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PRIMEENERGY RESOURCES : 10-K/A - Management's Discussion and Analysis of Financial Condition and Results of Operations

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04/17/2019 | 04:22pm EDT
The following discussion is intended to assist you in understanding our results
of operations and our present financial condition. Our Consolidated Financial
Statements and the accompanying Notes to the Consolidated Financial Statements
included elsewhere in this Report contains additional information that should be
referred to when reviewing this material. Our subsidiaries are listed in Note 1
to the Consolidated Financial Statements.


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 our
oil and gas properties and interests are located in the United States. Assets in
our principal focus areas include mature properties with long-lived reserves and
significant development opportunities as well as newer properties with
development and exploration potential. We believe our balanced portfolio of
assets and our ongoing hedging program position us well for both the current
commodity price environment and future potential upside as we develop our
attractive resource opportunities. Our primary sources of liquidity are cash
generated from our operations and our credit facility.

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

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

Market Conditions and Commodity Prices:

Our financial results depend on many factors, particularly the price of natural
gas and crude oil and our ability to market our production on economically
attractive terms. Commodity prices are affected by many factors outside of our
control, including changes in market supply and demand, which are impacted by
weather conditions, pipeline capacity constraints, inventory storage levels,
basis differentials and other factors. In addition, our realized prices are
further impacted by our derivative and hedging activities. As a result, we
cannot accurately predict future commodity prices and, therefore, we cannot
determine with any degree of certainty what effect increases or decreases in
these prices will have on our capital program, production volumes or revenues.
Location differentials have increased in certain regions, such as in the
Appalachian region, resulting in further declines in natural gas prices. We
expect natural gas and crude oil prices to remain volatile. In addition to
production volumes and commodity prices, finding and developing sufficient
amounts of natural gas and crude oil reserves at economical costs are critical
to our long-term success.



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Critical Accounting Estimates:

Proved Oil and Gas Reserves

Proved oil and gas reserves directly impact financial accounting estimates,
including depreciation, depletion and amortization. Proved reserves represent
estimated quantities of natural gas, crude oil, condensate, and natural gas
liquids that geological and engineering data demonstrate, with reasonable
certainty, to be recoverable in future years from known reservoirs under
economic and operating conditions existing at the time the estimates were made.
The process of estimating quantities of proved oil and gas reserves is very
complex, requiring significant subjective decisions in the evaluation of all
available geological, engineering and economic data for each reservoir. The data
for a given reservoir may also change substantially over time as a result of
numerous factors including, but not limited to, additional development activity,
evolving production history and continual reassessment of the viability of
production under varying economic conditions. Consequently, material revisions
(upward or downward) to existing reserve estimates may occur from time to time.

Depreciation, Depletion and Amortization for Oil and Gas Properties

The quantities of estimated proved oil and gas reserves are a significant
component of our calculation of depletion expense and revisions in such
estimates may alter the rate of future expense. Holding all other factors
constant, if reserves were revised upward or downward, earnings would increase
or decrease respectively. Depreciation, depletion and amortization of the cost
of proved oil and gas properties are calculated using the unit-of-production
method. The reserve base used to calculate depletion, depreciation or
amortization is the sum of proved developed reserves and proved undeveloped
reserves for leasehold acquisition costs and the cost to acquire proved
properties. The reserve base includes only proved developed reserves for lease
and well equipment costs, which include development costs and successful
exploration drilling costs. Estimated future dismantlement, restoration and
abandonment costs, net of salvage values, are taken into account.

Liquidity and Capital Resources:

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

Net cash provided by operating activities for the year ended December 31, 2018
was $39.1 million, compared to $40.1 million in the prior year. Excluding the
effects of significant unforeseen expenses or other income, our cash flow from
operations fluctuates primarily because of variations in oil and gas production
and prices or changes in working capital accounts. Our oil and gas production
will vary based on actual well performance but may be curtailed due to factors
beyond our control.

Our realized oil and gas prices vary due to world political events, supply and
demand of products, product storage levels, and weather patterns. We sell the
majority of our production at spot market prices. Accordingly, product price
volatility will affect our cash flow from operations. To mitigate price
volatility, we sometimes lock in prices for some portion of our production
through the use of derivatives.

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

Maintaining a strong balance sheet and ample liquidity are key components of our
business strategy. For 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 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



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our capital program throughout the year, divest assets, or enter into strategic joint ventures. We are actively in discussions with financial partners for funding to develop our asset base and, if required, pay down our revolving credit facility should our borrowing base become limited due to the deterioration of commodity prices.

The Company maintains a Credit Agreement with a maturity date of February 15,
2021, providing for a credit facility totaling $300 million, with a borrowing
base of $100 million. As of March 31, 2019, the Company has $73.5 million in
outstanding borrowings and $26.5 million in availability under this facility.
The bank reviews the borrowing base semi-annually and, at their discretion, may
decrease or propose an increase to the borrowing base relative to a
re-determined estimate of proved oil and gas reserves. The 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 re-determined 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, NGLs and natural gas.

                                               Volumes                   Prices
                                         2019          2020         2019        2020
       Natural Gas (MMBTU)               749,000       180,000     $  2.93$  2.95
       Natural Gas Liquids (barrels)      60,000            -      $ 21.66          -
       Oil (barrels)                     490,100       225,500     $ 53.35$ 58.43

The Company's activities include development and exploratory drilling. Our
strategy is to develop a balanced portfolio of drilling prospects that includes
lower risk wells with a high probability of success and higher risk wells with
greater economic potential. Based upon the results of horizontal wells drilled
by us and other offsetting operators and historical vertical well performance,
we decided in 2016 to reduce the number of vertical wells in our drilling
program and drill primarily horizontal wells. We believe horizontal development
of our resource base provides superior returns relative to vertical drilling by
accessing a larger base of reserves in each target pay zone with a lateral

We participated in 28 gross (6.1 net) horizontal wells drilled and completed in
2018; 14 of these were producing at year-end while the remaining 14 wells were
categorized as shut-in and started producing in the first quarter of 2019. Of
the total 28 wells, 15 are in our West Texas horizontal drilling program, while
13 are in our Oklahoma Scoop-Stack horizontal development program. In addition,
the Company participated in the drilling of three Probable Undeveloped
horizontal wells in Upton County, Texas targeting pay intervals above the Middle
Wolfcamp: one in the Wolfcamp "A", one in the Jo Mill and one in the Lower
Spraberry. These wells are expected to be in production during the second
quarter of 2019. These are important tests of the economic viability of the
target reservoirs, both for the 1,300 acre block in which they were drilled, in
which Prime holds between 5% and 48% working interest, as well as for our nearby
2,600 leasehold acres with the same potential. Our share of the cost of these
three wells will be approximately $8.9 million. If favorable results are
achieved from these three wells, an additional 21 locations are likely to be
drilled in the near future at a gross cost of approximately $182 million with
the Company's share being approximately $60 million. In the nearby 2,600 acres,
Prime holds between 14% and 56% interest and if favorable results from these
three wells occur it is likely to spur the drilling of as many as 96 additional
horizontal wells on this acreage over the coming years. The cost



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of such development 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 first quarter of 2019, the Company was participating with 10 percent
interest in the drilling of one well, as well as participating with less than
1 percent in seven other wells, all in Grady County, Oklahoma. We anticipate
these wells to be on-line in the second quarter of 2019.

The Exploration, Development and Recent Activities section in Part I above
describes in more detail the recent activities of the Company. The focus of our
future activity will be on the continued development of our resource's potential
in the West Texas horizontal drilling program as well as our Scoop-Stack
horizontal drilling program acreage in Oklahoma in order to maximize cash flow
and return on investment.

The Company maintains an acreage position of 20,292 gross (12,824 net) acres in
the Permian Basin in West Texas, primarily in Reagan, Upton, Martin and Midland
counties and we believe this acreage has significant resource potential in as
many as 10 reservoirs, including benches of the Spraberry, Jo Mill, and Wolfcamp
that support the potential drilling of as many as 250 additional horizontal

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, with our share of the capital expenditures being
approximately $82 million at an average 10% ownership level.

To supplement cash flow and finance our drilling program during 2018, the
Company sold or farmed-outleasehold rights through several transactions,
receiving gross proceeds of approximately $3.1 million in exchange for leasehold
interest in Oklahoma, Kansas, Colorado, Texas and Wyoming. This includes the
sale of 1,808 net acres and 20 wells in Garfield County, Oklahoma, and 5,005 net
acres along with 54 wells, in Yuma County, Colorado and Cheyenne County, Kansas.

As of March 2019, the Company has $464 thousand outstanding on our equipment
financing facilities which are secured by substantially all of our field service
equipment. The majority of our capital spending is discretionary, and the
ultimate level of expenditures will be dependent on our assessment of the oil
and gas business environment, the number and quality of oil and gas prospects
available, the market for oilfield services, and oil and gas business
opportunities in general.

The Company has in place both a stock repurchase program and a limited
partnership interest repurchase program. Spending under these programs in 2018
was $8 million. The Company expects continued spending under these programs in

Results of Operations:

2018 and 2017 Compared

We reported net income for 2018 of $14.5 million, or $6.95 per share, compared to $42.0 million, or $18.99 per share for 2017. This increase was due to increases in oil, NGL and natural gas production and sales compared to 2017 offset by reduced gains related to the sale of acreage. The significant components of net income are discussed below.

Oil, NGL and gas salesincreased $26.3 million, or 39.4% to $93.2 million for the
year ended December 31, 2018 from $66.9 million for the year ended December 31,
2017. Crude oil, NGL and natural gas sales vary due to changes in volumes of
production sold and realized commodity prices. Our realized prices at the well
head increased an average of $10.61 per barrel, or 21.3% on crude oil, increased
an average of $4.53 per barrel or 19.5% on NGL and decreased $0.43 per Mcf, or
15.7% on natural gas during 2018 as compared to 2017.



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Our crude oil production increased by 183,000 barrels, or 18.2% from 1,004,000
barrels for the year ended December 31, 2017 to 1,187,000 barrels for the year
ended December 31, 2018. Our NGL production increased by 158,000 or 51.8% from
305,000 barrels for the year ended December 31, 2017 to 463,000 barrels for the
year ended December 31, 2018. Our natural gas production increased by 164 MMcf,
or 4.6% from 3,571 MMcf for the year ended December 31, 2017 to 3,735 MMcf for
the year ended December 31, 2018. The increase in crude oil, NGL and natural gas
production volumes are a result our continued drilling success in the West Texas
and Oklahoma regions as we place new wells into production offset by the natural
decline of existing properties.

The following table summarizes the primary components of production volumes and
average sales prices realized for the years ended December 31, 2018 and 2017
(excluding realized gains and losses from derivatives).

                                          Twelve months ended
                                              December 31,                  Increase /          Increase /
                                        2018               2017             (Decrease)          (Decrease)
Barrels of Oil Produced                1,187,000          1,004,000             183,000                18.2 %
Average Price Received               $     60.46$     49.85$      10.61                21.3 %

Oil Revenue (In 000's)               $    71,766$    50,041$     21,725                43.4 %

Mcf of Gas Sold                        3,735,000          3,571,000             164,000                 4.6 %
Average Price Received               $      2.30$      2.73$      (0.43 )             (15.7 )%

Gas Revenue (In 000's)               $     8,590$     9,745$     (1,155 )             (11.9 )%

Barrels of Natural Gas Liquids
Sold                                     463,000            305,000             158,000                51.8 %
Average Price Received               $     27.79$     23.27$       4.53                19.5 %

Natural Gas Liquids Revenue (In
000's)                               $    12,859$     7,097$      5,762                81.2 %

Total Oil & Gas Revenue (In
000's)                               $    93,215$    66,883$     26,332                39.4 %

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 twelve months ended December 2018 and 2017:

                                                                      Twelve months ended
                                                                         December 31,
                                                                     2018              2017
Oil derivatives - realized gains (losses)                         $   (3,642 )$   (146 )
Oil derivatives - unrealized gains (losses)                            5,600           (1,720 )

Total gains (losses) on oil derivatives                           $    1,958$ (1,866 )
Natural gas derivatives - realized gains (losses)                 $     (278 )$     (9 )
Natural gas derivatives - unrealized gains (losses)                     

(394 ) 2,267

Total gains (losses) on natural gas derivatives                   $     (672 )$  2,258
NGL derivatives - realized (losses)                               $     (175 )             -
NGL derivatives - unrealized gains (losses)                              124               -

Total gains (losses) on NGL derivatives                                  (51 )             -

Total gains (losses) on oil, natural gas and NGL derivatives $ 1,235$ 392



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Prices received for the twelve months ended December 31 2018 and 2017, respectively, including the impact of derivatives were:

                                                  Increase /        Increase /
                          2018        2017        (Decrease)        (Decrease)
             Oil Price   $ 57.39$ 49.70$       7.70              15.5 %
             Gas Price   $  2.23$  2.73$      (0.50 )           (18.4 )%
             NGL Price   $ 27.40$ 23.27$       4.13              17.7 %

Field service income increased $2 million, or 12.7% from $15.7 million for the
year ended December 31, 2017 to $17.7 million for the year ended December 31,
2018. Rates on our workover rigs and hot oiler services improved during 2018 in
response to the increased commodity prices and our SWD income increased
reflecting increased utilization of the pipeline and capacity upgrades added
during the past three years.

Lease operating expense increased $4.1 million, or 13.3% to $35.0 million for
the year ended December 31, 2018 from $30.9 million for the year ended
December 31, 2017. This increase was due to slight cost increases from
suppliers, additional lease operating expenses related to new properties and the
production taxes related to our increased oil and gas revenues.

Field service expense increased $2.5 million, or 20.8% from $12.0 million for
the year ended December 31, 2017 to $14.5 million for the year ended
December 31, 2018. Field service expenses primarily consist of salaries and
vehicle operating expenses which have increased during 2018 related to increased
utilization of our equipment services.

Depreciation, depletion, amortization and accretion on discounted liabilities
increased $1.6 million, or 4.4% from $36.1 million for the year ended
December 31, 2017 to $37.7 million for the year ended December 31, 2018. The
DD&A expense is primarily attributable to our properties in West Texas and
Oklahoma, reflecting the increased cost basis and production from development in
those areas.

General and administrative expense increased $4.0 million, or 41.7% to
$13.6 million for the year ended December 31, 2018 from $9.6 million for the
year ended December 31, 2017. This increase in 2018 reflects the combination of
a reduction in reimbursements related to the decrease in gains on sales of
properties from 2017 to 2018 and increases in personnel costs.

Gain on sale and exchange of assets of $3.7 million for the year ended December 31, 2017 and $41.3 million for the year ended December 31, 2017 consists of sales of non-producing acreage and oil and gas interests and non-essential field service equipment.

Interest expense increased $1.1 million, or 47.8% from $2.3 million for the year
ended December 31, 2017 to $3.4 million for the year ended December 31, 2018.
This increase relates to an increase in average debt outstanding during 2018 as
compared to 2017 combined with an increase in weighted average interest rates
during the 2018 periods. The average interest rate paid on outstanding bank
borrowings under its revolving credit facility during 2018 and 2017 were 5.33%
and 4.97%, respectively. As of December 31, 2018 and 2017, the total outstanding
borrowings under its revolving credit facility were $65.5 million and
$47.7 million, respectively.

Tax expense of $3.0 million was recorded for the year ended December 31, 2018,
versus a tax benefit of $7.8 million for the year ended December 31, 2017. The
2017 tax benefit was directly related to the effect of the Tax Cuts and Jobs Act
passed in 2017, based on the re-measurement of deferred tax assets and
liabilities at the lower corporate tax rate contained in the bill.



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