What changed in this filing

/stocks — the workspaceLOADING

Item 1. Business

2021-09-14 compared with 2020-09-10 · 220 added, 218 removed, 153 unchanged (74% of the section changed)

See Glossary of Selected Petroleum Industry Terms starting on page

Evolution Petroleum Corporation is an oil and gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management and development of producing oil and gas properties.

The Company's long-term goal is to build a diversified portfolio of oil and gas assets primarily through acquisition, while seeking opportunities to maintain and increase production through selective development, production enhancement and other exploitation efforts on its properties.

Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO 2 enhanced oil recovery project, and our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, and overriding royalty interests in two onshore Texas wells.

Evolution Petroleum Corporation is an oil and natural gas company focused on delivering a sustainable dividend yield to its shareholders through the ownership, management, and development of producing oil and natural gas properties.

The Company's long-term goal is to build a diversified portfolio of oil and natural gas assets primarily through acquisition, while seeking opportunities to maintain and increase production through selective development, production enhancement, and other exploitation efforts on its properties.

Our producing assets consist of our interests in the Delhi Holt-Bryant Unit in the Delhi field in Northeast Louisiana, a CO 2 enhanced oil recovery (“EOR”) project, our interests in the Hamilton Dome field located in Hot Springs County, Wyoming, a secondary recovery field utilizing water injection wells to pressurize the reservoir, our interests in the Barnett Shale located in North Texas, a natural gas producing shale reservoir, and overriding royalty interests in two onshore central Texas wells.

Our interests in the Delhi field consist of a 23.9% working interest, with an associated 19.0% revenue interest and separate overriding royalty and mineral interests of 7.2% yielding a total net revenue interest of 26.2%.

The field is operated by Denbury Onshore LLC ("Denbury"), a subsidiary of Denbury Resources, Inc.

The field is operated by Denbury Onshore LLC (“Denbury”), a subsidiary of Denbury Inc.

On November 1, 2019, the Company acquired non-operated working interests in the Hamilton Dome field consisting of a 23.5% working interest, with an associated 19.7% revenue interest (inclusive of a small overriding royalty interest).

The field is operated by Merit Energy Company ("Merit"), a private oil and gas company, who owns the vast majority of the remaining working interest in Hamilton Dome field.

The field is operated by Merit Energy Company (“Merit”), a private oil and natural gas company, who owns the vast majority of the remaining working interest in the Hamilton Dome field.

Our acquired interest in Hamilton Dome aligned with the Company's strategy of adding long-lived, low decline reserves expected to be supportive of our dividend over the long-term.

On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale consisting of approximately 21,000 net acres held by production across nine North Texas counties in the Barnett Shale (the “Barnett Shale Acquisition”).

The acreage has an average working interest of 17.3% and associated average revenue interest of 14.2% (inclusive of overriding royalty interests).

At the time of the Barnett Shale Acquisition, approximately 90% of the wells acquired were operated by Blackbeard Operating LLC (“Blackbeard”), while the remaining 10% were operated by seven other operators.

After the closing of the Barnett Shale Acquisition, Blackbeard announced the sale of its interests to Diversified Energy Company PLC (“Diversified Energy”), which subsequently closed in July of 2021.

At present, Blackbeard is still the operator of the assets

under a transition services agreement with Diversified Energy.

However, after the transition, Diversified Energy will take over operations of the assets.

Significant Activity in Fiscal 2021

Proved oil equivalent reserves at June 30, 2020 were 10.2 MMBOE, a 13% increase from the previous year primarily due to the acquisition of the Hamilton Dome field in November 2019.

The Standardized Measure for proved reserves decreased 51% to $62 million , as the acquisition of the Hamilton Dome field was offset by the decrease in the average first day of the month net oil price from $64.54 per barrel of oil and $23.83 per barrel of natural gas liquids at June 30, 2019 to $46.37 per barrel of oil and $9.00 per barrel of natural gas liquids at June 30, 2020.

Our proved reserves consist of 80% crude oil and 20% natural gas liquids, 82% are classified as proved developed producing and 18% are proved undeveloped.

We recognized net income of $5.9 million , or $0.18 per diluted common share, our ninth consecutive year of reporting net income.

Returned to shareholders $10.7 million in cash dividends and $2.5 million in stock repurchases in fiscal 2020.

• Closed the Barnett Shale Acquisition on May 7, 2021, which included total proved reserves of 13.1 MMBOE as of June 30, 2021 as estimated by DeGolyer & MacNaughton (“D&M”), an independent reservoir engineering firm.

• Returned to shareholders $4.3 million in cash dividends in fiscal 2021.

The Company has paid out to shareholders more than $74.5 million in cash dividends since inception of the dividend program in December 2013.

Closed the acquisition of non-operating working interest in the Hamilton Dome field on November 1, 2019 which included total proved reserves of 1.47 MMBOE as of June 30, 2020 as estimated by DeGolyer & MacNaughton ("D&M"), an independent reservoir engineering firm.

Reported $12.4 million of cash flows from operations for the fiscal year ended June 30, 2020.

We funded all operations, including $11.8 million of capital spending inclusive of our $9.3 million acquisition of our interest in the Hamilton Dome Field, from internal resources and remain debt free at June 30, 2020.

In order to mitigate the impact of the growing global COVID-19 pandemic on our employees, we continue to follow local stay-at-home orders and remotely work from home with minimal disruptions to our business operations.

We entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel, recording a loss of $1.4 million at June 30, 2020.

Of this amount, $1.9 million were non-cash, unrealized mark-to-market losses as commodity prices improved from those existing at fiscal year-end, offset in part by $0.5 million in realized gains during the fiscal fourth quarter.

We completed remaining capital expenditures for the six-well water curtain program and related infrastructure preceding the planned Delhi Phase V development, which was delayed by the operator until our fiscal fourth quarter of 2021.

In July 2020, Denbury Resources announced that it had entered into a restructuring support agreement with certain of its debt holders and filed a pre-packaged voluntary petition for reorganization under Chapter 11 of the Bankruptcy Code in Texas.

Denbury Resources is seeking to eliminate $2.1 billion of debt.

Denbury subsequently announced on September 3, 2020 that its plan to eliminate $2.1 billion of its bond debt has been confirmed by the court which will substantially reduce its debt and strengthen its balance sheet.

Our Reserves:

Delhi Field - Enhanced Oil Recovery - Onshore Louisiana

Our independent reservoir engineering firm, D&M, assigned the estimated reserves net to our interests at Delhi as of June 30, 2020 ;

we had 8.7 million bbls of total proved oil equivalent reserves.

The following table summarizes the reserves assigned by D&M:

Reserves as of June 30, 2020

Reserves MBOE

Development History of the Delhi Field - Enhanced Oil Recovery - Onshore Louisiana

Our working and royalty interests in the Delhi field is currently our largest producing asset.

The Holt-Bryant Unit ("Unit") is approximately 13,636 acres in size and has had a prolific production history totaling approximately 195 million bbls of oil through primary and limited secondary recovery operations since its discovery in the mid-1940s.

At the time of our purchase of the field in 2003, the Unit had minimal production.

We conveyed our working interest in the field to Denbury in May 2006 for $50 million for the purpose of installing an enhanced oil recovery ("EOR") project in the field.

• Generated $3.7 million in operating income before impairments.

• Funded our operations, development capital expenditures, and dividends out of operating cash flow.

• Proved oil equivalent reserves at June 30, 2021, were 23.4 MMBOE, a 129% increase from the previous year primarily due to the acquisition of interests in the Barnett Shale in May 2021.

• Primarily driven by proved oil and gas property impairments of $9.6 million and $15.2 million recorded during the first and second fiscal quarters of 2021, respectively, we recognized a net loss of $16.4 million, or $(0.49) per common share.

• We completed the NYMEX WTI oil swaps entered into during fiscal year 2020, and have not entered into any new oil and natural gas derivatives as of June 30, 2021.

• Denbury, whose subsidiary operates the Delhi field, emerged from bankruptcy on September 18, 2020, and returned to conformance projects with a refreshed capital budget after a period of no conformance spending.

Delhi Field - Enhanced Oil Recovery CO 2 Flood - Onshore Louisiana

The Company purchased the Delhi field in September 2003.

In May 2006, the Company conveyed its working interest in the field to Denbury for $50 million for the purpose of installing an EOR project;

we retained a 23.9% reversionary working interest upon payout of the project, as defined in the purchase and sale agreements.

Since EOR production began in March 2010, the Unit has produced over 21.5 million bbls of oil.

Today, our interests include a 23.9% working interest and a 7.2% royalty interest with a total net revenue interest of 26.2%.

Delhi field is located in northeast Louisiana in Franklin, Madison, and Richland parishes and encompasses approximately 13,600 unitized acres.

The Delhi field was discovered in the mid-1940s and has had a prolific production history totaling approximately 195 MMBbls of oil through primary and limited secondary recovery operations.

Since EOR production began in March 2010, the Unit has produced over 23.0 MMBbls of oil.

For fiscal 2021, average gross daily oil production at Delhi was 4,281 BOPD and 977 bbls NGLs per day (5,258 BOEPD).

After the May 2006 conveyance, Denbury as the operator originally planned six primary phases for the installation of the CO 2 flood in the Delhi field.

Four of these six phases have been completed as of June 30, 2021, and two remain undeveloped.

One of the remaining two phases (Phase V) is reflected as proved undeveloped in our current reserves report and the other (Phase VI) was removed from proved reserves as it was not deemed economic under current pricing guidelines for SEC purposes.

Phase I began CO 2 injection in November 2009.

First oil production response occurred in March 2010 and production in the field increased to approximately 1,000 gross barrels of oil per day by December 2010.

Implementation of Phase II, which was more than double the size of Phase I, commenced with incremental CO 2 injection at the end of December 2010.

First oil production response from Phase II occurred during March 2011, and field gross production increased to more than 4,000 barrels of oil per day by June 2011.

Phase III was initially installed and subsequently expanded during calendar 2011.

First oil production response from Phase III occurred during June 2011, and field gross production subsequently increased to more than 5,000 gross barrels of oil per day by December 2011.

Phase IV was installed during the first six months of calendar 2012.

During early calendar 2013, the operator intensified development in the previously redeveloped western side of the field based on production results and new geological mapping that included the results of seismic data acquired over the last few years.

First oil production response from Phase IV occurred during August 2012, and field gross production increased to more than 7,500 gross barrels of oil per day by February 2013.

the remaining two phases (Phase V) is reflected as proved undeveloped in our current reserves report and the other (Phase VI) was removed from proved reserves as it was not deemed economic due to distant location and oil price.

In June 2013, following an adverse fluid release event that consisted of the uncontrolled release of CO 2 , water, natural gas, and a small amount of oil from a previously plugged well in the southwest part of the field, the operator suspended CO 2 injection in most of the southwestern tip of the field.

The operator has fully remediated the affected area, has isolated that part of the field with a water curtain, thus removing the area from the CO 2 flood.

Construction began on the NGL extraction plant in February 2015 and was completed and began processing in December 2016.

The plant extracts methane and NGL's from the CO 2 recycle stream.

The methane and part of the ethane produced by the NGL extraction plant are used to generate electrical power for use in the field.

The extracted NGL's are sold at the field to a purchaser who transports them by truck to a plant for further processing.

In addition to the value of these hydrocarbon products, the increased purity of the CO 2 stream re-injected into the field has resulted in operational benefits to the CO 2 flood.

To date, we have incurred a net capital cost of approximately $27.4 million for the plant, including capital upgrades since its commissioning.

Subsequent to the reversion of our working interest to us in November 2014, the operator initiated work on the Phase V expansion of the CO 2 flood in the undeveloped eastern part of the field.

These operations were suspended shortly after reversion when the operator significantly reduced capital spending as a result of declining oil prices.

Resumption of this work has been delayed due to low prevailing oil prices and the operator's allocation of capital to other Delhi projects, primarily the large investment in the NGL plant together with the consensus that Phase V project economics would be enhanced if it were implemented after completion of the NGL plant.

An infill drilling program commenced in March 2018 to target productive oil zones in the developed areas of the field that were not being swept efficiently by the CO 2 flood.During fiscal 2019 the 12 well infill program, consisting of 10 producing wells and two CO 2 injection wells, was completed.

Proved undeveloped reserves of 536 MBOE were converted to proved developed reserves.

Additionally during fiscal 2019, one pad of the six-well water curtain program was completed and commenced water injection during the second half of fiscal 2019.

The project began late in fiscal 2017 after completion of the NGL plant with the drilling of one injection well followed by three injection wells in fiscal 2018.

During fiscal 2019, the operator drilled the two remaining injection wells and proceeded with completions and injection line work.

The first pad commenced operations during fiscal 2019 and the second pad began injections during our second quarter of fiscal 2020.

At June 30, 2020, we had total proved reserves of 8.7 MMBOE at Delhi, which was comprised of 6.7 MMBOE of oil and 2.0 MMBOE of NGLs as estimated by our independent petroleum engineering firm.

The operator has fully remediated the affected area, and has isolated that part of the field with a water curtain, thus removing the area from the CO 2 flood.

An NGL extraction plant was completed and began processing in December 2016.

The plant allows for the sale of NGLs, improves CO 2 flood efficiency, and provides the extracted methane as a source of power for plant reducing operating expenses.

Phase V development started in fiscal 2017 with the water curtain and related infrastructure program.

The first pad commenced injections in fiscal 2019 with the second pad starting in the second quarter of fiscal 2020.

Additional Delhi Phase V development has been delayed due to Denbury’s restructuring in fiscal 2021.

The total gross purchased CO 2 volume was 18 BCF for fiscal 2021.

In February 2020, the CO 2 purchase line to Delhi was shut-in by the pipeline operator for extensive repairs.

No CO 2 was purchased from the shut-in date through October 2020.

During the pipeline repairs, the CO 2 recycle facilities continued to operate providing approximately 80% of the historic total injected CO 2 volumes to Delhi.

The decrease in production within the field was primarily a result of lower injection volumes reducing reservoir pressure.

CO2 purchases resumed in November 2020 at a limited level, and resumption of desired purchase volumes is expected during fiscal 2022 which is projected to increase reservoir pressure.

At June 30, 2021, the Company had total proved reserves of 8.5 MMBOE at Delhi, which was comprised of 6.5 MMBOE of oil and 2.0 MMBOE of NGLs as estimated by our independent petroleum engineering firm.

The following table sets forth our estimated proved reserves as of June 30, 2021.

For additional reserve information see Note 20 to our consolidated financial statements in Item 8.

Reserve Category

Total Reserves

Reserve Category - Delhi field Oil

(MBbls) Natural Gas

(MMcf) Total Reserves

Developed Producing (79% of Proved) 4,879 1,784 — 6,663

Undeveloped (21% of Proved) 1,605 209 — 1,814

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.

TOTAL PROVED 6,484 1,993 — 8,477

Product Mix 76 % 24 % — % 100 %

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.

Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

For fiscal 2020, average gross daily oil production at Delhi was 5,632 BOPD and 1,106 bbls NGLs per day ( 6,738 BOEPD).

The total gross purchased CO 2 volume was 19 BCF for fiscal 2020.

In February 2020, the CO 2 purchase line to Delhi was shut-in by the pipeline operator for extensive repairs.

No CO 2 was purchased from the shut-in date through June 2020.

The recycle facilities continue to operate as usual providing approximately 80% of the injected CO 2 volumes to Delhi with production somewhat reduced due to lower injection volumes.

Per communications with Denbury, the CO 2 line is currently being repaired and is projected to be completed early in the second quarter of our fiscal 2021.

Our Reserves:

Hamilton Dome - Hot Springs County, Wyoming

Our independent reservoir engineering firm, D&M, assigned the estimated reserves net to our interests at Hamilton Dome as of June 30, 2020 ;

we had 1.5 million bbls of total proved oil equivalent reserves.

The following table summarizes the reserves assigned by D&M:

Reserves as of June 30, 2020

Reserves MBOE

Hamilton Dome - Historical, Low Decline Waterflood - Hot Springs County, Wyoming

On November 1, 2019, the Company acquired certain mineral interests in the Hamilton Dome field from Merit, who owns the vast majority of the remaining working interest in the field.

The Hamilton Dome field is located in the southwest part of the Big Horn Basin in northwest Wyoming about twenty miles northwest of Thermopolis in Hot Springs County.

Our interest includes a 23.5% working interest and an associated 19.7% revenue interest (inclusive of a small overriding royalty interest).

The Hamilton Dome field has produced over 160 MMBO over the last 100 years;

Merit has operated the field over the last 25 years.

Production from this field is 100% oil and is currently averaging low single-digit decline rates.

Development History of the Hamilton Dome Field - Hot Springs County, Wyoming

Oil was first discovered at the Hamilton Dome field within the Big Horn Basin in September 1918 in the Curtis/Chugwater reservoir by New York Oil Company via surface mapping.

Shortly thereafter, the Phosphoria and Tensleep formations were discovered in 1919 and 1929, respectively.

The field is part of an anticlinal fold with a southerly bounding fault with approximately 4,500-5,000 feet of displacement, thus providing a structural trap.

The two major producing formations are the Tensleep (sandstone) and Phospohoria (limestone) reservoirs.

Additional present day and historical production exists from the Curtis/Chugwater (sandstone), Amsden (sandstone), Madison (limestone), and Big Horn (dolomite) formations.

These formations produce from depths ranging approximately 1,500 to 3,600 feet and have historically produced at rates of greater than 25,000 gross BOPD.

The productive surface area of the field spans approximately 2,500 acres.

The original oil in place of the six producing reservoirs is estimated to be at least 500 million barrels.

Over the last 100 years, more than 160 million barrels have been produced from the field.

Although the Tensleep reservoir was discovered in 1929, it remained largely undeveloped until World War II.

Active development of the Tensleep reservoir occurred between 1944 and 1960.

The Madison and Darwin reservoirs were discovered in 1948 and 1959, respectively.

These two reservoirs were developed sporadically from 1950 through the 1970’s.

In 1970, 52 years after the field’s discovery, a waterflood was implemented in the Curtis/Chugwater reservoir.

In 1973, the Phosphoria reservoir was unitized in order to implement a waterflood of the reservoir, this unit is still in place and is approximately 3,160 acres.

In the early 1970’s, Tensleep production was down spaced to 5 acres and in the late 1970’s an isolated Tensleep waterflood was implemented.

By 1981, the Tensleep reservoir had produced more than 147 million bbls.

The last active development of the Curtis/Chugwater reservoir occurred in 1978 when the waterflood was ended.

The Madison reservoir was further developed in the early 1990’s.

Merit Energy purchased the field in 1995 and has operated the field for 25 years;

the field was unitized in 1996.

The Phosphoria and Tensleep reservoirs were permitted for unlimited commingling in 1996 as well.

In 1997, Merit began a capital workover program to downspace the Phosphoria reservoir to 10 acres in addition to improving the Tensleep and Phosphoria waterfloods and eliminating commingled production.

Under Merit’s operations, the wells in the Hamilton Dome field are produced via electric submersible pumps (ESP) and rod pumps.

Our interest includes a 23.5% working interest and an associated 19.7% revenue interest (inclusive of a small overriding royalty interest) in the approximately 3,160 acre unitized field.

The Hamilton Dome field has been operated by Merit since 1995.

Under Merit's operations, the wells in the Hamilton Dome field are produced using secondary recovery water flood methods via electric submersible pumps (ESP) and rod pumps.

Typical workovers in the field include rod repair, ESP repair, injector acid jobs, and wellbore cleanouts.

At June 30, 2020, EPM has total net proved reserves of 1.47 MMBOE at Hamilton Dome which was entirely comprised of oil as estimated by our independent reservoir engineering firm.

The Hamilton Dome field was discovered in 1918 and has produced over 160 MMBO.

Production from this field is 100% oil and is currently averaging low single-digit decline rates.

The primary producing reservoirs in the field are the Tensleep and Phosphoria with an approximate depth of 3,000 feet.

Average gross daily production was 1,987 BOPD for the year ended June 30, 2021.

Produced oil from the field is subject to Western Canadian Select pricing.

At June 30, 2021, the Company has total net proved reserves of 1.9 MMBOE at Hamilton Dome which was entirely comprised of oil as estimated by our independent reservoir engineering firm.

The following table sets forth our estimated proved reserves as of June 30, 2021 for our Hamilton Dome field.

For additional reserve information see Note 20 to our consolidated financial statements in Item 8.

Reserve Category

Total Reserves

Reserve Category - Hamilton Dome field Oil

(MBbls) Natural Gas

(MMcf) Total Reserves

Developed Producing (100% of Proved) 1,851 — — 1,851

Undeveloped (0% of Proved) — — — —

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.

TOTAL PROVED 1,851 — — 1,851

Product Mix 100 % — % — % 100 %

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.

Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

Following acquisition in November 2019, average gross daily production was 2,048 BOPD through the end of fiscal 2020.

From March to June 2020, the production rate was negatively impacted by an estimated 870 gross BOPD, or approximately 38%, due to the shut-in of 61 wells as a result of the drop in oil prices.

Barnett Shale - Mature, Low Decline Natural Gas Production - North Texas

On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale from TG Barnett Resources, LP, a wholly owned subsidiary of Tokyo Gas Americas, Ltd.

The acquired assets consist of approximately 21,000 net acres held by production across nine North Texas counties (Bosque, Denton, Erath, Hill, Hood, Johnson, Parker, Somervell, and Tarrant) in the Barnett Shale.

Our interest includes an average working interest of 17.3% and associated average revenue interest of 14.2%.

At the time of acquisition, approximately 90% of the wells acquired were operated by Blackbeard, while the remaining 10% were operated by seven other operators.

After the close of the Barnett Shale Acquisition, Blackbeard announced the sale of its interests to Diversified Energy, which closed in July 2021.

The Barnett Shale was discovered as a natural gas resource play in the Newark East field in 1981;

following completions of technology advancements in the 1990s, development of the Barnett Shale began in earnest in 1998.

The majority of the wells included in our Barnett Shale assets were completed between 2007 and 2010 and are horizontals.

The assets are characterized by mature, low-decline production.

Average net daily production from the acquisition date of May 7, 2021 to June 30, 2021, was 4.3 MBOE per day.

Commodities produced from our Barnett Shale assets include natural gas, oil and NGLs that are sold to Gulf Coast markets.

At June 30, 2021, the Company has total net proved reserves of 13.1 MMBOE in the Barnett Shale which is comprised of natural gas and NGLs with a small amount of oil, as estimated by our independent reservoir engineering firm.

The following table sets forth our estimated proved reserves as of June 30, 2021 for our Barnett Shale assets.

For additional reserve information, see Note 20 to our consolidated financial statements in Item 8.

Reserve Category - Barnett Shale field Oil

(MBbls) Natural Gas

(MMcf) Total Reserves

Developed Producing (100% of Proved) 85 4,879 48,571 13,059

Undeveloped (0% of Proved) — — — —

TOTAL PROVED 85 4,879 48,571 13,059

Product Mix 1 % 37 % 62 % 100 %

Estimated Oil and Natural Gas Reserves and Estimated Future Net Revenues

The SEC sets rules related to reserve estimation and disclosure requirements for oil and natural gas companies.

These rules require disclosure of oil and gas proved reserves by significant geographic area, using the trailing 12-month average price,

calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes.

These rules require disclosure of oil and natural gas proved reserves by significant geographic area, using the trailing 12-month average price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, rather than year-end prices, and allows the use of new technologies in the determination of proved reserves if those technologies have been demonstrated empirically to lead to reliable conclusions about reserve volumes.

Subject to limited exceptions, the rules also require that proved undeveloped reserves may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years.

1 unchanged sentence

Summary of Oil & Gas Reserves for Fiscal Year Ended 2021

Our proved reserves at June 30, 2020 , denominated in equivalent barrels using six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio, were estimated by our independent reservoir engineer, DeGolyer and MacNaughton which was formed in 1936.

Our proved reserves at June 30, 2021, denominated in barrels of oil equivalent (BOE) using six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio, were estimated by our independent reservoir engineer, DeGolyer and MacNaughton (“D&M”) which was formed in 1936.

D&M has completed more than 23,000 projects in more than 100 countries.

3 unchanged sentences

For additional reserve information, see Note 20 to our consolidated financial statements in Item 8.

The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $47.37 per barrel of crude oil.

The NYMEX previous 12-month unweighted arithmetic average first-day-of-the-month price used to calculate estimated revenues was $49.72 per barrel of oil and $2.46 per MMBtu of natural gas.

The net price per barrel of NGLs was $19.81, which does not have any single comparable reference index price.

3 unchanged sentences

Reserves as of June 30, 2021

Reserve Category

Total Reserves

Reserve Category - Combined Oil

(MBbls) Natural Gas

(MMcf) Total Reserves

Developed Producing (92% of Proved) 6,815 6,663 48,571 21,573

Undeveloped (8% of Proved) 1,605 208 — 1,813

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.

TOTAL PROVED 8,420 6,871 48,571 23,386

Product Mix 36 % 29 % 35 % 100 %

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.

Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

2 unchanged sentences

Delhi Field Proved

Proved reserves, MBOE

Proved reserves, MBOE MBOE

June 30, 2020 8,746

Production (504)

Revisions (a) 235

2 unchanged sentences

June 30, 2021 8,477

(a) Positive revisions of 412 MBOE at Delhi field reflect adjusted methodology of forecasting NGLs independently from the oil production forecast by our independent reservoir engineering firm.

(a) Positive revisions of 235 MBOE at Delhi field reflect operating cost reductions and improved NGL differential extending the reserves life of the field.

Hamilton Dome Field Proved

Proved reserves, MBOE

Proved reserves, MBOE MBOE

June 30, 2020 1,473

Production (143)

Revisions (a) 521

2 unchanged sentences

June 30, 2021 1,851

(a) Negative revisions of 1,856 MBOE were due to the impacts of lower oil prices since the field’s November 2019 acquisition and to subsequent reduced rates of production.

Responding to lower oil prices, in March, the operator shut in wells that were not economic to optimize the field's cash flow.

Although some returned to production as prices improved, as of June 30, 2020, approximately 25% of the wells remained shut-in.

The lowered historical production curve and lower SEC average price, resulted in the field reaching its economic limit sooner than it had when proved reserves were estimated at the acquisition date.

(a) Positive revisions of 521 MBOE reflect improved trailing twelve month SEC pricing and differentials, reactivation of shut-in production throughout the year, and reduced operating expenses.

These factors resulted in wells remaining economic longer, extending the reserves life of the field.

Barnett Shale Field Proved

Proved reserves, MBOE MBOE

June 30, 2020 —

Purchases 13,299

Production (240)

Sales of minerals in place —

Improved recovery, extensions and discoveries —

June 30, 2021 13,059

Internal Controls Over Reserves Estimation Process and Qualifications of Technical Persons with Oversight for the Company's Overall Reserve Estimation Process

2 unchanged sentences

degree in chemical engineering from the University of Tulsa and his M.B.A.

from the Mendoza School of Business at the University of Notre Dame.

Such reserves estimates are in compliance with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.

The reserves information in this filing is based on estimates prepared by D&M, our independent petroleum engineering firm, which was formed in 1936 and has completed more than 23,000 projects in more than 100 countries.

The person responsible for preparing the reserves report with D&M is a Registered Professional Engineer in the State of Texas and a Vice President of the firm.

He received a Bachelor of Science degree in petroleum engineering from the University of Texas in 1984, has over 35 years of experience in the energy industry and is a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers.

from the Mendoza School of

Business at the University of Notre Dame.

Such reserves estimates comply with generally accepted petroleum engineering and evaluation principles, definitions, and guidelines as established by the SEC.

The reserves information in this filing is based on estimates prepared by D&M.

The person responsible for the preparation of the reserve report is a Senior Vice President and Division Manager of North America at D&M.

He received a Bachelor of Science degree in Petroleum Engineering in 2003 from Istanbul Technical University and a Master’s degree and Doctorate in Petroleum Engineering in 2005 and 2010, respectively, from Texas A&M University, and he has in excess of 10 years of experience in oil and gas reservoir studies and evaluations.

We provide D&M with our property interests, production, current operating costs, current production prices, and other information in order to prepare the reserve estimates.

3 unchanged sentences

Our proved undeveloped reserves were 1,813 MBOE at June 30, 2021, with associated future development costs of approximately $8.6 million, which are associated with the Phase V development of Delhi field.

The Company does not have any proved undeveloped reserves associated with its Hamilton Dome field acquired in November of 2019.

The Company does not have any proved undeveloped reserves associated with its Hamilton Dome field or Barnett Shale asset.

During the year ended June 30, 2021 our proved undeveloped reserves changed as follows:

Total Reserves

(MBbls) Natural Gas

(MMcf) Total Reserves

June 30, 2020 1,648 216 — 1,864

2 unchanged sentences

June 30, 2021 1,605 208 — 1,813

Price declines resulted in a reclassification of a small volume of oil reserves from PDP to PUD at June 30, 2020.

Fiscal year 2020 price declines resulted in a reclassification of a small volume of oil reserves from PDP to PUD at June 30, 2020.

The decline in price led to currently producing wells becoming uneconomic at an earlier point in time than previously estimated.

However, when forecasted in conjunction with the PUD reserves the overall economic life of the field is extended.

Due to the EOR unit nature of Delhi, this PDP reduction shifts those reserves to our PUD oil reserves as they are considered proved and expected to be recovered as a result of the development of our Phase V.

NGL reserves were revised downward 25 MBbls primarily due to the adjusted methodology of projecting NGL volumes independent of oil production, shifting them into developed NGL volumes.

The infill program, consisting of ten producer wells and two CO 2 injection wells, was completed during 2019 resulting in the conversion of 463 MBbls of oil and and 73 MBOE of NGLs from proved undeveloped reserves to proved developed reserves.

Since this project's inception in March 2018, its net capital expenditures have totaled $4.6 million.

During fiscal year 2021, we experienced reductions in expenses and improvement of the NGL differential at Delhi which extended the economic life of the PDP reserves.

This caused a revision to PUD reserves by shifting them from PUD to PDP.

Additionally, changes to Phase V development timing, as further discussed below, have slightly decreased PUD reserves.

The initial assignment of proved undeveloped reserves in the Delhi field was made on June 30, 2010, which encompassed a large-scale CO 2 enhanced oil recovery project.

The operator’s development plans for the field have remained essentially unchanged and were originally scheduled to be completed by June 30, 2015, within five years from the initial recording of such proved reserves.

However, as a result of the adverse fluid release event in the field in June 2013 and the resulting delay in reversion of our working interest, development of the field has not proceeded as originally scheduled.

Expansion of the CO 2 flood to the remaining undeveloped eastern portion of the field commenced subsequent to reversion of our working interest in late calendar 2014.

We incurred $3.8 million of capital expenditures before the operator electively deferred this project as a result of a reduction in its cash flows and capital spending from the significant drop in oil prices.

The operator’s original development plans for the field to be completed by June 30, 2015, within five years from the initial recording of such proved reserves, has not proceeded as originally scheduled as a result of the adverse fluid release event in the field in June 2013 and the resulting delay in reversion of our working interest.

Expansion of the CO 2 flood to the remaining undeveloped eastern portion of the field commenced subsequent to reversion of our working interest in late calendar 2014 but was electively deferred by the operator shortly thereafter due to reductions in its cash flows and capital spending from the significant drop in oil prices.

This project was further electively deferred as we began work on the NGL recovery plant field in February 2015.

It was determined that the economics of development of the remaining eastern portion of the field would be significantly improved after the NGL plant was completed.

During fiscal 2015, we authorized the NGL plant project and from late in that fiscal year until January 2017 when production of NGLs began, we incurred $26.0 million of related capital expenditures.

The NGL plant was completed in December 2016 and we converted approximately 1,377 MBOE of proved undeveloped reserves to proved developed reserves during fiscal 2017.

Since completion of the plant, we have resumed work that had been suspended in late 2014 and further deferred until the NGL recovery plant was complete.

Cumulatively, we have spent $3.7 million as of June 30, 2020, including $0.6 million and $1.6 million in fiscal years 2020 and 2019, respectively, on the six well water curtain program and related infrastructure required to precede the development of Phase V.

As of June 30, 2020 we had drilled all the injection wells, including four gross injection wells during fiscal 2019, and commenced operations for one of the program's pads.

The program was configured as two pads, each having two injection wells and one water source well.

The second pad was completed during fiscal 2020 and began injections during our second quarter of fiscal 2020.

As of June 30, 2020, we have estimated total future net capital expenditures of approximately $8.6 million for remaining curtain infrastructure and development of Phase V in the eastern part of the field, which we expect to commence in May 2021 based on our discussions with the operator.

The timing of Phase V development is dependent on the field operator's available funds and capital spending plans and priorities within its portfolio of properties.

We believe this project is economic in the current oil price environment and we expect it to be completed within the next four fiscal years.

Authorization for construction of the NGL plant project occurred in fiscal 2015 and was completed in December 2016.

Since completion of the plant, we have resumed work that had been suspended in late 2014 and further deferred until the NGL recovery plant was complete, including construction of the six-well water curtain program and related infrastructure required to precede the development of Phase V.

All injection wells have been completed and injections from the second pad began in second quarter of fiscal 2020.

As of June 30, 2021, we have estimated total future net capital expenditures of approximately $8.6 million for remaining development of Phase V in the eastern part of the field, which we expect to commence in fiscal year 2023, however the timing is dependent on the field operator's available funds, capital spending plans, and priorities within its portfolio of properties.

We have been continuously developing the Delhi field and have spent over $48 million subsequent to reversion of our working interest in November 2014.

Given the long-term nature of CO 2 EOR development projects, we believe that the remaining undeveloped reserves in the Delhi field satisfy the conditions to continue to be treated as proved undeveloped reserves because (1) we initially established the development plan for the Delhi field in 2010 and continue to follow that plan, as adjusted to incorporate the completion of the NGL plant in late 2016 and delays relating to the 2013 adverse fluid release event;

incorporate the completion of the NGL plant in late 2016 and delays relating to the 2013 adverse fluid release event;

(2) we have had significant ongoing development activities at this project that, as budgeted and currently being expended, reflect a significant and sufficient portion of remaining capital expenditures to convert proved undeveloped reserves to proved developed reserves;

4 unchanged sentences

Sales Volumes, Average Sales Prices and Average Production Costs

The following table shows the Company's sales volumes and average sales prices received for crude oil, natural gas liquids, and natural gas for the periods indicated:

June 30, 2020

June 30, 2019

The following table shows the Company's sales volumes and average sales prices received for oil, NGLs, and natural gas for the periods indicated:

June 30, 2021 Year Ended

June 30, 2020 Year Ended

June 30, 2019

Crude oil (Bbls)

Natural gas liquids (Bbls)

Product Volume Price Volume Price Volume Price

Oil (Bbls) 554,888 $ 47.60 638,464 $ 44.76 626,879 $ 65.05

NGL (Bbls) 171,451 $ 21.36 106,159 $ 9.59 112,013 $ 21.87

Natural gas (Mcf) 963,496 $ 2.73 1,087 $ 1.90 459 $ 2.64

Average price per BOE* 886,922 $ 36.87 744,804 $ 39.74 738,968 $ 58.50

Production costs

Production costs Amount per BOE Amount per BOE Amount per BOE

Production costs, excluding ad valorem and production taxes $ 15,414,166 $ 17.38 $ 12,966,923 $ 17.41 $ 14,027,461 $ 18.98

Total production costs, including ad valorem and production taxes $ 16,587,052 $ 18.70 $ 13,505,502 $ 18.13 $ 14,266,784 $ 19.31

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of natural gas liquids to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.

*Equivalent oil reserves are defined as six MCF of gas and 42 gallons of NGLs to one barrel of oil conversion ratio which reflects energy equivalence and not price equivalence.

Gas prices per MCF and NGL prices per barrel often differ significantly from the equivalent amount of oil.

Drilling Activity

Our productive drilling activity during the past three fiscal years at Delhi field ended June 30, 2020 , and was limited to five gross (1.2 net) producer wells drilled and completed in fiscal 2019 and another five (1.2 net) producer wells completed in fiscal 2018.

We completed one (0.239 net) CO 2 injection well during fiscal 2019 and completed one (0.239 net) CO 2 injection well during fiscal 2018.

Our productive drilling activity at Delhi field during the past three fiscal years ended June 30, 2021, was limited to five (1.2 net) producer wells completed in fiscal 2019.

We completed one (0.24 net) CO 2 injection well during fiscal 2019.

No dry wells were drilled in the past three fiscal years.

In connection with establishing a six-well water curtain in advance of Phase V site development, during fiscal 2019 we drilled two (0.48 net) wells and completed three (0.72 net) wells.

In fiscal 2018, we drilled three (0.72 net) wells and in fiscal 2017 one (0.239 net) well was drilled.

There were no new wells drilled in fiscal 2020 or fiscal 2021.

In connection with establishing a six-well water curtain on two pads in advance of Phase V site development, during fiscal 2019 our operator drilled two (0.48 net) wells and completed three (0.72 net) wells.

A pad consists of one gross water source well and two gross water injector wells.

The three completed wells comprise the northern pad of the water curtain program which commenced injection during fiscal 2019.

The southern pad became fully operational late in the second quarter of fiscal 2020 when capital expenditures for completion work concluded.

The northern pad commenced injection during fiscal 2019 and the southern pad became fully operational late in the second quarter of fiscal 2020 when capital expenditures for completion work concluded.

Barnett Shale acreage contains potential drilling locations;

however, they are not included within our proved reserves as of June 30, 2021.

Diversified Energy has recently acquired the assets and has not yet formalized a capital drilling budget for fiscal year 2022.

Hamilton Dome field is considered fully developed.

1 unchanged sentence

Present Activities

The operator is completing a SCADA (supervisory control and data acquisition) well monitoring capital project at present which will improve the flow of information and assist in the real-time management of the Delhi field.

There are no significant drilling plans until Phase V development, expected to commence in the fourth quarter of fiscal 2021.

Starting in late third quarter 2021, the operator of the Delhi field resumed some capital conformance work to recomplete existing wells into different production zones, including recompleting a temporarily abandoned well in Test Site V.

This work is still ongoing and too early to quantify the impact of these projects on the patterns.

There are no significant drilling plans until Phase V development, expected to commence in 2023.

The Hamilton Dome operator is performing expense workovers within the field to maintain production and expects to plug four wells in first half of fiscal year 2022.

There are currently no capital projects proposed within the field for fiscal year 2022.

The primary Barnett Shale operator has recently taken over as operator and has yet to formalize a budget, however they have expressed interest in identifying and performing remedial workovers to maintain and restore production.

For further discussion, see “Highlights for our fiscal year 2021” and “Capital Expenditures” within Item 7.

Delivery Commitments

As of June 30, 2020 , we were not committed to provide a fixed and determinable quantity of oil, NGLs or gas under existing agreements, nor do we currently intend to enter into any such agreements.

If the price of oil remains above $32.00, we have a financial commitment as we entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel.

As of June 30, 2021, we were not committed to provide a fixed and determinable quantity of oil, NGLs, or natural gas under existing agreements, nor do we currently intend to enter into any such agreements.

Productive Wells

The following table sets forth the number of productive oil and gas wells in which we own a working interest as of June 30, 2021.

Company Operated

Company Operated Non-Operated Total

Gross Net Gross Net Gross Net

Oil — — 326 77 326 77

Natural gas — — 1,074 186 1,074 186

Total — — 1,400 263 1,400 263

The following table sets forth certain information regarding our developed and undeveloped lease acreage as of June 30, 2021.

1 unchanged sentence

Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves.

Developed Acreage

Undeveloped Acreage

Field (1) Developed Acreage Undeveloped Acreage Total

Gross Net Gross Net Gross Net

Delhi Field, Louisiana 9,126 2,180 4,510 1,077 13,636 3,257

Hamilton Dome Field, Wyoming 5,908 1,389 — — 5,908 1,389

Barnett Shale, Texas 123,777 20,918 — — 123,777 20,918

Total(2) 138,811 24,487 4,510 1,077 143,321 25,564

(1) All acreage, including any undeveloped, nonproductive or undrilled acreage, is held by existing production as long as continuous production is maintained in the unit.

2 unchanged sentences

It does not currently appear likely that we will obtain any significant value from these interests and no reserves have been assigned to any of the Giddings interests.

When the Company acquired the Delhi field in 2003, the field had been fully developed through primary and secondary recovery and all of such acreage was reflected as developed acreage.

With the addition of a CO 2 -EOR project in the field, certain acreage is now reflected as undeveloped using tertiary recovery operations.

When the Company acquired the Delhi field in 2003, the field had been fully developed through primary and secondary recovery methods and all of such acreage was reflected as developed acreage.

With the addition of a CO 2 -EOR project in the field, certain acreage is now reflected as undeveloped, due to the transition to using tertiary recovery methods.

We estimate that our developed acreage currently includes 9,126 gross (2,180 net) acres in the Delhi field, with approximately 4,510 gross (1,077 net) acres attributable to the remaining undeveloped areas in the eastern part of the field.

We own a 23.9% working interest in the field, along with certain mineral and royalty interests.

We are not the operator of the EOR project.

Our interests include all depths from the surface of the earth to the top of the Massive Anhydride, including the Delhi Holt Bryant Unit, which is currently under CO 2 flood, and the Mengel Sand Interval, which is within the boundary of the field, but is currently not producing.

As the Delhi field is unitized per the State of Louisiana Department of Conservation order number 96-G-5, all acreage, including any undeveloped, nonproductive or undrilled acreage is held by existing production as long as continuous production is maintained in the unit.

When the Company acquired Hamilton Dome field on November, 1 2019, the field had been fully developed through primary recovery and all acreage is reflected as developed acreage.

The Tensleep and Phosphoria were permitted for commingling and unitized in 1996 following purchase of the field by Merit Energy.

At the Delhi field, our interests include all depths from the ground surface to the top of the Massive Anhydride.

These depth rights include the Delhi Holt Bryant Unit (Tuscaloosa and Paluxy formations) which is currently under CO 2 flood, and the Mengel Sand Interval which is within the boundary of the field but is currently not producing.

As the Delhi field is unitized per the State of Louisiana Department of Conservation order number 96-G-5, all acreage, including any undeveloped, non-productive or undrilled acreage is held by existing production as long as continuous production is maintained in the unit.

When the Company acquired its interests in the Hamilton Dome field on November 1, 2019, the field had been fully developed through primary recovery and therefore all acreage is reflected as developed acreage.

The Tensleep and Phosphoria were permitted for commingling and unitized in 1996 following purchase of the field by Merit Energy in 1995.

The Company estimates that our developed acreage includes 5,908 gross (1,389 net) acres in the Hamilton Dome field, with no acres attributable as undeveloped.

We own 23.5% working interest in the field, along with a small overriding royalty interest.

As Hamilton Dome is unitized, all acreage is held by existing production as long as continuous production is maintained in the unit.

We are not operators of Hamilton Dome field.

For more complete information regarding current year activities, including crude oil and natural gas production, refer to Item 7.

The Company acquired the Barnett Shale field on May 7, 2021, which is currently being developed through primary recovery.

The Company estimates that our developed acreage includes 123,777 gross (20,918 net) acres in the Barnett Shale field, with no acres attributable as undeveloped.

For more complete information regarding current year activities, including oil and natural gas production, refer to Item 7.

Markets and Customers

Our production is marketed to third parties in a manner consistent with industry practices.

In the United States of America market, where we operate, crude oil and natural gas liquids are readily transportable and marketable.

We do not currently market our share of crude oil production from Delhi nor from Hamilton Dome separately from the operators' shares of production.

In the United States of America market where we operate, oil, natural gas, and NGLs are readily transportable and marketable.

We do not currently market our share of oil, natural gas, or NGLs production from the Delhi field, the Barnett Shale or from the Hamilton Dome field separately from the operators' shares of production.

Although we have the right to take our working interest production in-kind, we are currently selling our production through the field operators pursuant to the delivery and pricing terms of their sales contracts.

Under such arrangements we typically do not know the identity of the buyers of production except in the case of the Delhi field where there is a sole buyer for oil and another for NGL's.

Under such arrangements, we typically do not know the identity of the buyers of production except in the case of the Delhi field where there is a sole buyer for oil and another for NGL's, and in the case of the Barnett Shale where there is a sole buyer for approximately all of the natural gas.

The oil from Delhi is currently transported from the field by pipeline, which results in better net pricing than the alternative of transportation by truck.

Delhi crude oil production sells at Louisiana Light Sweet ("LLS") pricing which generally trades at a premium to West Texas Intermediate ("WTI") crude oil pricing.

The positive LLS Gulf Coast average price differential over WTI, as quoted daily on the New York Mercantile Exchange ("NYMEX"), was approximately $0.77 per barrel during our fiscal year ended June 30, 2020, compared to $4.11 per barrel for the prior year.

In the current fiscal year, the differential was impacted by market conditions over the second half of the fiscal year and trucking charges that were incurred for several months while the sales pipeline underwent repair.

NGL production is sold to a midstream processing company which fractionates the stream and sells the resulting hydrocarbons.

Delhi oil production sells at Louisiana Light Sweet (“LLS”) pricing which generally trades at a premium to West Texas Intermediate (“WTI”) oil pricing.

However, due to global market conditions, this premium was reduced during fiscal year ended 2021 versus fiscal year 2020.

The LLS Gulf Coast average price differential over WTI, as quoted daily on the New York Mercantile Exchange (“NYMEX”), was approximately $1.75 during our fiscal year ended June 30, 2021, compared to $3.70 for the prior year.

In the current fiscal year, the differential was impacted by market conditions over the fiscal year.

NGL production is sold to a midstream processing company that fractionates the stream and sells the resulting hydrocarbons.

The NGL revenues we receive are substantially reduced when the field oil realized price falls below $60 due to a capital recovery agreement with the operator;

however, the impact is partially offset by corresponding reduced gas plant operating expense.

On November 1, 2019, Evolution acquired a non-operated interest in the Hamilton Dome field in Wyoming.

All the field’s production is sour heavy crude oil which is the sole component of the field’s reserves.

Crude oil is transported by pipeline primarily to purchasers in Casper, Wyoming.

As a result of transportation differentials, the high sulfur content and low API gravity, this crude trades at a discount to WTI, averaging $17.62 lower over the last eight months.

All the field’s production is sour heavy oil which is the sole component of the field’s reserves.

Oil is transported by pipeline primarily to purchasers in Casper, Wyoming.

As a result of transportation differentials, the high sulfur content and low API gravity, this oil trades at a discount to WTI, averaging $9.60 lower for the year ended June 30, 2021, and $17.62 lower for the eight months ended June 30, 2020.

Although we have the option of taking our production in-kind, we have elected to have the operator market our share of production.

Our realized price is net of transportation and marketing costs.

The following table sets forth purchasers of our oil and natural gas liquid production for the years indicated:

On May 7, 2021, the Company acquired non-operated working interests in the Barnett Shale field in North Texas.

The asset's production has various zones of wet and dry gas.

The wet gas is gathered and transported by pipeline to a processing facility to process the wet gas into NGL components, oil condensate, and residue gas.

Although we have the option of taking our production in-kind, we have elected to have the operator market our share of production.

The following table sets forth purchasers of our oil, natural gas, and NGL production for the years indicated:

Year Ended June 30,

Customer 2021 2020

Plains Marketing L.P.

1 unchanged sentence

Merit Energy Company (Hamilton Dome field oil) 19 % 10 %

Third Coast Midstream (Delhi field NGLs)

The loss of a purchaser at either the Delhi or Hamilton Dome fields or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.

All others 19 % 3 %

Total 100 % 100 %

As the purchase of the Barnett Shale occurred on May 7, 2021, the Company expects purchases of our natural gas and NGL production from the Barnett Shale to represent a larger percentage of total sales in fiscal year 2022 and beyond.

The loss of a purchaser at the Delhi field, Barnett Shale, or the Hamilton Dome field or disruption to pipeline transportation from these fields could adversely affect our net realized pricing and potentially our near-term production levels.

Market Conditions

Marketing of crude oil, natural gas, and natural gas liquids and the prices we receive are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict.

These factors include changes in supply and demand, market prices, government regulation and actions of major foreign producers.

Oil prices over the past few years have fluctuated and been extremely volatile.

For example, average daily prices for WTI crude oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel over our past few fiscal years.

Starting in the fourth quarter of 2014, the price of oil per barrel dropped dramatically and continuing into 2017 before recovering somewhat in late calendar 2018, then weakening again in 2019 and dropping substantially in 2020 as a result of the impact of the COVID-19 pandemic and geopolitical factors.

Worldwide factors such as global health pandemics, geopolitical, international trade disruptions and tariffs, macroeconomic, supply and demand, refining capacity, petrochemical production and derivatives trading, among others, influence prices for crude oil.

Local factors also influence prices for crude oil and include increasing or decreasing production trends, quality differences, regulation and transportation issues unique to certain producing regions and reservoirs.

Prices we receive for oil, natural gas, and NGLs are influenced by many factors that are beyond our control, the exact effect of which is difficult to predict.

These factors include changes in supply and demand, market prices, government regulation, weather, and actions of major foreign producers.

Oil prices over the past few years have fluctuated widely and been extremely volatile.

For example, average daily prices for WTI oil ranged from a high of $74 per barrel to a low of a negative $38 per barrel over our last two fiscal years.

The price of oil per barrel dropped substantially in fiscal 2020 as a result of the impact of the COVID-19 pandemic and geopolitical factors but recovered to average above $66 per barrel during the fiscal fourth quarter of 2021.

The severe drop in oil price during the pandemic and market share competition between OPEC+ members in the Spring of 2020 substantially and adversely impacted oil, gas, and NGL prices during the balance of 2020, thus impacted the trailing twelve-month commodity prices required for reserves and ceiling tests for asset carrying value which in turn led to substantial impairments during our first and second quarters of fiscal 2021.

Worldwide factors such as global health pandemics, geopolitical, international trade disruptions and tariffs, macroeconomics, supply and demand, refining capacity, petrochemical production, and derivatives trading, among others, influence prices for oil, natural gas, and NGLs.

Local factors also influence prices for oil, natural gas, and NGLs and include increasing or decreasing production trends, quality differences, regulation, and transportation issues unique to certain producing regions and reservoirs.

The oil and natural gas industry is highly competitive for prospects, acreage, and capital.

Our competitors include major integrated crude oil and natural gas companies, numerous independent crude oil and natural gas companies, individuals, and drilling and income programs.

Many of our competitors are large, well-established companies with substantially larger operating staffs and greater capital resources.

Our competitors include major integrated oil and natural gas companies, numerous independent oil and natural gas companies, individuals, and drilling and income programs.

Many of our competitors are large, well-established companies with substantially larger operating staff and greater capital resources.

Competitors are national, regional, or local in scope and compete on the basis of financial resources, technical prowess or local knowledge.

The principal competitive factors in our industry are expertise in given geographical areas and geological systems and the abilities to efficiently conduct operations, achieve technological advantages, identify, and acquire economically producible reserves and obtain capital at rates which allow economic investments.

The principal competitive factors in our industry are expertise in given geographical areas and geologic systems and the ability to efficiently conduct operations, achieve technological advantages, identify and acquire economically producible reserves, and obtain capital at rates that allow economic investments.

Risk Management

3 unchanged sentences

We do not enter into derivative contracts for speculative trading purposes.

While there are many different types of derivatives available, we typically use fixed-price swap and costless collars to attempt to manage price risk.

While there are many different types of derivatives available, we typically use fixed-price swaps and costless collars to attempt to manage price risk.

The fixed-price swap agreements call for payments to, or receipts from, counterparties depending on whether the index price of oil or natural gas for the period is greater or less than the fixed price established for the period contracted under the fixed-price swap agreement.

1 unchanged sentence

All costless collar agreements provide for payments to counterparties if the settlement price under the agreement exceeds the ceiling and payments from the counterparties if the settlement price under the agreement is below the floor.

We entered into NYMEX WTI oil swaps covering approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel.

During fiscal 2020, we entered into NYMEX WTI oil swaps that covered approximately 42,000 barrels per month for the period of April 2020 through December 2020 at a fixed swap price of $32.00 per barrel.

As of June 30, 2021, we did not have any open fixed-price swaps or costless collars.

In the future, we may add additional swaps or other derivative positions covering a variable portion of our anticipated future production during subsequent periods.

It is our policy to enter into derivative contracts only with counterparties that are creditworthy financial institutions deemed by management as competent and competitive market makers.

As of June 30, 2020, we did not post collateral under any of our derivative contracts as they are uncollateralized trades.

For the year ended June 30, 2021, we did not post collateral under any of our derivative contracts as they are uncollateralized trades.

We will continue to evaluate the benefit of employing derivatives in the future.

1 unchanged sentence

Government Regulation

Numerous federal and state laws and regulations govern the oil and gas industry, including environmental laws and regulations.

Numerous federal and state laws and regulations govern the oil and natural gas industry, including environmental laws and regulations.

These laws and regulations are often changed in response to changes in the political or economic environment.

Compliance with this evolving regulatory environment is often difficult and costly;

substantial penalties may be incurred for noncompliance.

substantial penalties may be incurred for

noncompliance.

To the best of our knowledge, we are in compliance with all federal and state-level laws and regulations applicable to our operations.

The future annual capital cost of complying with the regulations applicable to our operations is

uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable.

The future annual capital cost of complying with the regulations applicable to our operations is uncertain and will be governed by several factors, including future changes to regulatory requirements which are unpredictable.

We do not currently anticipate that continued and future compliance with existing laws and regulations will have a materially adverse effect on our consolidated financial position or results of operations.

See discussion captioned “Government regulation and liability for oil and gas operations and environmental matters may adversely affect our business and results of operations” in Item 1A.

We maintain insurance on our oil and gas properties and operations for risks and in amounts customary in the industry.

We maintain insurance on our oil and natural gas properties and operations for risks and in amounts customary in the industry.

Such insurance includes general liability, excess liability, control of well, operators extra expense, casualty, fraud, and directors and officer's liability coverage.

1 unchanged sentence

We do not carry lost profits coverage, and we do not have coverage for consequential damages.

At June 30, 2020 , we had four full-time employees, not including contract personnel and outsourced service providers.

None of the Company’s employees are currently represented by a union, and the Company believes that it has excellent relations with its employees.

Our team is broadly experienced in oil and gas operations, development, acquisitions and financing.

At June 30, 2021, we had five full-time employees, not including contract personnel and outsourced service providers.

None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees.

Our team is broadly experienced in oil and natural gas operations, development, acquisitions, and financing.

We follow a strategy of outsourcing most of our property accounting, human resources, administrative, and other non-core functions.

9 unchanged sentences

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business