What changed in this filing

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Item 2. Properties

2022-04-21 compared with 2021-04-26 · 122 added, 174 removed, 65 unchanged (82% of the section changed)

Our executive offices, as well as offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company are located in

leased premises in Houston, Texas.

We maintain district offices in Midland, Texas and Oklahoma City, Oklahoma and have field offices in

Carrizo Springs and Midland, Texas, and Elmore City, Oklahoma.

Substantially all of our oil and gas properties are subject to a mortgage

given to collateralize indebtedness or are subject to being mortgaged upon request by our lenders for additional collateral.

information set forth below concerning our properties, activities, and oil and gas reserves include our interests in affiliated entities.

The following table sets forth the exploratory and development drilling experience with respect to wells in which we participated during the

three years ended December 31, 2020.

In 2020, we participated in seven new horizontal wells, however, only one well was completed in 2020, and the remaining six wells are to be completed in 2021.

Our executive offices, as well as offices of Prime Operating Company, Eastern Oil Well Service Company and EOWS Midland Company are located in leased premises in Houston, Texas.

We maintain district offices in Midland, Texas and Oklahoma City, Oklahoma and have field offices in Carrizo Springs and Midland, Texas, as well as, Elmore City, Oklahoma.

Substantially all of our oil and gas properties are subject to a mortgage given to collateralize indebtedness or are subject to being mortgaged upon request by our lenders for additional collateral.

The information set forth below concerning our properties, activities, and oil and gas reserves includes our interests in affiliated entities.

The following table sets forth the exploratory and development drilling experience with respect to wells in which we participated during the three years ended December 31, 2021.

In 2021, we participated in the completion of twelve horizontal wells.

Oil and Gas Production

As of December 31, 2020, we had ownership interests in the following numbers of gross and net producing oil and gas wells (1) .

As of December 31, 2021, we had ownership interest in the following number of gross and net producing oil and gas wells (1)

Producing wells (1)

A gross well is a well in which a working interest is owned.

A net well is the sum of the fractional revenue

interests owned in gross wells.

A net well is the sum of the fractional revenue interests owned in gross wells.

Wells are classified by their primary product.

Some wells produce both oil and gas.

following table shows our net production of oil, NGL and natural gas for each of the three years ended December 31, 2020.

Net production is net after royalty interests of others are deducted and is determined by multiplying the

gross production volume of properties in which we have an interest by percentage of the leasehold, mineral or royalty interest owned by us.

The following table shows our net production of oil, NGL and natural gas for each of the three years ended December 31, 2021.

“Net” production is net after royalty interests of others are deducted and is determined by multiplying the gross production volume of properties in which we have an interest by the percentage of the leasehold, mineral or royalty interest owned by us.

Oil (barrels)

NGL (barrels)

The following table sets forth our average sales prices together with our average production

costs per unit of production for the three years ended December 31, 2020.

The following table sets forth our average sales prices together with our average production costs per unit of production for the three years ended December 31, 2021.

Average sales price per barrel of oil

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Average sales price per Mcf of natural gas

The following table sets forth the approximate gross and net undeveloped acreage in which we have leasehold and mineral interests as of

December 31, 2020.

Undeveloped acreage is that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage

contains proved reserves.

The following table sets forth the approximate gross and net undeveloped acreage in which we have leasehold and mineral interests as of December 31, 2021.

“Undeveloped acreage” is that acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil and gas, regardless of whether or not such acreage contains proved reserves.

Leasehold acreage

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Total Net Undeveloped Acreage Expiration

As of December 31, 2020, we have no acreage subject to expiration during the years ending 2021 through 2023.

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.

In the event that production is not established, or we take no action to extend or renew the terms of our leases, our net undeveloped acreage that will expire over the next three years, as of December 31, 2021, is zero acres for the year ending December 31, 2022, zero in 2023, and zero acres in 2024.

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.

for each of the three years ended December 31, 2021.

The professional qualifications of the

technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P.

The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in Exhibit 99.1, the Ryder Scott Company, L.P.

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.

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.

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.

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.

The following table

summarizes our oil and gas reserves at each of the respective dates:

The following table summarizes our oil and gas reserves at each of the respective dates:

Reserve Category

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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;

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 2018, the Company drilled and completed 17 horizontal wells in West Texas and 11 horizontal wells in Oklahoma.

In addition, the Company

added reserves through overriding royalty interest in 16 wells, primarily in Oklahoma and Texas.

At year-end 2018, thirteen of the seventeen wells completed in 2018 were designated as Shut-In:

eight located in our West Texas horizontal development program that were brought on production in February, 2019, and five in our Oklahoma Scoop-Stack development program, which were brought on production

in March, 2019.

At December 31, 2018, our reserve report included 43 MBoe of proved undeveloped reserves attributable to eight

horizontal wells that had been drilled but not yet been completed:

three of these were completed in 2019, converting 24 Mboe of undeveloped reserves to proved developed, and four remained uncompleted as of December 31, 2020, which account for

18 Mboe of the 43 Mboe.

The Company has 9% ownership in one of these four wells and less than 1% in three wells.

In 2019, in West Texas,

in addition to the eight wells classified as Shut-in at year-end 2018 that were brought on production in February, we participated in the drilling and completion of

three wells on our Kashmir tract:

two wells with an average 49% interest, and a third well for 5.3% interest.

One of each of these wells was completed in the Wolfcamp A, Jo Mill, and Lower Spraberry.

All three wells were brought on

production in May of 2019.

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% which was brought into

production in July of 2020, and six wells with an average 47.5% interest that were shut-in and are planned for completion in mid-2021 with production to start early in

the third quarter of 2021.

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.

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 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 Slash, Osborn, and Leon tracts, with an average 1.34% interest.

In addition, three wells drilled in Oklahoma in 2018, designated as proved undeveloped at

year-end 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 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 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.

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 Slash, Osborn, and Leon tracts, with an average 1.34% interest.

In addition, three wells drilled in Oklahoma in 2018, designated as proved undeveloped at year-end

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 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.

December 31, 2020, the Company had 3,221 Mboe of proved undeveloped reserves attributable to 13 wells operated by others, three of which are new wells, spud in 2020 but not drilled until the first quarter of 2021 and 10 of which were drilled as

The three new horizontals along with six uncompleted wells are located in Upton County, Texas and are in the process of being completed and we expect them to be placed on production by the end of

the second quarter of 2021.

Apache Corporation is the operator of these wells.

These nine PUD wells account for 3,127 Mboe of the total undeveloped reserves.

The nine wells mentioned above are located on our 1,300 acre Kashmir tract in Upton County,

operated by Apache Corporation.

Our average 47.5% share of the total cost of these nine horizontal wells will be approximately $26 million.

The four remaining PUD wells, drilled but not completed, are located in Grady County, Oklahoma and

account for 95 Mboe of the total undeveloped reserves.

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

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 where.

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 horizontals drilled and completed in Canadian County, Oklahoma in December of 2021, but not yet online.

Reserves of the four PUD wells in Grady County, Oklahoma were not included in the 2021 year-end

reserve report as the operator does not have near-term plans for their completion.

In the first quarter of 2022, the Company is participating in the drilling of four wells with SEM Operating Company for 10% interest and has received drilling proposals for an additional 17 horizontal wells to be drilled this year.

In total the Company is likely to invest approximately $54 million in these 21 wells.

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 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.

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 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, 2020, are summarized as follows (in thousands of dollars):

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, 2021, are summarized as follows (in thousands of dollars):

Proved Developed

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As of December 31,

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas

reserves before income tax, discounted at 10%.

The PV 10 Value represents the discounted future net cash flows attributable to our proved oil and gas reserves before income tax, discounted at 10%.

Although this measure is not in accordance with U.S.

generally accepted accounting principles (GAAP), we believe that the presentation of the PV10 Value is relevant and useful to investors

because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure.

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.

generally accepted accounting principles (“GAAP”), we believe that the presentation of the PV10 Value is relevant and useful to investors because it presents the discounted future net cash flow attributable to proved reserves prior to taking into account corporate future income taxes and the current tax structure.

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.

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

The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved

oil and natural gas reserves after income tax, discounted at 10%.

Proved developed oil and gas reserves are reserves that can

be expected to be recovered from existing wells with existing equipment and operating methods.

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.

The standardized measure of discounted future net cash flows represents the present value of future cash flows attributable to proved oil and natural gas reserves after income tax, discounted at 10%.

“Proved developed” oil and gas reserves are reserves that can be expected to be recovered from existing wells with existing equipment and operating methods.

“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.

generally accepted accounting principles, product prices are determined using the twelve-month

average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g.

grade, transportation, gravity,

sulfur, and basic sediment and water) as appropriate.

generally accepted accounting principles, product prices are determined using the twelve-month average oil and gas index prices, calculated as the unweighted arithmetic average for the first day of the month price for each month, adjusted for oilfield or gas gathering hub and wellhead price differentials (e.g.

grade, transportation, gravity, sulfur, and basic sediment and water) as appropriate.

Also, in accordance with SEC specifications and U.S.

generally accepted accounting principles, changes in market prices subsequent to December 31 are not considered.

While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in

this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from

consideration in making this evaluation for the SEC case.

While it may be reasonably anticipated that the prices received for the sale of our production may be higher or lower than the prices used in this evaluation, as described above, and the operating costs relating to such production may also increase or decrease from existing levels, such possible changes in prices and costs were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation for the SEC case.

Actual volumes produced, prices received and costs incurred may vary significantly from the SEC case.

Natural gas prices, based on the twelve-month average of the first of the month Henry Hub index price, were $1.985 per MMBtu in 2020 as

compared to $2.58 per MMBtu in 2019, and $3.10 per MMBtu in 2018.

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.

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.

January 1, 2020, 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.

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.

District Information

The following table represents certain reserve and well information as of December 31, 2020.

The following table represents certain reserves and well information as of December 31, 2021.

Proved Reserves as of December 31, 2021 (MBoe)

Average Daily Production (Boe per day)

Average Net Daily Production (Boe per day)

Gross Productive Wells (Working Interest and ORRI Wells)

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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 in the area.

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

Our operations are performed utilizing workover or swab rigs, water

transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

Our operations are performed utilizing workover or swab rigs, water transport trucks, saltwater disposal facilities, various land excavating equipment and trucks we own and that are operated by our field employees.

Gulf Coast Region

Our development,

exploitation, exploration and production activities in the Gulf Coast region are primarily concentrated in 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.

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

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

Average net daily production in our Gulf Coast

Region in 2020 was 297 Boe.

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

At December 31, 2021, we had 906 MBoe of proved reserves in the Gulf Coast region, which represented 7% of our total proved reserves.

We maintain an acreage position of over 12,700 gross (5,120 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, nineteen 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

We maintain an acreage position of over 11,500 gross (3,967 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, nineteen water transport trucks, two saltwater disposal wells and several trucks and excavating equipment.

As of March 31, 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, 2020, we had 549 wells (217 net) in the Mid-Continent area, of which 209 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 2020 was 788 Boe.

At December 31, 2020, we had 1670 MBoe of proved reserves in the Mid-Continent area, or 16% of our total proved reserves.

We maintain an acreage position of approximately 56,000 gross

(10,355 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties.

We operate a field service group in this region from a field office in Elmore City, utilizing one workover rig and one saltwater hauling truck.

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, 2021, in the Mid-Continent region, the Company was participating in the completion

of four wells included as Proved Undeveloped in the 2020 year-end reserve report.

Mid-Continent

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.

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.

We maintain an acreage position of approximately 48,400 gross (10,802 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 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, 2022, in the Mid-Continent

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

The first of these is slated to begin drilling in early April and completion of all four wells is expected in June of this year.

These proved undeveloped drilling plans and their reserves were not included in the 2021 year-end

reserve report.

West Texas Region

Our West Texas activities are concentrated in the Permian Basin in Texas and New Mexico.

The Spraberry field was discovered in 1949,

encompasses eight counties in West Texas and the Company believes it is the largest oil field in the United States.

The Spraberry field was discovered in 1949, encompasses eight counties in West Texas and the Company believes it is the largest oil field in the United States.

The field is approximately 150 miles long and 75 miles wide at its widest point.

The oil produced is West Texas Intermediate Sweet,

and the gas produced is casing-head gas with an average energy content of 1,400 Btu.

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

The oil and gas are produced primarily from five intervals;

the Upper and Lower Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700

feet to 11,300 feet.

region is managed from our office in Midland, Texas.

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

Principal producing

intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet.

Principal producing intervals are in the Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to 12,500 feet.

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

At December 31, 2020, we had 8,242 MBoe of proved

reserves in the West Texas area, or 79% of our total proved reserves.

We maintain an acreage position of approximately 19,679 gross (12,461 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.

At 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 17,148 gross (10,639 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.

At December 31, 2020, the Company was committed to participate with Apache Corporation in the drilling of three Proved Undeveloped

horizontal locations in Upton County, Texas and the completion of these along with six other wells drilled in 2020 on the same tract.

The three new horizontals have been drilled and cased as of April 1, 2021.

Completion operations for all nine

are scheduled for June 2021.

As of March 31, 2022, the Company was participating with 10.3% interest in the drilling of four horizontal wells in Irion County, Texas operated by SEM Operating Company, LLC.

These four wells are expected to be completed in the second quarter of 2022.

In addition, the Company has received proposals for 13 new horizontal wells in West Texas and intends to participate for 50% interest in the drilling of nine horizontal wells in Reagan

County, Texas with BTA Oil Producers, Inc and to participate for 38% in the drilling of four horizontal wells in Martin County, Texas with Conoco Inc.

These 13 wells are planned to be drilled in the third quarter of 2022.

These proved undeveloped drilling plans have been added in the first quarter of 2022 and were not included in the year-end

2021 reserves report.

LEGAL PROCEEDINGS.

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

What changed 10-K

Item 2. Properties