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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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08/14/2019 | 01:06pm 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.



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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
19,830 gross (12,580 net) acres, 97% of which is located in Reagan, Upton,
Martin, and Midland counties of Texas where our current horizontal drilling
activity is focused. Recent results from our wells and the wells of other
operators have proven the potential of the Lower Spraberry, Jo Mill and Wolfcamp
A intervals, in addition to the Middle Wolfcamp. We believe our Permian Basin
acreage has the resource potential to support the future drilling of as many as
375 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 2,210
net acres in these counties hold significant additional resource potential that
could support the drilling of as many as 105 new horizontal wells based on an
estimate of four to eight wells per section depending on the reservoir target
area.

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


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 second 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 for the



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Company are in the Spraberry, Jo Mill, 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 19,830 gross (12,580 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. In the first quarter of 2019, in our West Texas horizontal
drilling program, the Company participated for 49.3% interest in eight one-mile
horizontal wells drilled in the Middle Wolfcamp. These wells were brought on
production in February, 2019. The total cost of these eight wells and their
facilities is approximately $50.6 million, with the Company's share being
$24.9 million. Since completion these wells will have produced approximately
600,000 barrels of oil, along with associated gas. PrimeEnergy's net revenue
interest is 36.82%, therefore, our share of the oil recovered in just the first
six months is approximately 212,500 barrels. We are pleased with the economic
performance of these eight wells and expect 100% capital recover in less than
two years.

In the second quarter of 2019, in our West Texas horizontal drilling program, we
completed three new horizontal wells in intervals above the Middle Wolfcamp that
previously were not proven as horizontal target reservoirs for our acreage. In
the first 60 days of production the three wells have produced 125,000 gross
barrels of oil along with associated wellhead gas: 50,000 barrels from the Lower
Spraberry, 46,000 barrels from the Jo Mill, and 31,000 barrels from the Upper
Wolfcamp. PrimeEnergy has 49% working interest and 40.7% net revenue interest in
the Lower Spraberry well, 47% working interest and 39% net revenue interest in
the Jo Mill well and 5.3% working interest and 3.9% net revenue interest in the
Upper Wolfcamp well. Our share of the gross $26 million cost of these three
wells is approximately $8.9 million.

These three new horizontal wells in Upton County are important tests of the
economic viability of the shallower target zones, both for the 1,300 acre block
in which they were drilled, as well as for our nearby 2,600 leasehold AMI (Area
of Mutual Interest) acreage with Apache that holds similar potential. The
successful outcome has proven-up 21 additional locations in the 1,300 acre
block, making these locations more likely to be drilled in the near future. The
gross cost of an additional 21 wells would be approximately $182 million, with
the Company's share being $60 million. In the nearby Apache AMI, Prime holds
several leases with interest varying from 14% to 56%. The strong performance of
these new horizontals is likely to spur the drilling of as many as 96 additional
horizontal wells in the Apache AMI 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.

In the Permian Basin of West Texas the Company maintains an acreage position of
approximately 19,830 gross (12,580 net) acres primarily in Reagan, Upton, Martin
and Midland counties. We believe this acreage has significant resource potential
in approximately 10 reservoir benches, including benches of the Spraberry, Jo
Mill, and Wolfcamp formations to support the potential for drilling as many as
375 additional horizontal wells.

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 shale plays of Oklahoma where drilling is primarily
targeting reservoirs of the Mississippian, Woodford, and Hunton formations.

In the Mid-Continent Region, in 2018, the Company participated in 11 wells in
Oklahoma, with six of these on production by year-end. Another five of the 11
wells were drilled by Marathon in the "Ruthie 1609" tract in Kingsfisher County
and brought on-line in March of 2019. Prime participated with 11.87% interest in
these five new wells, investing approximately $4.9 million. This group of wells
is showing strong initial production performance. This activity has now been
closely followed by the



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proposed drilling of 19 new wells by Encana Corporation in nearby leases in
which PrimeEnergy has an average of 7.05% interest. Twelve of these wells were
spud in June 2019 and the Company has agreed to participate for its average
interest in these wells of 4.9% interest. Drilling and completion costs of these
19 wells net to our interest are expected to be $9.3 million. Also in Oklahoma,
the Company recently participated with Roane Resources, Inc. in the drilling of
seven wells in Grady County, Oklahoma. The Company has 10% interest in one of
these seven wells and less than one percent interest in the remaining six. These
wells were included as Proved Undeveloped in the 2018 year-end reserve report.
The estimated total expenditure net to the Company is approximately $1.46
Million. Three of these seven wells came on line July, 2019 and we anticipate
the other four wells will also be completed and put into production in the third
quarter of 2019. In addition, there are eight new wells spud in the first and
second quarter of 2019 from which the Company will receive a minor over-riding
royalty interest.

The Company's horizontal activity in Oklahoma is primarily focused in Canadian,
Grady, Kingfisher, and Garvin counties where we have approximately 2,210 net
leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has
significant additional resource potential that could support the drilling of as
many as 105 new horizontal wells based on an estimate of eight wells per
section: four in the Mississippian and four in the Woodford Shale.

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, 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 June 30, 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 June 30, 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.



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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.

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 and third
quarters of 2019. Additional 2019 activity is discussed in the Recent Activities
section below.

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.



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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.

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.



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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


Since the start of our West Texas horizontal drilling program in 2015 the
Company has participated in 67 horizontal wells and invested approximately
$103 million dollars. The Company has an acreage position approximately 12,580
net acres in West Texas with the potential to drill 375 or more new horizontal
wells. In Oklahoma, since the start in 2012 of our horizontal drilling program
in the SCOOP/STACK shale plays, the Company has drilled or committed to drill 64
wells with a total investment of approximately $46 million dollars, plus has
elected to receive an overriding royalty interest in 63 additional wells drilled
to-date. The Company holds approximately 2,210 net acres within the SCOOP/STACK
shale plays with the potential for 105 new horizontal wells.

In 2018, the Company participated in a total of 28 gross (6.1 net) horizontal
wells with an investment to our share of approximately $41 million. We completed
17 horizontal wells in our West Texas horizontal development program and 11
horizontal wells in our Scoop-Stack horizontal development program in Oklahoma.
All 28 wells were successful and are producing.

In the first quarter of 2019, in our West Texas horizontal drilling program, the
Company participated for 49.3% interest in eight one-mile horizontal wells
drilled in the Middle Wolfcamp. These wells were brought on production in
February, 2019. The total cost of these eight wells and their facilities is
approximately $50.6 million, with the Company's share being
$24.9 million.  Since completion these wells will have produced approximately
600,000 barrels of oil, along with associated gas. PrimeEnergy's net revenue
interest is 36.82%, therefore, our share of the oil recovered in just the first
six months is approximately 212,500 barrels. We are pleased with the economic
performance of these eight wells and expect 100% capital recover in less than
two years.

In the second quarter of 2019, in our West Texas horizontal drilling program, we
completed three new horizontal wells in intervals above the Middle Wolfcamp that
previously were not proven as horizontal target reservoirs for our acreage. In
the first 60 days of production the three wells have produced 125,000 gross
barrels of oil along with associated wellhead gas: 50,000 barrels from the Lower
Spraberry, 46,000 barrels from the Jo Mill, and 31,000 barrels from the Upper
Wolfcamp. PrimeEnergy has 49% working interest and 40.7% net revenue interest in
the Lower Spraberry well, 47% working interest and 39% net revenue interest in
the Jo Mill well and 5.3% working interest and 3.9% net revenue interest in the
Upper Wolfcamp well. Our share of the gross $26 million cost of these three
wells is approximately $8.9 million.

These three new horizontal wells in Upton County are important tests of the
economic viability of the shallower target zones, both for the 1,300 acre block
in which they were drilled, as well as for our nearby 2,600 leasehold AMI
acreage with Apache that holds similar potential. The successful outcome has
proven-up 21 additional locations in the 1,300 acre block, making these
locations more likely to be drilled in the near future. The gross cost of an
additional 21 wells would be approximately $182 million, with the Company's
share being $60 million. In the nearby Apache AMI, Prime holds several leases
with interest varying from 14% to 56%. The strong performance of these new
horizontals is likely to spur the drilling of as many as 96 additional
horizontal wells in the Apache AMI 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.

In the Permian Basin of West Texas the Company maintains an acreage position of
approximately 19,830 gross (12,580 net) acres primarily in Reagan, Upton, Martin
and Midland counties. We believe this acreage has significant resource potential
in approximately 10 reservoir benches, including benches of the Spraberry, Jo
Mill, and Wolfcamp formations to support the potential for drilling as many as
375 additional horizontal wells.

In Oklahoma, in 2018, the Company participated in 11 wells, with six of these on
production by year-end. Five of these wells, drilled by Marathon in the "Ruthie
1609" tract in Kingsfisher County, were brought on-line in March of 2019. Prime
participated with 11.87% interest in these five new wells, investing
approximately $4.9 million. This group of wells is showing strong initial
production performance. This activity has now been closely followed by the
proposed drilling of 19 new wells by



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Encana Corporation in nearby leases in which PrimeEnergy has an average of 7.05%
interest. Twelve of these wells were spud in June 2019 and the Company has
agreed to participate for its average interest in these wells of 4.9% interest.
Drilling and completion costs of these 19 wells net to our interest are expected
to be $9.3 million.

Also in Oklahoma, the Company recently participated with Roane Resources, Inc.
in the drilling of seven wells in Grady County, Oklahoma. The Company has 10%
interest in one of these seven wells and less than one percent interest in the
remaining six. The estimated total expenditure net to the Company is
approximately $1.46 Million. Three of these seven wells came on line July, 2019
and we anticipate the other four wells will also be completed and put into
production in the third quarter of 2019. In addition, there are eight new wells
spud in the first and second quarter of 2019 from which the Company will receive
a minor over-riding royalty interest.

The Company's horizontal activity in Oklahoma is primarily focused in Canadian,
Grady, Kingfisher, and Garvin counties where we have approximately 2,210 net
leasehold acres within the SCOOP/STACK shale plays. We believe this acreage has
significant additional resource potential that could support the drilling of as
many as 105 new horizontal wells based on an estimate of eight wells per
section: four in the Mississippian and four in the Woodford Shale.

RESULTS OF OPERATIONS

2019 and 2018 Compared


We reported net income of $2.7 million, or $1.35 per share and $5.8 million, or
$2.85 per share for the six and three months ended June 30, 2019, respectively,
as compared to net income for the six months ended June 30, 2018 of
$2.7 million, or $1.29 per share and a net loss for the three months ended
June 30, 2018 of $0.6 million, or $0.27 per share. Current year net income
reflects an increase in production combined with commodity price changes over
the three and six months ended June 30, 2019, decrease in gains related to the
sale of acreage and changes related to the valuation of derivative instruments.
The significant components of income and expense are discussed below.

Oil, gas and NGLs sales increased $1.7 million, or 8% from $21.7 million for the
three months ended June 30, 2018 to $23.4 million for the three months ended
June 30, 2019 and increased $0.5 million, or 1% from $46.8 million for the six
months ended June 30, 2018 to $47.2 million for the six months ended June 30,
2019.

Our realized prices at the well head decreased an average of $4.52 per barrel,
or 7% and $7.04 per barrel, or 11% on crude oil during the three and six months
ended June 30, 2019, respectively from the same periods in 2018. Our average
price for natural gas decreased $1.01 per Mcf, or 49% and $0.73 per Mcf, or 31%
during the three and six months ended June 30, 2019, respectively from the same
periods in 2018. Our average price for NGLs sold decreased an average of $11.15
per barrel, or 41% and $8.61 per barrel, or 32% during the three and six months
ended June 30, 2019, respectively from the same periods in 2018. Production
increases were negatively impacted by natural gas prices at the Waha hub where
Permian Basin production exceeded West Texas takeaway capacity. Gas prices
traded at historic lows, and at times were negative, for portions of the second
quarter of 2019. This gas pricing is expected to continue until Waha prices
improve, which is anticipated when the third-party operated Gulf Coast Express
(GCX) pipeline enters service in late September.

Our crude oil production increased by 71,000 barrels or 27% from 261,000 barrels
for the second quarter 2018 to 332,000 barrels for the second quarter 2019 and
increased by 104,000 barrels, or 18% from 584,000 barrels for the six months
ended June 30, 2018 to 688,000 barrels for the six months ended June 30, 2019.
Our natural gas production increased by 331,000 Mcf, or 34% from 964,000 Mcf for
the second quarter 2018 to 1,295,000 Mcf for the second quarter 2019 and
increased by 372,000 Mcf, or 20% from 1,871,000 Mcf for the six months ended
June 30, 2018 to 2,243,000 Mcf for the six months ended June 30, 2019. Our NGL
production increased by 33,000 barrels or 29% from 113,000 barrels for the
second quarter 2018 to 146,000 barrels for the second quarter 2019 and increased
by 75,000 barrels, or 35% from 213,000 barrels for the six months ended June 30,
2018 to 288,000 barrels for the six months ended June 30, 2019. The net increase
in production volumes reflect by production from new wells added in February
through May 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 June 30, 2019 and 2018
(excluding realized gains and losses from derivatives).



                                                      Six months ended June 30,
                                                             Increase /        Increase /
                               2019            2018          (Decrease)        (Decrease)
  Barrels of Oil Produced       688,000         584,000          104,000                18 %
  Average Price Received    $     55.84$     62.88$      (7.04 )             (11 )%

  Oil Revenue (In 000's)    $    38,442$    36,723$      1,719                 5 %

  Mcf of Gas Sold             2,243,000       1,871,000          372,000                20 %




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                                                                      Six 

months ended June 30,

Increase / Increase /

                                             2019             2018           (Decrease)         (Decrease)
Average Price Received                     $    1.60$     2.33$      (0.73 )              (31 )%

Gas Revenue (In 000's)                     $   3,590$    4,352$       (762 )              (18 )%

Barrels of Natural Gas Liquids Sold 288,000 213,000

       75,000                 35 %
Average Price Received                     $   18.14$    26.75$      (8.61 )              (32 )%

Natural Gas Liquids Revenue (In 000's) $ 5,219$ 5,698$ (479 )

               (8 )%

Total Oil & Gas Revenue (In 000's)         $  47,251$   46,773$        478                  1 %





                                                                        Three months ended June 30,
                                                                           

Increase / Increase /

                                              2019              2018            (Decrease)          (Decrease)
Barrels of Oil Produced                        332,000           261,000             71,000                  27 %
Average Price Received                     $     59.17$     63.69$      (4.52 )                (7 )%

Oil Revenue (In 000's)                     $    19,644$    16,622$      3,022                  18 %

Mcf of Gas Sold                              1,295,000           964,000            331,000                  34 %
Average Price Received                     $      1.05$      2.06$      (1.01 )               (49 )%

Gas Revenue (In 000's)                     $     1,355$     1,989$       (634 )               (32 )%

Barrels of Natural Gas Liquids Sold            146,000           113,000             33,000                  29 %
Average Price Received                     $     16.27$     27.42$     (11.15 )               (41 )%

Natural Gas Liquids Revenue (In 000's) $ 2,375$ 3,098

    $       (723 )               (23 )%

Total Oil & Gas Revenue (In 000's) $ 23,374$ 21,709

    $      1,665                   8 %



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 2019 and 2018:



                                                     Three Months Ended            Six Months Ended
                                                          June 30,                     June 30,
                                                     2019           2018          2019          2018
                                                                     ($ in thousand)

Oil derivatives - realized gains (losses) $ (964 )$ (1,156 )$ (876 )$ (1,634 ) Oil derivatives - unrealized gains (losses)

            2,637        (3,564 

) (3,101 ) (5,432 )


Total gains (losses) on oil derivatives            $   1,673$ (4,720 )$ (3,977 )$ (7,066 )
Natural gas derivatives - realized gains
(losses)                                           $       4$    105$     (8 )$     85
Natural gas derivatives - unrealized gains
(losses)                                                 156          (249 

) 151 (328 )

Total gains (losses) on natural gas derivatives $ 160$ (144 )$ 143$ (243 ) NGL derivatives - realized gain (losses)

           $     109$    (30 )$    111$    (27 )
NGL derivatives - unrealized gains (losses)               69          (323 

) 60 (197 )


Total gains (losses) on NGL derivatives                  178          (353 

) 171 (225 )


Total gains (losses) on oil, natural gas and
NGL derivatives                                    $   2,011$ (5,217 )$ (3,663 )$ (7,533 )

Prices received for the six months ended June 30, 2019 and 2018, respectively, including the impact of derivatives were:



                                         2019        2018
                           Oil Price    $ 54.56$ 59.26
                           Gas Price    $  1.00$  2.17
                           NGLS Price   $ 18.52$ 27.15




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Field service income increased $0.4 million or 0.01% from $4.4 million for the
second quarter 2018 to $4.8 million for the second quarter 2019 and
$0.8 million, or 0.01% from $8.7 million for the six months ended June 30, 2018
to $9.5 million for the six months ended June 30, 2019. 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 $0.7 million or 0.01% from $8.8 million for
the second quarter 2018 to $8.1 million for the second quarter 2019, and
decreased $1.1 million or 0.01% from $17.3 million for the six months ended
June 30, 2018 to $16.2 million for the six months ended June 30, 2019. This
decrease is primarily due to the sales of high lifting cost properties during
2019 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 $0.8 million or 0.02% from $3.2 million for the
second quarter 2018 to $4.0 million for the second quarter 2019 and increased
$1.2 million, or 0.02% from $6.4 million for the six months ended June 30, 2018
to $7.6 million for the six months ended June 30, 2019. Field service expenses
primarily consist of salaries and vehicle operating expenses which have
increased during the six months ended June 30, 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 $1.4 million, or 0.02% from $7.9 million for the second quarter 2018
to $9.3 million for the second quarter 2019 and $2.8 million, or 0.02% from
$15.8 million for the six months ended June 30, 2018 to $18.6 million for the
six months ended June 30, 2019, reflecting the increased production related to
new wells placed on production late in 2018 and the first two quarters of 2019.

General and administrative expense increased $1.3 million, or 0.01% from
$8.5 million for the six months ended June 30, 2018 to $9.8 million for the six
months ended June 30, 2019, and increased $0.3 million, or 0.01% from
$2.6 million for the three months ended June 30, 2018 to $2.9 million for the
three months ended June 30, 2019. This increase in 2019 reflects the combination
of a reduction in G&A reimbursements related to the sale of property and
increases in personnel costs.

Gain on sale and exchange of assets of $2.7 million and $1.7 million for the six
months ended June 30, 2018 and June 30, 2019, respectively consists of sales of
non-essential oil and gas interests and field service equipment.

Interest expense increased from $0.9 million for the second quarter 2018 to $1.0 million for the second quarter 2019 and from $1.8 million for the six months ended June 30, 2018 to $2.0 million for the six months ended June 30, 2019. This increase reflects the increase in current borrowings under our revolving credit agreement.

Income tax expense for the June 30, 2018 and 2019 periods varied due to the change in net income for those periods.

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 provided by our operating activities for the six months ended June 30,
2019 was $13.7 million compared to $7.4 million for the six months ended
June 30, 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.



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We currently maintain a credit facility totaling $300 million, with a borrowing
base of $90 million. As of August 1, 2019 the Company has $64.5 million in
outstanding borrowings and $25.5 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 December 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)               180,000       180,000     $  2.77$  2.95
       Natural Gas Liquids (barrels)      30,000            -      $ 21.66          -
       Oil (barrels)                     264,000       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 August 1, 2019, we have spent $4.109 million under these programs
during 2019.

© Edgar Online, source Glimpses

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