Search the web
Welcome, Guest
[Sign Out, My Account]
EDGAR_Online

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
PNRG > SEC Filings for PNRG > Form 10-K on 27-Mar-2013All Recent SEC Filings

Show all filings for PRIMEENERGY CORP | Request a Trial to NEW EDGAR Online Pro

Form 10-K for PRIMEENERGY CORP


27-Mar-2013

Annual Report


Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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.

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, West Virginia, the Gulf of Mexico, 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.


Table of Contents

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, 2012 was $40 million, compared to $41 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.

The Company has in place both a stock repurchase program and a limited partnership interest repurchase program. Spending under these programs in 2012 was $5.1 million. The Company expects continued spending under these programs in 2013.

As of March 1, 2013, the Company maintains a credit facility totaling $250 million, with a borrowing base of $145 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. 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.

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. During 2013, we intend to drill a total of approximately 30 gross (20 net) wells, primarily in the West Texas area, at a net cost of $36 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.


Table of Contents

Results of Operations:

2012 and 2011 Compared

We reported net income for 2012 of $15.06 million, or $5.74 per share. During 2011, we reported net income of $4.81 million, or $1.75 per share. Net income increased in 2012 by $10.25 million or 213%, primarily due to decreased depreciation and depletion expenses and decreases in net income attributable to non-controlling interests partially offset by decreased operating revenues and an increase lease operating and income tax expenses. Depreciation and depletion decreased by $25.13 million in 2012 as compared to 2011 primarily associated with offshore properties as our offshore properties enter into the last phase of their productive lives and were plugged and abandoned during 2012. Operating revenues decreased by $6.10 million in 2012 as compared to 2011 largely due to gains on derivative instruments associated with early settlement transactions and recovery of gas transportation revenues recognized in 2011.

The significant components of net income are discussed below.

Oil and gas sales decreased $0.60 million, or 1% from $88.43 million for the year ended December 31, 2011 to $87.83 million for the year ended December 31, 2012. 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 decreased an average of $0.37 per barrel, or less than 1% on crude oil and $1.93 per Mcf, or 30% on natural gas during 2012 as compared to 2011.

Our crude oil production increased by 117,000 barrels, or 19% from 628,000 barrels for the year ended December 31, 2011 to 745,000 barrels for the year ended December 31, 2012. Our natural gas production decreased by 285 MMcf, or 6% from 5,000 MMcf for the year ended December 31, 2011 to 4,715 MMcf for the year ended December 31, 2012. The net increase in crude oil production volumes are a result of continued drilling success in West Texas and the Gulf Coast regions as we place new wells into production partially offset by the natural decline of existing properties. The natural gas volume decreases are primarily due to the decline of the primary natural gas producing offshore properties, slightly offset by 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, 2012 and 2011 (excluding realized gains and losses from derivatives).

                                            Year Ended December 31,                Increase (Decrease)
                                             2012              2011              Amount             Percent
Barrels of Oil Produced                       745,000           628,000             117,000               19 %
Average Price Received (excluding
the impact of derivatives)               $      89.67       $     90.04       $       (0.37 )              0 %

Oil Revenue (In 000's)                   $     66,830       $    56,544       $      10,286               18 %

Mcf of Gas Produced                         4,715,000         5,000,000            (285,000 )             (6 )%
Average Price Received (excluding
the impact of derivatives)               $       4.45       $      6.38       $       (1.93 )            (30 )%

Gas Revenue (In 000's)                   $     21,004       $    31,885       $     (10,881 )            (34 )%

Total Oil & Gas Revenue (In 000's)       $     87,834       $    88,429       $        (595 )             (1 )%

Realized net gains on derivative instruments include net gains of $0.5 million on the settlements of crude oil and natural gas derivatives for the year ended December 31, 2012. During 2012, we unwound and 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. During 2011, we unwound and monetized


Table of Contents

crude oil swaps and collars with original settlement dates from September 2011 through December 2014 for net proceeds of $3.4 million and natural gas swaps with original settlement dates from October 2011 through December 2012 for net proceeds of $2.9 million. The $6.3 million gain associated with these early settlement transactions is included in realized gain on derivative instruments for the year ended December 31, 2011.

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

                              Year Ended
                             December 31,             Increase (Decrease)
                           2012        2011         Amount            Percent
              Oil Price   $ 88.96     $ 86.72     $      2.24                3 %
              Gas Price   $  4.45     $  7.06     $     (2.61 )            (37 )%

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, 2012, we recognized $3.5 million in unrealized gains. This unrealized gain primarily relates to held crude oil fixed swaps and collars associated with future production due to a decrease in crude oil futures market prices between January 1, 2012 and December 31, 2012.

Field service income decreased $2.78 million, or 12% from $23.20 million for the year ended December 31, 2011 to $20.42 million for the year ended December 31, 2012. This decrease in field service income is largely due to gas transportation revenues recovered in 2011. During 2011, we recognized $2.59 million in gas transportation revenues associated with approvals for the recovery of additional cost of our pipelines associated with our offshore properties.

Lease operating expense increased $2.97 million, or 8% from $36.90 million for the year ended December 31, 2011 to $39.87 million for the year ended December 31, 2012. This increase is primarily due to higher salt water disposal costs, production taxes and chemical expenses associated with new wells coming on line from the recent drilling success in West Texas, partially offset by decreased operating expenses on the offshore properties and decreased expensed workovers across all districts during 2012.

Field service expense increased $0.34 million, or 2% from $17.24 million for the year ended December 31, 2011 to $17.58 million for the year ended December 31, 2012. Field service expenses primarily consist of salaries and vehicle operating expenses which remained relatively flat with services and utilization of the equipment during the year ended December 31, 2012 as compared to the same period of 2011.

Depreciation, depletion, amortization and accretion on discounted liabilities decreased $25.13 million, or 52% from $48.40 million for the year ended December 31, 2011 to $23.27 million for the year ended December 31, 2012. This decrease is primarily due to decreased depletion rates recognized during 2012 associated with offshore properties as our offshore properties enter into the last phase of their productive lives and were plugged and abandoned during 2012.

General and administrative expense increased $0.98 million, or 7% from $14.89 million for the year ended December 31, 2011 to $15.87 million for the year ended December 31, 2012. This slight increase is largely due to increased personnel costs in 2012. The largest component of these personnel costs was salaries, however engineering consultants, rent and employee related taxes and insurance also contributed to the increase.


Table of Contents

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 whereas the gain on sale and exchange of assets of $1.60 million for the year ended December 31, 2011 consists of $1.10 million related to sales of non-producing acreage and non-core producing properties combined with $0.50 million related to undeveloped acreage sold into a joint venture.

Interest expense decreased $0.13 million, or 4% from $3.71 million for the year ended December 31, 2011 to $3.58 million for the year ended December 31, 2012. This decrease includes the reduction of interest expense of $0.79 million for the year ended December 31, 2012 associated with interest on the subordinated credit facility with a related party private lender which was paid off in June 2011. The decrease is partially offset with a net increase of $0.64 million for the year ended December 31, 2012 related to interest on outstanding bank debt. The average interest rate paid on outstanding bank borrowings subject to interest during 2012 and 2011 were 3.81% and 4.78%, respectively. As of December 31, 2012 and 2011, the total outstanding borrowings were $122.00 million and $69.80 million, respectively.

A provision for income taxes of $6.86 million, or an effective tax rate of 31% was recorded for the year ended December 31, 2012 verses a provision of $1.28 million, or an effective tax rate of 21% for the year ended December 31, 2011. 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, 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.

  Add PNRG to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for PNRG - All Recent SEC Filings
Sign Up for a Free Trial to the NEW EDGAR Online Pro
Detailed SEC, Financial, Ownership and Offering Data on over 12,000 U.S. Public Companies.
Actionable and easy-to-use with searching, alerting, downloading and more.
Request a Trial      Sign Up Now


Copyright © 2014 Yahoo! Inc. All rights reserved. Privacy Policy - Terms of Service
SEC Filing data and information provided by EDGAR Online, Inc. (1-800-416-6651). All information provided "as is" for informational purposes only, not intended for trading purposes or advice. Neither Yahoo! nor any of independent providers is liable for any informational errors, incompleteness, or delays, or for any actions taken in reliance on information contained herein. By accessing the Yahoo! site, you agree not to redistribute the information found therein.