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

Our cash flows depend on many factors, including the price of oil and gas, the
success of our acquisition and drilling activities and the operational
performance of our producing properties. We use derivative instruments to manage
our commodity price risk. This practice may prevent us from receiving the full
advantage of any increases in oil and gas prices above the maximum fixed amount
specified in the derivative agreements and subjects us to the credit risk of the
counterparties to such agreements. Since all our derivative contracts are
accounted for under mark-to-market 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.

On January 30, 2020, the World Health Organization ("WHO") announced a global
health emergency due to the COVID-19 outbreak, which originated in Wuhan, China,
and the risks to the international community as the virus spreads globally
beyond its point of origin. In March 2020, the WHO classified the COVID-19
outbreak as a pandemic, based on the rapid increase in exposure globally. In
addition, in March 2020, members of OPEC failed to agree on production levels
which has caused an increased supply and has led to a substantial decrease in
oil prices and an increasingly volatile market. The oil price war ended with a
deal to cut global petroleum output but did not go far enough to offset the
impact of COVID-19 on demand. There has been an increase in supply which has
pushed prices down further since March. If the depressed pricing continues for
an extended period it will lead to i) further reductions in the borrowing base
under our credit facility which would require us to make additional borrowing
base deficiency payments, ii) reductions in reserves, and iii) additional
impairment of proved and unproved oil and gas properties. We also expect
disclosures of supplemental oil and gas information to be impacted by price
declines.

In response to recent commodity prices our efforts to reduce costs include
reducing operating costs and electing to shut-in marginal wells. The Company
reviewed field operations to minimize costs and identify wells for short term
shut-ins. The Company has also implemented a reduction in workforce to further
reduce general and administrative costs. The full impact of the COVID-19
outbreak and the decline in oil prices continues to evolve as of the date of
this report. As such, it is uncertain as to the full magnitude that these events
will have on the Company's financial condition, liquidity, and future results of
operations.

Management is actively monitoring the global situation on its financial
condition, liquidity, operations, suppliers, industry, and workforce. Given the
daily evolution of the COVID-19 outbreak and the global responses to curb its
spread, the Company is not able to estimate the effects of the COVID-19 outbreak
on its results of operations, financial condition, or liquidity for fiscal year
2020. These matters may have a continued material adverse impact on economic and
market conditions and trigger a period of global economic slowdown, which may
impair the Company's asset values, including reserve estimates. Further,
consumer demand has decreased since the spread of the outbreak and new travel
restrictions placed by governments in an effort to curtail the spread of the
coronavirus. Although the Company cannot estimate the length or gravity of the
impacts of these events at this time, if the pandemic and/or decreased oil
prices continue, they may have a material adverse effect on the Company's
results of future operations, financial position, and liquidity in fiscal year
2020.

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.

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



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may receive for our oil, natural gas and NGLs. The price of oil and natural gas
has fallen significantly since the beginning of 2020, due in part to failed
Organization of Petroleum Exporting Countries ("OPEC") negotiations as well as
concerns about the COVID-19 pandemic and its impact on the worldwide economy and
global demand for oil and gas. The resulting precipitous decline in oil and gas
pricing experienced during March 2020, through the date of this report, if
prolonged. or a further deterioration of the market price for oil and natural
gas, will negatively impact our cash flows.

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
20,400 gross (12,700 net) acres, 97% of which is located in Reagan, Upton,
Martin, and Midland counties of Texas where our current horizontal drilling
activity is focused. We believe this acreage has significant resource potential
in the Spraberry and Wolfcamp intervals for additional horizontal drilling that
could support the drilling of as many as 250 additional horizontal wells. In
Oklahoma we maintain an acreage position of approximately 81,800 gross (10,900
net) acres. Our Oklahoma horizontal development is focused primarily in
Canadian, Kingfisher, Grady, and Garvin counties. We believe approximately 3,460
net acres in these counties hold significant additional resource potential that
could support the drilling of as many as 52 new horizontal wells based on an
estimate of four to ten 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 $40 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 reserve and well information as of
December 31, 2019.



                                                            Gulf         Mid-           West
                                          Appalachian      Coast       Continent       Texas       Other       Total
Proved Reserves as of December 31,
2019 (MBoe)
Developed                                          296        726           2,013        7,582         11       10,628
Undeveloped                                         -          -               81        3,526         -         3,607
Total                                              296        726           2,094       11,108         11       14,235
Average Daily Production (Boe per day)             240        348             840         3703          4        5,133
Gross Productive Wells (Working
Interest and ORRI Wells)                           528        263             567          561        105        2,024
Gross Productive Wells (Working
Interest Only)                                     481        233             418          522         45        1,699
Net Productive Wells (Working Interest
Only)                                              451        143             216          257          4        1,071
Gross Operated Productive Wells                    438        125             144          298         -         1,005
Gross Operated Water Disposal,
Injection and Supply wells                           1          7              44            7         -            59


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

Appalachian Region



Our Appalachian activities are concentrated primarily in West Virginia. This
region is managed from our office in Charleston, West Virginia. Our assets in
this region include a large acreage position and a high concentration of wells.
At December 31, 2019, we had interest in 481 wells (451 net), of which 438 wells
are operated. Multiple producing intervals here include the Big Lime, Injun,
Blue Monday, Weir, Berea, Gordon and Devonian Shale formations at depths
primarily ranging from 1,600 to 5,600 feet. Average net daily production in 2019
was 240 Boe. While natural gas production volumes from Appalachian reservoirs
are relatively low on a per-well basis compared to other areas of the United
States, the productive life of Appalachian reserves is relatively long. At
December 31, 2019, we had 296 MBoe of proved developed reserves (substantially
all natural gas) in the Appalachian region, constituting 2.1% of our total
proved reserves. We maintain an acreage position of approximately 35,790 gross
(35,350 net) acres in this region, primarily in Calhoun, Clay, and Roane
counties. We operate a small field service group in this region utilizing one
swab rig, one paraffin truck, one saltwater hauling truck and limited excavating
equipment to primarily service our own operated wells and locations. As of
March 31, 2020, the Appalachian region has no wells in the process of being
drilled, no waterfloods in the process of being installed and no other related
activities of material importance. Effective August 1, 2020 the Company sold our
Appalachian properties for $200,000 and retained an overriding royalty on
approximately 31,000 undeveloped acres.



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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 233 producing wells (143 net) in the Gulf Coast region as
of December 31, 2019, of which 125 wells are operated by us. Average net daily
production in 2019 was 348 Boe. At December 31, 2019, we had 726 MBoe of proved
reserves in the Gulf Coast region, which represented 5.1% of our total proved
reserves. We maintain an acreage position of over 12,700 gross (5,120 net) acres
in this region, primarily in Dimmit and Polk counties. We operate a field
service group in this region from a field office in Carrizo Springs, Texas
utilizing four workover rigs, nineteen water transport trucks, two saltwater
disposal wells and several trucks and excavating equipment. Services including
well service support, site preparation and construction services for drilling
and workover operations are provided to third-party operators as well as
utilized in our own operated wells and locations. As of March 31, 2020, 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, 2019,
we had 418 wells (216 net) in the Mid-Continent area, of which 144 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 2019 was 840 Boe. At December 31, 2019, we had 2,094 MBoe of
proved reserves in the Mid-Continent area, or 14.7% of our total proved
reserves. We maintain an acreage position of approximately 55,880 gross (10,690
net) acres in this region, primarily in Canadian, Kingfisher, Grant, Major, and
Garvin counties. We operate a field service group in this region from a field
office in Elmore City, utilizing one workover rig and one saltwater hauling
truck. Our Mid-Continentregion is actively participating with third-party
operators in the horizontal development of lands that include Company owned
interest in several counties in the Stack and Scoop plays of Oklahoma where
drilling is primarily targeting reservoirs of the Mississippian, and Woodford
formations. As of March 31, 2020, in the Mid-Continent region, the Company was
is participating in the drilling and/or completion of four wells, with
overriding royalty only in eight additional wells, all included as Proved
Undeveloped in the 2019 year-end reserve report.

West Texas Region



Our West Texas activities are concentrated in the Permian Basin in Texas and New
Mexico. The Spraberry field was discovered in 1949, encompasses eight counties
in West Texas and the Company believes it is the largest oil field in the United
States. The field is approximately 150 miles long and 75 miles wide at its
widest point. The oil produced is West Texas Intermediate Sweet, and the gas
produced is casing-head gas with an average energy content of 1,400 Btu. The oil
and gas are produced primarily from five intervals; the Upper and Lower
Spraberry, the Wolfcamp, the Strawn, and the Atoka, at depths ranging from 6,700
feet to 11,300 feet. This region is managed from our office in Midland, Texas.
As of December 31, 2019, we had 522 wells (257 net) in the West Texas area, of
which 298 wells are operated by us. Principal producing intervals are in the
Spraberry, Wolfcamp, and San Andres formations at depths ranging from 4,200 to
12,500 feet. Average net daily production in 2019 was 3,703 Boe. At December 31,
2019, we had 11,108 MBoe of proved reserves in the West Texas area, or 78% of
our total proved reserves. We maintain an acreage position of approximately
19,910 gross (12,560 net) acres in the Permian Basin in West Texas, primarily in
Reagan, Upton, Martin and Midland counties and believe this acreage has
significant resource potential for horizontal drilling in the Spraberry, Jo
Mill, and Wolfcamp intervals. We operate a field service group in this region
utilizing nine workover rigs, four hot oiler trucks, one kill truck and two
roustabout trucks. Services including well service support, site preparation and
construction services for drilling and workover operations are provided to
third-party operators as well as utilized in our own operated wells and
locations. At December 31, 2019, the Company had committed to participate in the
drilling of ten Proved Undeveloped horizontal drilling locations. Seven of the
nine wells were drilled by April 15, 2020, but are not expected to be completed
and producing until the fourth quarter of 2020.

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, 2019. 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 twenty-five years of experience, holds a Bachelor degree in Geology and an
MBA in finance and is a member of the Society of Petroleum Engineers and
American Association of Petroleum Geologist. See Part II, Item 8 "Financial
Statements and Supplementary Data", for additional discussions regarding proved
reserves and their related cash flows.



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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)
2017                    5,333        1,703       17,143        9,893          505          156         710         779        5,838        1,859       17,853       10,672
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

(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.




At December 31, 2017 our reserve report included 779 MBoe of proved undeveloped
reserves attributable to 22 horizontal wells that were all completed in 2018,
therefore, 100% of these reserves were converted to proved developed in the 2018
year-end reserves report.

In 2018, the Company drilled and completed seventeen horizontal wells in West
Texas and eleven horizontal wells in Oklahoma. In addition, the Company added
reserves through overriding royalty interest in 16 wells, primarily in Oklahoma
and Texas. At year-end 2018, thirteen of the seventeen wells completed in 2018
were designated as Shut-In: eight in our West Texas horizontal development
program, which were brought on production in February, 2019, and five in our
Oklahoma Scoop-Stack development program, which were brought on production in
March, 2019.

At December 31, 2018, our reserve report included 43 MBoe of proved undeveloped
reserves attributable to eight horizontal wells that had been drilled but had
not yet been completed: three of these were completed in 2019, converting 24
Mboe of undeveloped reserves to proved developed, and five remained uncompleted
as of December 31, 2019, which account for 18 Mboe of the 43 Mboe. The Company
has 9% ownership in one of these five wells and less than 1% in four wells.

In 2019, in West Texas, in addition to the eight wells classified as Shut-in at
year-end 2018 that were brought on production in February, we participated in
the drilling and completion of three wells on our Kashmir tract: two wells with
an average 49% interest, and a third well for 5.3% interest. One of each of
these wells was completed in the Wolfcamp "A", Jo Mill, and Lower Spraberry. All
three wells were brought on production in May of 2019.

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

At December 31, 2019, the Company had 3,607 Mboe of undeveloped reserves
attributable to 22 wells operated by others that are anticipated to be drilled
and completed primarily in 2020: ten of these are located in our West Texas
horizontal development program and account for 3,526 Mboe of the total, and 12
wells are located in our Oklahoma Scoop-Stack horizontal program and account for
81 Mboe of the total. Nine of the ten wells in West Texas are located on our
1,300 acre Kashmir tract in Upton County, operated by Apache Corporation and, as
of April 15, 2020, six of these have been drilled and are awaiting completion,
which is expected to occur in the fourth quarter of 2020. Our average 47.76%
share of the cost of these six horizontal wells will be approximately
$19.4 million. Drilling of the remaining three wells will likely occur in 2021.

In the first half of 2020, the Company participated in a horizontal well for
8.36% interest operated by Pioneer Natural Resources completed and brought into
production in July 2020. Our total net expenditure for this well will be
approximately $630,000. 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.



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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,
2019, 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
2017                                   $    160,737      $  111,614      $      13,564      $     6,100      $    174,301      $  117,714      $    10,800      $      106,914
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


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.

RECENT ACTIVITIES

Since the start of our West Texas horizontal drilling program in 2015 and
through the second quarter of 2020 the Company has participated in 74 horizontal
wells in the Permian Basin, seven of which were drilled in the first half of
2020. Through July 2020, the Company has invested approximately $111 MM in our
West Texas horizontal drilling program. Of the 74 total horizontal wells
participated in, we have an average of 24% working interest. In 2019, 11 wells
were brought on production: the Company has 49% interest in eight of these
wells, all one-mile in length, located on our CC-33 tract, and an average 48%
interest in two horizontals and 5.3% interest in one additional horizontal, that
are each two-miles in length, located on the Kashmir tract. The Company invested
approximately $31.5 million in these 11 wells brought on production in 2019.
Through the second quarter of 2020, the Company participated in seven new
horizontal wells, all located in Upton County, Texas. Six of these are operated
by Apache Corporation and one is operated by Pioneer Natural Resources. The
Pioneer well was completed in late June and came on production in early July
2020. The six Apache operated wells are anticipated to be completed in the
fourth quarter of 2020.



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In Upton County, West 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, in this block, eight wells
drilled horizontally in the Wolfcamp "B", were participated in for 49% interest.
This is believed to be full development of the Wolfcamp "B" reservoir for this
lease block. Apache will likely now set its sights on development of the Upper
Wolfcamp, Jo Mill, and Lower Spraberry reservoirs for this block, following the
recent successful testing in 2019 of these reservoirs on our offset 1,300-acre
lease block. Given the favorable results achieved by the initial three wells on
the offset block, it is expected that as many as 54 additional horizontals will
be slated for development on the 3,260-acre block in the near future. The cost
of such development would be approximately $370.6 million with the Company's
share being approximately $170.8 million. In addition, there is a fourth target
reservoir, the Middle Spraberry, that is also prospective for development. The
potential of the Middle Spraberry, on the 3,280-acre block, is for 18 horizontal
wells to be drilled, with the Company likely participating for approximately
$61.8 million. The actual number of wells that are eventually drilled as well as
the cost and the timing of drilling will vary based upon many factors, including
commodity market conditions.

In addition to the 3,260 acreage block under development, the Company is also
developing an offsetting 1,300-acre block in Upton County, Texas with Apache
Corporation as operator. In the second quarter of 2019 three horizontal wells
were completed and brought on production from reservoirs above the Middle
Wolfcamp: one in the Wolfcamp "A", one in the Jo Mill, and one in the Lower
Spraberry, confirming the economic viability of these reservoirs on our acreage.
Prime holds between 5% and 48% working interest in various depths of this
acreage, and of the $26.7 million development cost for these three wells, our
share was approximately $9.2 million. As a result of the success of these three
wells, six horizontals were drilled in the first half of 2020 on this acreage
block. We have an average 47.76% share of these wells. In addition to the six
development locations in the Wolfcamp "A", Jo Mill and Lower Sprayberry of our
1,300-acre block, there are four locations in the Middle Spraberry that are
likely to be considered for future development at an estimated gross cost of
approximately $30.2 million, with the Company's share being approximately
$14.2 million. Also in the first half of 2020, the Company participated in a
horizontal well for 8.36% interest operated by Pioneer Natural Resources
completed and brought into production in July, 2020. Our total net expenditure
for this well will be approximately $630,000.

Also in the Permian Basin of West Texas, we are developing a 965-acre block with
Concho Resources in Martin County, Texas. In 2016 and 2017, four horizontal
wells were drilled and completed and put on production. The Company owns 35% to
38% interest in this joint venture acreage where Concho Resources is the
operator. No near-term additional drilling plans have been received from Concho
Resources, however, offset operators have been actively drilling and their
results are encouraging for the future development of multiple landing zones
within this acreage block.

In Central Reagan County, of West Texas, the Company has entered into a contract
to sell deep rights covering approximately 1,950 acres for a purchase price of
approximately $10.7 MM. The sale is planned to close on or before September 01,
2020.

Since the start of our Oklahoma Scoop-Stack horizontal development program,
which began in 2013, the Company has participated in 41 horizontal wells for
approximately $23.5 million through 2019 with an average of approximately 7%
interest. There have been no new wells participated in through the second
quarter of 2020. During this same period the Company chose to retain an
overriding royalty interest in an additional 62 horizontal wells. In 2019, the
Company participated for an average 5.78% interest in 20 horizontal wells in
Canadian, Grady, and Kingfisher counties for a net cost of approximately
$8.8 million. All 20 wells were completed in 2019, and of these 20 wells, twelve
are operated by Encana/Newfield. In addition, the Company is also participating
in four wells in Grady County, Oklahoma spud in 2018 that have not yet been
completed. During 2019, the Company retained an overriding royalty interest in
eighteen wells, nine of which were completed in 2019, and nine of which have yet
to be completed.

Our horizontal activity in Oklahoma is focused in Canadian, Grady, Kingfisher,
Garfield, Major, and Garvin counties where we have approximately 3,401 net
acres. We believe this acreage has significant additional resource potential
that could support the drilling of as many as 49 new horizontals based on an
estimate of six wells per section: three in the Mississippian and three in the
Woodford Shale. Should we choose to participate in future development, our share
of the capital expenditures would be approximately $3.4 million at an average
10% ownership level; the Company will otherwise sell its rights for cash, or
cash plus a royalty or working interest.

In 2019, in the Gulf Coast region of Texas, the Company participated with Unit
Petroleum in the successful recompletion of two wells in the Wilcox Formation of
the Jazz field in Polk County, Texas. The Company has a 2.8125% working interest
and a 3.768% net revenue interest in these wells and participated for
approximately $45,000. Also in 2019, the Company successfully recompleted a
shallow straight hole well in the Segno field of Polk County, Texas with a 72.5%
working interest.

In early August 2020, the Company closed on the sale of its West Virginia District operated assets. The sale includes 456 producing wells, along with approximately 31,000 leasehold acres, one salt water disposal well, and operating equipment. The Company has retained an overriding royalty interest in most properties of up to 12.5% interest.


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RESULTS OF OPERATIONS

2020 and 2019 Compared

We report a net loss of $170 thousand, $0.09 per share, for the three months
ended March 2020 compared with net loss of $3.04 million, $1.49 per share, for
the same period of 2019. The current year net loss reflects decreases in oil,
gas and NGLs sales due to lower commodity prices offset by an unrealized gain on
derivatives. The significant components of income and expense are discussed
below.

Oil, gas and NGLs sales decreased $11.08 million, or 46.4% from $23.88 million
for the three months ended March 31, 2019 to $12.8 million for the three months
ended March 31, 2020. Sales vary due to changes in volumes of production sold
and realized commodity prices. Our realized prices decreased an average of $7.03
per barrel, or 13.3% on crude oil, decreased an average of $1.46 per mcf, or
61.7% on natural gas and decreased an average of $10.24 per barrel, or 51.1% on
NGLs, during the three months ended March 31, 2020 from the same period in 2019.

Our crude oil production decreased by 122,000 barrels, or 34.3% from 356,000
barrels for the first quarter 2019 to 234,000 barrels for the first quarter
2020. Our natural gas production decreased by 10,000 mcf, or 1.1% from 948,000
mcf for the first quarter 2019 to 938,000 mcf for the first quarter 2020. Our
natural gas liquids production decreased by 15,000 barrels, or 10.6% from
142,000 barrels for the first quarter 2019 to 127,000 barrels for the first
quarter 2020. The decrease in production volumes reflect the natural decline of
our properties combined with the shut-in of high lifting cost properties as
commodity prices decreased during the quarter.

The following tables summarizes the primary components of production volumes and
average sales prices realized for the three and six months ended June 30, 2020
and 2019 (excluding realized gains and losses from derivatives).



                                                                        Six months ended June 30,

Increase / Increase /


                                              2020              2019           (Decrease)         (Decrease)
Barrels of Oil Produced                        378,000           688,000          (310,000 )            (45.1 )%
Average Price Received                     $     37.89       $     55.84       $    (17.95 )            (32.1 )%

Oil Revenue (In 000's)                     $    14,324       $    38,442       $   (24,118 )            (62.7 )%

Mcf of Gas Sold                              1,812,000         2,243,000          (431,000 )            (19.2 )%
Average Price Received                     $      0.77       $      1.60       $     (0.83 )            (52.1 )%

Gas Revenue (In 000's)                     $     1,389       $     3,590       $    (2,201 )            (61.3 )%

Barrels of Natural Gas Liquids Sold            213,000           288,000           (75,000 )            (26.0 )%
Average Price Received                     $      8.16       $     18.14       $     (9.98 )            (55.0 )%

Natural Gas Liquids Revenue (In 000's) $ 1,738 $ 5,219

    $    (3,481 )            (66.7 )%

Total Oil & Gas Revenue (In 000's) $ 17,451 $ 47,251

   $   (29,800 )            (63.1 )%





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                                                                     Three

months ended June 30,

Increase / Increase /


                                             2020             2019           (Decrease)         (Decrease)
Barrels of Oil Produced                      144,000           332,000          (188,000 )            (10.8 )%
Average Price Received                     $   (7.88 )     $     59.17       $       (11 )            (18.8 )%

Oil Revenue (In 000's)                     $  (3,613 )     $    19,644       $   (16,031 )            (19.7 )%

Mcf of Gas Sold                              874,000         1,295,000          (421,000 )            (18.1 )%
Average Price Received                     $   (0.13 )     $      1.05       $      0.63                9.6 %

Gas Revenue (In 000's)                     $     543       $     1,355       $      (812 )              0.8 %

Barrels of Natural Gas Liquids Sold           86,000           146,000           (60,000 )            (15.4 )%
Average Price Received                     $   (1.63 )     $     16.27       $      0.26               (3.9 )%

Natural Gas Liquids Revenue (In 000's) $ 495 $ 2,375

  $    (1,880 )            (10.4 )%

Total Oil & Gas Revenue (In 000's) $ 4,651 $ 23,374

  $   (18,723 )           (16.70 )%



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-marketadjustments, 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. The following table summarizes the results of our
derivative instruments for the three and six months ended June 2020 and 2019:



                                                    Three Months Ended            Six Months Ended
                                                         June 30,                     June 30,
                                                     2020          2019          2020          2019
                                                                     ($ in thousand)

Oil derivatives - realized gains (losses) $ 4,539 $ (964 )

$  5,545      $   (876 )
Oil derivatives - unrealized gains (losses)           (5,397 )      2,637

854 (3,101 )



Total gains (losses) on oil derivatives           $     (858 )    $ 1,673      $  6,399      $ (3,977 )
Natural gas derivatives - realized gains
(losses)                                          $      218      $     4      $    409      $     (8 )
Natural gas derivatives - unrealized gains
(losses)                                                (218 )        156            87           151

Total gains (losses) on natural gas
derivatives                                       $       -       $   160      $    496      $    143
NGL derivatives - realized gain (losses)          $       -       $   109      $     -       $    111
NGL derivatives - unrealized gains (losses)               -            69            -             60

Total gains (losses) on NGL derivatives                   -           178

$ - $ 171



Total gains (losses) on oil, natural gas and
NGL derivatives                                   $     (858 )    $ 2,011      $  6,895      $ (3,663 )

Prices received for the six months ended June 30, 2020 and 2019, respectively, including the impact of derivatives were:





                                         2020        2019
                           Oil Price    $ 52.56     $ 54.56
                           Gas Price    $  0.99     $  1.00
                           NGLS Price   $  8.16     $ 18.52


Field service income decreased $2.4 million or 49.95% from $4.8 million for the
second quarter 2019 to $2.4 million for the second quarter 2020 and
$2.8 million, or 29.60% from $9.5 million for the six months ended June 30, 2019
to $6.7 million for the six months ended June 30, 2020. This decrease is a
combined result of decreased utilization and rates charged to customers as oil
and gas prices declined during 2020. Workover rig services, hot oil treatments,
saltwater hauling and disposal represent the bulk of our field service
operations.

Lease operating expense decreased $1.9 million or 23.55% from $8.1 million for
the second quarter 2019 to $6.2 million for the second quarter 2020, and
decreased $3.6 million or 22.50% from $16.2 million for the six months ended
June 30, 2019 to $12.6 million for the six months ended June 30, 2020. This
decrease is primarily due to the shut-in of high lifting cost properties during
2020 combined with lower production taxes related to lower commodity prices.



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Field service expense decreased $2.1 million or 1.92% from $4.0 million for the
second quarter 2019 to $1.9 million for the second quarter 2019 and decreased
$2.2 million, or 28.39% from $7.6 million for the six months ended June 30, 2019
to $5.5 million for the six months ended June 30, 2020. Field service expenses
primarily consist of salaries and vehicle operating expenses which have
decreased during the three and six months ended June 30, 2020 over the same
periods of 2019 related to decreased utilization of the equipment as oil and gas
prices declined during 2020.

Depreciation, depletion, amortization and accretion on discounted liabilities
increased $2.4 million, or 25.74% from $9.3 million for the second quarter 2019
to $6.9 million for the second quarter 2020 and $3.5 million, or 18.64% from
$18.6 million for the six months ended June 30, 2019 to $15.1 million for the
six months ended June 30, 2020, reflecting the reduced production rates in the
first half of 2020.

General and administrative expense increased $0.5 million, or 5.48% from
$9.8 million for the six months ended June 30, 2019 to $10.3 million for the six
months ended June 30, 2020, and decreased $0.3 million, or 11.23% from
$2.9 million for the three months ended June 30, 2019 to $2.6 million for the
three months ended June 30, 2020. This overall increase in 2020 is primarily due
to increases in employee wages and benefits during the first quarter offset by
staff reductions reflected in the second quarter decrease.

Gain on sale and exchange of assets of $0.2 million and $1.7 million for the six
months ended June 30, 2020 and June 30, 2019, respectively consists of sales of
non-essential oil and gas interests and field service equipment.

Interest expense decreased from $1.0 million for the second quarter 2019 to
$0.5 million for the second quarter 2020 and from $2.0 million for the six
months ended June 30, 2019 to $1.2 million for the six months ended June 30,
2020. This decrease reflects the decrease in rates and current borrowings under
our revolving credit agreement.

Income tax expense or benefit for the June 30, 2020 and 2019 periods varied due
to the change in net income or loss for those periods. The tax benefit recorded
for the six months ended June 30, 2020 includes the benefits related to tax
changes under the CARES Act.

LIQUIDITY AND CAPITAL RESOURCES

Our primary sources of liquidity are cash generated from our operations, through our producing oil and gas properties, field services business and sales of acreage.



Net cash provided by operating activities for the six months ended June 30, 2020
was $8.8 million. 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.

If our exploratory drilling results in significant new discoveries, we will have
to expend additional capital to finance the completion, development, and
potential additional opportunities generated by our success. We believe that,
because of the additional reserves resulting from the successful wells and our
record of reserve growth in recent years, we will be able to access sufficient
additional capital through bank financing.

Maintaining a strong balance sheet and ample liquidity are key components of our
business strategy. For 2020, we will continue our focus on preserving financial
flexibility and ample liquidity as we manage the risks facing our industry. Our
2020 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,
2021, providing for a credit facility totaling $300 million, with a borrowing
base of $72 million. As of August 19, 2020, the Company has $53.5 million in
outstanding borrowings and $18.5 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 borrowing base review
is in progress and due to declines in commodity prices we expect our borrowing
base to be set at an amount



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substantially reducing our availability under the line and requiring paydowns of
our current outstanding balance during the third and fourth quarters. We expect
cash flows from producing properties combined with proceeds from the sale of
acreage to fund these paydowns. 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 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 and put agreements for oil and natural gas.





                                    2020           2021         2020        2021
           Swap Agreements
           Natural Gas (MMBTU)            -        951,000     $    -      $  2.41

                                    2020           2021         2020        2021
           Put Agreements
           Natural Gas (MMBTU)     1,090,000       500,000     $  2.25     $  2.00
           Oil (barrels)              61,400        66,000     $ 48.27     $ 35.00


On March 27, 2020, President Trump signed into law the Coronavirus Aid, Relief,
and Economic Security Act (the "CARES Act"). The CARES Act, among other things,
includes provisions relating to refundable payroll tax credits, deferment of
employer side social security payments, net operating loss carryback periods,
alternative minimum tax credit refunds, modifications to the net interest
deduction limitations, increased limitations on qualified charitable
contributions, and technical corrections to tax depreciation methods for
qualified improvement property.

We have experienced significant disruptions to our business and operations. In
particular, COVID-19restrictions have limited access to our corporate offices
and required our corporate personnel, including our legal and accounting staff.

Paycheck Protection Program Loans



During May 2020, Prime Operating Company and Eastern Oil Well Services
Corporation, subsidiaries of the Company received loan proceeds in the amount of
$1.28 million and $0.47 million , respectively, under the Paycheck Protection
Program (the "PPP") of the CARES Act. The PPP Loans are evidenced by a
promissory note in favor of the Lender, which bears interest at the rate of
1.00% per annum. No payments of principal or interest are due under the note
until the date on which the amount of loan forgiveness (if any) under the CARES
Act, which can be up to 10 months after the end of the related notes covered
period (which is defined as 24 weeks after the date of the loan) (the "Deferral
Period"). The note may be prepaid at any time prior to maturity with no
prepayment penalties. Funds from the PPP Loans may be used only for payroll and
related costs, costs used to continue group health care benefits, mortgage
payments, rent, utilities, and interest on other debt obligations that were
incurred prior to February 15, 2020 (the "Qualifying Expenses"). Under the terms
of the PPP Loans, certain amounts thereunder may be forgiven if they are used
for Qualifying Expenses as described in and in compliance with the CARES Act.
While the Company intends to use the PPP Loan proceeds exclusively for
Qualifying Expenses, it is unclear and uncertain whether the conditions for
forgiveness of the PPP Loans will be met under the current guidelines of the
CARES Act. Accordingly, we cannot make any assurance that the Company will be
eligible for forgiveness of the PPP Loans, in whole or in part. To the extent,
if any, that any or all of the PPP loans are not forgiven, beginning one month
following expiration of the Deferral Period, and continuing monthly until 24
months from the date of each applicable Note (the "Maturity Date"), the Company
is obligated to make monthly payments of principal and interest to the Lender
with respect to any unforgiven portion of the Note, in such equal amounts
required to fully amortize the principal amount outstanding on such Note as of
the last day of the applicable Deferral Period by the applicable Maturity Date.

The Company's activities include development and exploratory 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.



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We participated in 18 gross (1.6 net) horizontal wells drilled and completed in
2019, all of which were producing at year-end. In addition, 14 gross (4.63 net)
wells that had been completed at year-end 2018 and in which we had participated,
were also brought on-line in 2019. Of the total 18 wells completed in 2019,
three are located in West Texas, while 13 are in our Oklahoma Scoop-Stack
horizontal development program. The three wells drilled in West Texas in 2019
added significantly to our reserve base, as these probable undeveloped locations
were the initial test wells in intervals above the Middle Wolfcamp: one in the
Wolfcamp "A", one in the Jo Mill and one in the Lower Spraberry, and have proved
up these reservoirs for the 1,300 acre block in which they were drilled. Our
share of the cost of these three wells is approximately $9.2 million. Not only
did these wells add proved developed reserves, but as a result, nine additional
locations in these reservoirs were proven for horizontal development. Six of the
nine horizontals were drilled as of April 15, 2020. The successful development
of these reservoirs has also proved-up locations to be drilled on our nearby
2,600-acre block in which the Company holds between 14% and 56% interest. It is
anticipated that development of as many as 54 additional horizontal wells on
this 2,600-acre block will occur over the coming years. The cost of such
development would be approximately $370.6 million with the Company's share being
approximately $170.8 million. The actual number of wells that will be drilled,
the cost, and the timing of drilling will vary based upon many factors,
including commodity market conditions.

In early 2020, the Company participated in the drilling of six wells in Upton
County, Texas, operated by Apache Corporation. These wells are expected to be
completed in the fourth quarter of 2020 with a total anticipated investment of
$19.4 million. Also in the first half of 2020, the Company participated in a
horizontal well for 8.36% interest operated by Pioneer Natural Resources
completed and brought into production in July 2020. Our total net expenditure
for this well will be approximately $630,000. 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 focus of our future activity will be on the continued development of our
resource's potential in the West Texas horizontal drilling program as well as
our Scoop-Stack horizontal drilling program acreage in Oklahoma in order to
maximize cash flow and return on investment.

The Company maintains an acreage position of 19,910 gross (12,560 net) acres in
the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland
counties and we believe this acreage has significant resource potential in as
many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp
that support the potential drilling of as many as 180 additional horizontal
wells.

In Oklahoma, the Company's horizontal activity is primarily focused in Canadian,
Grady, Kingfisher, Garfield, Major, and Garvin counties where we have
approximately 3,460 net leasehold acres. We believe this acreage has significant
additional resource potential that could support the drilling of as many as 52
new horizontal wells based on an estimate of six wells per section: three in the
Mississippian and three in the Woodford Shale. Should we choose to participate
in future development, our share of the capital expenditures would be
approximately $40 million at an average 10% ownership level; the Company will
otherwise 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
and 2019 was $0.71 million and $5.9 million, respectively. In the current price
environment, the Company will suspend their stock repurchase program.

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