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MarketScreener Homepage  >  Equities  >  Nasdaq  >  Primeenergy Resources Corp    PNRG

PRIMEENERGY RESOURCES CORP

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PRIMEENERGY RESOURCES : MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (form 10-Q)

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05/20/2019 | 04:04pm EDT
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, Oklahoma and West Virginia.
In addition, we own a substantial amount of well servicing equipment. All of our
oil and gas properties and interests are located in the United States. Assets in
our principal focus areas include mature properties with long-lived reserves and
significant development opportunities as well as newer properties with
development and exploration potential.

We 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 2,215
net acres in these counties hold significant additional resource potential that
could support the drilling of as many as 161 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 $82 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, 2018.



                                                           Gulf         Mid-          West
                                         Appalachian      Coast       Continent       Texas      Other       Total
Proved Reserves as of December 31,
2018 (MBoe)
Developed                                         559        814           2,839       8,401          8       12,622
Undeveloped                                        -          -               43          -          -            43
Total                                             559        814           2,882       8,401          8       12,665
Average Daily Production (Boe per
day)                                              244        572             977       4,248          7        6,048
Gross Productive Wells (Working
Interest and ORRI Wells)                          547        293             580         558        105        2,083
Gross Productive Wells (Working
Interest Only)                                    500        263             430         519         45        1,757
Net Productive Wells (Working
Interest Only)                                    469        164             227         256          4        1,120
Gross Operated Productive Wells                   476        211             243         354         -         1,284
Gross Operated Water Disposal,
Injection and Supply wells                          1          9              67           7         -            84




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In several of our regions we operate 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.

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 six formations; 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, 2018, we had 519 wells (256 net) in the West Texas area, of
which 361 wells are operated by us. Principal producing intervals are in the
Spraberry, Wolfcamp and San Andres formations at depths ranging from 5,500 to
12,500 feet. Average net daily production in 2018 was 4,248 Boe. At December 31,
2018, we had 8,401 MBoe of proved reserves in the West Texas area, or 66% of our
total proved reserves. We maintain an acreage position of approximately 20,292
gross (12,824 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,five hot oiler trucks, one kill truck and one
roustabout truck. 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, 2018, the Company was participating in three Probable
Undeveloped horizontal drilling locations not included in the 2018
year-endreserve report. All three of these wells have been drilled and are
expected to be completed and producing in the second quarter of 2019.

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, 2018,
we had 580 wells (227 net) in the Mid-Continent area, of which 310 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 2018 was 977 Boe. At December 31, 2018, we had 2,882 MBoe of
proved reserves in the Mid-Continent area, or 23% of our total proved reserves.
We maintain an acreage position of approximately 81,800 gross (10,900 net) acres
in this region, primarily in Canadian, Kingfisher, Grant 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-Continent
region is actively participating with third-party operators in the horizontal
development of lands that include Company owned interest in several counties in
the Stack and Scoop plays of Oklahoma where drilling is primarily targeting
reservoirs of the Mississippian, Woodford, and Hunton formations. As of
March 31, 2019, the Mid-Continent region is participating in the drilling and
completion of seven wells included as Proved Undeveloped in the 2018 year-end
reserve report.

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, 2018, we had interest in 500 wells (469 net), of which 477 wells
are operated. There are multiple producing intervals that 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 2018
was 244 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, 2018, we had 559 MBoe of proved developed reserves (substantially
all natural gas) in the Appalachian region,



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constituting 4% of our total proved reserves. We maintain an acreage position of
over 40,200 gross (39,700 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, 2019, 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.

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 263 producing wells (164 net) in the Gulf Coast region as
of December 31, 2018, of which 220 wells are operated by us. Average daily
production in 2018 was 572 Boe.

At December 31, 2018, we had 925 MBoe of proved reserves in the Gulf Coast
region, which represented 6% 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, 2019, 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.

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, 2018. 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 over ten 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's degree in Geology and an MBA in finance and is a
member of the Society of Petroleum Engineers and American Association of
Petroleum Geologist.

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)
2016                    3,107        1,265       13,001        6,539           643           159       2,003       1,135        3,750        1,424       15,004        7,674
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



(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, 2016, we had undeveloped reserves of 1,135 MBoe, attributable to
20 wells that were all put on production in the first quarter of 2017. During
2017, 22 horizontal wells were drilled and completed in West Texas, two in
Oklahoma, and one vertical well in the Gulf Coast of Texas. In addition, we had
an increase in reserves from overriding royalty interest in nine horizontal
wells drilled in Oklahoma by other operators.

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,
and therefore, 100% of these reserves were converted to proved developed in the
2018 year-end reserves report.



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In 2018, the Company completed and put on production nine horizontal wells in
West Texas and six horizontal wells in Oklahoma. Proved Developed reserves at
year-end included an additional eight Shut-In horizontal wells in West Texas
that have been brought on production in February, 2019 and five Shut-In
horizontal wells in Oklahoma brought on production in March, 2019. In addition,
at December 31, 2018, our reserve report included 43 MBoe of proved undeveloped
reserves attributable to eight horizontal wells drilled in Oklahoma. These eight
wells are expected to be completed and put on production in the second quarter
of 2019.

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,
2018, 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
2016                                        $     56,467$   46,827$      18,114$    10,403$     74,581$   57,230$     4,993$       52,237
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


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 PV 10 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 PV 10 of future income taxes represents the sole reconciling item between
this non-GAAP PV 10 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
major expenditure is required before the well is put on production. Our reserves
include amounts attributable to non-controlling interests in the Partnerships.
These interests represent less than 3% 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 reasonably be anticipated that the prices received for the sale of
our production may be higher or lower than the prices used in this evaluation,
as described above, and the operating costs relating to such production may also
increase or decrease from existing levels, such possible changes in prices and
costs were, in accordance with rules adopted by the SEC, omitted from
consideration in making this evaluation for the SEC case. Actual volumes
produced, prices received and costs incurred may vary significantly from the SEC
case.

Natural gas prices, based on the twelve-month average of the first of the month
Henry Hub index price, were $3.10 per MMBtu in 2018 as compared to $2.98 per
MMBtu in 2017 and $2.49 per MMBtu in 2016. Oil prices, based on the NYMEX first
of the month average price, were $65.56 per barrel in 2018 as compared to $51.34
per barrel in 2017, and $42.75 per barrel in 2016. Since January 1, 2019, 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.



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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
flows generated from operations, through our producing oil and gas properties,
our field services business, and from sales of non-core acreage.

The Company will continue to pursue the acquisition of leasehold acreage and
producing properties in areas where we currently operate and believe there is
additional exploration and development potential and will attempt to assume the
position of operator in all such acquisitions. In order 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 so as 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 may 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.

Maintaining a strong balance sheet and ample liquidity are key components of our
business strategy. For 2019, we will continue our focus on preserving financial
flexibility and ample liquidity as we manage the risks facing our industry. Our
2019 capital budget is reflective of current commodity prices and has been
established based on an expectation of available cash flows, with any cash flow
deficiencies expected to be funded by borrowings under our revolving credit
facility. As we have done historically to preserve or enhance liquidity, we may
adjust our capital program throughout the year, divest non-strategic assets, or
enter into strategic joint ventures.

RECENT ACTIVITIES


In 2018, the Company participated in a total of 28 gross (6.1 net) horizontal
wells. Capital investment in this group of wells was approximately $41 million
net to the Company. In 2018, nine horizontal wells, drilled in our West Texas
horizontal development program, were completed and brought on production and six
horizontal wells in our Scoop-Stack horizontal development program of Oklahoma
were completed and producing by year-end. In addition, the Company had 13 new
horizontal wells completed in 2018 that have been brought into production in the
first quarter of 2019: eight are located in West Texas and five are located in
Oklahoma.

In the first quarter of 2019, in our West Texas horizontal drilling program, the
Company participated for 49.3% interest in eight wells that were brought on
production in February. The total cost for drilling, completion and facilities
for these eight wells will be approximately $48.2 million, with the Company's
share being approximately $23.8 million.

Also in our West Texas horizontal drilling program, in 2019, the Company is
participating in two horizontal wells for 46% interest each, one targeting the
Jo Mill and one the Lower Spraberry; and we are participating in a third
horizontal well for 5.3% interest, targeting the Wolfcamp "A" reservoir. All
three wells are in the clean out process after being recently fracture
stimulated and are expected to be on-line in June of this year. These wells were
designated as Probable Undeveloped as of December 31, 2018 and, therefore, were
not included in the proved reserves of our year-end reserve report.
PrimeEnergy's share of the gross $26 million drilling and completion costs for
these wells will be approximately $8.6 million. These three horizontals are
important tests of the economic viability of each target reservoir not only for
the 1,300 acre block in which they were drilled, where Prime holds between 5%
and 48% working interest, but also for our nearby 2,600 leasehold acre block
that we believe holds the same potential.

If favorable results are achieved from these three probable undeveloped wells
described above, an additional 21 locations are likely to be drilled in the near
future in this 1,300 acre block at a gross cost of approximately $182 million,
with the Company's share being approximately $60 million. In the nearby 2,600
acre block, Prime holds from 14% to 56% interest, and if favorable results do
occur it is likely to spur the drilling of as many as 96 additional horizontal
wells on this block over the coming years. The gross cost of 96 wells here would
be approximately $748 million with the Company's share being approximately
$284 million. The actual number of wells that will be drilled, the cost, and the
timing of drilling will vary based upon many factors, including commodity market
conditions.



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In the Permian Basin of West Texas, the Company maintains an acreage position of
approximately 20,400 gross (12,700 net) acres, 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 formations that support drilling potential for as many as 250
additional horizontal wells.

In Oklahoma, in 2018, the Company participated in 11 wells drilled and completed
by December 31, 2018, however, six of these were designated as Shut-In at
year-end. In March 2019, these six wells were brought into production. Also
during 2018, the Company participated in the drilling of seven wells in Oklahoma
that were designated as Proved Undeveloped at year-end, as these had not yet
been completed. The Company has 10% interest in one of these seven wells and
less than one percent interest in the remaining six. All seven of these wells
are located in Grady County, Oklahoma and the estimated total expenditure is
approximately $1.46 Million net to the Company's interest. We anticipate these
seven wells will be completed and put into production in the second quarter of
2019.

In Oklahoma, the Company's horizontal activity is primarily focused in Canadian,
Grady, Kingfisher, and Garvin counties where we have approximately 2,215 net
leasehold acres. We believe this acreage has significant additional resource
potential that could support the drilling of as many as 161 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 $82 million at an average 10% ownership level; the Company will
otherwise sell its rights for cash, or cash plus a royalty or working interest.

RESULTS OF OPERATIONS

2019 and 2018 Compared

We report a net loss of $3.04 million, $1.49 per share, for the three months
ended March 2018 compared with net income of $3.29 million, $1.53 per share, for
the same period of 2018. The current year net loss reflects an unrealized loss
on derivatives, decreases in oil, gas and NGLs sales due to lower commodity
prices and a decrease in gains related to the sale of acreage during the three
months ended March 2019 compared to the same period in 2018. The significant
components of income and expense are discussed below.

Oil, gas and NGLs sales decreased $1.2 million, or 4.7% from $25.1 million for
the three months ended March 31, 2018 to $23.9 million for the three months
ended March 31, 2019. Sales vary due to changes in volumes of production sold
and realized commodity prices. Our realized prices decreased an average of,
$9.43 per barrel, or 15% on crude oil, decreased an average of $0.25 per mcf, or
10% on natural gas and decreased an average of $5.98 per barrel, or 23% on NGLs,
during the three months ended March 31, 2019 from the same period in 2018.

Our crude oil production increased by 33,000 barrels, or 10% from 323,000
barrels for the first quarter 2018 to 356,000 barrels for the first quarter
2019. Our natural gas production increased by 41,000 mcf, or 5% from 907,000 mcf
for the first quarter 2018 to 948,000 mcf for the first quarter 2019. Our
natural gas liquids production increased by 42,000 barrels, or 42% from 100,000
barrels for the first quarter 2018 to 142,000 barrels for the first quarter
2019. The net increase in production volumes reflect by production from new
wells added in February and March 2019, offset with the natural decline of the
previously existing properties.

The following table summarizes the primary components of production volumes and
average sales prices realized for the three months ended March 31, 2019 and 2018
(excluding realized gains and losses from derivatives).



                                                                       

Three Months Ended March 31,

Increase / Increase /

                                             2019              2018             (Decrease)          (Decrease)
Barrels of Oil Produced                      356,000            323,000              33,000                  10 %
Average Price Received                     $   52.80$      62.23$      (9.43 )               (15 )

Oil Revenue (In 000's)                     $  18,798$     20,101$     (1,303 )                 6 %

Mcf of Gas Sold                              948,000            907,000              41,000                   5 %
Average Price Received                     $    2.36$       2.61$      (0.25 )               (10 )%

Gas Revenue (In 000's)                     $   2,235$      2,363$       (128 )                (5 )%

Barrels of Natural Gas Liquids Sold          142,000            100,000              42,000                  42 %
Average Price Received                     $   20.02$      26.00$      (5.98 )               (23 )%

Natural Gas Liquids Revenue (In 000's) $ 2,844$ 2,600

    $        244                   9 %

Total Oil & Gas Revenue (In 000's) $ 23,877$ 25,064

   $      1,187                  (5 )%





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Realized net losses on derivative instruments include net gains of
$0.002 million and $0.089 million on the settlements of natural gas liquids and
crude oil derivatives, and net losses on the settlements of natural gas
derivatives, respectively for the first quarter 2019, and net losses of
$0.02 million and $0.48 million on the settlements of natural gas and crude oil
derivatives, and net gains on the settlements of natural gas liquids
derivatives, respectively for the first quarter 2018.

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. Changes
in market values in the first quarter of 2018 resulted in net unrealized losses
of $0.08 million associated with natural gas fixed swap contracts and
$1.87 million associated with crude oil fixed swaps and $0.13 million in net
unrealized gains associated with natural gas liquids fixed swaps. Changes in
market values in the first quarter of 2019 resulted in net unrealized losses of
$5.738 million, $0.005 million and $0.009 million associated with crude oil
fixed swaps, natural gas fixed swap contracts and natural gas liquids fixed
swaps, respectively.

Prices received for the three months ended March 31, 2019 and 2018, respectively, including the impact of derivatives were:



                                         2019        2018
                           Oil Price    $ 53.09$ 60.75
                           Gas Price    $  2.34$  2.58
                           NGLS Price   $ 20.07$ 25.98


Field service income increased $0.5 million or 12% for the first quarter 2019 to
$4.7 million from $4.2 for the first quarter 2018. This increase is a combined
result of increased utilization and rates charged to customers during the 2019
period. Workover rig services, hot oil treatments, salt water hauling and
disposal represent the bulk of our field service operations.

Lease operating expense decreased $0.5 million or 20% from $8.58 million for the
first quarter 2018 to $8.08 million for the first quarter 2019. This decrease is
primarily due to the sales of high lifting cost properties during 2018 combined
with lower production taxes related to lower commodity prices, offset by costs
related to new wells brought on-line and general rate increases on vendor
services during the first three months of 2019 as compared to the same period of
2018.

Field service expense increased $0.45 million or 14% to $3.67 million for the
first quarter 2019 from $3.21 million for the first quarter 2018. Field service
expenses primarily consist of salaries and vehicle operating expenses which have
increased during the three months ended March 31, 2019 over the same period of
2018 as a direct result of increased services and utilization of the equipment.

Depreciation, depletion, amortization and accretion on discounted liabilities
increased $1.3 million or 16.8% from $7.92 million for the first quarter 2018 to
$9.23 million for the first quarter 2019 reflecting the increased production
related to new wells placed on production late in 2018 and the first quarter of
2019.

General and administrative expense increased $4.24 million, or 244% from
$5.98 million for the three months ended March 31, 2018 to $6.88 million for the
three months ended March 31, 2019. This increase in 2019 reflects the
combination of a reduction in reimbursements related to the decrease in gains on
sales of properties from 2018 to 2019, and increases in personnel costs.

Gain on sale and exchange of assets decreased $1.08 million from $2.47 million
for the three months ended March 31, 2018 to $0.66 million for the three months
ended March 31, 2019. These sales primarily consist of sales of non-essential
oil and gas interests and field service equipment.

Interest expenseincreased $0.12 million or 42% from $0.86 million for the first
quarter 2018 to $0.98 million for the first quarter 2018. This increase reflects
the increase in current borrowings under our revolving credit agreement.

Income tax benefit and expense for the March 31, 2018 and 2019 quarters varied due to the change in net income for those periods.

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LIQUIDITY AND CAPITAL RESOURCES

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


Net cash used in our operating activities for the three months ended March 31,
2019 was $0.25 million compared to $1.59 million for the three months ended
March 31, 2018. 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 in order 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, we
will be able to access sufficient additional capital through bank financing.

The Company maintains Equipment Financing term loans with JPMorgan Chase with a
current outstanding balance of $369 thousand as of May 14, 2019. We intend to
pay off the balance of these loans by June 1, 2019.

We currently maintain a credit facility totaling $300 million, with a borrowing
base of $100 million. As of May 14, 2019 the Company has $71.5 million in
outstanding borrowings and $28.5 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 redetermined
estimate of proved oil and gas reserves. The next borrowing base review is
scheduled for June 2019. 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 redetermined borrowing base.

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.



                                         2019          2020         2019        2020
       Natural Gas (MMBTU)               360,000       180,000     $  2.72$  2.95
       Natural Gas Liquids (barrels)      45,000            -      $ 21.66          -
       Oil (barrels)                     404,000       225,500     $ 53.00$ 58.43


Maintaining a strong balance sheet and ample liquidity are key components of our
business strategy. For 2019, we will continue our focus on preserving financial
flexibility and ample liquidity as we manage the risks facing our industry. Our
2019 capital budget is reflective of decreased 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. 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.

We have in place both a stock repurchase program and a limited partnership interest repurchase program under which we expect to continue spending during 2019. As of May 14, 2019, we have spent $2.085 million under these programs during 2019.




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