The following discussion is intended to assist you in understanding our results
of operations and our present financial condition. 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.
OVERVIEW
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. 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. Since
all our derivative contracts are accounted for under
mark-to-market
accounting, we expect continued volatility in gains and losses on
mark-to-market
derivative contracts in our consolidated statement of operations as changes
occur in the NYMEX price indices.
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. In addition, our realized prices are
further impacted by our derivative and hedging activities.
We derive our revenue and cash flow principally from the sale of oil, natural
gas, and NGLs. 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. 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.
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. 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, 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.
Future development plans are established based on various factors, including the
expectation of available cash flows from operations and availability of funds
under our revolving credit facility.

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

                                                   Gulf         Mid-          West
                                                  Coast       Continent       Texas      Other       Total
Proved Reserves as of December 31, 2020 (MBoe)
Developed                                            517           1,575       5,116          6        7,214
Undeveloped                                           -               95       3,126         -         3,221
Total                                                517           1,670       8,242          6       10,435
Average Daily Production (Boe per day)               297             788       3,178          2        4,265
Gross Productive Wells (Working Interest and
ORRI Wells)                                          239             549         556        170        1,514
Gross Productive Wells (Working Interest Only)       209             485         518         69        1,281
Net Productive Wells (Working Interest Only)         124             217         263          2          606
Gross Operated Productive Wells                      158             209         325         -           692
Gross Operated Water Disposal, Injection and
Supply wells                                           9              53           6         -            68


In several of our producing regions, we have field service groups to service our
operated wells and locations as well as third-party operators in the area. These
services consist of well service support, site preparation, and construction
services for drilling and workover operations. Our operations are performed
utilizing workover 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.
Gulf Coast Region
Our development, exploitation, exploration, and production activities in the
Gulf Coast region are primarily concentrated in southeast Texas. This region is
managed from our office in Houston, Texas. Principal producing intervals are in
the Wilcox, San Miguel, Olmos, and Yegua formations at depths ranging from 3,000
to 12,500 feet. 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. Average net daily
production in our Gulf Coast Region in 2020 was 297 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. We maintain an acreage position of over 11,548
gross (3,968 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.
Mid-Continent
Region
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

year-end

reserve ratio: one for 9.9% interest and three for less than one percent

interest.

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

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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. 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. 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, three
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 operated wells and locations.
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:
Our interests in proved developed and undeveloped oil and gas properties,
including the interests held by the Partnerships, have been evaluated by Ryder
Scott Company, L.P. for each of the three years ended December 31, 2020. The
professional qualifications of the technical persons primarily responsible for
overseeing the preparation of the reserve estimates can be found in Exhibit
99.1, the Ryder Scott Company, L.P. Report on Registrant's Reserves Estimates.
In matters related to the preparation of our reserve estimates, our district
managers report to the Engineering Data manager, who maintains oversight and
compliance responsibility for the internal reserve estimate process and provides
oversight for the annual preparation of reserve estimates of 100% of our
year-end
reserves by our independent third-party engineers, Ryder Scott Company, L.P. The
members of our district and central groups consist of degreed engineers and
geologists with between approximately twenty and thirty-five years of industry
experience, and between eight and twenty-five years of experience managing our
reserves. Our Engineering Data manager, the technical person primarily
responsible for overseeing the preparation of reserves estimates, has over
thirty years of experience, holds a Bachelor'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. The
following table summarizes our oil and gas reserves at each of the respective
dates:

                                                             Reserve Category
                                    Proved Developed                                  Proved Undeveloped                                        Total
                       Oil          NGLs         Gas         Total         Oil          NGLs         Gas        Total        Oil          NGLs         Gas         Total
As of December 31,   (MBbls)      (MBbls)       (MMcf)       (MBoe)      (MBbls)      (MBbls)      (MMcf)      (MBoe)      (MBbls)      (MBbls)       (MMcf)       (MBoe)
2018                    6,404        2,707       21,065       12,622           10           12         124          43        6,414        2,719       21,189       12,665
2019                    4,381        2,914       19,995       10,268        1,833        1,017       4,547       3,608        6,214        3,931       24,542       14,235
2020                    2,684        2,258       13,633        7,214        1,784          787       3,897       3,221        4,468        3,045       17,530       10,435


(a) In calculating total reserves based on a barrel of oil equivalent (boe), gas is

converted to petroleum based on its relative energy content at the rate of six Mcf

of gas to a barrel of oil, and NGLs are converted by volume; a

Barrel of natural gas liquids is equivalent to one barrel of oil.

At

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 all nine wells are producing as of October 4, 2021.
These nine wells account for 3,127 Mboe of the total undeveloped reserves at

end of the year.

Our average share of 47.5% 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

end of the year,

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

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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. The estimated reserves of
wells with sufficient production history are estimated using appropriate decline
curves. Estimated reserves of producing wells with limited production history
and for undeveloped locations are estimated using performance data from
analogous wells in the area. These wells are considered analogous based on
production performance from the same formation and with similar completion
techniques.
The estimated future net revenue (using current prices and costs as of those
dates) and the present value of future net revenue (at a 10% discount for
estimated timing of cash flow) for our proved developed and proved undeveloped
oil and gas reserves at the end of each of the three years ended December 31,
2020, are summarized as follows (in thousands of dollars):

                             Proved Developed                    Proved Undeveloped                                            Total
                                           Present                               Present                           Present            Present
                                           Value 10                             Value 10                           Value 10          Value 10           Standardized
                                          Of Future                             Of Future                         Of Future          Of Future           Measure of
                        Future Net           Net            Future Net             Net          Future Net           Net              Income             Discounted
As of December 31,       Revenue           Revenue            Revenue            Revenue         Revenue           Revenue             Taxes             Cash flow
2018                   $    239,337       $  161,376       $         767       $       525     $    240,104       $  161,901        $    23,992        $      137,909
2019                   $    116,592       $   82,155       $      42,700       $    17,876     $    159,292       $  100,031        $    18,419        $       81,612
2020                   $     43,886       $   34,717       $      37,346       $    21,823     $     81,232       $   56,539        $    14,920        $       41,619


The PV 10 Value represents the discounted future net cash flows attributable to
our proved oil and gas reserves before income tax, discounted at 10%. Although
this measure is not in accordance with U.S. generally accepted accounting
principles ("GAAP"), we believe that the presentation of the PV10 Value is
relevant and useful to investors because it presents the discounted future net
cash flow attributable to proved reserves before taking into account corporate
future income taxes and the current tax structure. We use this measure when
assessing the potential return on investment related to oil and gas properties.
The PV10 of future income taxes represents the sole reconciling item between
this
non-GAAP
PV10 Value versus the GAAP measure presented in the standardized measure of
discounted cash flow. A reconciliation of these values is presented in the last
three columns of the table above. The standardized measure of discounted future
net cash flows represents the present value of future cash flows attributable to
proved oil and natural gas reserves after income tax, discounted at 10%.
"Proved developed" oil and gas reserves are reserves that can be expected to be
recovered from existing wells with existing equipment and operating methods.
"Proved undeveloped" oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Our reserves include
amounts attributable to
non-controlling
interests in the Partnerships. These interests represent less than 10% of our
reserves.
In accordance with U.S. generally accepted accounting principles, product prices
are determined using the twelve-month average oil and gas index prices,
calculated as the unweighted arithmetic average for the first day of the month
price for each month, adjusted for oilfield or gas gathering hub and wellhead
price differentials (e.g. grade, transportation, gravity, sulfur, and basic
sediment and water) as appropriate. Also, in accordance with SEC specifications
and U.S. generally accepted accounting principles, changes in market prices
subsequent to December 31 are not considered.
While it may be reasonably anticipated that the prices received for the sale of
our production may be higher or lower than the prices used in this evaluation,
as described above, and the operating costs relating to such production may also
increase or decrease from existing levels, such possible changes in prices and
costs were, in accordance with rules adopted by the SEC, omitted from
consideration in making this evaluation for the SEC case. Actual volumes
produced, prices received and costs incurred may vary significantly from the SEC
case.
Natural gas prices, based on the twelve-month average of the first of the month
Henry Hub index price, were $1.985 per MMBtu in 2020 as compared to $2.58 per
MMBtu in 2019, and $3.10 per MMBtu in 2018. Oil prices, based on the NYMEX first
of the month average price, were $39.57 per barrel in 2020 as compared to $55.69
per barrel in 2019, and $65.56 per barrel in 2018.
RECENT ACTIVITIES
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. 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.

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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
laterals. 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.
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.

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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.

                        2021          2022          2023         2021        2022        2023
Swap Agreements
Natural Gas (MMBTU)     268,000       928,000       131,000     $  2.48     $  2.67     $  2.81
Oil (barrels)           133,500       196,200        27,200     $ 53.60     $ 51.99     $ 50.31


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
,
2021. 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.

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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: 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.
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. 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,

Increase / Increase /

                                              2021               2020            (Decrease)         (Decrease)
Barrels of Oil Produced                        480,000            538,000            (58,000 )           (10.80 )%
Average Price Received                     $     63.28       $      38.41       $      24.88               64.8 %

Oil Revenue (In 000's)                     $    30,376       $     20,663       $      9,713               47.0 %

Mcf of Gas Sold                              2,395,000          2,038,000            357,000               17.5 %
Average Price Received                     $      3.32       $       1.20       $       2.12              177.1 %

Gas Revenue (In 000's)                     $     7,948       $      2,441       $      5,507              225.6 %

Barrels of Natural Gas Liquids Sold            298,000            319,000            (21,000 )            (6.60 )%
Average Price Received                     $     26.11       $      10.07       $      16.04              159.3 %

Natural gas liquids sales (in thousands) $ 7,781 $ 3,212

     $      4,569              142.2 %

Total oil and gas revenue (in thousands) $ 46,105 $ 26,316

    $     19,789               75.2 %




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                                                                    Three 

months ended September 30,

Increase / Increase /

                                             2021              2020             (Decrease)         (Decrease)
Barrels of Oil Produced                      152,000            160,000              (8,000 )             (5.0 )%
Average Price Received                     $   68.70       $      39.62        $      29.08               73.4 %

Oil Revenue (In 000's)                     $  10.442       $      6,339        $      4,103               64.7 %

Mcf of Gas Sold                              950,000            496,000             454,000               91.5 %
Average Price Received                     $    4.21       $       2.12        $       2.09               98.5 %

Gas Revenue (In 000's)                     $   3,998       $      1,052        $      2,946              280.0 %

Barrels of Natural Gas Liquids Sold          103,000            106,000              (3,000 )            (2.80 )%
Average Price Received                     $   35.26       $      13.91        $      21.35              153.5 %

Natural gas liquids sales (in thousands) $ 3,632 $ 1,474

    $      2,158              146.4 %

Total oil and gas revenue (in thousands) $ 18,072 $ 8,865

    $      9,207              103.9 %



Oil, Natural Gas and NGL Derivatives
We do not apply hedge accounting to any of our commodity based derivatives, thus
changes in the fair market value of commodity contracts held at the end of a
reported period, referred to as
mark-to-market
adjustments, are recognized as unrealized gains and losses in the accompanying
condensed consolidated statements of operations. As oil and natural gas prices
remain volatile,
mark-to-market
accounting treatment creates volatility in our revenues.
Field service income
increased $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
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 $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 $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 $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 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.

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