What changed in this filing

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Item 2. Management’s Discussion and Analysis

2022-11-21 compared with 2022-08-19 · 149 added, 193 removed, 187 unchanged (65% of the section changed)

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We are an independent oil and natural gas company engaged in acquiring, developing, and producing oil and natural gas.

We presently own producing and non-producing

properties located primarily in Texas, and Oklahoma.

We also own a 12.5% over-riding royalty interest in over 30,000 acres in the state of West Virginia.

In addition, we own a substantial amount of well-servicing equipment and, through a wholly owned offshore company, a 60-mile-long

pipeline offshore on the shallow shelf of Texas.

We also hold a 30% interest in a limited partnership which owns a 138,000 square foot retail shopping center on ten acres in Prattville, Alabama.

We presently own producing and non-producing properties located primarily in Texas, and Oklahoma.

We also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia.

We are currently not receiving revenue from this asset, as development has not begun.

In addition, we own well-servicing equipment and, through a wholly owned offshore company, a 60-mile-long pipeline offshore on the shallow shelf of Texas not currently in use.

We also hold a 33.3% interest in a limited partnership that owns a 138,000-square-foot retail shopping center on ten acres in Prattville, Alabama.

There is currently no debt on the shopping center and it has approximately $500,000 of working capital on its balance sheet.

All of our oil and gas properties and interests are located in the United States.

Assets in our principal focus areas include mature properties with long-lived reserves and significant development opportunities, as well as, newer properties with development and exploration potential.

We believe our balanced portfolio of assets position us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities.

Our primary sources of liquidity are cash generated from our operations and our credit facility.

We believe our balanced portfolio of assets positions us well for both the current commodity price environment and future potential upside as we develop our attractive resource opportunities.

Our primary sources of liquidity are cash generated from our operations, our credit facility and existing cash on our balance sheet.

In addition to developing our oil and natural gas reserves, we continue to actively pursue the acquisition of producing properties.

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This practice may prevent us from receiving the full advantage of any increases in oil and gas prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements.

Since all our derivative contracts are accounted for under mark-to-market

accounting, we expect continued volatility in gains and losses on mark-to-market

derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

Since our derivative contracts are accounted for under mark-to-market accounting, we expect continued volatility in gains and losses on mark-to-market derivative contracts in our consolidated statement of operations as changes occur in the NYMEX price indices.

Our existing derivative instruments expire in March of 2023 and at this time we do not intend to enter into future derivative contracts unless required for our bank line of credit.

Our financial results depend on many factors, particularly the price of natural gas and crude oil and our ability to market our production on economically attractive terms.

Commodity prices are affected by many factors outside of our control, including changes in market supply and demand, which are impacted by weather conditions, pipeline capacity constraints, inventory storage levels, basis differentials and other factors.

In addition, our realized prices are further impacted by our derivative and hedging activities.

In addition, our realized prices are further impacted by our derivative and hedging activities when used to manage commodity price risk.

As mentioned above, our existing contracts are set to expire in March of 2023 and we currently do not intend to use future derivative contracts unless required by our bank loan.

We derive our revenue and cash flow principally from the sale of oil, natural gas, and NGLs.

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consequently, we cannot accurately predict or control the price we may receive for our oil, natural gas, and NGLs.

Index prices for oil, natural gas and NGL’s have improved since the lows of 2020, however, we expect prices to remain volatile and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue.

Index prices for oil, natural gas, and NGL’s are higher than in the recent past, however, prices may be volatile and, consequently, we cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue.

We are the operator of the majority of our developed and undeveloped acreage which is nearly all held by production.

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Proved Reserves as of December 31, 2021 (MBoe)

Undeveloped Total

Average Net Daily Production (Boe per day)

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Gross Operated Water Disposal, Injection and Supply wells

In several of our producing regions we have field service groups to service our operated wells and locations as well as third-party operators in the area.

In several of our producing regions we have field service groups to service our operated wells and locations as well as third-party operators.

These services consist of well service support, site preparation and construction services for drilling and workover operations.

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Services including well service support, site preparation and construction services for drilling and workover operations are provided to third-party operators as well as utilized in our own operated wells and locations.

The Company also owns, through its wholly owned offshore company, a 60-mile-long

pipeline on the shallow shelf of Texas that is currently idle, but may someday have value.

As of June 30, 2022, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Mid-Continent

Our Mid-Continent

activities are concentrated in central Oklahoma.

The Company also owns, through its wholly-owned offshore company, a 60-mile-long pipeline on the shallow shelf of Texas that is currently idle but may someday have value.

As of September 30, 2022, the Gulf Coast region has no operated wells in the process of being drilled, no waterfloods in the process of being installed and no other related activities of material importance.

Mid-Continent Region

Our Mid-Continent activities are concentrated in central Oklahoma.

This region is managed from our office in Oklahoma City, Oklahoma.

As of December 31, 2021, we had 549 producing wells (189 net) in the Mid-Continent

area, of which 195 wells are operated by us.

As of December 31, 2021, we had 549 producing wells (189 net) in the Mid-Continent area, of which 195 wells are operated by us.

Principal producing intervals are in the Roberson, Avant, Skinner, Sycamore, Bromide, McLish, Hunton, Mississippian, Oswego, Red Fork, and Chester formations at depths ranging from 1,100 to 10,500 feet.

Average net daily production in our Mid-Continent

Region in 2021 was 747 Boe.

At December 31, 2021, we had 2,383 MBoe of proved reserves in the Mid-Continent

area, representing 20% of our total proved reserves.

Average net daily production in our Mid-Continent Region in 2021 was 747 Boe.

On December 31, 2021, we had 2,383 MBoe of proved reserves in the Mid-Continent area, representing 20% of our total proved reserves.

We maintain an acreage position of approximately 47,120 gross (10,300 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties.

Our Mid-Continent

region is actively participating with third-party operators in the horizontal development of lands that include Company owned interests in several counties in the Stack and Scoop plays of Oklahoma where drilling primarily targets reservoirs of the Mississippian and Woodford formations.

In the first half of 2022, in the Mid-Continent

region, the Company participated with 9.38% interest in the drilling of four horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent

Our Mid-Continent region is actively participating with third-party operators in the horizontal development of lands that include Company owned interests in several counties in the Stack and Scoop plays of Oklahoma where drilling primarily targets reservoirs of the Mississippian and Woodford formations.

In the first half of 2022, in the Mid-Continent region, the Company participated with 9.38% interest in the drilling of four horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc.

All four wells have been completed and are online as of August 1st.

The resulting reserves of this new drilling will be an addition to our 2021 year-end

reserve base.

The resulting production is an addition to our 2021 year-end proved producing reserve base.

The Company divested of 354 non-strategic acres in Canadian County, year-to-date, with proceeds of $1.269 million.

West Texas Region

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As of December 31, 2021, we had 576 wells (263 net) in the West Texas area, of which 321 wells are operated by us.

Average net daily production in Our West Texas Region in 2021 was 2,878 Boe.

At December 31, 2021, we had 8,957 MBoe of proved reserves in the West Texas area, or 73% of our total proved reserves.

The average net daily production in Our West Texas Region in 2021 was 2,878 Boe.

On December 31, 2021, we had 8,957 MBoe of proved reserves in the West Texas area, or 73% of our total proved reserves.

We maintain an acreage position of approximately 16,960 gross (10,640 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties, and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals.

We operate a field service group in this region utilizing nine workover rigs, four hot oiler trucks, one kill truck, and two roustabout trucks.

Services, including well service support, site preparation, and construction services for drilling and workover operations, are provided to third-party operators as well as utilized in our own operated wells and locations.

In the first half of 2022, the Company participated with 10.3% interest in the drilling of four 1.5-mile-long

horizontal wells in Irion County, Texas operated by SEM Operating Company, LLC.

All four wells have been drilled and completed and are expected to start production in August of 2022.

In addition to the eight wells drilled in the first half of 2022, the Company has received proposals for 24 new horizontal wells in West Texas:

fifteen planned for the second half of 2022 and eleven for the first quarter of 2023.

In the fourth quarter of this year, we expect to participate with 27% interest in the drilling of five 2.5-mile-long

horizontal wells in Martin County, Texas with ConocoPhillips and to participate with 25% interest in the drilling of ten 2-mile-long

horizontals with Hibernia Energy III, LLC.

In the first quarter of 2023, we anticipate the start of nine 2.5-mile-long

horizontals with BTA Oil Producers, LLC in Reagan County, and two 3-mile-long

horizontals with Apache Corporation in Upton County.

The Company will participate with an average of approximately 42% interest in the BTA wells and 47% in the Apache wells.

These proved undeveloped drilling plans were added in 2022 and therefore are not represented in the year-end

2021 reserves report.

In the first half of 2022, the Company participated with 10.3% interest in the drilling of four 1.5-mile-long horizontal wells in Irion County, Texas operated by SEM Operating Company, LLC.

All four wells have been drilled and completed and began production in early August.

In the fourth quarter of 2022, the Company completed an acreage exchange agreement with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin.

In combination with existing acreage, this newly acquired acreage results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp formation and other prospective reservoirs through 2-mile-long horizontal laterals.

Along with the 1,200 contiguous acres created from the acreage exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a 2,560-acre AMI for the joint development of horizontal wells.

As part of the agreement, the Company has divested of a portion of its interest to operator for $16.1 million with the ability to acquire additional acreage from the operator located within the AMI.

These exchanges should result in an approximately 50/50 ownership of the development with the operator.

This newly formed 2,560 acreage-block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.

In the fourth quarter of this year, we plan to participate with 20.8% interest in the drilling of five 2.5-mile-long horizontal wells in Martin County, Texas operated by ConocoPhillips, and to participate with 25% interest in the drilling of ten 2-mile-long horizontals in Reagan County, Texas with Hibernia Energy III, LLC.

In the first quarter of 2023, BTA Oil Producers, LLC has indicated plans to drill nine 2.5-mile-long horizontals in Reagan County, Texas in which the Company will have an average 42 % interest.

In addition, we plan to participate for 47% interest in two 3-mile-long horizontals with Apache Corporation in Upton County.

In total, the Company will invest approximately $87 million in these 26 new wells with completions expected in the Spring of 2023 and all to be on production by mid-year 2023.

Reserve Information:

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Report on Registrant’s Reserves Estimates.

In matters related to the preparation of our reserve estimates, our district managers report to the Engineering Data manager, who maintains oversight and compliance responsibility for the internal reserve estimate process and provides oversight for the annual preparation of reserve estimates of 100% of our year-end

reserves by our independent third-party engineers, Ryder Scott Company, L.P.

The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight and twenty-five years of experience managing our reserves.

The members of our district and central groups consist of degreed engineers and geologists with between approximately twenty and thirty-five years of industry experience, and between eight and

twenty-five years of experience managing our reserves.

Our Engineering Data manager, the technical person primarily responsible for overseeing the preparation of reserves estimates, has over thirty years of experience, holds a Bachelor degree in Geology and an MBA in finance and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.

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In 2020, in West Texas we participated in the drilling of seven wells:

one for 8.6% interest which was brought into production in July of 2020, and six wells with an average 47.5% interest that were drilled but not completed at year-end

and therefore classified as Proved Undeveloped in the year-end

reserve report.

one for 8.6% interest which was brought into production in July of 2020, and six wells with an average 47.5% interest that were drilled but not completed at year-end and therefore classified as Proved Undeveloped in the year-end reserve report.

The Company invested approximately $8.0 million in these seven wells in 2020.

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In addition, three wells drilled in Oklahoma in 2018, were completed in 2019 converting 24 Mboe of reserves to proved developed.

Also in Oklahoma, six wells designated as Shut-in

on December 31, 2018, were brought into production in 2019:

Also in Oklahoma, six wells designated as Shut-in on December 31, 2018, were brought into production in 2019:

five located on our Ruthie tract, and one on our Braum tract.

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In 2020, the Company successfully recompleted one additional operated well in the Segno field with a 72.5% interest.

At December 31, 2020, in total, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, 10 of which were drilled but not completed by year-end

2020, and three that were not drilled until 2021.

The three new horizontals along with the six uncompleted wells at year-end

were brought online in late September and early October of 2021.

At December 31, 2020, in total, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, 10 of which were drilled but not completed by year-end 2020, and three that were not drilled until 2021.

The three new horizontals along with the six uncompleted wells at year-end were brought online in late September and early October of 2021.

These successful new wells are on our Kashmir tract in Upton County, Texas operated by Apache Corporation.

These nine PUD wells at year-end

2020 accounted for 3,127 Mboe of the total undeveloped reserves where the Company has an average 47.5% interest and invested approximately $30 million dollars in these wells.

The four other PUD wells, drilled but not completed at year-end

2020, are located in Grady County, Oklahoma and accounted for 95 Mboe of the total undeveloped reserves.

At December 31, 2021, the Company had 159 Mboe of proved developed shut-in

reserves attributable to three horizontal wells drilled and completed in Canadian County, Oklahoma in December of 2021, but not yet online.

These nine PUD wells at year-end 2020 accounted for 3,127 Mboe of the total undeveloped reserves where the Company has an average 47.5% interest and invested approximately $30 million dollars in these wells.

The four other PUD wells, drilled but not completed at year-end 2020, are located in Grady County, Oklahoma and accounted for 95 Mboe of the total undeveloped reserves.

At December 31, 2021, the Company had 159 Mboe of proved developed shut-in reserves attributable to three horizontal wells drilled and completed in Canadian County, Oklahoma in December of 2021, but not yet online.

Three of the four wells were successfully completed and online in January, 2022, while one well had completion issues and has been temporarily abandoned.

Regarding the four drilled but uncompleted PUD wells in Grady County, Oklahoma noted in the paragraph above, reserves previously attributed to these wells were not included in the 2021 year-end

reserve report as the operator has no near-term plans for their completion.

In the first half of 2022, in our West Texas horizontal drilling program, we participated with 10.3% interest in the drilling of four horizontal wells with SEM Operating Company and have received proposals for an additional 24 horizontal wells, 15 of those to begin in the fourth quarter of this year.

Regarding the four drilled but uncompleted PUD wells in Grady County, Oklahoma noted in the paragraph above, reserves previously attributed to these wells were not included in the 2021 year-end reserve report as the operator has no near-term plans for their completion.

During 2022, in our West Texas horizontal drilling program, we participated with 10.3% interest in the drilling of four horizontal wells with SEM Operating Company and have received proposals for an additional 24 horizontal wells, 15 of those to begin in the fourth quarter of this year.

In total, the Company is likely to invest approximately $75 million in these 28 wells.

In Oklahoma, thus far in 2022, the Company is participating for 9.38% interest with Ovintiv Mid-Continent

in the drilling of four wells on our Bohlman tract in Canadian County, Oklahoma.

These four wells and the four SEM wells in West Texas are anticipated to be online in August of this year.

In the first quarter of 2023, we intent to participate with Apache in the drilling of two 3-mile-long

horizontals in Upton County, Texas and with BTA Oil Producers in the drilling of nine 2.5 mile-long horizontals in Reagan County, Texas.

In Oklahoma, thus far in 2022, the Company is participating for 9.38% interest with Ovintiv Mid-Continent in the drilling of four wells on our Bohlman tract in Canadian County, Oklahoma.

These four wells and the four SEM wells in West Texas were placed in production during August of this year.

In the first quarter of 2023, we intent to participate with Apache in the drilling of two 3-mile-long horizontals in Upton County, Texas and with BTA Oil Producers in the drilling of nine 2.5 mile-long horizontals in Reagan County, Texas.

Additional drilling and future development plans will be established based on an expectation of available cash flows from operations and availability of funds under our revolving credit facility.

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We use this measure when assessing the potential return on investment related to oil and gas properties.

The PV10 of future income taxes represents the sole reconciling item between this non-GAAP

PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow.

The PV10 of future income taxes represents the sole reconciling item between this non-GAAP PV10 Value versus the GAAP measure presented in the standardized measure of discounted cash flow.

A reconciliation of these values is presented in the last three columns of the table above.

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“Proved undeveloped” oil and gas reserves are reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Our reserves include amounts attributable to non-controlling

interests in the Partnerships.

Our reserves include amounts attributable to non-controlling interests in the Partnerships.

These interests represent less than 10% of our reserves.

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Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $3.598 per MMBtu in 2021 as compared to $1.985 per MMBtu in 2020, and $2.581 per MMBtu in 2019.

Through November 1, 2022, the twelve-month average of the first of the month Henry Hub index price is $6.166 per MMBtu.

Oil prices, based on the NYMEX first of the month average price, were $66.56 per barrel in 2021 as compared to $39.57 per barrel in 2020, and $55.69 per barrel in 2019.

Through November 1, 2022, the NYMEX first of the month average price was $92.37.

Since January 1, 2021, we have not filed any estimates of our oil and gas reserves with, nor were any such estimates included in any reports to, any federal authority or agency, other than the Securities and Exchange Commission.

RECENT ACTIVITIES

The Company’s activities include development and exploratory drilling.

Our strategy is to develop the Company’s extensive oil and gas reserves primarily through horizontal drilling.

This strategy includes targeting reservoirs with high initial production rates and cash flow as well as targeting reservoirs with lower initial production rates but with higher expected return on investment.

We believe that with today’s technology, horizontal development of our reserves provides superior economic results as compared to vertical development, by delivering higher production rates through greater contact and stimulation of a larger volume of reservoir rock while minimizing the surface footprint required to develop those same reserves.

Maintaining a strong balance sheet and ample liquidity are key components of our business strategy.

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Our capital budget for the year is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.

As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic

assets, or enter into strategic joint ventures.

In the third quarter of 2021, nine two-mile

horizontal wells in Upton County, Texas, operated by Apache Corporation, were completed and brought into production.

In the fourth quarter of 2021, three two-mile

horizontal wells operated by Ovintiv Mid-Continent

in Canadian County, Oklahoma were completed and brought online in January 2022.

As we have done historically to preserve or enhance liquidity, we may adjust our capital program throughout the year, divest non-strategic assets, or enter into strategic joint ventures.

In the third quarter of 2021, nine two-mile horizontal wells in Upton County, Texas, operated by Apache Corporation, were completed and brought into production.

In the fourth quarter of 2021, three two-mile horizontal wells operated by Ovintiv Mid-Continent in Canadian County, Oklahoma were completed and brought online in January 2022.

The Company has an average of 47.5% interest in the nine wells completed with Apache and 11.25% interest in the three wells completed with Ovintiv.

Through the second quarter of 2022, the Company has participated with SEM Operating Company LLC in the drilling of four 7,900’ horizontal wells in Irion County, Texas with 10.3% interest, and participated with Ovintiv Mid-Continent

Inc in the drilling of four 10,000’-long horizontal wells in Canadian County, Oklahoma with 9.38% interest.

All eight of these wells are in the process of being completed and are expected to be producing in August of this year.

An additional 15 wells are planned to begin development in the fourth quarter of 2022;

five with ConocoPhillips, and ten with Hibernia Energy III.

In the first quarter of 2023, we are planning the drilling of two horizontals in Upton County, Texas, with Apache Corporation and nine horizontals with BTA Oil Producers in Reagan County, Texas.

In the second quarter of 2022, the Company participated with SEM Operating Company LLC in the drilling of four 7,900’ horizontal wells in Irion County, Texas with 10.3% interest.

These four wells began their production in August.

Also in the second quarter of 2022, the Company participated in the drilling of four 10,000’-long horizontal wells in Canadian County, Oklahoma with 9.38% interest.

These four wells, operated by Ovintiv Mid-Continent, were also put into production in early August of this year.

In the fourth quarter of this year another fifteen wells are planned to be spud.

Since the start of our West Texas horizontal drilling program in 2015, we have participated in 81 wells and invested approximately $130 million in horizontal drilling in the Permian Basin.

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Together with Apache, we are planning development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs of this block.

These shallower reservoirs have been proven-up

on our offset 1,300 acre Kashmir tract.

These shallower reservoirs have been proven-up on our offset 1,300-acre Kashmir tract.

It is expected that as many as 36 additional horizontals will be developed on this 3,260-acres in the near future.

This development is estimated to cost approximately $387.0 million, with the Company’s share being approximately $174.4 million.

Two 3-mile-long

horizontals have been slated for the first quarter of 2023.

Two 3-mile-long horizontals have been slated for the first quarter of 2023.

In addition to the 36 prospective wells to be drilled for these three reservoirs, a fourth target reservoir, the Middle Spraberry, is also prospective for future development.

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In 2016 and 2017, four horizontal wells were drilled, completed, and put on production.

The Company owns 35% to 38% interest in this joint venture acreage where we have potential to drill as many as 36 additional wells.

As mentioned above, in West Texas, the Company is participating for 10.3% interest with SEM Operating Company in four 7,900’-long horizontal wells in Irion County, Texas.

We anticipate an investment of $2.55 million in these wells and for them to begin production in August.

Also planned for this year is the drilling of ten 2-mile-long

horizontals in Hibernia Energy, III, LLC, in Reagan County, Texas and the drilling of five 2.5 mile long horizontal wells with ConocoPhillips in Martin County.

The Company intends to participate for approximately 25% interest in the ten wells with Hibernia and for 27% interest in the five wells with Connoco Phillips.

The Company owns 35% to 38% interest in this joint venture acreage where we have the potential to drill as many as 36 additional wells.

As mentioned above, in West Texas, the Company participated for 10.3% interest with SEM Operating Company in four 7,900’-long horizontal wells in Irion County, Texas.

We anticipate an investment of $2.55 million in these wells which have been producing since August.

Also planned for this year is the drilling of ten 2-mile-long horizontals in Hibernia Energy, III, LLC, in Reagan County, Texas and the drilling of five 2.5-mile-long horizontal wells with ConocoPhillips in Martin County.

The Company intends to participate for approximately 25% interest in the ten wells with Hibernia and for 20.8% interest in five wells with Conoco Phillips.

Our expected investment in the drilling and completion of these wells is $36.3 million.

In Oklahoma, we are focused on development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 5,800 net leasehold acres in the Scoop/Stack Play.

In the fourth quarter of 2022, the Company completed an acreage exchange agreement with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin.

As part of the agreement, the Company has divested of a portion of its interest to operator for $16.1 million with the ability to acquire additional acreage from the operator located within the AMI.

These exchanges should result in an approximately 50/50 ownership of the development with the operator.

In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 5,800 net leasehold acres in the Scoop/Stack Play.

In 2019, we participated for an average of 4.6% interest with Newfield Exploration in twelve successful wells in Canadian County on our Slash and Wallace tracts.

In 2021, we participated for 11.25% interest with Ovintiv Mid-Continent

In 2021, we participated for 11.25% interest with Ovintiv Mid-Continent Inc.

in four wells on our Peters tract, in Canadian County.

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At today’s product prices, payout of the Company’s $2.3 million investment in these four wells occurred in four months.

In April 2022, in Oklahoma, the Company and Ovintiv Mid-Continent

began drilling four horizontal wells on our Bohlman tract in the same area as the successful Peters wells.

All four of the Bohlman wells have been drilled, completed, and are flowing back.

The Company is participating with 9.38% interest with an approximate investment $2.2 million

In April 2022, in Oklahoma, the Company and Ovintiv Mid-Continent began drilling four horizontal wells on our Bohlman tract in the same area as the successful Peters wells.

All four of the Bohlman wells have been drilled, completed, and were placed on production in early August..

The Company is participating with 9.38% interest in these wells with an approximate investment $2.45 million.

In May, we sold 241 acres in Canadian County, Oklahoma for proceeds of $845,000, and in August another 113 acres for $423,700.

Both of these sales were of non-strategic acreage and the Company retained its interest in existing wells and a small overriding royalty interest in future development.

We believe our 5,800 net leasehold acres in Oklahoma have the resource potential to support the drilling of as many as 50 new horizontal wells based on an estimate of four wells per multi-section drilling unit:

two in the Mississippian and two in the Woodford Shale.

Should we choose to participate in future development, our share of the capital expenditures would be approximately $34.6 million at an average 10% ownership level;

Should we choose to participate in future development, our share of the capital expenditures would be approximately 34.6 million at a 10% ownership level;

the Company will otherwise sell its rights for cash or cash plus a royalty or working interest.

RESULTS OF OPERATIONS

2022 and 2021 Compared

We reported net income of $22.1 million, or $11.18 per share and $11 million, or $5.57 per share for the six and three months ended June 30, 2022, respectively, as compared to net losses of $3.9 million, or $1.93 per share and $2.4 million, or $1.20 per share for the six and three months ended June 30, 2021, respectively.

Current year net income reflects increases in production and commodity price increases over the three and six months ended June 30, 2021, fluctuations in gains related to the sale of assets and changes related to the valuation of derivative instruments.

The significant components of income and expense are discussed below.

Oil, gas and NGLs sales

increased $19.6 million, or 127.3% from $15.4 million for the three months ended June 30, 2021 to $34.9 million for the three months ended June 30, 2022, and $40.8 million, or 145.5% from $28.0 million for the six months ended June 30, 2021 to $68.8 million for the six months ended June 30, 2022.

The following tables summarizes the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2022 and 2021 (excluding realized gains and losses from derivatives).

Six months ended June 30,

Barrels of Oil Produced

Average Price Received

Oil Revenue (In 000’s)

Mcf of Gas Sold

Average Price Received

Gas Revenue (In 000’s)

Barrels of Natural Gas Liquids Sold

Average Price Received

Natural Gas Liquids Revenue (In 000’s)

Total Oil & Gas Revenue (In 000’s)

Three months ended June 30,

Barrels of Oil Produced

Average Price Received

Oil Revenue (In 000’s)

Mcf of Gas Sold

Average Price Received

Gas Revenue (In 000’s)

Barrels of Natural Gas Liquids Sold

Average Price Received

Natural Gas Liquids Revenue (In 000’s)

Total Oil & Gas Revenue (In 000’s)

Oil, Natural Gas and NGL Derivatives

We do not apply hedge accounting to any of our commodity based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market

adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations.

As oil and natural gas prices remain volatile, mark-to-market

accounting treatment creates volatility in our revenues.

The following table summarizes the results of our derivative instruments for the three and six months ended June 2022 and 2021:

Three Months Ended

Six Months Ended

($ in thousand)

Oil derivatives – realized losses

Oil derivatives – unrealized gains (losses)

Total losses on oil derivatives

Natural gas derivatives – realized losses

Natural gas derivatives – unrealized gains (losses)

Total losses on natural gas derivatives

Total losses on oil and natural gas derivatives

Prices received for the six months ended June 30, 2022 and 2021, respectively, including the impact of derivatives were:

Field service income

increased $1.3 million or 54.2% from $2.4 million for the second quarter 2021 to $3.7 million for the second quarter 2022 and increased $3.2 million, or 84.2% from $3.8 million for the six months ended June 30, 2021 to $7.0 million for the six months ended June 30, 2022.

These changes reflect the increase in utilization and rates resulting from the oil and gas price increases during these periods.

Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

Lease operating expense

increased $4.8 million or 109.1% from $4.4 million for the second quarter 2021 to $9.2 million for the second quarter 2022 and increased $9.0 million or 101.1% from $8.9 million for the six months ended June 30, 2021 to $17.9 million for the six months ended June 30, 2022.

This increase is primarily due to higher production taxes related to higher commodity prices during 2022 combined with workover expenses and lease operating expense related to higher lifting cost properties returned to production.

Field service expense

increased $1.7 million or 94.4% from $1.8 million for the second quarter 2021 to $3.5 million for the second quarter 2022 and increased $3.2 million, or 97.0% from $3.3 million for the six months ended June 30, 2021 to $6.5 million for the six months ended June 30, 2022.

Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and six months ended June 30, 2022 compared with the same periods of 2021.

These changes reflect the increase in utilization and rates resulting from the oil and gas price increases during these periods.

Depreciation, depletion, amortization and accretion on discounted liabilities

increased $0.4 million, or 6.1% from $6.6 million for the second quarter 2021 to $7.0 million for the second quarter 2022 and $1.1 million, or 8.4% from $13.1 million for the six months ended June 30, 2021 to $14.2 million for the six months ended June 30, 2022.

These increases reflect the change in the property basis combined with production increases in 2022.

General and administrative expense

increased $4.9 million, or 116.7% from $4.2 million for the six months ended June 30, 2021 to $9.1 million for the six months ended June 30, 2022, and increased $0.2 million, or 9.1% from $2.2 million for the three months ended June 30, 2021 to $2.4 million for the three months ended June 30, 2022.

This increase in 2022 is primarily due to increased employee compensation and benefits.

Interest expense

decreased from $500 thousand for the second quarter 2021 to $150 thousand for the second quarter 2022 and from $1.0 million for the six months ended June 30, 2021 to $499 thousand for the six months ended June 30, 2022.

This decrease reflects the increase in rates and lower current borrowings under our revolving credit agreement.

Income tax benefit

for the June 30, 2022 and 2021 periods varied due to the change in net income or loss for those periods.

LIQUIDITY AND CAPITAL RESOURCES

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Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage.

Net cash provided by operating activities and proceeds from the sale of properties for the six months ended June 30, 2022 was $42.3 million, compared to $11.5 million in the prior year.

Net cash provided by operating activities and proceeds from the sale of properties for the nine months ended September 30, 2022 was $47.3 million, compared to $18.8 million in the prior period.

Excluding the effects of significant unforeseen expenses or other income, our cash flow from operations fluctuates primarily because of variations in oil and gas production and prices or changes in working capital accounts.

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Oil (barrels)

In the first quarter of 2022, the Company participated in the drilling of four wells with SEM Operating Company in Irion County, Texas for 10.3% interest and in April of this year began participating with Ovintiv Mid-Continent

in four wells in Canadian County, Oklahoma with 9.38% interest.

These eight wells have been completed and are expected to be on production in August of this year.

These eight wells have been completed and were put on production in early August.

In addition, the Company has received drilling proposals for an additional 26 horizontal wells to be drilled in West Texas with 15 of these slated to begin drilling this year.

3 unchanged sentences

As of August 15, 2022, the Company has no outstanding borrowings under this line.

The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined

estimate of proved oil and gas reserves.

The bank reviews the borrowing base semi-annually and, at their discretion, may decrease or propose an increase to the borrowing base relative to a re-determined estimate of proved oil and gas reserves.

The next borrowing base review is scheduled for December 2022.

3 unchanged sentences

Our borrowing base may decrease as a result of lower natural gas or oil prices, operating difficulties, declines in reserves, lending requirements or regulations, the issuance of new indebtedness or for other reasons set forth in our revolving credit agreement.

In the event of a decrease in our borrowing base due to declines in commodity prices or otherwise, our ability to borrow under our revolving credit facility may be limited and we could be required to repay any indebtedness in excess of the re-determined

borrowing base.

In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Regan and Midland Counties, Texas through two transactions receiving gross proceeds of $14.0 million and retaining certain over-riding royalty interests.

In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through three transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests.

In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for proceeds of $845,000 and a retained over-riding royalty interest.

In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700.

In November of 2022, the Company completed an acreage exchange with a large independent oil & gas operator to exchange approximately 725 net acres in the Midland Basin.

When combined with currently held acreage, this acreage exchange results in the Company having 100% working interest in approximately 1,200 contiguous acres and therefore the ability to efficiently and cost-effectively develop the Wolfcamp and other prospective reservoirs through 2-mile-long horizontal laterals.

In addition to this exchange, the Company has completed an agreement with a separate prominent independent oil & gas operator to create a 2,560-acre AMI for the joint development of horizontal wells.

As part of the plan, the Company has divested a portion of its interest to the operator for $16.1 million and has the right to acquire additional acreage from the operator within the AMI.

These exchanges should result in an approximate 50/50 ownership of the AMI development with the operator.

This newly formed 2,560 acreage block will allow the Company to reinvest approximately $90 million of its cash flow in the drilling of as many as 18 new wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.

The majority of our capital spending is discretionary, and the ultimate level of expenditures will be dependent on our assessment of the oil and gas business environment, the number and quality of oil and gas prospects available, the market for oilfield services, and oil and gas business opportunities in general.

The Company has a stock repurchase program in place, spending under this program during the first six months of 2022 was $3.2 million.

The Company has a stock repurchase program in place, spending under this program during the first nine months of 2022 was $5.0 million.

The Company expects continued spending under the stock repurchase program in 2022.

RESULTS OF OPERATIONS

2022 and 2021 Compared

We reported net income of $35.3 million, or $17.95 per share and $13.2 million, or $6.79 per share for the nine and three months ended September 30, 2022, respectively, as compared to net losses of $1.2 million, or $(0.58) per share and $5.0 million, or $(2.52) per share for the three and nine months ended September 30, 2021, respectively.

Current year net income reflects increases in production and commodity price increases over the three and nine months ended September 30, 2022, fluctuations in gains related to the sale of assets and changes related to the valuation of derivative instruments.

The significant components of income and expense are discussed below.

Oil, gas and NGLs sales increased $15.9 million, or 87.8% from $18.1 million for the three months ended September 30, 2021 to $34.0 million for the three months ended September 30, 2022, and $56.7 million, or 122.9% from $46.1 million for the nine months ended September 30, 2021 to $102.8 million for the nine months ended September 30, 2022

The following tables summarizes the primary components of production volumes and average sales prices realized for the three and nine months ended September 30, 2022 and 2021 (excluding realized gains and losses from derivatives).

Nine months ended September 30,

Barrels of Oil Produced

Average Price Received

Oil Revenue (In 000’s)

Mcf of Gas Sold

Average Price Received

Gas Revenue (In 000’s)

Barrels of Natural Gas Liquids Sold

Average Price Received

Natural Gas Liquids Revenue (In 000’s)

Total Oil & Gas Revenue (In 000’s)

Three months ended September 30,

Barrels of Oil Produced

Average Price Received

Oil Revenue (In 000’s)

Mcf of Gas Sold

Average Price Received

Gas Revenue (In 000’s)

Barrels of Natural Gas Liquids Sold

Average Price Received

Natural Gas Liquids Revenue (In 000’s)

Total Oil & Gas Revenue (In 000’s)

Oil, Natural Gas and NGL Derivatives We do not apply hedge accounting to any of our commodity-based derivatives, thus changes in the fair market value of commodity contracts held at the end of a reported period, referred to as mark-to-market adjustments, are recognized as unrealized gains and losses in the accompanying condensed consolidated statements of operations.

As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues.

Field service income increased $1.4 million or 58.3% from $2.4 million for the third quarter 2021 to $3.8 million for the third quarter 2022 and increased $4.6 million, or 74.2% from $6.2 million for the nine months ended September 30, 2021 to $10.8 million for the nine months ended September 30, 2022.

These changes reflect the increase in utilization and rates resulting from the oil and gas price increases during these periods.

Workover rig services, hot oil treatments, saltwater hauling and disposal represent the bulk of our field service operations.

Lease operating expense increased $2.3 million or 35.9% from $6.4 million for the third quarter 2021 to $8.7 million for the third quarter 2022 and increased $11.3 million or 73.9% from $15.3 million for the nine months ended September 30, 2021 to $26.6 million for the nine months ended September 30, 2022.

Field service expense increased $0.1 million or 3.4% from $2.9 million for the third quarter 2021 to $3.0 million for the third quarter 2022 and increased $3.3 million, or 53.2% from $6.2 million for the nine months ended September 30, 2021 to $9.5 million for the nine months ended September 30, 2022.

Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and nine months ended September 30, 2022 compared with the same periods of 2021.

These changes reflect the increase in utilization resulting from the oil and gas price increases during these periods.

Depreciation, depletion, amortization and accretion on discounted liabilities increased $0.8 million, or 11.6% from $6.9 million for the third quarter 2021 to $7.7 million for the third quarter 2022 and $1.9 million, or 9.5% from $20.0 million for the nine months ended September 30, 2021 to $21.9 million for the nine months ended September 30, 2022.

These increases reflect the change in the property basis combined with production increases in 2022.

General and administrative expense increased $5.3 million, or 85.5% from $6.2 million for the nine months ended September 30, 2021 to $11.5 million for the nine months ended September 30, 2022, and increased $0.5 million, or 25.0% from $2.0 million for the three months ended September 30, 2021 to $2.5 million for the three months ended September 30, 2022.

This increase in 2022 is primarily due to increased employee compensation and benefits.

Interest expense decreased from $0.5 million for the third quarter 2021 to $0.3 million for the third quarter 2022 and from $1.5 million for the nine months ended September 30, 2021 to $0.8 million for the nine months ended September 30, 2022.

This decrease reflects the increase in rates and reduced borrowings under our revolving credit agreement.

Income tax benefit /expense for the September 30, 2022 and 2021 periods varied due to the change in net income or loss for those periods.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

1 unchanged sentence

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-Q

Item 2. Management’s Discussion and Analysis