What changed in this filing

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Item 2. Management’s Discussion and Analysis

2023-05-22 compared with 2022-11-21 · 186 added, 217 removed, 119 unchanged (77% of the section changed)

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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 also own a 12.5% overriding royalty interest in over 30,000 acres in the state of West Virginia, although we are currently not receiving revenue from this asset as development has not begun.

In Texas, we own well-servicing equipment that is used to service our operated properties as well as to provide oil field services to third-party operators.

In addition, we own a 60-mile-long pipeline offshore on the shallow shelf of Texas that is currently idle but that we believe has future value for producers in the area.

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.

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.

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

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

We attempt to assume the position of operator in all acquisitions of producing properties and will continue to evaluate properties for leasehold acquisition and for exploration and development operations in areas in which we own interests.

To diversify and broaden our asset base, we will consider acquiring the assets or stock in other entities in the oil and gas business.

Our main objective in making any such acquisitions will be to acquire income-producing assets or developable leasehold acreage to build stockholder value through consistent growth and development of our oil and gas reserve base on a cost-effective basis.

Our main objective in making any such acquisitions will be to acquire income-producing assets or developable leasehold acreage to build stockholder value.

Our cash flows depend on many factors, including the price of oil and gas, the success of our acquisition and drilling activities, and the operational performance of our producing properties.

We use derivative instruments to manage our commodity price risk.

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 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.

On occasion, we will use derivative instruments to manage our commodity price risk.

This practice may prevent us from receiving the full advantage of 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.

When used our derivative contracts are accounted for under mark-to-market accounting and we can expect volatility in gains and losses on contracts in our consolidated statements of operations as changes occur in the NYMEX price indices.

Our existing derivative instruments expired 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.

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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.

As mentioned above, our existing contracts expired 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 natural gas liquids (NGLs).

As a result, our revenues are determined, to a large degree, by prevailing prices for crude 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 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.

In the Permian Basin of West Texas and eastern New Mexico the Company maintains an acreage position of approximately 16,960 gross (10,640 net) acres, 96.5% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current West Texas horizontal drilling activities are focused.

Index prices for oil, natural gas, and NGLs 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.

The Company is actively developing additional reserves of its leasehold acreage positions in Texas and Oklahoma.

In the Permian Basin of West Texas the Company maintains an acreage position of approximately 16,139 gross (9,569 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused.

We believe this acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of as many as 250 additional horizontal wells.

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Our Oklahoma horizontal development is focused primarily in Canadian, Kingfisher, Grady, and Garvin counties.

We believe approximately 5,800 net acres in these counties hold significant additional resource potential that could 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.

We believe approximately 4,113 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 43 new horizontal wells based on an estimate of four wells per section, two in the Mississippian and two in the Woodford Shale.

Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $33 million at an average 10% ownership level.

Future development plans are established based on various factors, including the expectation of available cash flows from operations and availability of funds under our revolving credit facility.

Future development plans are established based on various factors, including the expectation of available cash flows from operations and the availability of funds under our revolving credit facility.

District Information

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Proved Reserves as of December 31, 2022 (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 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.

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

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Gulf Coast Region

Our activities in the Gulf Coast region are primarily production and development of our existing operated properties concentrated in east and southeast Texas.

Our development, exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in southeast Texas.

This region is managed from our office in Houston, Texas.

Principal producing intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000 to 12,500 feet.

As of December 31, 2021, we had 207 producing wells (105 net) in the Gulf Coast region, of which 137 wells are operated by us.

The Average net daily production in our Gulf Coast Region in 2021 was 336 Boe.

We had 150 producing wells (69 net) in the Gulf Coast region as of December 31, 2022, of which 89 wells are operated by us.

Average net daily production in our Gulf Coast Region at year-end 2022 was 227 Boe.

At December 31, 2022, we had 790 MBoe of proved reserves in the Gulf Coast region, which represented 4.7% of our total proved reserves.

We maintain an acreage position of over 8,707 gross (1,215 net) acres in this region, primarily in Dimmit and Polk counties.

We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, twenty-three water transport trucks, two saltwater disposal wells and several trucks and excavating equipment.

We operate a field service group in this region from a field office in Carrizo Springs, Texas utilizing four workover rigs, twenty water transport trucks, two saltwater disposal wells and several trucks and excavating equipment.

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 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.

As of March 31, 2023, 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

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As of December 31, 2022, we had 508 producing wells (169 net) in the Mid-Continent area, of which 176 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.

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

Principal producing intervals are in the Robberson, 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 2022 was 897 Boe.

At December 31, 2022, we had 2,659 MBoe of proved reserves in the Mid-Continent area, representing 16% of our total proved reserves.

We maintain an acreage position of approximately 47,120 gross (10,297 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 Inc.

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

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.

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

As of March 31, 2023, in the Mid-Continent region, the Company is participating with 1.96% interest in three 15,000’ long horizontal wells in Canadian County, Oklahoma operated by Ovintiv Mid-Continent Inc.

All three wells have been drilled and are in the process of being completed with production starts expected by the end of the second quarter.

The expected reserves of these three wells were included in the 2022 year-end reserve report as proved undeveloped.

West Texas Region

Our West Texas activities are concentrated in the Spraberry and Wolfcamp shale plays of the Permian Basin encompassing eight counties in West Texas.

The oil produced from these shales is West Texas Intermediate Sweet and the gas is primarily casing-head gas with an average energy content of 1,400 Btu.

The horizontal target depths range from 7,600 feet to 12,500 feet.

Our West Texas activities are concentrated in the Permian Basin where much of the United States’ oil reserves are produced from the prolific Wolfcamp and Spraberry reservoirs.

The oil is West Texas Intermediate Sweet and the produced casing-head gas has a high BTU content making it a source of our natural gas liquids.

The oil and gas are primarily from five producing intervals;

the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700 feet to 11,300 feet.

This region is managed from our office in Midland, Texas.

As of December 31, 2022, we had 557 wells (254 net) in the West Texas area, of which 310 wells are operated by us.

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.

Average net daily production in Our West Texas Region at year-end 2022 was 3,257 Boe.

At December 31, 2022, we had 13,256 MBoe of proved reserves in the West Texas area, or 79.3 % of our total proved reserves.

We maintain an acreage position of approximately 16,139 gross (9,569 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 for our 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 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:

Our interests in proved developed and undeveloped oil and gas properties, including the interests held by the Partnerships, have been evaluated by Ryder Scott Company, L.P.

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

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.

As of March 31, 2023, the Company was participating in the drilling of 15 two-mile-long horizontal wells in Reagan County, Texas with 49.7% interest in five wells operated by Double Eagle and 25% interest in ten wells operated by Hibernia Energy.

In Upton County, Texas, the Company was also participating with Apache in the drilling of two 3-mile-long horizontals with 47.52% ownership.

In Martin County, Texas, the Company is participating with ConocoPhillips in the drilling of five 2.5-mile-long horizontals with 20.83% interest.

Combined, we expect to spend approximately $78 million in the drilling and completion of these 22 West Texas horizontals and their associated facilities.

These 22 wells and their forecast reserves were included in the 2022 year-end reserve report as proved undeveloped.

The 10 wells operated by Hibernia were placed on production in late April 2023 and based on the success of these wells Hibernia has indicated their intent to spud an additional 16 wells on adjacent acreage late in the third quarter of this year.

These additional wells are slated to be in production in the first quarter of 2024.

Our share of these 16 wells will be between 37.5% and 50% with an average of 41.1% and an investment of approximately $75 million.

In addition, Double Eagle has notified us of their plans to drill six 10,000’ horizontal wells in Reagan County with spud dates in July and production start expected in December 2023.

These six wells will be drilled on an acreage block that is an extension to Double Eagle’s Hughes Alpine development described above and where the Company holds leasehold acreage giving us the right to participate for approximately 6.5% interest in these two-mile-long horizontals.

Our share of the investment in these will be approximately $4 million.

Our interests in proved developed and undeveloped oil and gas properties have been evaluated by Ryder Scott Company, L.P.

for each of the three years ended December 31, 2022.

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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.

See Part II, Item 8 “Financial Statements and Supplementary Data”, for additional discussions regarding proved reserves and their related cash flows.

All of our reserves are located within the continental United States.

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Proved Undeveloped

As of December 31,

In computing total reserves on a barrels of oil equivalent (Boe) basis, gas is converted to oil based on its relative energy content at the rate of six Mcf of gas to one barrel of oil and NGLs are converted based upon volume;

one barrel of natural gas liquids equals one barrel of oil.

In 2019, in West Texas, we participated in the initial three shallow horizontals on our Kashmir tract with one of each of these wells completed in the Wolfcamp “A”, Jo Mill, and Lower Spraberry.

The Company has 48% interest in two of these wells and 5.3% in one well.

All three wells were brought on production in May of 2019.

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 with Pioneer Natural Resources for 8.6% interest which was brought into production in July of 2020, and six wells with Apache on our Kashmir tract 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 2020 reserve report.

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

Also in 2020, proved producing reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we receive 0.56% to 1% over-riding royalty interest.

In 2021, in West Texas, we participated with Apache in the drilling of three additional horizontals on the Kashmir Tract in Upton County, Texas and completed these three wells in September of 2021 along with six other wells drilled in 2020 on the same lease that were drilled but uncompleted at year-end 2020.

The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells.

In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and completion of six wells on our WM Wallace tract for 7.67% interest, and nine wells, included on our Slash, Osborn, and Leon tracts, with an average 1.34% interest.

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:

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

In 2019, in our Gulf Coast region, we added production through the recompletion of three vertical wells in Polk County, Texas:

one operated by the Company in which we have 72.5% interest, and two operated by Unit Petroleum in which the Company owns 2.81% working interest and 3.77% net revenue interest.

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

Also in 2020, reserves were added in West Texas through the addition of 11 horizontal wells completed in Midland County, Texas, in which we receive 0.56% to 1% over-riding royalty interest.

In our Gulf Coast Region, in 2020, we successfully recompleted one operated well in the Segno field of Polk County, Texas 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.

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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.

These nine PUD wells at year-end 2020 accounted for 3,127 Mboe of the total undeveloped.

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.

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 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.

We employ technologies to establish proved reserves that have been demonstrated to provide consistent results capable of repetition.

The technologies and economic data being used in the estimation of our proved reserves include, but are not limited to, electrical logs, radioactivity logs, geologic maps, production data, and well-test data.

The estimated reserves of wells with sufficient production history are estimated using appropriate decline curves.

Estimated reserves of producing wells with limited production history and for undeveloped locations are estimated using performance data from analogous wells in the area.

These wells are considered analogous based on production performance from the same formation and with similar completion techniques.

The Company has an average of 47.8% interest in these nine wells and invested approximately $30 million in these horizontal wells.

Also in 2021, the Company participated with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma.

Twelve of these thirteen horizontal wells were successfully completed and placed into production in the fourth quarter of 2021.

One of the Ovintiv wells had a casing leak issue and has been temporarily abandoned.

The Company invested approximately $32 million in these thirteen wells.

In addition, in 2021, the Company added minor reserves through over-riding royalty interest in two wells drilling and completed in Grady County, Oklahoma.

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

These reserves were converted to proved producing in the first quarter of 2022.

At year-end 2021, we did not include proved undeveloped reserves in our reserve report because we had not yet received definitive drilling proposals from third-party operators for the more than fifteen horizontal wells that we planned to participate in located primarily in West Texas.

In 2022, the Company participated in eight horizontal wells that were drilled and completed;

four located in Irion County, West Texas, operated by SEM Operating Company, in which we have 10.13% interest, and four located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc., in which we have an average 9% interest.

Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022.

In addition, the Company added reserves through 15 wells in which we have various minor over-riding royalty interests.

Eight of these wells are located in West Texas and seven are located in Oklahoma.

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators.

In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital investment of $12.1 million.

In Reagan County, we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million.

Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million.

All twenty of these West Texas wells are either producing or are in the process of being completed.

All 10 of the wells drilled by Hibernia Energy III in the first quarter were put on production in late April 2023.

The five active horizontal wells operated by Double Eagle are in the process of being completed and slated to be on production in June of 2023.

The remaining five wells with ConocoPhillips are expected to start completion in June and be on production in August of 2023.

In January of 2023, the Company joined Ovintiv USA, Inc.

in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000.

Production is expected to begin in June of 2023.

In addition, in March of 2023, Apache Corporation spud two 3-mile-long horizontals in Upton County, Texas in which the Company has 49.4% interest with an expected total capital investment of $16.1 million.

We anticipate completion of these two 15,000’ long horizontals in Upton County in May and initial production to occur in the third quarter of 2023.

At December 31, 2022, the Company had 6,366 Mboe of proved undeveloped reserves attributable to the 25 horizontal wells described above.

In total, the Company expects to invest $78 million in these 25 horizontal wells, all of which, as of April 30, 2023, have been drilled and are either producing or in the process of being completed with production to begin by the end of the second quarter or early in the third quarter of 2023.

Additional anticipated development mentioned in this report is not included in the 2022 year-end reserve report.

The estimated future net revenue (using current prices and costs as of those dates) and the present value of future net revenue (at a 10% discount for estimated timing of cash flow) for our proved developed and proved undeveloped oil and gas reserves at the end of each of the three years ended December 31, 2022, are summarized as follows (in thousands of dollars):

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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.

These interests represent less than 10% of our reserves.

In accordance with U.S.

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Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $6.358 per MMBtu in 2022 as compared to $3.598 per MMBtu in 2021, and $1.985 per MMBtu in 2020.

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.

Oil prices, based on the West Texas Intermediate (WTI) Light Sweet Crude first of the month average spot price, were $93.67 per barrel in 2022 as compared to $66.56 per barrel in 2021, and $39.57 per barrel in 2020.

Since January 1, 2022, 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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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.

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.

This includes the four wells currently in progress with SEM Operating Company in Irion County, Texas.

In Upton County, Texas, we are developing a contiguous 3,260-acre block with our joint venture partner, Apache Corporation.

In this block the Company has 2,600 leasehold acres with interest between 14% and 56% depending on the particular lease and depth being developed.

In 2018, eight successful wells were drilled horizontally by Apache Corporation in the Wolfcamp “B” of this block with the Company participating for 49% interest and this is believed to be full development of the Wolfcamp “B” reservoir.

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.

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.

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.

The potential of the Middle Spraberry on the 3,260-acre block is for 12 horizontal wells to be drilled and completed at a gross cost of approximately $138.0 million with the Company’s share being approximately $63.0 million.

The actual number of wells that are eventually drilled as well as the cost and the timing of drilling will vary based upon many factors, including commodity market conditions.

In addition to the 3,260-acre block being developed, as described above, the Company has also been developing an offsetting 1,300-acre block in Upton County, Texas, with Apache Corporation as operator.

In the second quarter of 2019 three horizontal wells were completed and brought on production from reservoirs above the Middle Wolfcamp:

one in the Wolfcamp “A”, one in the Jo Mill, and one in the Lower Spraberry, confirming the economic viability of these reservoirs on our acreage.

Prime holds 47.5% working interest in these reservoirs.

As a result of the success of the initial three wells, nine additional horizontals followed and were completed in the third quarter of 2021.

Our average 47.5% share of the cost of these nine horizontal wells was approximately $26.7 million in total.

In addition to the Wolfcamp “A”, Jo Mill and Lower Spraberry, that are now considered fully developed on the tract, four locations in the Middle Spraberry will be considered for future development at an estimated gross cost of approximately $40.0 million with the Company’s share being approximately $18.8 million.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with ConocoPhillips in Martin County, Texas.

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 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 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.

We are actively developing our leasehold acreage in West Texas and in Oklahoma and on track to drill and complete approximately 40 wells in 2023.

The following is a description of recent, current, and expected near-term drilling activities.

In 2021, The Company participated for 47.5% interest with Apache Corporation in the drilling of nine two-mile-long horizontal wells in Upton County, Texas, and with Ovintiv Mid-Continent for 11.25% interest in four two-mile horizontal wells in Canadian County, Oklahoma.

Twelve of these horizontal wells were completed and placed into production in the fourth quarter of 2021.

One of the Ovintiv wells, however, had a casing leak issue and has been temporarily abandoned.

The Company invested approximately $32 million in these thirteen wells.

In the first three quarters of 2022, the Company participated in eight horizontal wells.

Four of these wells are located in Irion County, West Texas, operated by SEM Operating Company, and four are located in Canadian County, Oklahoma, operated by Ovintiv Mid-Continent, Inc.

Our investment in these eight wells was approximately $4 million and all were brought on production in August of 2022.

In the fourth quarter of 2022, we began participation in the drilling of 20 horizontal wells located in West Texas operated by three different operators.

In Martin County, we are participating with ConocoPhillips in five 2.5-mile-long horizontal wells in which the Company has 20.83% interest with a planned capital investment of $12.1 million.

In Reagan County, we are participating with Hibernia Energy III in 10 two-mile horizontals with 25% interest and an expected investment of $25.6 million.

Also in Reagan County, we are participating with Double Eagle (DE IV) in five two-mile-long horizontals with nearly 50% interest, carrying an expected net capital outlay of $23.4 million.

All twenty of these West Texas wells have been drilled and are either producing or in the process of being completed.

All 10 of the wells operated by Hibernia Energy III were put on production in late April 2023.

The five wells operated by Double Eagle are expected to be on production in June of 2023.

The remaining five wells with ConocoPhillips are expected to start completion in June and be on production in August of 2023.

In January of 2023, the Company joined Ovintiv USA, Inc.

in the spudding of three 3-mile-long horizontal wells in Canadian County, Oklahoma with 1.96% interest and an expected investment of $645,000.

Production is expected to begin in June of 2023.

We anticipate completion of these two 15,000’ long horizontals in Upton County in May and initial production to occur in the third quarter of 2023.

In total, the Company expects to invest $78 million in these 25 horizontal wells.

In December 2022, we prepaid $32 million toward drilling costs, and the remaining $46 million in estimated drilling and completion expenses will be incurred in 2023.

All 25 wells have been drilled as of May 1, 2023.

Ten wells were put into production in late April, eight more are expected to be on-line in June of 2023 and the remaining seven wells are expected to be on production in June or early in the third quarter of 2023.

We anticipate that success from the 22 horizontals in West Texas described above will lead to additional near-term horizontal drilling covering five leasehold blocks in three counties of West Texas:

26 additional 10,000’ long horizontals in Reagan County from Hibernia, Double Eagle, and BTA Oil Producers (or its successor in the South Stiles Project), ten additional 12,500’ long horizontals in Martin County by ConocoPhillips, and six additional 15,000’ long horizontals in Upton County by Apache.

Based on the success of their recent 10 wells in Reagan County, Texas, Hibernia has indicated their intent to drill 16 additional 10,000’ long horizontal wells this year with spud dates to occur late in the third quarter and production to begin in the first quarter of 2024.

Our interest in these wells will be from 37.5% to 50% with an average of 41.18% and our investment will be approximately $75 million.

In addition, Double Eagle has notified us of their plans to drill six 10,000’ horizontal wells in Reagan County with spud dates in July and production start expected in December 2023.

These six wells will be drilled on an acreage block that is an extension to Double Eagle’s Hughes Alpine development described above and where the Company has leasehold acreage giving us the right to participate for approximately 6.5% interest in these two-mile-long horizontals.

Our share of the investment in these wells will be approximately $4 million.

The upcoming six wells to be drilled by Double Eagle, along with the 16 wells planned by Hibernia and the additional 26 drilling proposals we anticipate in the near future, will target pay intervals of the Wolfcamp and Spraberry formations and will require an estimated $200 million in net capital investment through 2024.

We have also identified 27 horizontal locations that would be a natural progression of development for three of these project areas in Upton and Reagan counties.

These 27 wells are anticipated to be drilled in the 2025-2026 timeframe and would require net investment of approximately $100 million.

In total, with the $78 million current investment in 22 wells, the $200 million near-term investment in 48 wells in Upton and Reagan counties, $100 million in 27 subsequent drill sites, and additional drilling not yet scheduled, we are expecting to invest approximately $400 million in horizontal development over the next several years.

In the Permian Basin of West Texas and eastern New Mexico, we maintain an acreage position of approximately 16,139 gross (9,569 net) acres, 96.5% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current West Texas horizontal drilling activities are focused.

We believe this acreage has the resource potential to support the drilling of as many as 190 future horizontal wells following the active 22 and anticipated 42 horizontal wells described above.

In Oklahoma, we are focused on the development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 4,113 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 Inc.

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

Three of these wells were successfully completed in December 2021 and online in January 2022, while one well had completion issues and has been temporarily abandoned.

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 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 a 10% ownership level;

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

We are currently participating with Ovintiv in three 3-mile-long horizontals in Canadian County with 1.95% Of our 4,113 net leasehold acres, we believe 2,355 net acres hold significant additional resource potential that could support the drilling of as many as 46 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.

In the near term, we anticipate nine new drilling proposals to be received with an estimated net expense of $5.2 million covering 338 net leasehold acres.

Proposals may be received on the remaining 2,017 acres, however, rather than participate we may choose to sell the acreage or farm-out, receiving cash and retaining an over-riding royalty interest.

RESULTS OF OPERATIONS

We reported net income of $1.4 million, $0.75 per share, for the three months ended March 2023 compared with $11.1 million, $5.62 per share, for the same period of 2022.

The current year net income reflects changes in oil, gas and NGLs sales related to changes in production combined with lower commodity prices offset by net gains on derivative contracts.

The significant components of income and expense are discussed below.

Oil, gas and NGLs sales decreased 44.8% to $18.7 million for the three months ended March 2023 from $33.9 million in the same period of 2022.

Sales vary due to changes in volumes of production sold and realized commodity prices.

Our oil production decreased reflecting the natural decline in production from our West Texas wells added in the fourth quarter of 2021 and our Oklahoma wells which were placed in production in January 2022.

The changes in volumes and prices are presented in the table below.

The following table summarizes the primary components of production volumes and average sales prices realized for the three months ended March 31, 2023, and 2022 (excluding realized gains and losses from derivatives).

Three Months Ended March 31,

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)

Gains or Losses on derivative instruments 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.

Unrealized and realized losses by product are presented in the table below for the three months ended March 31.

Unrealized gain (loss) on natural gas derivative instruments

Unrealized gain (loss) on crude oil derivative instruments

Realized gain (loss) on natural gas derivative instruments

Realized (loss) on crude oil derivative instruments

Average oil and gas prices received for the three months ended March 31, including the impact of derivatives were:

Average sales prices per barrel of oil

Average sales price per MCF of natural gas

Lease operating expense decreased $0.7 million or 8.0% from $8.7 million for the first quarter 2022 to $8.0 million for the first quarter 2023.

This decrease reflects the decreased production taxes related to the decreased oil, gas and NGL revenue, net of the additional operating expenses related to the wells added in 2022.

Field service income increased $0.5 million or 16.7% for the first quarter 2023 to $3.5 million from $3.0 million for the first quarter 2022.

This increase is a combined result of increased utilization and rates charged to customers during the current quarter compared to the same quarter in 2022.

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

Field service expense increased $0.5 million or 18.5% to $3.2 million for the first quarter 2023 from $2.7 million for the first quarter 2022.

Field service expenses primarily consist of wages and equipment operating expenses which have increased during the three months ended March 31, 2023 over the same period of 2022 related to increased utilization of the equipment during the current quarter compared to the same quarter in 2022.

Depreciation, depletion and amortization decreased $0.6 million or 8.6% from $7.0 million for the first quarter 2022 to $6.4 million for the first quarter 2023 reflecting the decreased production in the first quarter of 2023.

General and administrative expense decreased $3.6 million or 53.7% from $6.7 million for the three months ended March 31, 2022 to $3.1 million for the three months ended March 31, 2023.

This decrease in 2023 is primarily due to decreased employee compensation and benefits.

Interest expense decreased $0.1 million or 33.3% from $0.3 million for the first quarter 2022 to $0.2 million for the first quarter 2023.

This decrease reflects the decrease in current borrowings under our revolving credit agreement.

Income tax expense for the March 31, 2023 and 2022 quarters varied due to the change in net income.

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 nine months ended September 30, 2022 was $47.3 million, compared to $18.8 million in the prior period.

Net cash provided by operating activities and proceeds from the sale of properties for the quarter ended March 31, 2023 was $30.3 million, compared to $23.3 million in the prior year.

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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Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports.

Accordingly, the Company has in place the following swap agreements for oil and natural gas.

Swap Agreements

Natural Gas (MMBTU)

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 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.

In total, the Company is likely to invest approximately $86 million in these 26 wells.

If the borrowing base utilization percentage is less than 15% of total available borrowings, the Company is not required to enter into any hedge agreements.

The Company has no outstanding borrowings and all hedge agreements were settled or terminated prior to March 31, 2023.

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.

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $60 million.

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

As of May 19, 2023, 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 next borrowing base review is scheduled for December 2022.

The next borrowing base review is scheduled for June 2023.

Our oil and gas properties are pledged as collateral for the line of credit and we are subject to certain financial and operational covenants defined in the agreement.

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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 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 nine months of 2022 was $5.0 million.

The Company has a stock repurchase program in place, spending under this program during the first quarter of 2023 was $2.75 million.

The Company expects continued spending under the stock repurchase program in 2023.

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.

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 as commodity prices increased.

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

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What changed 10-Q

Item 2. Management’s Discussion and Analysis