What changed in this filing

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Item 2. Management’s Discussion and Analysis

2021-11-19 compared with 2021-08-23 · 118 added, 128 removed, 199 unchanged (55% of the section changed)

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Our Condensed Consolidated Financial Statements and the accompanying Notes to the Condensed Consolidated Financial Statements included elsewhere in this Report contain additional information that should be referred to when reviewing this material.

The Company’s activities include development 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.

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

We presently own producing and non-producing

properties located primarily in Texas and Oklahoma.

In addition, we own a substantial amount of well servicing equipment.

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

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

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

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

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.

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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 natural gas liquids and our ability to market our products on economically attractive terms.

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.

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

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.

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 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.

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.

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 19,680 gross (12,460 net) acres, 97% of which is located in Reagan, Upton, Martin, and Midland counties of Texas where our current horizontal drilling activity is focused.

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

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.

In Oklahoma, we maintain an acreage position of approximately 49,765 gross (10,953 net) acres.

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

We believe approximately 3,460 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 to ten wells per section, depending on the reservoir target area.

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.

Should we choose to participate with a working interest in future development, our share of these future capital expenditures would be approximately $34 million at an average 10% ownership level.

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

As of June 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.

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.

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, 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.

On December 31, 2020, we had 1,670 MBoe of proved reserves in the Mid-Continent

area, or 16% of our total proved reserves.

We maintain an acreage position of approximately 52,800 gross (10,300 net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and Garvin counties.

Our Mid-Continent

region is actively participating with third-party operators in the horizontal development of lands that include Company-owned 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 June 30, 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

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

reserve report:

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

In addition, the Company has committed to participate for 11.25% working interest in the drilling and completion of four wells in Canadian County, Oklahoma.

Our share of these wells will be approximately $1.98 million.

As of August 16, 2021, these four wells have been drilled and are currently awaiting completion.

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

West Texas Region

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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.

Production from these reservoirs is West Texas Intermediate Sweet

Crude oil and high-quality casing-head gas.

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

As of December 31, 2020, we

had 556 wells (263 net) in the West Texas area, of which 325 wells are operated by us.

As of December 31, 2020, we had 556 wells (263 net) in the West Texas area, of which 325 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.

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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.

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 spring of 2020, the Company participated with Apache Corporation in the drilling of six horizontal wells on our Kashmir acreage in Upton County, Texas.

In March of 2021, we drilled an additional three wells on the same acreage block.

As of June 30, 2021, the Company was participating in the completion of these nine horizontal wells for an average of 47.5% interest with an estimated total investment of approximately $27.8 million.

As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production.

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.

Reserve Information:

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for each of the three years ended December 31, 2020.

The professional qualifications of the technical persons primarily responsible for overseeing the preparation of the reserve estimates can be found in the Company’s 2020 Form 10K 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.

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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.

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

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

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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 year-end

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 in the process of being completed and will be on production in the third quarter of 2021.

These nine wells account for 3,127 Mboe of the total undeveloped reserves at year-end.

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 year-end,

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.

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.

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assets, or enter into strategic joint ventures.

In Upton County, West Texas, we are actively developing a contiguous 3,260 acre Area of Mutual Interest (AMI) with our joint venture partner, Apache Corporation.

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

Development to date has been from the Wolfcamp “B” reservoir where we have 34 horizontals currently producing.

Planning now is for the development of the shallower Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs that have been proven economical by near-offset completions.

We have 36 horizontals slated for the development of these three reservoirs, with 18 of these planned as 3-mile

In addition, there is a Middle Spraberry target reservoir that will likely be developed with 12 horizontals.

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.

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.

Two miles east of the AMI acreage described above, the Company is also developing a 1,280-acre

block with Apache Corporation.

Initially, six horizontal wells developed the Middle Wolfcamp reservoir.

In 2019, three horizontals proved the viability of production from the Wolfcamp “A”, Jo Mill, and Lower Spraberry.

Since early 2020, the Company and Apache drilled nine more laterals targeting these three reservoirs, three of which were drilled in the first quarter of 2021.

As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production.

Prime holds an average 47.5% working interest in these wells.

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

In addition to these shallow reservoirs, the Middle Spraberry is also being considered as a target.

Future development of the Middle Spraberry is likely to occur using four horizontals.

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

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

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

block with ConocoPhillips in Martin County, Texas.

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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 and Pioneer Natural Resources have agreed to jointly develop approximately 3,680 gross acres.

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.

Also in Reagan County, Texas, the Company has separate joint development projects with BTA Producers, Inc.

and Hibernia Energy III, LLC.

These two development 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 net to 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.

In Canadian County, Oklahoma, the Company is participating in the drilling of four 2-mile

long horizontal laterals operated by Ovintiv Mid-Continent

These wells have spud and will target reservoirs of the Mississippian and Woodford formations at roughly 8,900’.

As of August 16, 2021, the wells have been drilled and are awaiting completion.

The Company has an 11.25% interest and will invest approximately $1.98 million in the drilling and completion of these wells.

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 six months ended June 30, 2021 was $11.4 million compared to $8.8 million for the same period of 2020.

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.

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

If our exploratory drilling results in significant new discoveries, we will have to expend additional capital to finance the completion, development, and potential additional opportunities generated by our success.

We believe that, because of the additional reserves resulting from the successful wells and our record of reserve growth in recent years, we will be able to access sufficient additional capital through bank financing.

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

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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.

As of August 23, 2021, the Company has $32 million in outstanding borrowings and $8 million in availability under this facility.

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 next borrowing base review is scheduled for October 2021.

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.

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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 June 30, 2021, the Company has in place the following swap and put agreements for oil and natural gas.

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

Swap Agreements

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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 as many as 250 additional horizontal wells.

The Middle Wolfcamp has been the primary target for production in the area until, however, in 2019, in Upton County, the Company drilled three horizontal wells with Apache Corporation targeting shallower reservoirs in the Wolfcamp “A”, the Jo Mill, and the Lower Spraberry.

These three test wells proved the productive capability of these reservoirs for the 1,280 acre block in which they were drilled and led to the drilling of nine additional wells in early 2020 and the first quarter of 2021.

As of August 23, 2021, all nine wells have been completed and are in the process of being placed on production.

We have an average 47.5% interest in these wells and anticipated a total investment net to the Company of approximately $27.8 million.

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 anticipates the future development of as many as 48 additional horizontal wells targeting four reservoirs from the Wolfcamp “A” through the Middle Spraberry.

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.

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

Here the Company could participate in as many as 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, and six horizontal laterals on a second acreage block with laterals from 7,500’ to 10,000’ in length.

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.

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.

In Oklahoma, the Company’s horizontal activity is primarily focused in Canadian, Grady, Kingfisher, Garfield, Major, and Garvin counties where we have approximately 3,460 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 six wells per section:

three in the Mississippian and three 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.

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:

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.

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Spending under these programs in 2020 was $1.452 million.

The Company expects continued spending under these programs in 2021.

The Company expects continued spending under these programs through 2021.

RESULTS OF OPERATIONS

2021 and 2020 Compared

We reported net losses of $3.9 million, or $1.93 per share and $2.4 million, or $1.20 per share for the six and three months ended June 30, 2021, respectively, as compared to net losses of $6.4 million, or $3.23 per share and $6.3 million, or $3.14 per share for the six and three months ended June 30, 2020, respectively.

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

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.

The significant components of income and expense are discussed below.

Oil, gas and NGLs sales

increased $10.7 million, or 230.3% from $4.7 million for the three months ended June 30, 2020 to $15.4 million for the three months ended June 30, 2021 and $10.6 million, or 60.6% from $17.5 million for the six months ended June 30, 2020 to $28.0 million for the six months ended June 30, 2021.

The following tables summarizes the primary components of production volumes and average sales prices realized for the three and six months ended June 30, 2021 and 2020 (excluding realized gains and losses from derivatives).

Six months ended June 30,

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

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Total Oil & Gas Revenue (In 000’s)

Three months ended June 30,

Three months ended September 30,

Barrels of Oil Produced

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accounting treatment creates volatility in our revenues.

The following table summarizes the results of our derivative instruments for the three and six months ended June 2021 and 2020:

Three Months Ended

Six Months Ended

($ in thousand)

Oil derivatives – realized gains (losses)

Oil derivatives – unrealized gains (losses)

Total gains (losses) on oil derivatives

Natural gas derivatives – realized gains (losses)

Natural gas derivatives – unrealized gains (losses)

Total gains (losses) on natural gas derivatives

Total gains (losses) on oil and natural gas derivatives

Prices received for the six months ended June 30, 2021 and 2020, respectively, including the impact of derivatives were:

Field service income

increased $0.5 million or 21.8% from $2.4 million for the second quarter 2020 to $2.9 million for the second quarter 2021 however decreased $1.5 million, or 22.7% from $6.7 million for the six months ended June 30, 2020 to $5.2 million for the six months ended June 30, 2021.

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

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.

Lease operating expense

decreased $0.9 million or 15.1% from $6.2 million for the second quarter 2020 to $5.3 million for the second quarter 2021 and decreased $2.0 million or 15.9% from $12.6 million for the six months ended June 30, 2020 to $10.6 million for the six months ended June 30, 2021.

This decrease is primarily due to the sale or shut-in

of high lifting cost properties during 2020 offset by higher production taxes related to higher commodity prices.

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.

Field service expense

increased $0.5 million or 23.5% from $1.9 million for the second quarter 2020 to $2.4 million for the second quarter 2021 and decreased $1.1 million, or 20.9% from $5.4 million for the six months ended June 30, 2020 to $4.3 million for the six months ended June 30, 2021.

Field service expenses primarily consist of wages and vehicle operating expenses which have fluctuated during the three and six months ended June 30, 2021 compared with the same periods of 2020.

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

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.

Depreciation, depletion, amortization and accretion on discounted liabilities

decreased $0.3 million, or 4.2% from $6.9 million for the second quarter 2020 to $6.6 million for the second quarter 2021 and $2.0 million, or 13.2% from $15.1 million for the six months ended June 30, 2020 to $13.1 million for the six months ended June 30, 2021.

These declines reflect the decrease in the property basis combined with production increases in 2021.

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.

General and administrative expense

decreased $5.2 million, or 50.4% from $10.3 million for the six months ended June 30, 2020 to $5.1 million for the six months ended June 30, 2021, and decreased $0.1 million, or 3.8% from $2.6 million for the three months ended June 30, 2020 to $2.5 million for the three months ended June 30, 2021.

These changes reflect staff reductions and decreases in compensation and benefits implemented in during the past year.

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.

Interest expense

decreased from $500 thousand for the second quarter 2020 to $484 thousand for the second quarter 2021 and from $1.2 million for the six months ended June 30, 2020 to $1.0 million for the six months ended June 30, 2021.

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

Income tax benefit

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

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.

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.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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What changed 10-Q

Item 2. Management’s Discussion and Analysis