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PNRG > SEC Filings for PNRG > Form 10-K on 26-Mar-2014All Recent SEC Filings

Show all filings for PRIMEENERGY CORP



Annual Report


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, West Virginia, New Mexico, Colorado and Louisiana. 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 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. 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 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 of 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.

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.

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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:

Net cash provided by operating activities for the year ended December 31, 2013 was $36 million, compared to $40 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 vast 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 and our record of reserve growth in recent years, we will be able to access sufficient additional capital through additional bank financing.

As of March 1, 2014, the Company maintains a credit facility totaling $250 million, with a borrowing base of $140 million. 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. 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.

In July 2013, we obtained a $10 million loan secured by most of the field service equipment that we own to conduct our field service operations. We used the funds from that loan to pay down our credit facility, and as a result, freed up additional funds under the credit facility for future acquisitions, development and operations. As of March 20, 2014, we had a total of $8.9 million outstanding on this loan.

It is our goal to increase our oil and gas reserves and production through the acquisition and development of oil and gas properties. We continued our drilling program in our West Texas and Mid-Continent regions. Based upon the results of horizontal wells drilled by us and other offsetting operators and historical vertical well performance we have decided to reduce the number of vertical wells in our drilling program and drill more horizontal wells. We believe horizontal development of our resource base will provide the opportunity to improve returns relative to vertical drilling by accessing a larger base of reserves in target zone with a lateral wellbore. During 2014, we intend to drill a total of approximately 20 gross (11 net) wells, primarily in the West Texas area, at a net cost of $60 million. We also continue to explore and consider opportunities to further expand our oilfield servicing revenues through additional investment in field service equipment. However, 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.

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The Company has in place both a stock repurchase program and a limited partnership interest repurchase program. Spending under these programs in 2013 was $4.2 million. The Company expects continued spending under these programs in 2014.

Results of Operations:

2013 and 2012 Compared

We reported net income for 2013 of $12.27 million, or $5.04 per share. During 2012, we reported net income of $15.06 million, or $5.74 per share. Net income decreased in 2013 by $2.79 million or 18%, primarily due to net decreases in gains from derivative instruments, increased lease operating and field service expenses partially offset by increases in oil and gas sales and field service income and decreased depreciation and depletion expenses. Operating revenues increased by $4.09 million in 2013 as compared to 2012 largely due to a slight increase in net production and increased commodity prices realized in 2013 and an increase in field service income with the addition of new service equipment during 2013 partially offset by losses on derivative instruments in 2013 versus gains on derivative instruments recognized in 2012. Lease operating and field service expenses increased $3.94 million and $3.45 million, respectively, in 2013 as compared to 2012 primarily from increased labor and chemical costs and an increase in services provided. Depreciation and depletion decreased by $1.41 million in 2013 as compared to 2012 primarily associated with offshore properties as our offshore properties were plugged and abandoned during 2012.

The significant components of net income are discussed below.

Oil and gas sales increased $4.96 million, or 6% from $87.83 million for the year ended December 31, 2012 to $92.79 million for the year ended December 31, 2013. Crude oil 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 $4.08 per barrel, or 5% on crude oil and $0.52 per Mcf, or 12% on natural gas during 2013 as compared to 2012.

Our crude oil production decreased by 15,000 barrels, or 2% from 745,000 barrels for the year ended December 31, 2012 to 730,000 barrels for the year ended December 31, 2013. Our natural gas production increased by 182 MMcf, or 4% from 4,715 MMcf for the year ended December 31, 2012 to 4,897 MMcf for the year ended December 31, 2013. The slight decrease in crude oil production volumes are a result of significant disruptions in our production due to the effects of the extreme cold weather in our producing areas - particularly West Texas and Oklahoma and the natural decline of existing properties substantially offset by production from new wells we placed into production from our continued drilling success in West Texas and the Gulf Coast regions. The natural gas volume increases are primarily due to the natural gas production from wells in the West Texas region recently placed into production.

The following table summarizes the primary components of production volumes and average sales prices realized for the years ended December 31, 2013 and 2012 (excluding realized gains and losses from derivatives).

                                          Year Ended December 31,                 Increase (Decrease)
                                           2013              2012              Amount              Percent
Barrels of Oil Produced                     730,000           745,000             (15,000 )              (2 )%
Average Price Received (excluding
the impact of derivatives)             $      93.75       $     89.67       $        4.08                 5 %

Oil Revenue (In 000's)                 $     68,446       $    66,830       $       1,616                 2 %

Mcf of Gas Produced                       4,897,000         4,715,000             182,000                 4 %
Average Price Received (excluding
the impact of derivatives)             $       4.97       $      4.45       $        0.52                12 %

Gas Revenue (In 000's)                 $     24,339       $    21,004       $       3,335                16 %

Total Oil & Gas Revenue (In 000's)     $     92,785       $    87,834       $       4,951                 6 %

Realized net gains (losses) on derivative instruments include net losses of $1.3 million on the settlements of crude oil and natural gas derivatives for the year ended December 31, 2013. During 2012, we unwound and

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monetized crude oil swaps with original settlement dates from January 2012 through December 2013 for net proceeds of $1.0 million. The $1.0 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2012.

Oil and gas prices received including the impact of derivatives but excluding the early settlement transactions were:

                               Year Ended
                              December 31,            Increase (Decrease)
                            2013        2012         Amount          Percent
               Oil Price   $ 90.85     $ 88.96     $      1.89              2 %
               Gas Price   $  5.13     $  4.45     $      0.68             15 %

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 consolidated statements of operations. As oil and natural gas prices remain volatile, mark-to-market accounting treatment creates volatility in our revenues. During the year ended December 31, 2013, we recognized $0.6 million in net unrealized losses. This unrealized loss primarily relates to held crude oil and natural gas fixed swaps and collars associated with future production due to an increase in crude oil and natural gas futures market prices between January 1, 2013 and December 31, 2013.

Field service income increased $4.51 million, or 22% from $20.42 million for the year ended December 31, 2012 to $24.93 million for the year ended December 31, 2013. This underlying increase is a result of adding service equipment and the market allowing us to charge slightly higher rates to customers. Workover rig services represent the bulk of our field service operations, and those rates have all increased between the periods in our most active districts.

Lease operating expense increased $3.94 million, or 10% from $39.87 million for the year ended December 31, 2012 to $43.81 million for the year ended December 31, 2013. This underlying increase is primarily due to higher pumper / labor costs and chemical expenses associated with new wells coming on line from the recent drilling success in West Texas and increased expensed workovers across all districts, partially offset by decreased operating expenses on the offshore properties during 2013.

Field service expense increased $3.45 million, or 20% from $17.58 million for the year ended December 31, 2012 to $21.03 million for the year ended December 31, 2013. Field service expenses primarily consist of salaries and vehicle operating expenses which have increased as a direct result of increased services and utilization of the equipment during the year ended December 31, 2013 as compared to the same period of 2012.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $1.41 million, or 6% from $23.27 million for the year ended December 31, 2012 to $21.86 million for the year ended December 31, 2013. This decrease is primarily due to decreased depletion rates recognized during 2013 associated with offshore properties as our offshore properties were plugged and abandoned during 2012, partially offset by increased depletion expenses related to new wells coming on line from the recent drilling success in West Texas.

General and administrative expense increased $0.79 million, or 5% from $15.87 million for the year ended December 31, 2012 to $16.66 million for the year ended December 31, 2013. This slight increase is largely due to increased personnel costs in 2013. The largest component of these personnel costs was salaries, employee related taxes and insurance.

Gain on sale and exchange of assets of $2.82 million for the year ended December 31, 2013 consists of sales of non-producing acreage and non-core oil and gas interests and non-essential field service equipment

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whereas the gain on sale and exchange of assets of $0.73 million for the year ended December 31, 2012 consists of sales of non-essential field service equipment.

Interest expense increased $0.64 million, or 18% from $3.58 million for the year ended December 31, 2012 to $4.22 million for the year ended December 31, 2013. This increase relates to an increase in average debt outstanding during 2013 as compared to 2012 slightly offset by a decrease in weighted average interest rates during the 2013 periods. The average interest rate paid on outstanding bank borrowings subject to interest during 2013 and 2012 were 3.58% and 3.81%, respectively. As of December 31, 2013 and 2012, the total outstanding borrowings were $121.89 million and $122.00 million, respectively.

A provision for income taxes of $6.82 million, or an effective tax rate of 36% was recorded for the year ended December 31, 2013 verses a provision of $6.86 million, or an effective tax rate of 31% for the year ended December 31, 2012. Our provision for income taxes varies from the federal statutory tax rate of 34% primarily due to percentage depletion. We are entitled to percentage depletion on certain of our wells for tax purposes, which is calculated without reference to the basis of the property. To the extent that such depletion exceeds a property's basis it creates a permanent difference, which lowers our effective rate.

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