    $     75.28    $     85.82
Natural Gas    $      2.46    $      2.97    $       3.64    $      4.15    $      5.19

Overview of Cash Flow Activities



                                                           Years Ended June

30,


                                                            2022           2021         Change
Cash flows provided by operating activities              $    52,460    $    4,733    $   47,727
Cash flows used in investing activities                     (54,873)      (18,769)      (36,104)
Cash flows provided by (used in) financing activities          5,416

(349) 5,765 Net increase (decrease) in cash and cash equivalents $ 3,003 $ (14,385) $ 17,388

Cash provided by operating activities increased $47.7 million during the fiscal year ended June 30, 2022 compared to fiscal year ended June 30, 2021 primarily due to an increased average daily production and an approximate $13.26 per BOE average realized price increase which both contributed to higher revenues in fiscal year 2022.


Cash used in investing activities increased $36.1 million primarily due to the
acquisition of the Jonah Field properties in April 2022 totaling $26.4 million
(net of customary purchase price adjustments) and Williston Basin properties in
January 2022 totaling $25.8 million (net of customary purchase price
adjustments), compared to the acquisition of the Barnett Shale properties in
May 2021 for $18.3 million (net of customary purchase price adjustments). In
addition, capital expenditures increased $1.0 million in fiscal year 2022 due to
increased capital workovers for certain return-to-production projects now viable
with the increase in commodity prices.

Net cash flows provided by financing activities were $5.4 million for the year
ended June 30, 2022, compared to $0.3 million of net cash flows used in
financing activities for the year ended June 30, 2021. As of June 30, 2021, we
had borrowings of $4.0 million outstanding under our Senior Secured Credit
Facility. During the year ended June 30, 2022, we increased these borrowings by
a net $17.3 million, ending the year with $21.3 million outstanding under the
Senior Secured Credit Facility. In fiscal year 2022, we used cash of $11.8
million for dividends paid to our common stockholders compared to $4.3 million
in fiscal year 2021.

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                             Results of Operations

                       Years Ended June 30, 2022 and 2021

We reported net income of $32.6 million for the year ended June 30, 2022 compared to a net loss of $16.4 million for the year ended June 30, 2021. The following table summarizes the comparison of financial information for the periods presented:



                                        Years Ended June 30,
(in thousands, except per unit and
per BOE amounts)                         2022           2021        Variance      Variance %
Net income (loss)                     $    32,628    $ (16,438)    $   49,066      (298.5) %
Revenues:
Crude oil                                  52,683        26,411        26,272         99.5 %
Natural gas                                39,174         2,629        36,545      1,390.1 %
Natural gas liquids                        17,069         3,662        13,407        366.1 %
Total Revenue                             108,926        32,702        76,224        233.1 %
Operating costs:
Lease operating costs:
CO2 costs                                   7,708         3,062         4,646        151.7 %
Ad valorem and production taxes             6,960         1,280         5,680        443.8 %
Other lease operating costs                33,989        12,245        21,744        177.6 %
Depletion, depreciation, and
amortization:
Depletion of full cost proved oil
and gas properties                          7,518         4,903         2,615         53.3 %
Depreciation of other property and
equipment                                       4             7           (3)       (42.9) %
Amortization of intangibles                     -            47          (47)      (100.0) %
Accretion of asset retirement
obligations                                   531           210           321        152.9 %
Impairment of proved property                   -        24,792      (24,792)      (100.0) %
Impairment of Well Lift Inc. -
related assets                                  -           146         (146)      (100.0) %
General and administrative:
General and administrative                  6,710         5,496         1,214         22.1 %
Stock-based compensation                      125         1,258       (1,133)       (90.1) %
Other Income (expenses):
Net gain (loss) on derivative
contracts                                 (3,763)         (615)       (3,148)        511.9 %
Interest and other income                      95            40            55        137.5 %
Interest expense                            (572)         (103)         (469)        455.3 %
Income tax (expense) benefit              (8,513)         4,984      (13,497)      (270.8) %

Production:
Crude oil (MBBL)                              619           555            64         11.5 %
Natural gas (MMCF)                          7,141           963         6,178        641.5 %
Natural gas liquids (MBBL)                    364           171           193        112.9 %
Equivalent (MBOE)(1)                        2,173           887         1,286        145.0 %
Average daily production
(BOEPD)(1)                                  5,953         2,430         3,523        145.0 %

Average price per unit(2):
Crude oil (BBL)                       $     85.11    $    47.59    $    37.52         78.8 %
Natural gas (MCF)                            5.49          2.73          2.76        101.1 %
NGL (BBL)                                   46.89         21.42         25.47        118.9 %
Equivalent (BOE)(1)                         50.13         36.87         13.26         36.0 %

Average cost per unit:
Operating costs:
Lease operating costs:
CO2 costs                             $      3.55    $     3.45          0.10          2.9 %
Ad valorem and production taxes              3.20          1.44          1.76        122.2 %
Other lease operating costs                 15.64         13.80          1.84         13.3 %
Depletion of full cost proved oil
and gas properties                           3.46          5.53        (2.07)       (37.4) %
General and administrative:
General and administrative                   3.09          6.20        (3.11)       (50.2) %
Stock-based compensation                     0.06          1.42        (1.36)       (95.8) %

(1) Equivalent oil reserves are defined as six MCF of natural gas and 42 gallons

of NGLs to one barrel of oil conversion ratio which reflects energy

equivalence and not price equivalence. Natural gas prices per MCF and NGL

prices per barrel often differ significantly from the equivalent amount of

oil.

(2) Amounts exclude the impact of cash paid or received on the settlement of


    derivative contracts since we did not elect to apply hedge accounting.


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Revenues

Fiscal year ended June 30, 2022 revenues increased 233.1% to $108.9 million
compared to $32.7 million for the fiscal year ended June 30, 2021. The increase
in revenue is primarily due to a 145% increase in average daily equivalent
production from 2,430 BOEPD to 5,953 BOEPD due the addition of the Jonah Field
Acquisition in April 2022, Williston Basin Acquisition in January 2022, and
Barnett Shale Acquisition in May 2021, which increased current fiscal year
production by approximately 518 BOEPD, 241 BOEPD, and 2,847 BOEPD, respectively.
In addition, our average realized commodity prices (excluding the impact of
derivative contracts) increased approximately $13.26 per BOE, or 36%, for the
fiscal year ended June 30, 2022 compared to June 30, 2021. Oil and natural gas
prices are inherently volatile and began to stabilize in 2021 and continuing
into 2022. Our average realized oil price was higher primarily due to the
recovery of WTI pricing in 2022, as the demand for oil has begun to recover
primarily as a result of the roll-out of the COVID -19 vaccines, lessening of
pandemic related government restrictions on individuals and businesses, and
sanctions affecting Russian oil and natural gas supplies.

Lease Operating Costs



The following table summarizes CO2 costs per Mcf and CO2 volumes for the years
ended June 30, 2022 and 2021. CO2 purchase costs are for the Delhi Field. Under
our contract with the Delhi Field operator, purchased CO2 is priced at 1% of the
realized oil price in the field per Mcf, plus sales taxes and transportation
costs as per contract terms.

                                               Years Ended June 30,
                                            2022                    2021        Variance     Variance %
CO2 costs per MCF                       $        1.07             $    0.71    $     0.36        50.7 %

CO2 volumes (MMCF per day, gross)                82.6                  49.1

33.5 68.2 %




The $4.6 million increase in CO2 costs for the fiscal year ended June 30, 2022
was primarily due to a 68.2% increase in purchased CO2 volumes combined with a
50.7% increase in CO2 costs per MCF, which was driven by a 78.8% increase in our
average realized oil price. The increase in purchased CO2 volumes is due to the
completion of preventative maintenance on the pipeline that supplies newly
purchased CO2 to the Delhi Field which resulted in temporary suspension of CO2
purchases for the three months ended September 30, 2021. Additionally, CO2
purchase nominations increased throughout fiscal year 2022 to compensate for
reduced reservoir pressure. CO2 purchases provide approximately 20% of the
injected volumes in the field and the field's recycle facilities provide the
other 80%. The pipeline is owned and operated by Denbury and we do not have any
ownership in the pipeline. On a per unit basis, CO2 costs were $3.55 per BOE and
$3.45 per BOE for the years ended June 30, 2022 and 2021, respectively.

Ad valorem and production taxes were $7.0 million and $1.3 million for the years
ended June 30, 2022 and 2021, respectively. On a per unit basis, ad valorem and
production taxes were $3.20 per BOE and $1.44 per BOE for the years ended
June 30, 2022 and 2021, respectively. The increase in ad valorem and production
taxes is primarily due to increases in oil and natural gas prices and increased
production volumes described above as production taxes are based on sales at the
wellhead.

Compared to fiscal year ended June 30, 2021, other lease operating costs
increased 177.6% primarily due to the Jonah Field Acquisition in April 2022,
Williston Basin Acquisition in January 2022 and Barnett Shale Acquisition in
May 2021. Other lease operating costs per BOE for our Jonah Field, Williston
Basin and Barnett Shale properties were approximately $10.69 per BOE, $21.86 per
BOE and $14.70 per BOE, respectively, for the years ended June 30, 2022. Other
lease operating costs for the Delhi and Hamilton Dome fields increased $0.8
million and $0.9 million, respectively, due to higher labor, electricity and
chemical expenses during the year ended June 30, 2022.

Depletion expense increased $2.6 million or 53.3% from $4.9 million for the
fiscal year ended June 30, 2021 to $7.5 million for the fiscal year ended
June 30, 2022 primarily due to an increase in production. On a per unit basis,
depletion expense was $3.46 per BOE and $5.53 per BOE for the fiscal years ended
June 30, 2022 and 2021, respectively. The integration of the Jonah Field
properties in April 2022, Williston Basin properties in January 2022, and
Barnett Shale properties in May 2021 together with the ceiling test impairments
recorded during the fiscal year ended June 30, 2021 contributed to the overall
lower composite depletion per BOE rate for the year ended June 30, 2022.

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Impairment of Proved Property



We utilize the full cost method of accounting for our oil and natural gas
properties under the full cost method of accounting, capitalized costs of oil
and natural gas properties, net of accumulated depletion, depreciation, and
amortization and related deferred taxes, are limited to the estimated future net
cash flows from proved oil and natural gas reserves, discounted at 10%, plus the
lower of cost or fair value of unproved properties included in the amortization
base, plus the cost of unproved properties excluded from amortization, as
adjusted for related income tax effects (the valuation "ceiling"). As of
June 30, 2022, our net book value of oil and natural gas properties did not
exceed the current ceiling. During the fiscal year ended June 30, 2021, we
recorded a proved property impairment of $24.8 million primarily as a result of
the decline in the price of oil over the historical 12-month period.

Impairment of Well Lift Inc. - Related Expenses


Our royalty rights and investment in Well Lift, Inc. ("WLI") resulted from the
separation of our artificial lift technology operations in December 2015. We
conveyed our patents and other intellectual property to WLI and retained a 5%
royalty on future gross revenues associated with the technology. We own
approximately 18% of the common stock and 100% of the preferred stock of WLI and
account for our investment in this private company at cost less impairment, if
any, plus or minus changes resulting from observable price changes in orderly
transactions for the identical or a similar investment of the same issuer, if
such were to occur. We evaluate the investment for impairment when we identify
any events or changes in circumstances that might have a significant adverse
effect on the fair value of the investment. As of March 31, 2021, we reviewed
our investment in WLI for potential impairment and, as a result, recorded an
impairment expense of $0.1 million. This impairment charge was recorded based on
a variety of factors including the level of activity associated with this
technology.

General and Administrative Expenses


General and administrative expenses for the fiscal year ended June 30, 2022
increased $1.2 million, or 22.1%, to $6.7 million compared to $5.5 million for
the fiscal year ended June 30, 2021. The increase is primarily due to
approximately $0.2 million for salary and employee benefits due to additional
personnel, $0.3 million in severance, $0.2 million for professional fees related
to increased accounting services as a result of the Jonah Field Acquisition, the
Williston Basin Acquisition and the Barnett Shale Acquisition, and $0.3 million
for increased business development activity. On a per unit basis, general and
administrative expenses decreased $3.11 per BOE to $3.09 per BOE for the year
ended June 30, 2022 from $6.20 per BOE for the prior year. The decrease in
general and administrative expenses on a per unit basis are due to the increased
production volumes described above.

Stock-based Compensation Expenses



Stock-based compensation decreased $1.1 million, or 90%, to $0.1 million for
the year ended June 30, 2022 compared to $1.3 million the prior period due to a
$1.2 million reduction in current period expense related to the forfeiture of
unvested shares in connection with severance.

Net Gain (Loss) on Derivative Contracts



Periodically, we utilize commodity derivative financial instruments to reduce
our exposure to fluctuations in oil and natural gas prices. We have elected not
to designate our open derivative contracts for hedge accounting, and
accordingly, we recorded the net change in the mark-to-market valuation of the
derivative contracts in the consolidated statements of operations. The amounts
recorded on the consolidated statements of operations related to derivative
contracts represent the (i) gains (losses) related to fair value adjustments on
our open, or unrealized, derivative contracts, and (ii) gains (losses) on
settlements of derivative contracts for positions that have settled or been
realized. The table below summarizes our net realized and unrealized gains
(losses) on derivative contracts as well as the impact of net realized (gains)
losses on our average realized prices for the periods presented. As a result of
the Williston Basin Acquisition in January 2022 and Jonah Field Acquisition in
April 2022, we were required by the terms of our Senior Secured Credit Facility
to hedge a portion of our production. The increase in commodity prices since
entering into the hedges resulted in a realized loss on hedges for the year
ended June 30, 2022 and an unrealized loss due to the mark-to-market value

of

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remaining hedges. Certain of our hedges begin to expire in October 2022 with our
final hedges expiring March 2023. As of June 30, 2022, we had a $0.2 million
derivative asset all of which was classified as current, and a $2.2 million
derivative liability, all of which was classified as current.

                                        Years Ended June 30,
(in thousands, except per unit and
per BOE amounts)                          2022          2021       Variance      Variance %
Realized gain (loss) on derivative
contracts                             $    (1,769)    $ (2,526)    $     757       (30.0) %
Unrealized gain (loss) on
derivative contracts                       (1,994)        1,911      (3,905)      (204.3) %
Total net gain (loss) on
derivative contracts                  $    (3,763)    $   (615)    $ (3,148)        511.9 %

Average realized crude oil price
per Bbl                               $      85.11    $   47.59    $   37.52         78.8 %
Cash effect of oil derivative
contracts per Bbl                           (1.24)       (4.55)         3.31       (72.7) %
Crude oil price per Bbl (including
impact of realized derivatives)       $      83.87    $   43.04    $   40.83         94.9 %

Average realized natural gas price
per Mcf                               $       5.49    $    2.73    $    2.76        101.1 %
Cash effect of natural gas
derivative contracts per Mcf                (0.14)            -       (0.14)            - %
Natural gas price per Mcf
(including impact of realized
derivatives)                          $       5.35    $    2.73    $    2.62         96.0 %


Interest Expense

Interest expense increased $0.5 million during the fiscal year ended June 30, 2022 compared to fiscal year 2021 primarily due to the increased borrowings outstanding on our Senior Secured Credit Facility due to our acquisitions throughout the year.

Income tax (expense) provision


For the year ended June 30, 2022, we recognized income tax expense of $8.5
million on net income before income taxes of $41.1 million compared to an income
tax benefit of $5.0 million on net loss before income taxes of $21.4 million for
the year ended June 30, 2021.

                   Critical Accounting Policies and Estimates

The preparation of financial statements in accordance with accounting principles
generally accepted in the United States of America requires that we select
certain accounting policies and make estimates and assumptions that affect the
reported amounts of the assets, liabilities, and disclosures of contingent
assets and liabilities as of the date of the balance sheet as well as the
reported amounts of revenues and expenses during the reporting period. These
policies, together with our estimates, have a significant effect on our
consolidated financial statements. Our significant accounting policies are
included in Note 1, "Summary of Significant Events and Accounting Policies" to
our consolidated statements in Item 8. Following is a discussion of our most
critical accounting estimates, judgments, and uncertainties that are inherent in
the preparation of our consolidated financial statements.

Oil and Natural Gas Properties.  Companies engaged in the production of oil and
natural gas are required to follow accounting rules that are unique to the oil
and natural gas industry. We apply the full cost accounting method for our oil
and natural gas properties as prescribed by SEC Regulation S-X Rule 4-10. Under
this method of accounting, the costs of unsuccessful and successful, exploration
and development activities are capitalized as properties and equipment. This
includes any internal costs that are directly related to property acquisition,
exploration, and development activities but does not include any costs related
to production, general corporate overhead, or similar activities. Gain or loss
on the sale or other disposition of oil and natural gas properties is not
recognized unless the gain or loss would significantly alter the relationship
between capitalized costs and proved reserves. Oil and natural gas properties
include costs that are excluded from costs being depleted or amortized. Oil and
natural gas property costs excluded represent investments in unevaluated
properties. We exclude these costs until the property has been evaluated. Costs
are transferred to the full cost pool as the properties are evaluated. As of
June 30, 2022, we had no unevaluated property costs. Oil and natural gas
properties include costs that are excluded from depletion and amortization,
which represent investments in unproved and unevaluated properties and include
non-producing leasehold, geologic and geophysical costs associated with
leasehold or drilling interests, and exploration drilling costs.

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Estimates of Proved Reserves.   The estimated quantities of proved oil and

natural gas reserves have a significant impact on the underlying financial
statements. The estimated quantities of proved reserves are used to calculate
depletion expense and the estimated future net cash flows associated with those
proved reserves is the basis for determining impairment under the quarterly
ceiling test calculation. The process of estimating oil and natural gas reserves
is very complex and requires significant decisions in the evaluation of all
available geologic, geophysical, engineering, and economic data. Estimated
reserves are often subject to future revisions, which could be substantial,
based on the availability of additional information; this includes reservoir
performance, additional development activity, new geologic and geophysical data,
additional drilling, technological advancements, price changes, and other
economic factors. As a result, material revisions to existing reserve estimates
may occur from time to time. Although every reasonable effort is made to ensure
that the reported reserve estimates prepared by our third-party independent
engineers represent the most accurate assessments possible, the subjective
decisions and variances in available data for the properties make these
estimates generally less precise than other estimates included in our financial
statements. Material revisions to reserve estimates and/or significant changes
in commodity prices could substantially affect our estimated future net cash
flows of our proved reserves. These changes could affect our quarterly ceiling
test calculation and could significantly affect our depletion rate. A 10%
decrease in commodity prices used to determine our proved reserves as of
June 30, 2022 would not have resulted in an impairment of our oil and natural
gas properties. Holding all other factors constant, a reduction our proved
reserve estimates at June 30, 2022 of 10% would affect depletion, depreciation,
and amortization expense by approximately $0.4 million.

On December 31, 2008, the SEC issued its final rule on the modernization of
reporting oil and natural gas reserves. The rule allows consideration of new
technologies in evaluating reserves, generally limits the designation of proved
reserves to those projects forecasted to be drilled five years from the initial
recognition date of such reserves, allows companies to disclose their probable
and possible reserves to investors, requires reporting of oil and natural gas
reserves using an average price based on the previous 12-month unweighted
arithmetic average first-day-of-the-month price rather than year-end prices,
revises the disclosure requirements for oil and natural gas operations, and
revises accounting for the limitation on capitalized costs for full cost
companies.

Valuation of Deferred Tax Assets.  We make certain estimates and judgments in
determining our income tax expense for financial reporting purposes. These
estimates and judgments occur in the calculation of certain tax assets and
liabilities that arise from differences in the timing and recognition of revenue
and expense for tax and financial reporting purposes. Our federal and state
income tax returns are generally not prepared or filed before the consolidated
financial statements are prepared or filed; therefore, we estimate the tax basis
of our assets and liabilities at the end of each period as well as the effects
of tax rate changes, tax credits, and net operating loss carry backs and carry
forwards. Adjustments related to these estimates are recorded in our tax
provision in the period in which we file our income tax returns. Further, we
must assess the likelihood that we will be able to recover or utilize our
deferred tax assets. If recovery is not likely, we must record a valuation
allowance against such deferred tax assets for the amount we would not expect to
recover; this would result in an increase to our income tax expense. The
deferred tax asset and valuation allowance of $0.1 million related to the
portion of the NOLs that are limited by IRC Section 382 were written off during
the year ended June 30, 2022.

Management considers the scheduled reversal of deferred tax liabilities,
projected future taxable income, and tax planning strategies in making the
assessment of the ultimate realization of deferred tax assets. The Company has
historically established a valuation allowance against net operating losses and
other deferred tax assets to the extent it believes the future benefit from
these assets will not be realized in the statutory carryforward periods, based
upon the level of historical taxable income and projections for future taxable
income over the periods for which the deferred tax assets are deductible. At the
time of this report, we have not recorded a valuation allowance for our expected
inability to realize the future benefits of certain federal and state deferred
tax assets as further discussed in Note 7, "Income Taxes".

Stock-based Compensation.  The fair value, and for certain awards the expected
vesting period, of our performance-based awards were determined using a Monte
Carlo simulation. This technique uses a geometric Brownian motion model with
defined variables and randomly generates values for each variable through
multiple trials. Variables include stock price volatility, expected term of the
award, the expected risk-free interest rate, and the expected dividend yield of
our stock. The risk-free interest rate used is the U.S. Treasury yield for bonds
matching the expected term of the award on the date of grant. Vesting of
performance-based awards is based on our total common stock return compared

to a
peer

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group of other companies in our industry with comparable market capitalizations and, for certain awards, our share price attaining a set target.



Recent Accounting Pronouncements.   Refer to Note 1, "Summary of Significant
Events and Accounting Policies" to our consolidated financial statements in
Item 8. Financial Statements and Supplementary Data for discussion of the recent
accounting pronouncements issued by the Financial Accounting Standards Board.

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