What changed in this filing

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Item 2. Management’s Discussion and Analysis

2022-05-20 compared with 2021-11-19 · 231 added, 194 removed, 123 unchanged (78% of the section changed)

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

Our cash flows depend on many factors, including the price of oil, gas, and natural gas liquids (NGL’s), the success of our acquisition and drilling activities, and the operational performance of our producing properties.

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

We continue to actively pursue the acquisition of producing properties.

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

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

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 commodity prices above the maximum fixed amount specified in the derivative agreements and subjects us to the credit risk of the counterparties to such agreements.

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

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

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

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

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

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

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As a result, our revenues are determined, to a large degree, by prevailing prices for crude oil, natural gas and NGLs.

We sell our oil, natural gas, and NGLs on the open market and to local processing companies at prevailing market prices or through forward delivery contracts.

We sell our oil and natural gas on the open market at prevailing market prices or through forward delivery contracts.

Because some of our operations are located outside major markets, we are directly impacted by regional prices regardless of Henry Hub, WTI or other major market pricing.

The market price for oil, natural gas and NGLs is dictated by supply and demand;

consequently, we cannot accurately predict or control the prices we may receive for our produced products.

Index prices for oil, natural gas, and NGLs are considerably higher than and we expect prices to remain volatile and consequently cannot determine with any degree of certainty what effect increases or decreases in these prices will have on our capital program, production volumes or revenue.

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

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

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 17,148 gross (10,640 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused.

This acreage has significant resource potential in the Spraberry and Wolfcamp intervals for additional horizontal drilling that could support the drilling of more than 250 additional horizontal wells.

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.

In Oklahoma we maintain an acreage position of approximately 48,400 gross (10,802 net) acres.

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

We believe approximately 5,579 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 49 new horizontal wells based on an estimate of four wells per section, depending on the reservoir target area.

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

We believe approximately 6,200 net acres in these counties hold significant additional resource potential that could support the drilling of as many as 5 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 $36 million at an average 10% ownership level.

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

Our operations are performed utilizing workover and swab rigs, water transport trucks, hot oil 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 activities in the Gulf Coast region are primarily production and development of our existing operated properties concentrated in east and 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.

We had 239 producing wells (124 net) in the Gulf Coast region as of December 31, 2020, of which 158 wells are operated by us.

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.

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

On December 31, 2020, we had 517 MBoe of proved reserves in the Gulf Coast region, which represented 5% of our total proved reserves.

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 11,000 gross (3,447 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, two hot oilers, 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 operated wells and locations.

As of September 30, 2021, 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.

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

Mid-Continent

Our Mid-Continent

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.

In the second quarter of 2021, the Company participated for 11.25% with Ovintiv

Mid-Continent,

LLC in the drilling of four wells in Canadian County, Oklahoma targeting the Mississippian and Woodford formations, which are currently in the process of being completed.

Our share of these will be approximately $2.8 million.

As of September 30, 2021, our

Mid-Continent

region has four other wells operated by third parties that have been drilled but have yet to be completed.

These four wells were included as Proved Undeveloped in the 2020

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 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 quarter of 2022, in the Mid-Continent

region the Company committed 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 was spud April 2, and the fourth on May 1,

All four wells are expected to be completed and online in July of this year.

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

reserve report.

one for 9.9% interest and three for less than one percent

West Texas Region

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

The basin covers more than 75,000 square miles and extends across 52 Counties.

The Wolfcamp and Spraberry reservoirs of this basin are among the largest contiguous accumulations of oil and gas in the United States.

Production from these reservoirs is West Texas Intermediate Sweet

Crude oil and high-quality casing-head gas.

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.

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 Wolfcamp and Spraberry formations at depths ranging from 5,500 to 12,500 feet.

The average net daily production in Our West Texas Region in 2020 was 3,178 Boe.

On December 31, 2020, we had 8,242 MBoe of proved reserves in the West Texas area, or 79% of our total proved reserves.

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

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

We maintain an acreage position of approximately 17,148 gross (10,640 net) acres in the Permian Basin in West Texas, primarily in Reagan, Upton, Martin, and Midland counties and believe this acreage has significant resource potential for horizontal drilling in the Spraberry, Jo Mill, and Wolfcamp intervals.

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

In the third quarter of 2021, the Company and Apache Corporation completed nine new Kashmir wells in Upton County, Texas:

three each in the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs.

Six of these had been drilled in the spring of 2020 and three were drilled early in 2021.

The Company owns 47.5% working interest in these wells and has invested approximately $24 million to-date

in their drilling and completions.

All nine wells are producing as of October 4, 2021.

We believe the additional production from these wells will have a significant impact on the Company’s cash flow in the fourth quarter of 2021.

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

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

In the first quarter 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 finished drilling and are awaiting completion which is expected to occur in the second quarter of 2022.

In addition, the Company has received proposals for 13 new horizontal wells in West Texas planned for the third quarter.

We intend 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 ConocoPhilips.

We also anticipate to begin development of ten new horizontal wells with Hibernia Energy III, LLC, in Reagan County, Texas, in the fourth quarter of 2022.

The Company will own approximately 25% of these ten wells expected to be completed in 2023.

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

2021 reserves report.

Reserve Information:

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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’s degree in Geology and an MBA in finance, and is a member of the Society of Petroleum Engineers and American Association of Petroleum Geologist.

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.

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As of December 31,

In computing total reserves on a barrel 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.

On December 31, 2020, the Company had 3,221 Mboe of proved undeveloped (PUD) 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 that were drilled as of

but not yet completed.

The three new horizontal wells along with six uncompleted wells are located on our Kashmir tract in Upton County, Texas.

They are operated by Apache Corporation and all nine wells are producing as of October 4, 2021.

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

Our average 47.5% share of the total cost of these nine horizontal wells will be approximately $27.8 million.

The four remaining PUD wells, drilled but not completed at

are located in Grady County, Oklahoma and account for 95 Mboe of the total undeveloped

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

We employ technologies to establish proven reserves that have demonstrated consistent results capable of repetition.

The technologies being used in the estimation of our proved reserves include, but are not limited to, decline curve and volumetric analysis, analogy, geologic mapping, as well as evaluation of reservoir properties, production, and well test data.

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.

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

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.

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

2020, and three that were not drilled until 2021.

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

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

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

These nine PUD wells at year-end

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

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

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

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

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

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

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

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

In the first quarter of 2022, in our West Texas horizontal drilling program, the Company participated with 10.3% interest in the drilling of four horizontal wells with SEM Operating Company and has received proposals for an additional 23 horizontal wells to begin this year.

In total the Company is likely to invest approximately $76 million in these 27 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 in Canadian County, Oklahoma.

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

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.

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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 before taking into account corporate future income taxes and the current tax structure.

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.

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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.

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

RECENT ACTIVITIES

The Company’s activities include development and exploratory drilling.

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

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

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

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

For 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2021 capital budget is reflective of current commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.

In 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

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

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

assets, or enter into strategic joint ventures.

In the third quarter of 2021, the Company, together with Apache Corporation, completed nine new horizontal wells on the Kashmir tract in Upton County, Texas.

These nine wells include three laterals in each of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs.

All nine wells were on production by October 4, 2021.

The Company has an average of 47.5% working interest in these nine wells with a total investment of approximately $24 million.

We believe the additional income from these wells will have a significant impact on the Company’s fourth-quarter cash flow.

In addition to the Middle and Upper Wolfcamp, the Jo Mill and the Lower Spraberry, which we now consider fully developed, we believe there is future development potential in the Middle Spraberry reservoir on this 1280 acre block.

This reservoir will likely be developed with four two-mile

The approximate completed cost of four wells in the Middle Spraberry is $30.2 million, with the Company’s share being $14.2 million.

In the second quarter of 2021, the Company participated with Ovintiv Mid-Continent,

LLC in the drilling of four horizontal wells located in Canadian County, Oklahoma.

These four two-mile

laterals are in the process of being completed and are expected to be on production in December of this year.

The Company has an 11.25% working interest in each well and expects to invest approximately $1.98 million in these wells.

In West Texas, in addition to the Kashmir Tract described above, we are actively developing a contiguous 3,260 acre Area of Mutual Interest (AMI) in Upton County with our joint venture partner Apache Corporation.

In this acreage block, the Company has leasehold interest of between 14% and 56% depending on the particular lease and depth being developed.

Development to-date

has been in the Wolfcamp “B” reservoir where we have 33 horizontal wells currently producing.

We believe this reservoir is fully developed and the next phase of development for this block is of the shallower Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs.

These reservoirs have been proven-up

by near-offset completions.

PrimeEnergy and Apache are planning an initial three wells to be drilled in 2022 that will each be three miles in length.

The Company has 36 horizontals laid out for the development of these three reservoirs,18 of which are designed as three-mile laterals.

In addition to these reservoirs, there is a Middle Spraberry target that will likely be developed in the future with 12 horizontal wells.

In total, we anticipate 48 horizontal wells will develop these four reservoirs with a cost estimate of $146 million net to the Company.

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.

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

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

We expect all eight of these wells to be completed soon and online in July of this year.

An additional 23 wells are planned to begin development in the second half of 2022;

nine with BTA Oil Producers, four with ConocoPhilips, and ten with Hibernia Energy III>

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 54 additional horizontals will be developed on this 3,260 acres in the near future.

This development is estimated to cost approximately $370.6 million, with the Company’s share being approximately $170.8 million.

In addition to the 54 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 18 horizontal wells to be drilled and completed at a gross cost of approximately $126.3 million with the Company’s share being approximately $61.8 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.

Also in the Permian Basin, we are developing a 965-acre

block with ConocoPhillips in Martin County, Texas.

In 2016 and 2017, four horizontal wells were drilled and have been producing from the Wolfcamp.

The Company owns between 35% and 38% interest in various leases of this joint venture acreage where ConocoPhillips is the operator.

No near-term additional drilling plans have been received, however, development of offset acreage by other operators has demonstrated the potential for good economic production from multiple landing zones on our acreage block.

In Reagan County, Texas, the Company has two separate joint development projects that are in the planning stage for the initial phase of development to occur in 2022:

one with BTA Producers, Inc.

and one with Hibernia Resources, LLC.

These two joint development acreage blocks can accommodate the drilling of 144 horizontal wells to produce from five prospective reservoirs, four of which are proven.

The Company’s share is expected to be 50% and the potential investment by the Company would be approximately $442 million.

The actual number of wells eventually drilled, and the cost and the timing of such wells are dependent upon many factors including commodity market conditions.

Also, In Reagan County, Texas, the Company and Pioneer Natural Resources have agreed to jointly develop approximately 3,680 gross acres.

This agreement facilitates the drilling of as many as 108 horizontal laterals where the company would have an average of 34.5% working interest and invest approximately $236 million.

We believe this agreement represents significant future value for PrimeEnergy.

In addition, we are in discussions with Earthstone Energy, Inc.

regarding the drilling of three wells in Reagan County, Texas, in which the Company would have 20% working interest and would invest approximately $3.8 million in three 9,650 foot laterals.

LIQUIDITY AND CAPITAL RESOURCES

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 for the nine months ended September 30, 2021, was $18.8 million, compared to $17.9 million in the first nine months of 2020.

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.

Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns.

We sell the majority of our production at spot market prices.

Accordingly, product price volatility will affect our cash flow from operations.

To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.

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

For 2021, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2021 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.

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

We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.

The Company maintains a Credit Agreement with a maturity date of February 15, 2023, providing for a credit facility totaling $300 million, with a borrowing base of $40 million.

At September 30, 2021, the Company had $31.5 million in outstanding borrowings and $8.5 million in availability under this facility.

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 current borrowing base review is in progress and expected to be set at $50 million.

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.

We are currently in compliance with these covenants and expect to be in compliance over the next twelve months.

If we do not comply with these covenants on a continuing basis, the lenders have the right to refuse to advance additional funds under the facility and/or declare all principal and interest immediately due and payable.

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

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

borrowing base.

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

Accordingly, as of September 30, 2021, the Company has in place the following swap and put agreements for oil and natural gas.

Swap Agreements

Natural Gas (MMBTU)

Oil (barrels)

The Company’s activities include development drilling.

Our strategy is to develop a balanced portfolio of drilling prospects that includes lower risk wells with a high probability of success and higher risk wells with greater economic potential.

In 2016, based upon the results of horizontal wells and historical vertical well performance, we decided to reduce the number of vertical wells in our drilling program and focus primarily on horizontal well drilling.

We believe horizontal development of our resource base provides superior returns relative to vertical development, due to the ability of horizontals to come in contact with and drain from a greater volume of reservoir rock over more acreage, with less infrastructure, and thus at a lower cost of development per acre.

Our primary focus is the development of our leasehold acreage in the Permian Basin of West Texas where the Company currently holds an acreage position of 19,680 gross (12,460 net) acres, the majority of which is in Reagan, Upton, Martin and Midland counties.

We believe this acreage has significant resource potential in as many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp, and can support the potential drilling of more than 250 additional horizontal wells.

The Middle Wolfcamp was our primary target for production in the area until the Company drilled three horizontal wells with Apache Corporation into the shallower reservoirs of the Wolfcamp “A”, the Jo Mill, and the Lower Spraberry, in 2019.

These three test wells proved the productive capability of these reservoirs for the 1,280 acre Kashmir block in which we recently completed an additional nine wells.

These nine wells were completed in the third quarter and all were on production by October 4 ,

We have an average 47.5% interest in these wells and expect a total investment net to the Company of approximately $24 million.

The successful development of these reservoirs has proven the productive potential of these reservoirs on our nearby 3,260-acre

AMI block with Apache Corporation in Upton County, Texas.

Here the Company holds between 14% and 56% interest and is planning the drilling of an initial three wells to be drilled in 2022.

These three will each be three-mile-long laterals.

The future development will likely be the drilling of 48 horizontal wells targeting four reservoirs from the Wolfcamp “A” through the Middle Spraberry.

The cost of such development will be approximately $370 million with the Company’s share being approximately $146 million.

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

In Reagan County, Texas, the Company holds 12,700 Gross (8.870 net) acres with exceptional potential.

Offset operators have proven the productive capability of four reservoirs from the Middle Wolfcamp to the Lower Spraberry.

Here the Company could participate in an estimated 352 horizontals with a net cost of approximately $890 million.

Near-term development plans being discussed include the drilling of three 12,500’ laterals on one acreage block with BTA Producers, Inc., and six horizontal laterals on a second acreage block with laterals from 7,500’ to 10,000’ in length with Hibernia Resources, LLC.

The Company’s share of these wells would average about 37.5% and cost approximately $35.2 million net.

In Oklahoma, the Company’s horizontal activity is focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 579 net leasehold acres with exceptional development potential.

We believe this acreage could support the drilling of as many as 49 new horizontal wells based on an estimate of four wells per section:

In addition to the 3,260 acre block being developed, as described above, the Company is also 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 $30.2 million with the Company’s share being approximately $14.2 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 and we have received drilling plans from ConocoPhilips for the drilling of four wells in the third quarter of 2022 that are likely to be 2.5-mile

The Company’s investment in these wells is expected to be $15 million.

In 2022, in West Texas, the Company is currently participating for 10.3% interest with SEM Operating Company in the drilling of four 7,900’-long horizontal wells in Irion County, Texas.

We anticipate an investment of $2.55 million in these wells.

We have also received proposals from BTA Oil Producers for the drilling of nine 2.5-mile-long

horizontals in Reagan County, Texas to begin in the third quarter of this year.

The Company intends to participate for its 50% interest in six wells and 31% interest in three wells.

Our expected investment in the drilling and completion of these wells is $40.5 million.

In addition, we received a proposal from ConocoPhilips for the drilling of four horizontal wells in Marting Couty, and a proposal from Hibernia Energy III for the drilling of ten horizontal wells in Reagan County.

We expect the development of these projects to begin in the fourth quarter of 2022.

PrimeEnergy will have approximately 38% interest in the four ConocoPhilips wells and 25% interest in the Hibernia Energy wells.

In Oklahoma, we are focused on development of our reserves in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 6,200 net leasehold acres in the Scoop/Stack Play.

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

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

in 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 $2.2 million investment in these four wells is expected to be in approximately six 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 spud and the first is in the process of being drilled at the time of this writing.

The Company is participating with 9.38% interest for approximately $1.8 million through completion which is expected to occur in June and July.

We believe our 6,200 net leasehold acres in Oklahoma have the resource potential to support the drilling of as many as 54 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 in future development, our share of the capital expenditures would be approximately $34 million at an average 10% ownership, otherwise the Company will sell its rights for cash, or cash plus a royalty or working interest.

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 in place both a stock repurchase program and a limited partnership interest repurchase program.

Spending under these programs in 2020 was $1.452 million.

The Company expects continued spending under these programs through 2021.

Should we choose to participate in future development, our share of the capital expenditures would be approximately $36 million at an average 10% ownership level;

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

RESULTS OF OPERATIONS

2021 and 2020 Compared

We reported net income of $6.5 million, or $3.26 per share and $65 thousand or $0.03 per share for the three and nine months ended September 30, 2020, 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 loss reflects changes in production combined with commodity price increases over the three and nine months ended September 30, 2020, decreases in gains related to the sale of acreage and changes related to the valuation of derivative instruments.

We reported net income of $11.1 million, $5.62 per share, for the three months ended March 2022 compared with a net loss of $1.5 million, $0.73 per share, for the same period of 2021.

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

The significant components of income and expense are discussed below.

Oil, gas and NGLs sales

increased $9.2 million, or 103.9% to $18.1 million for the three months ended September 30, 2021 from $8.9 million for the three months ended September 30, 2020 and $19.8 million, or 75.2% to $46.1 million for the nine months ended September 30, 2021 from $26.3 million for the nine months ended September 30, 2020.

The following table summarizes the primary components of production volumes and average sales prices realized for the nine months ended September 30, 2021 and 2020 (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,

increased 166.9% to $33.9 million for the three months ended March 2022 from $12.7 million in the same period of 2021.

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

Our production across all three products increased substantially reflecting the 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, 2022 and 2021 (excluding realized gains and losses from derivatives).

Three Months Ended March 31,

Barrels of Oil Produced

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Total Oil & Gas Revenue (In 000’s)

Oil, Natural Gas and NGL Derivatives

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

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accounting treatment creates volatility in our revenues.

Unrealized and realized losses by product are presented in the table below.

Unrealized (loss) on natural gas derivative instruments

Unrealized (loss) on crude oil derivative instruments

Realized (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

Field service income

increased $0.4 million or 15.9% to $3.0 million for the third quarter 2021 from $2.6 million for the third quarter 2020 and decreased $1.1 million, or 12.0% to $8.1 million for the nine months ended September 30, 2021 from $9.2 million for the nine months ended September 30, 2020.

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

increased $1.8 million or 128.6% for the first quarter 2022 to $3.2 million from $1.4 million for the first quarter 2021.

This increase is a combined result of increased utilization and rates charged to customers during the current quarter compared to the same quarter in 2021.

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

Lease operating expense

increased $3.4 million or 90.5% to $7.2 million for the third quarter 2021 to $3.8 million for the third quarter 2020, and increased $1.4 million or 8.8% to $17.8 million for the nine months ended September 30, 2021 from $16.4 million for the nine months ended September 30, 2020.

This increase is primarily due to returning to production the high lifting cost properties shut-in

during 2020 combined with higher production taxes related to higher commodity prices.

increased $4.2 million or 93.3% from $4.5 million for the first quarter 2021 to $8.7 million for the first quarter 2022.

This increase reflects the increased production taxes related to the increased oil, gas and NGL revenue, and the additional operating expenses related to the wells added in the fourth quarter of 2021 and the first quarter of 2022.

Field service expense

increased $1.4 million or 72.9% to $3.4 million for the third quarter 2021 from $2.0 million for the third quarter 2020 and increased $0.3 million, or 4.0% to $7.7 million for the nine months ended September 30, 2021 from $7.4 million for the nine months ended September 30, 2020.

Field service expenses primarily consist of salaries and vehicle operating expenses which have increased during the three and nine months ended September 30, 2021 over the same periods of 2020 related to increased utilization of the equipment as oil and gas prices increased during 2021.

increased $1.6 million or 114.3% to $3.0 million for the first quarter 2022 from $1.4 million for the first quarter 2021.

Field service expenses primarily consist of wages and equipment operating expenses which have increased during the three months ended March 31, 2022 over the same period of 2021 related to increased utilization of the equipment during the current quarter compared to the same quarter in 2021.

Depreciation, depletion, amortization and accretion on discounted liabilities

decreased $2.5 million, or 27.0% to $6.9 million for the third quarter 2021 from $9.4 million for the third quarter 2020 and decreased $4.5 million, or 18.5% to $20.0 million for the nine months ended September 30, 2021 from $24.5 million for the nine months ended September 30, 2020, reflecting the reduced capital base of the producing properties in 2021.

increased $0.7 million or 10.8% from $6.5 million for the first quarter 2021 to $7.2 million for the first quarter 2022 reflecting the increased production in the first quarter of 2022.

General and administrative expense

decreased $0.2 million, or 7.9% to $2.4 million for the three months ended September 30, 2021 from $2.6 million for the three months ended September 30, 2020, and decreased $5.4 million, or 42.0% to $7.5 million for the nine months ended September 30, 2021 from $12.9 million for the nine months ended September 30, 2020.

This overall decrease in 2021 is primarily due to decreases in employee wages and benefits and by staff reductions in 2020.

Gain on sale and exchange of assets

of $15.0 million for the nine months ended September 30, 2020 consists of principally of sales of deep rights in undeveloped acreage in West Texas and marginal wells in West Virginia.

No such sales took place during 2021.

increased $4.7 million or 235% from $2.0 million for the three months ended March 31, 2021 to $6.7 million for the three months ended March 31, 2022.

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

Interest expense

decreased to $0.46 million for the third quarter 2021 from $0.47 million for the third quarter 2020 and to $1.5 million for the nine months ended September 30, 2021 from $1.6 million for the nine months ended September 30, 2020.

decreased $0.2 million or 40% from $0.5 million for the first quarter 2021 to $0.3 million for the first quarter 2022.

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

Income tax expense or benefit

for the September 30, 2021 and 2020 periods varied due to the change in net income or loss for those periods.

Income tax expense and benefit

for the March 31, 2022 and 2021 quarters varied due to the change in net income and loss for those periods.

LIQUIDITY AND CAPITAL RESOURCES

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

For 2022, we will continue our focus on preserving financial flexibility and ample liquidity as we manage the risks facing our industry.

Our 2022 capital budget is reflective of commodity prices and has been established based on an expectation of available cash flows, with any cash flow deficiencies expected to be funded by borrowings under our revolving credit facility.

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

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 quarter ended March 31, 2022 was $23.3 million, compared to $4.7 million in the prior year.

Our oil and gas production will vary based on actual well performance but may be curtailed due to factors beyond our control.

Our realized oil and gas prices vary due to world political events, supply and demand of products, product storage levels, and weather patterns.

We sell the majority of our production at spot market prices.

Accordingly, product price volatility will affect our cash flow from operations.

To mitigate price volatility, we sometimes lock in prices for some portion of our production through the use of derivatives.

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.

In addition, the Company has received drilling proposals for an additional 23 horizontal wells to be drilled in West Texas this year.

In total the Company is likely to invest approximately $76 million in these 31 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.

The Company maintains a Credit Agreement providing for a reserves-based line of credit totaling $300 million, with a current borrowing base of $50 million.

As of May 20, 2022, the Company has no outstanding borrowings under this line.

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

estimate of proved oil and gas reserves.

The next borrowing base review is scheduled for June 2022, at this time we expect the borrowing base to be increased approximately 50%.

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.

We are currently in compliance with these covenants and expect to be in compliance over the next twelve months.

borrowing base.

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

The Company has a stock repurchase program in place, spending under this program during the first quarter of 2022 was $833 thousand.

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

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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What changed 10-Q

Item 2. Management’s Discussion and Analysis