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. We also own a
12.5% overriding royalty interest in over 30,000 acres in the state of West
Virginia. We are currently not receiving revenue from this asset, as development
has not begun. In addition, we own well-servicing equipment and, through a
wholly owned offshore company, a 60-mile-long pipeline offshore on the shallow
shelf of Texas not currently in use. We also hold a 33.3% interest in a limited
partnership that owns a 138,000-square-foot retail shopping center on ten acres
in Prattville, Alabama. There is currently no debt on the shopping center and it
has approximately $500,000 of working capital on its balance sheet. All of our
oil and gas properties and interests are located in the United States. Assets in
our principal focus areas include mature properties with long-lived reserves and
significant development opportunities, as well as, newer properties with
development and exploration potential. We believe our balanced portfolio of
assets positions us well for both the current commodity price environment and
future potential upside as we develop our attractive resource opportunities. Our
primary sources of liquidity are cash generated from our operations, our credit
facility and existing cash on our balance sheet.

In addition to developing our oil and natural gas reserves, we continue to
actively pursue the acquisition of producing properties. We attempt to assume
the position of operator in all acquisitions of producing properties and will
continue to evaluate properties for leasehold acquisition and for exploration
and development operations in areas in which we own interests. To diversify and
broaden our asset base, we will consider acquiring the assets or stock in other
entities in the oil and gas business. Our main objective in making any such
acquisitions will be to acquire income-producing assets or developable leasehold
acreage to build stockholder value through consistent growth and development of
our oil and gas reserve base on a cost-effective basis.

Our cash flows depend on many factors, including the price of oil and gas, the
success of our acquisition and drilling activities, and the operational
performance of our producing properties. We use derivative instruments to manage
our commodity price risk. This practice may prevent us from receiving the full
advantage of any increases in oil and gas prices above the maximum fixed amount
specified in the derivative agreements and subjects us to the credit risk of the
counterparties to such agreements. Since our derivative contracts are accounted
for under mark-to-market accounting, we expect continued volatility in gains and
losses on mark-to-market derivative contracts in our consolidated statement of
operations as changes occur in the NYMEX price indices. Our existing derivative
instruments expire in March of 2023 and at this time we do not intend to enter
into future derivative contracts unless required for our bank line of credit.

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. In addition, our realized prices are
further impacted by our derivative and hedging activities when used to manage
commodity price risk. As mentioned above, our existing contracts are set to
expire in March of 2023 and we currently do not intend to use future derivative
contracts unless required by our bank loan.

We derive our revenue and cash flow principally from the sale of oil, natural
gas, and NGLs. As 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. 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 are higher than in the recent past,
however, prices may be volatile and, consequently, we cannot determine with any
degree of certainty what effect increases or decreases in these prices will have
on our capital program, production volumes or revenue.

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We are the operator of the majority of our developed and undeveloped acreage
which is nearly all held by production. In the Permian Basin of West Texas and
eastern New Mexico the Company maintains an acreage position of approximately
16,960 gross (10,640 net) acres, 96.5% of which is located in Reagan, Upton,
Martin, and Midland counties of Texas where our current West Texas horizontal
drilling activities are focused. 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
47,120 gross (10,300 net) acres. Our Oklahoma horizontal development is focused
primarily in Canadian, Kingfisher, Grady, and Garvin counties. We believe
approximately 5,800 net acres in these counties hold significant additional
resource potential that could support the drilling of as many as 50 new
horizontal wells based on an estimate of four wells per multi-section drilling
unit, two in the Mississippian and two in the Woodford Shale. Should we choose
to participate with a working interest in future development, our share of these
future capital expenditures would be approximately $34.6 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.

District Information

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



                                                   Gulf         Mid-

West

Proved Reserves as of December 31, 2021 (MBoe) Coast Continent 


  Texas      Other       Total
Developed                                            906           2,383       8,957          6       12,252
Undeveloped Total                                     -               -           -          -            -
Average Net Daily Production (Boe per day)           336             747       2,878          3        3,964
Gross Productive Wells (Working Interest and
ORRI Wells)                                          207             549         576        200        1,532
Gross Productive Wells (Working Interest Only)       189             400         530         88        1,207
Net Productive Wells (Working Interest Only)         105             189         263          6          564
Gross Operated Productive Wells                      137             195         321         -           653
Gross Operated Water Disposal, Injection and
Supply wells                                           7              44           6         -            57


In several of our producing regions we have field service groups to service our
operated wells and locations as well as third-party operators. These services
consist of well service support, site preparation and construction services for
drilling and workover operations. Our operations are performed utilizing
workover or swab rigs, water transport trucks, saltwater disposal facilities,
various land excavating equipment and trucks we own and that are operated by our
field employees.

Gulf Coast Region

Our activities in the Gulf Coast region are primarily production and development
of our existing operated properties concentrated in east and southeast Texas.
This region is managed from our office in Houston, Texas. Principal producing
intervals are in the Wilcox, San Miguel, Olmos, and Yegua formations at depths
ranging from 3,000 to 12,500 feet. As of December 31, 2021, we had 207 producing
wells (105 net) in the Gulf Coast region, of which 137 wells are operated by us.
The Average net daily production in our Gulf Coast Region in 2021 was 336 Boe.
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 10,700 gross (3,215 net) acres in this region,
primarily in Dimmit and Polk counties. We operate a field service group in this
region from a field office in Carrizo Springs, Texas utilizing four workover
rigs, twenty-three water transport trucks, two saltwater disposal wells and
several trucks and excavating equipment. Services including well service
support, site preparation and construction services for drilling and workover
operations are provided to third-party operators as well as utilized in our own
operated wells and locations. The Company also owns, through its wholly-owned
offshore company, a 60-mile-long pipeline on the shallow shelf of Texas that is
currently idle but may someday have value. As of September 30, 2022, the Gulf
Coast region has no operated wells in the process of being drilled, no
waterfloods in the process of being installed and no other related activities of
material importance.

Mid-Continent Region

Our Mid-Continent activities are concentrated in central Oklahoma. This region
is managed from our office in Oklahoma City, Oklahoma. As of December 31, 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. On
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 47,120 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 interests in several
counties in the Stack and Scoop plays of Oklahoma where drilling primarily
targets reservoirs of the Mississippian and Woodford formations.

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In the first half of 2022, in the Mid-Continent region, the Company participated
with 9.38% interest in the drilling of four horizontal wells in Canadian County,
Oklahoma operated by Ovintiv Mid-Continent Inc. All four wells have been
completed and are online as of August 1st. The resulting production is an
addition to our 2021 year-end proved producing reserve base. The Company
divested of 354 non-strategic acres in Canadian County, year-to-date, with
proceeds of $1.269 million.

West Texas Region



Our West Texas activities are concentrated in the Spraberry and Wolfcamp shale
plays of the Permian Basin encompassing eight counties in West Texas. The oil
produced from these shales is West Texas Intermediate Sweet and the gas is
primarily casing-head gas with an average energy content of 1,400 Btu. The
horizontal target depths range from 7,600 feet to 12,500 feet. 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. The average net daily production in Our West
Texas Region in 2021 was 2,878 Boe. On December 31, 2021, we had 8,957 MBoe of
proved reserves in the West Texas area, or 73% of our total proved reserves. We
maintain an acreage position of approximately 16,960 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, four
hot oiler trucks, one kill truck, and two roustabout trucks. Services, including
well service support, site preparation, and construction services for drilling
and workover operations, are provided to third-party operators as well as
utilized for our operated wells and locations.

In the first half of 2022, the Company participated with 10.3% interest in the
drilling of four 1.5-mile-long horizontal wells in Irion County, Texas operated
by SEM Operating Company, LLC. All four wells have been drilled and completed
and began production in early August.

In the fourth quarter of 2022, the Company completed an acreage exchange
agreement with a large independent oil & gas operator to exchange approximately
725 net acres in the Midland Basin. In combination with existing acreage, this
newly acquired acreage results in the Company having 100% working interest in
approximately 1,200 contiguous acres and therefore the ability to efficiently
and cost-effectively develop the Wolfcamp formation and other prospective
reservoirs through 2-mile-long horizontal laterals.

Along with the 1,200 contiguous acres created from the acreage exchange, the
Company has completed an agreement with a separate prominent independent oil &
gas operator to create a 2,560-acre AMI for the joint development of horizontal
wells. As part of the agreement, the Company has divested of a portion of its
interest to operator for $16.1 million with the ability to acquire additional
acreage from the operator located within the AMI. These exchanges should result
in an approximately 50/50 ownership of the development with the operator. This
newly formed 2,560 acreage-block will allow the Company to reinvest
approximately $90 million of its cash flow in the drilling of as many as 18 new
wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.

In the fourth quarter of this year, we plan to participate with 20.8% interest
in the drilling of five 2.5-mile-long horizontal wells in Martin County, Texas
operated by ConocoPhillips, and to participate with 25% interest in the drilling
of ten 2-mile-long horizontals in Reagan County, Texas with Hibernia Energy III,
LLC.  In the first quarter of 2023, BTA Oil Producers, LLC has indicated plans
to drill nine 2.5-mile-long horizontals in Reagan County, Texas in which the
Company will have an average 42 % interest. In addition, we plan to participate
for 47% interest in two 3-mile-long horizontals with Apache Corporation in Upton
County.  In total, the Company will invest approximately $87 million in these 26
new wells with completions expected in the Spring of 2023 and all to be on
production by mid-year 2023.

Reserve Information:



Our interests in proved developed and undeveloped oil and gas properties,
including the interests held by the Partnerships, have been evaluated by Ryder
Scott Company, L.P. for each of the three years ended December 31, 2021. The
professional qualifications of the technical persons primarily responsible for
overseeing the preparation of the reserve estimates can be found in Exhibit
99.1, the Ryder Scott Company, L.P. 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

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twenty-five years of experience managing our reserves. Our Engineering Data
manager, the technical person primarily responsible for overseeing the
preparation of reserves estimates, has over thirty years of experience, holds a
Bachelor degree in Geology and an MBA in finance and is a member of the Society
of Petroleum Engineers and American Association of Petroleum Geologist. See Part
II, Item 8 "Financial Statements and Supplementary Data", for additional
discussions regarding proved reserves and their related cash flows. All of our
reserves are located within the continental United States. The following table
summarizes our oil and gas reserves at each of the respective dates:

                                                             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)
2019                    4,381        2,914       19,995       10,628        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
2021                    5,386        2,882       23,902       12,252           -            -           -           -         5,386        2,882       23,902       12,252

(a) In computing total reserves on a barrels of oil equivalent (Boe) basis, gas

is converted to oil based on its relative energy content at the rate of six

Mcf of gas to one barrel of oil and NGLs are converted based upon volume; one

barrel of natural gas liquids equals one barrel of oil.




In 2019, in West Texas, we participated in the initial three shallow horizontals
on our Kashmir tract with one of each of these wells completed in the Wolfcamp
"A", Jo Mill, and Lower Spraberry. The Company has 48% interest in two of these
wells and 5.3% in one well. All three wells were brought on production in May of
2019.

In 2020, in West Texas we participated in the drilling of seven wells: one for
8.6% interest which was brought into production in July of 2020, and six wells
with an average 47.5% interest that were drilled but not completed at year-end
and therefore classified as Proved Undeveloped in the year-end reserve report.
The Company invested approximately $8.0 million in these seven wells in 2020.
Also in 2020, proved producing reserves were added in West Texas through the
addition of 11 horizontal wells completed in Midland County, Texas, in which we
receive 0.56% to 1% over-riding royalty interest.

In 2021, in West Texas, we participated with Apache in the drilling of three
additional horizontals on the Kashmir Tract in Upton County, Texas and completed
these three wells in September of 2021 along with six other wells drilled in
2020 on the same lease that were drilled but uncompleted at year-end 2020. The
Company has an average of 47.8% interest in these nine wells and invested
approximately $30 million in these horizontal wells.

In our Oklahoma, Scoop-Stack play, in 2019, we participated in the drilling and
completion of six wells on our WM Wallace tract for 7.67% interest, and nine
wells, included on our Slash, Osborn, and Leon tracts, with an average 1.34%
interest. In addition, three wells drilled in Oklahoma in 2018, were completed
in 2019 converting 24 Mboe of reserves to proved developed. Also in Oklahoma,
six wells designated as Shut-in on December 31, 2018, were brought into
production in 2019: five located on our Ruthie tract, and one on our Braum
tract.

In 2019, in our Gulf Coast region, we added production through the recompletion
of three vertical wells in Polk County, Texas: one operated by the Company in
which we have 72.5% interest, and two operated by Unit Petroleum in which the
Company owns 2.81% working interest and 3.77% net revenue interest. In 2020, the
Company successfully recompleted one additional operated well in the Segno field
with a 72.5% interest.

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. Regarding the
four drilled but uncompleted PUD wells in Grady County, Oklahoma noted in the
paragraph above, reserves previously attributed to these wells were not included
in the 2021 year-end reserve report as the operator has no near-term plans for
their completion.

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During 2022, in our West Texas horizontal drilling program, we participated with
10.3% interest in the drilling of four horizontal wells with SEM Operating
Company and have received proposals for an additional 24 horizontal wells, 15 of
those to begin in the fourth quarter of this year. In total, the Company is
likely to invest approximately $75 million in these 28 wells. In Oklahoma, thus
far in 2022, the Company is participating for 9.38% interest with Ovintiv
Mid-Continent in the drilling of four wells on our Bohlman tract in Canadian
County, Oklahoma. These four wells and the four SEM wells in West Texas were
placed in production during August of this year. In the first quarter of 2023,
we intent to participate with Apache in the drilling of two 3-mile-long
horizontals in Upton County, Texas and with BTA Oil Producers in the drilling of
nine 2.5 mile-long horizontals in Reagan County, Texas. Additional drilling and
future development plans will be established based on an expectation of
available cash flows from operations and availability of funds under our
revolving credit facility.

We employ technologies to establish proved reserves that have been demonstrated
to provide consistent results capable of repetition. The technologies and
economic data being used in the estimation of our proved reserves include, but
are not limited to, electrical logs, radioactivity logs, geologic maps,
production data, and well-test data. The estimated reserves of wells with
sufficient production history are estimated using appropriate decline curves.
Estimated reserves of producing wells with limited production history and for
undeveloped locations are estimated using performance data from analogous wells
in the area. These wells are considered analogous based on production
performance from the same formation and with similar completion techniques.

The estimated future net revenue (using current prices and costs as of those
dates) and the present value of future net revenue (at a 10% discount for
estimated timing of cash flow) for our proved developed and proved undeveloped
oil and gas reserves at the end of each of the three years ended December 31,
2021, are summarized as follows (in thousands of dollars):

                             Proved Developed                    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
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
2021                   $    275,227       $  171,906       $          -        $        -      $    275,227       $  171,906        $    36,100        $      135,806


The PV 10 Value represents the discounted future net cash flows attributable to
our proved oil and gas reserves before income tax, discounted at 10%. Although
this measure is not in accordance with U.S. generally accepted accounting
principles ("GAAP"), we believe that the presentation of the PV10 Value is
relevant and useful to investors because it presents the discounted future net
cash flow attributable to proved reserves prior to taking into account corporate
future income taxes and the current tax structure. We use this measure when
assessing the potential return on investment related to oil and gas properties.
The PV10 of future income taxes represents the sole reconciling item between
this non-GAAP PV10 Value versus the GAAP measure presented in the standardized
measure of discounted cash flow. 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.

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Natural gas prices, based on the twelve-month average of the first of the month
Henry Hub index price, were $3.598 per MMBtu in 2021 as compared to $1.985 per
MMBtu in 2020, and $2.581 per MMBtu in 2019. Through November 1, 2022, the
twelve-month average of the first of the month Henry Hub index price is $6.166
per MMBtu. Oil prices, based on the NYMEX first of the month average price, were
$66.56 per barrel in 2021 as compared to $39.57 per barrel in 2020, and $55.69
per barrel in 2019. Through November 1, 2022, the NYMEX first of the month
average price was $92.37. 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.

Maintaining a strong balance sheet and ample liquidity are key components of our
business strategy. 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, nine two-mile horizontal wells in Upton County,
Texas, operated by Apache Corporation, were completed and brought into
production. In the fourth quarter of 2021, three two-mile horizontal wells
operated by Ovintiv Mid-Continent in Canadian County, Oklahoma were completed
and brought online in January 2022. The Company has an average of 47.5% interest
in the nine wells completed with Apache and 11.25% interest in the three wells
completed with Ovintiv.

In the second quarter of 2022, the Company participated with SEM Operating
Company LLC in the drilling of four 7,900' horizontal wells in Irion County,
Texas with 10.3% interest. These four wells began their production in August.
Also in the second quarter of 2022, the Company participated in the drilling of
four 10,000'-long horizontal wells in Canadian County, Oklahoma with 9.38%
interest. These four wells, operated by Ovintiv Mid-Continent, were also put
into production in early August of this year. In the fourth quarter of this year
another fifteen wells are planned to be spud.

Since the start of our West Texas horizontal drilling program in 2015, we have
participated in 81 wells and invested approximately $130 million in horizontal
drilling in the Permian Basin. This includes the four wells currently in
progress with SEM Operating Company in Irion County, Texas.

In Upton County, Texas, we are developing a contiguous 3,260-acre block with our
joint venture partner, Apache Corporation. In this block the Company has 2,600
leasehold acres with interest between 14% and 56% depending on the particular
lease and depth being developed. In 2018, eight successful wells were drilled
horizontally by Apache Corporation in the Wolfcamp "B" of this block with the
Company participating for 49% interest and this is believed to be full
development of the Wolfcamp "B" reservoir. Together with Apache, we are planning
development of the Upper Wolfcamp, Jo Mill, and Lower Spraberry reservoirs of
this block. These shallower reservoirs have been proven-up on our offset
1,300-acre Kashmir tract. It is expected that as many as 36 additional
horizontals will be developed on this 3,260-acres in the near future. This
development is estimated to cost approximately $387.0 million, with the
Company's share being approximately $174.4 million. Two 3-mile-long horizontals
have been slated for the first quarter of 2023. In addition to the 36
prospective wells to be drilled for these three reservoirs, a fourth target
reservoir, the Middle Spraberry, is also prospective for future development. The
potential of the Middle Spraberry on the 3,260-acre block is for 12 horizontal
wells to be drilled and completed at a gross cost of approximately
$138.0 million with the Company's share being approximately $63.0 million. The
actual number of wells that are eventually drilled as well as the cost and the
timing of drilling will vary based upon many factors, including commodity market
conditions.

In addition to the 3,260-acre block being developed, as described above, the
Company has also been developing an offsetting 1,300-acre block in Upton County,
Texas, with Apache Corporation as operator. In the second quarter of 2019 three
horizontal wells were completed and brought on production from reservoirs above
the Middle Wolfcamp: one in the Wolfcamp "A", one in the Jo Mill, and one in the
Lower Spraberry, confirming the economic viability of these reservoirs on our
acreage. Prime holds 47.5% working interest in these reservoirs. As a result of
the success of the initial three wells, nine additional horizontals followed and
were completed in the third quarter of 2021. Our average 47.5% share of the cost
of these nine horizontal wells was approximately $26.7 million in total. In
addition to the Wolfcamp "A", Jo Mill and Lower Spraberry, that are now
considered fully developed on the tract, four locations in the Middle Spraberry
will be considered for future development at an estimated gross cost of
approximately $40.0 million with the Company's share being approximately
$18.8 million.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with
ConocoPhillips in Martin County, Texas. In 2016 and 2017, four horizontal wells
were drilled, completed, and put on production. The Company owns 35% to 38%
interest in this joint venture acreage where we have the potential to drill as
many as 36 additional wells.

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As mentioned above, in West Texas, the Company participated for 10.3% interest
with SEM Operating Company in four 7,900'-long horizontal wells in Irion County,
Texas. We anticipate an investment of $2.55 million in these wells which have
been producing since August. Also planned for this year is the drilling of ten
2-mile-long horizontals in Hibernia Energy, III, LLC, in Reagan County, Texas
and the drilling of five 2.5-mile-long horizontal wells with ConocoPhillips in
Martin County. The Company intends to participate for approximately 25% interest
in the ten wells with Hibernia and for 20.8% interest in five wells with Conoco
Phillips. Our expected investment in the drilling and completion of these wells
is $36.3 million.

In the fourth quarter of 2022, the Company completed an acreage exchange
agreement with a large independent oil & gas operator to exchange approximately
725 net acres in the Midland Basin. In combination with existing acreage, this
newly acquired acreage results in the Company having 100% working interest in
approximately 1,200 contiguous acres and therefore the ability to efficiently
and cost-effectively develop the Wolfcamp formation and other prospective
reservoirs through 2-mile-long horizontal laterals.

Along with the 1,200 contiguous acres created from the acreage exchange, the
Company has completed an agreement with a separate prominent independent oil &
gas operator to create a 2,560-acre AMI for the joint development of horizontal
wells. As part of the agreement, the Company has divested of a portion of its
interest to operator for $16.1 million with the ability to acquire additional
acreage from the operator located within the AMI. These exchanges should result
in an approximately 50/50 ownership of the development with the operator. This
newly formed 2,560 acreage-block will allow the Company to reinvest
approximately $90 million of its cash flow in the drilling of as many as 18 new
wells in a very promising area of the Wolfcamp and Spraberry horizontal trend.

In Oklahoma, we are focused on the development of our reserves in Canadian,
Grady, Kingfisher, Garfield, Major, and Garvin counties where we have
approximately 5,800 net leasehold acres in the Scoop/Stack Play. In 2019, we
participated for an average of 4.6% interest with Newfield Exploration in twelve
successful wells in Canadian County on our Slash and Wallace tracts. In 2021, we
participated for 11.25% interest with Ovintiv Mid-Continent Inc. in four wells
on our Peters tract, in Canadian County. Three of these wells were successfully
completed in December 2021 and online in January 2022, while one well had
completion issues and has been temporarily abandoned. At today's product prices,
payout of the Company's $2.3 million investment in these four wells occurred in
four months.

In April 2022, in Oklahoma, the Company and Ovintiv Mid-Continent began drilling
four horizontal wells on our Bohlman tract in the same area as the successful
Peters wells. All four of the Bohlman wells have been drilled, completed, and
were placed on production in early August.. The Company is participating with
9.38% interest in these wells with an approximate investment $2.45 million. In
May, we sold 241 acres in Canadian County, Oklahoma for proceeds of $845,000,
and in August another 113 acres for $423,700. Both of these sales were of
non-strategic acreage and the Company retained its interest in existing wells
and a small overriding royalty interest in future development.

We believe our 5,800 net leasehold acres in Oklahoma have the resource potential
to support the drilling of as many as 50 new horizontal wells based on an
estimate of four wells per multi-section drilling unit: two in the Mississippian
and two in the Woodford Shale. Should we choose to participate in future
development, our share of the capital expenditures would be approximately
34.6 million at a 10% ownership level; the Company will otherwise sell its
rights for cash or cash plus a royalty or working interest.

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

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.

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Our credit agreement required us to hedge a portion of our production as forecasted for the PDP reserves included in our borrowing base review engineering reports. Accordingly, the Company has in place the following swap agreements for oil and natural gas.



                        2022          2023        2022       2023

Swap Agreements Natural Gas (MMBTU) 279,000 254,000 $ $ 3.60 Oil (barrels)

            79,300        70,700     $         $ 69.50


In the first quarter of 2022, the Company participated in the drilling of four
wells with SEM Operating Company in Irion County, Texas for 10.3% interest and
in April of this year began participating with Ovintiv Mid-Continent in four
wells in Canadian County, Oklahoma with 9.38% interest.

These eight wells have been completed and were put on production in early
August. In addition, the Company has received drilling proposals for an
additional 26 horizontal wells to be drilled in West Texas with 15 of these
slated to begin drilling this year. In total, the Company is likely to invest
approximately $86 million in these 26 wells. 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 $75 million. As
of August 15, 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 December 2022. 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.

In the first quarter of 2022, the Company sold 1,809 net leasehold acres in Reagan and Midland Counties, Texas through three transactions receiving gross proceeds of $14.1 million and retaining certain over-riding royalty interests.

In the second quarter of 2022, the Company sold 241 net acres in Canadian County, Oklahoma for proceeds of $845,000 and a retained over-riding royalty interest.

In the third quarter of 2022, the Company sold an additional 113 net acres in Canadian County, Oklahoma for $423,700.



In November of 2022, the Company completed an acreage exchange with a large
independent oil & gas operator to exchange approximately 725 net acres in the
Midland Basin. When combined with currently held acreage, this acreage exchange
results in the Company having 100% working interest in approximately 1,200
contiguous acres and therefore the ability to efficiently and cost-effectively
develop the Wolfcamp and other prospective reservoirs through 2-mile-long
horizontal laterals. In addition to this exchange, the Company has completed an
agreement with a separate prominent independent oil & gas operator to create a
2,560-acre AMI for the joint development of horizontal wells. As part of the
plan, the Company has divested a portion of its interest to the operator for
$16.1 million and has the right to acquire additional acreage from the operator
within the AMI. These exchanges should result in an approximate 50/50 ownership
of the AMI development with the operator. This newly formed 2,560 acreage block
will allow the Company to reinvest approximately $90 million of its cash flow in
the drilling of as many as 18 new wells in a very promising area of the Wolfcamp
and Spraberry horizontal trend.

The majority of our capital spending is discretionary, and the ultimate level of
expenditures will be dependent on our assessment of the oil and gas business
environment, the number and quality of oil and gas prospects available, the
market for oilfield services, and oil and gas business opportunities in general.

The Company has a stock repurchase program in place, spending under this program during the first nine months of 2022 was $5.0 million. The Company expects continued spending under the stock repurchase program in 2022.


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RESULTS OF OPERATIONS

2022 and 2021 Compared

We reported net income of $35.3 million, or $17.95 per share and $13.2 million,
or $6.79 per share for the nine and three months ended September 30, 2022,
respectively, as compared to net losses of $1.2 million, or $(0.58) per share
and $5.0 million, or $(2.52) per share for the three and nine months ended
September 30, 2021, respectively. Current year net income reflects increases in
production and commodity price increases over the three and nine months ended
September 30, 2022, fluctuations in gains related to the sale of assets and
changes related to the valuation of derivative instruments. The significant
components of income and expense are discussed below.

Oil, gas and NGLs sales increased $15.9 million, or 87.8% from $18.1 million for
the three months ended September 30, 2021 to $34.0 million for the three months
ended September 30, 2022, and $56.7 million, or 122.9% from $46.1 million for
the nine months ended September 30, 2021 to $102.8 million for the nine months
ended September 30, 2022

The following tables summarizes the primary components of production volumes and
average sales prices realized for the three and nine months ended September 30,
2022 and 2021 (excluding realized gains and losses from derivatives).

                                                                   Nine

months ended September 30,

Increase / Increase /


                                             2022              2021          (Decrease)        (Decrease)
Barrels of Oil Produced                       752,500           480,000          272,500              56.8 %
Average Price Received                    $    100.39      $      63.28      $     37.11              58.6 %

Oil Revenue (In 000's)                    $    75,546      $     30,376      $ 45,170.00             148.7 %


Mcf of Gas Sold                             2,456,800         2,395,000           61,800               2.6 %
Average Price Received                    $      6.01      $       3.32      $      2.69              81.0 %

Gas Revenue (In 000's)                    $    14,762      $      7,948      $  6,814.00              85.7 %


Barrels of Natural Gas Liquids Sold           332,400           298,000           34,400              11.5 %
Average Price Received                    $     37.54      $      26.11      $     11.43              43.8 %

Natural Gas Liquids Revenue (In 000's) $ 12,477 $ 7,781

  $     4,696              60.4 %

Total Oil & Gas Revenue (In 000's) $ 102,785 $ 46,105

  $    56,680             122.9 %




                                                                  Three months ended September 30,

Increase / Increase /


                                             2022             2021            (Decrease)        (Decrease)
Barrels of Oil Produced                      244,500           152,000             92.500              60.9 %
Average Price Received                     $   95.72      $      68.70       $      27.02              39.3 %

Oil Revenue (In 000's)                     $  23,403      $     10.442       $     12,961             124.1 %


Mcf of Gas Sold                              879,800           950,000            (70,200 )           (7.39 )%
Average Price Received                     $    7.23      $       4.21       $       3.02              71.7 %

Gas Revenue (In 000's)                     $   6,359      $      3,998       $      2,361              59.1 %


Barrels of Natural Gas Liquids Sold          122,400           103,000             19,400              18.8 %
Average Price Received                     $   34.35      $      35.26       $      (0.91 )           (2.59 )%

Natural Gas Liquids Revenue (In 000's) $ 4,204 $ 3,632

  $        572              15.7 %

Total Oil & Gas Revenue (In 000's) $ 33,966 $ 18,072

  $     15,894              87.9 %



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 $1.4 million or 58.3% from $2.4 million for the
third quarter 2021 to $3.8 million for the third quarter 2022 and increased
$4.6 million, or 74.2% from $6.2 million for the nine months ended September 30,
2021 to $10.8 million for the nine months ended September 30, 2022. These
changes reflect the increase in utilization and rates resulting from the oil and
gas price increases during these periods. Workover rig services, hot oil
treatments, saltwater hauling and disposal represent the bulk of our field
service operations.

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Lease operating expense increased $2.3 million or 35.9% from $6.4 million for
the third quarter 2021 to $8.7 million for the third quarter 2022 and increased
$11.3 million or 73.9% from $15.3 million for the nine months ended
September 30, 2021 to $26.6 million for the nine months ended September 30,
2022. This increase is primarily due to higher production taxes related to
higher commodity prices during 2022 combined with workover expenses and lease
operating expense related to higher lifting cost properties returned to
production as commodity prices increased.

Field service expense increased $0.1 million or 3.4% from $2.9 million for the
third quarter 2021 to $3.0 million for the third quarter 2022 and increased
$3.3 million, or 53.2% from $6.2 million for the nine months ended September 30,
2021 to $9.5 million for the nine months ended September 30, 2022. Field service
expenses primarily consist of wages and vehicle operating expenses which have
fluctuated during the three and nine months ended September 30, 2022 compared
with the same periods of 2021. These changes reflect the increase in utilization
resulting from the oil and gas price increases during these periods.

Depreciation, depletion, amortization and accretion on discounted liabilities
increased $0.8 million, or 11.6% from $6.9 million for the third quarter 2021 to
$7.7 million for the third quarter 2022 and $1.9 million, or 9.5% from
$20.0 million for the nine months ended September 30, 2021 to $21.9 million for
the nine months ended September 30, 2022. These increases reflect the change in
the property basis combined with production increases in 2022.

General and administrative expense increased $5.3 million, or 85.5% from
$6.2 million for the nine months ended September 30, 2021 to $11.5 million for
the nine months ended September 30, 2022, and increased $0.5 million, or 25.0%
from $2.0 million for the three months ended September 30, 2021 to $2.5 million
for the three months ended September 30, 2022. This increase in 2022 is
primarily due to increased employee compensation and benefits.

Interest expense decreased from $0.5 million for the third quarter 2021 to $0.3 million for the third quarter 2022 and from $1.5 million for the nine months ended September 30, 2021 to $0.8 million for the nine months ended September 30, 2022. This decrease reflects the increase in rates and reduced borrowings under our revolving credit agreement.

Income tax benefit/expense for the September 30, 2022 and 2021 periods varied due to the change in net income or loss for those periods.

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