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MTDR > SEC Filings for MTDR > Form 10-Q on 15-May-2012All Recent SEC Filings

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Form 10-Q for MATADOR RESOURCES CO


15-May-2012

Quarterly Report


Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

The following discussion and analysis should be read in conjunction with our consolidated financial statements and notes thereto contained herein and in our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC, along with Management's Discussion and Analysis of Financial Condition and Results of Operations contained in such Form 10-K. The Annual Report is accessible on the SEC's website at www.sec.gov and on our website at www.matadorresources.com. Our discussion and analysis includes forward-looking information that involves risks and uncertainties and should be read in conjunction with "Cautionary Note Regarding Forward-Looking Statements" below for information about the risks and uncertainties that could cause our actual results to be materially different than our forward-looking statements.

In this Quarterly Report on Form 10-Q, references to "we," "our" or "the Company" refer to Matador Resources Company and its subsidiaries before the completion of our corporate reorganization on August 9, 2011 and Matador Holdco, Inc. and its subsidiaries after the completion of our corporate reorganization on August 9, 2011. Prior to August 9, 2011, Matador Holdco, Inc. was a wholly owned subsidiary of Matador Resources Company, now known as MRC Energy Company. Pursuant to the terms of our corporate reorganization, former Matador Resources Company became a wholly owned subsidiary of Matador Holdco, Inc. and changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.

Unless the context otherwise requires, the term "common stock" refers to shares of our common stock after the conversion of our Class B common stock into Class A common stock upon the consummation of our Initial Public Offering on February 7, 2012, as the Class A common stock became the only class of common stock authorized, and the term "Class A common stock" refers to shares of our Class A common stock prior to the automatic conversion of our Class B common stock into Class A common stock upon the consummation of our Initial Public Offering.

For certain oil and natural gas terms used in this report, please see the "Glossary of Oil and Natural Gas Terms" included with our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Cautionary Note Regarding Forward-Looking Statements

Certain statements in this Quarterly Report on Form 10-Q constitute "forward-looking statements" within the meaning of applicable U.S. securities legislation. Additionally, forward-looking statements may be made orally or in press releases, conferences, reports, on our website or otherwise, in the future, by us or on our behalf. Such statements are generally identifiable by the terminology used such as "anticipate," "believe," "continue," "could," "estimate," "expect," "intend," "may," "might," "potential," "predict," "project," "should" or other similar words.

By their very nature, forward-looking statements require us to make assumptions that may not materialize or that may not be accurate. Forward-looking statements are subject to known and unknown risks and uncertainties and other factors that may cause actual results, levels of activity and achievements to differ materially from those expressed or implied by such statements. Such factors include, among others: changes in oil or natural gas prices, the timing of planned capital expenditures, availability of acquisitions, uncertainties in estimating proved reserves and forecasting production results, operational factors affecting the commencement or maintenance of producing wells, the condition of the capital markets generally, as well as our ability to access them, the proximity to and capacity of transportation facilities, uncertainties regarding environmental regulations or litigation and other legal or regulatory developments affecting our business, and the other factors discussed below and elsewhere in this report and in other documents that we file with or furnish to the SEC, all of which are difficult to predict. Forward-looking statements may include statements about:


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our business strategy;

our reserves and the present value thereof;

our technology;

our cash flows and liquidity;

our financial strategy, budget, projections and operating results;

our oil and natural gas realized prices;

the timing and amount of future production of oil and natural gas;

the availability of drilling and production equipment;

the availability of oil field labor;

the amount, nature and timing of capital expenditures, including future exploration and development costs;

the availability and terms of capital;

our drilling of wells;

government regulation and taxation of the oil and natural gas industry;

our marketing of oil and natural gas;

our exploitation projects or property acquisitions;

our costs of exploiting and developing our properties and conducting other operations;

general economic conditions;

competition in the oil and natural gas industry;

the effectiveness of our risk management and hedging activities;

environmental liabilities;

counterparty credit risk;

developments in oil-producing and natural gas-producing countries;

our future operating results;

our estimated future reserves and the present value thereof;

our plans, objectives, expectations and intentions contained in this report that are not historical; and

other factors discussed in our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Although we believe that the expectations conveyed by the forward-looking statements are reasonable based on information available to us on the date such forward-looking statements were made, no assurances can be given as to future results, levels of activity, achievements or financial condition.


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You should not place undue reliance on any forward-looking statement and should recognize that the statements are predictions of future results, which may not occur as anticipated. Actual results could differ materially from those anticipated in the forward-looking statements and from historical results, due to the risks and uncertainties described above, as well as others not now anticipated. The impact of any one factor on a particular forward-looking statement is not determinable with certainty as such factors are interdependent upon other factors. The foregoing statements are not exclusive and further information concerning us, including factors that potentially could materially affect our financial results, may emerge from time to time. We do not intend to update forward-looking statements to reflect actual results or changes in factors or assumptions affecting such forward-looking statements except as required by law.

Overview

We are an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with a particular emphasis on oil and natural gas shale plays and other unconventional resources plays. Our current operations are located primarily in the Eagle Ford shale play in south Texas and the Haynesville shale play in northwest Louisiana and east Texas. We expect the majority of our near-term capital expenditures will focus on increasing our production and reserves from the Eagle Ford shale play. We believe our interests in the Eagle Ford shale play will enable us to create a more balanced commodity portfolio through the drilling of locations that are prospective for oil and liquids. In addition to these primary operating areas, we have acreage positions in southeast New Mexico and west Texas and in southwest Wyoming and adjacent areas of Utah and Idaho where we continue to identify new oil and gas prospects.

During the first quarter of 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in south Texas. We also participated in several non-operated Haynesville shale wells in northwest Louisiana where we owned small working interests. During the three months ended March 31, 2012, we completed and began producing oil and/or natural gas from 6 gross/5.9 net operated Eagle Ford shale wells and 12 gross/0.6 net non-operated Haynesville shale wells. We had two contracted drilling rigs operating in south Texas throughout the first quarter of 2012, and all of our operated drilling and completion activities were focused on the Eagle Ford shale. At May 15, 2012, we continue to have two contracted drilling rigs operating in south Texas: one drilling our first Eagle Ford well in Zavala County and one in Karnes County.

Our average daily production for the three months ended March 31, 2012 was approximately 48.1 MMcfe per day, including approximately 2,200 Bbl of oil per day and 34.9 MMcf of natural gas per day, as compared to approximately 37.8 MMcfe per day, including approximately 210 Bbl of oil per day and 36.5 MMcfe per day for the three months ended March 31, 2011. Oil production comprised approximately 27% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) during the first quarter of 2012 as compared to approximately 3% of our total production during the first quarter of 2011.

At March 31, 2012, based on the reserves audit by our independent reservoir engineers, Netherland, Sewell & Associates, Inc., we had 203.1 Bcfe of estimated proved reserves with a PV-10 of $329.6 million and a Standardized Measure of $287.4 million. At March 31, 2012, 36% of our estimated proved reserves were proved developed reserves, 17% of our estimated proved reserves were oil and 83% of our estimated proved reserves were natural gas. At March 31, 2011, based on the reserves audit by our independent reservoir engineers, we had 154.8 Bcfe of estimated proved reserves with a PV-10 of $140.6 million and a Standardized Measure of $131.5 million. At March 31, 2011, 36% of our estimated proved reserves were proved developed reserves, 3% of our estimated proved reserves were oil and 97% of our estimated proved reserves were natural gas.


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During 2012, we intend to allocate 84% of our 2012 capital expenditure budget of $313.0 million to the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Including these anticipated capital expenditures in the Eagle Ford shale, we plan to dedicate about 94% of our 2012 anticipated capital expenditure budget to opportunities prospective for oil and liquids production. While we have budgeted $313.0 million for 2012, the aggregate amount of capital we will expend may fluctuate materially based on market conditions and our drilling results.

In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. We would not expect to drill any operated natural gas wells, except for natural gas wells in specific exploratory projects like the Meade Peak shale in southwest Wyoming, until natural gas prices improved significantly from their recent levels. In addition, as a result of these low natural gas prices, several of our non-operated Haynesville shale wells were shut in for brief periods or produced less natural gas than we anticipated during the first quarter of 2012 as the operators curtailed a portion of the natural gas production from these wells.

As we transition our operations to the Eagle Ford shale play in south Texas, we may face challenges associated with establishing operations and securing the necessary services to drill and complete wells and with securing the necessary pipeline and natural gas processing capabilities to transport, process and market the oil and natural gas that we produce. We may also incur higher than anticipated costs associated with establishing new operating infrastructure and facilities on our leases throughout the area. We believe we have successfully secured the necessary drilling and completion services for our current Eagle Ford operations. We did not experience difficulties in securing completion, and particularly hydraulic fracturing services, for any wells drilled during the first quarter of 2012, although we experienced these problems at various times during 2011 in south Texas and may have such difficulties again in the future. We believe that maintaining reliable drilling and completion services and reducing drilling and completion costs will be essential to the successful development of the Eagle Ford shale play.

We experienced temporary pipeline interruptions from time to time during the three months ended March 31, 2012 associated with natural gas production from our Eagle Ford shale wells and have elected to either shut in wells for brief periods or to flare some of the natural gas we produced. We believe that these pipeline interruptions and capacity constraints are temporary and that additional oil and natural gas pipeline infrastructure currently being built throughout south Texas will help to alleviate these problems within 60 to 90 days. If we were required to shut in our production for long periods of time due to these pipeline interruptions, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

On February 2, 2012, our common stock began trading on the New York Stock Exchange, or NYSE, under the symbol "MTDR." Our general and administrative expenses have increased as a result of us operating as a public company. These increased expenses include costs associated with, among other items, legal and accounting support services, filing annual and quarterly reports with the SEC, investor relations activities, directors' fees, incremental directors' and officers' liability insurance costs, transfer and registrar agent fees and expenses associated with compliance with the Sarbanes-Oxley Act and other regulations. In addition, we have increased our staff size and compensation and incurred other ongoing general and administrative expenses necessary to maintain and grow


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a publicly traded exploration and production company. As a result, we believe that our general and administrative expenses for future periods may continue to increase. Our consolidated financial statements for future periods will reflect these increased expenses and affect the comparability of our financial statements with periods before the completion of our Initial Public Offering.

Initial Public Offering

We closed the Initial Public Offering of our common stock on February 7, 2012 and closed the over-allotment option on March 7, 2012. We issued 12,209,167 shares of common stock and 2,674,167 shares of common stock were sold by the selling shareholders. The shares were sold at a price to the public of $12.00 per share and we received cash proceeds of approximately $136.6 million from this transaction, net of underwriting discounts and commissions. We did not receive any proceeds from the sale of shares by the selling shareholders. The underwriters received underwriting discounts and commissions totaling approximately $9.9 million, and we incurred additional costs of approximately $3.5 million in connection with the offering, which amounted to total fees and costs of approximately $13.4 million. We used $123.0 million of the net proceeds to repay the then outstanding borrowings under our Credit Agreement. We used the remaining net proceeds to fund a portion of our 2012 capital expenditure requirements.


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Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at March 31, 2012 and March 31, 2011. These reserves estimates were based on evaluations prepared by our engineering staff and have been audited for their reasonableness by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the SEC's rules for oil and natural gas reserves reporting. The estimated reserves shown are for proved reserves only and do not include any unproved reserves classified as probable or possible reserves that might exist for our properties, nor do they include any consideration that could be attributable to interests in unproved and unevaluated acreage beyond those tracts for which proved reserves have been estimated. Proved oil and natural gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Our total estimated proved reserves are estimated using a conversion ratio of one Bbl per six Mcf.

                                                       At March 31,(1)
                                                      2012         2011
            Estimated Proved Reserves Data:(2)
            Estimated proved reserves:
            Oil (MBbl)                                 5,738          780
            Natural Gas (Bcf)                          168.7        150.1

            Total (Bcfe)                               203.1        154.8

            Estimated proved developed reserves:
            Oil (MBbl)                                 2,678          403
            Natural Gas (Bcf)                           56.1         53.7

            Total (Bcfe)                                72.1         56.1

            Percent developed                           35.5 %       36.2 %
            Estimated proved undeveloped reserves:
            Oil (MBbl)                                 3,060          377
            Natural Gas (Bcf)                          112.6         96.5

            Total (Bcfe)                               131.0         98.7

            PV-10(3) (in millions)                   $ 329.6      $ 140.6
            Standardized Measure(4) (in millions)    $ 287.4      $ 131.5

(1) Numbers in table may not total due to rounding.

(2) Our estimated proved reserves, PV-10 and Standardized Measure were determined using index prices for oil and natural gas, without giving effect to derivative transactions, and were held constant throughout the life of the properties. The unweighted arithmetic averages of the first-day-of-the-month prices for the period from April 2011 to March 2012 were $94.65 per Bbl for oil and $3.731 per MMBtu for natural gas and for the period from April 2010 to March 2011 were $80.04 per Bbl for oil and $4.102 per MMBtu for natural gas. These prices were adjusted by property for quality, energy content, regional price differentials, transportation fees, marketing deductions and other factors affecting the price received at the wellhead.

(3) PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. PV-10 is not an estimate of the fair market value of our properties. We and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies and of the potential return on investment related to the companies' properties without regard to the specific tax characteristics of such entities. Our PV-10 at March 31, 2012 and 2011 may be reconciled to our Standardized Measure of discounted future net cash flows at such dates by reducing our PV-10 by the discounted future income taxes associated with such reserves. The discounted future income taxes at March 31, 2012 and 2011 were, in millions, $42.2 and $9.1, respectively.

(4) Standardized Measure represents the present value of estimated future net cash flows from proved reserves, less estimated future development, production, plugging and abandonment costs and income tax expenses, discounted at 10% per annum to reflect the timing of future cash flows. Standardized Measure is not an estimate of the fair market value of our properties.


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Our total proved oil and natural gas reserves increased from 154.8 Bcfe at March 31, 2011 to 203.1 Bcfe at March 31, 2012. This increase is attributable to proved reserves added due to our drilling operations in both the Eagle Ford and Haynesville shale plays. The increase in total proved oil reserves specifically from 780 MBbl at March 31, 2011 to 5,738 MBbl at March 31, 2012 is attributable to proved oil reserves added due to our drilling operations in the Eagle Ford shale play. Our total proved reserves at March 31, 2012 were approximately 36% proved developed reserves and were made up of approximately 17% oil and 83% natural gas. Our total proved reserves at March 31, 2011 were approximately 36% proved developed reserves and were made up of approximately 3% oil and 97% natural gas.

In recent months, natural gas prices have declined to their lowest levels in many years, and at March 30, 2012, the NYMEX Henry Hub natural gas futures contract for the earliest delivery date closed at $2.13 per MMBtu. Although this decline in natural gas prices has not yet impacted the classification of our natural gas reserves at March 31, 2012, if natural gas prices continue to remain at or near these levels or if natural gas prices decline further, the unweighted arithmetic average of the first-day-of-the month prices for the previous 12 months used to estimate natural gas reserves will also continue to decline in future periods. Should this occur, the unweighted arithmetic average natural gas price for the previous 12 months, as adjusted by property for energy content, marketing and transportation fees and regional price differentials, may decline to a level where we are no longer able to classify a significant portion of our proved undeveloped natural gas reserves, particularly those associated with the Haynesville shale in northwest Louisiana, as proved undeveloped reserves. Should these natural gas volumes no longer be classified as proved undeveloped reserves, the net capitalized costs of our oil and natural gas properties less related deferred income taxes may exceed the present value of after-tax future net cash flows from our proved oil and natural gas reserves, discounted at 10%, in future periods, and if so, such excess must then be charged to operations as a full-cost ceiling impairment. As a non-cash item, a full-cost ceiling impairment impacts the accumulated depletion and net carrying value of our assets on the balance sheet, as well as the corresponding shareholders' equity, but it has no impact on our cash flows from operations.

There have been no changes to the technology we used to establish reserves or to our internal control over the reserves estimation process from those set forth in our Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Critical Accounting Policies

There have been no changes to our critical accounting policies and estimates from those set forth in the Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.

Recent Accounting Pronouncements

There have been no additional recent accounting pronouncements impacting our financial reporting from those set forth in the Annual Report on Form 10-K for the year ended December 31, 2011 filed with the SEC.


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Results of Operations

Revenues

The following table summarizes our revenues and production data for the periods
indicated:



                                                                  Three Months Ended
                                                                      March 31,
                                                              2012                  2011
                                                          (Unaudited)            (Unaudited)
Operating Data:
Revenues (in thousands):
Oil                                                      $       21,547         $       1,680
Natural gas                                                       7,617                12,019

Total oil and natural gas revenues                               29,164                13,699
Realized gain on derivatives                                      3,063                 1,849
Unrealized loss on derivatives                                   (3,270 )              (1,668 )

Total revenues                                           $       28,957         $      13,880

Net Production Volumes:
Oil (MBbl)                                                          200                    19
Natural gas (Bcf)                                                   3.2                   3.3
Total natural gas equivalents (Bcfe)(1)                             4.4                   3.4
Average net daily production (MMcfe/d)(1)                          48.1                  37.8
Average Sales Prices:
Oil (per Bbl)                                            $       107.57         $       89.11
Natural gas, with realized derivatives (per Mcf)         $         3.36         $        4.22
Natural gas, without realized derivatives (per Mcf)      $         2.40         $        3.65

(1) Estimated using a conversion ratio of one Bbl per six Mcf.

Three Months Ended March 31, 2012 Compared to Three Months Ended March 31, 2011

Oil and natural gas revenues. Our oil and natural gas revenues increased by approximately $15.5 million to approximately $29.2 million, or an increase of about 113% for the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. This increase in oil and natural gas revenues reflects an increase in our oil revenues of $19.9 million and a decrease in our natural gas revenues of $4.4 million for the three months ended March 31, 2012 as compared to the comparable period in 2011. Our oil revenues increased almost 13-fold to $21.5 million for the three months ended March 31, 2012 as compared to $1.7 million for the three months ended March 31, 2011. Our oil production increased just over 10-fold to approximately 200,000 Bbl of oil, or about 2,200 Bbl of oil per day, from approximately 19,000 Bbl of oil, or about 210 Bbl of oil per day, due to our drilling operations in the Eagle Ford shale. A portion of this increase in oil revenue also reflects a higher average oil price of $107.57 per Bbl realized during the first quarter of 2012 as compared to an average oil price of $89.11 per Bbl realized during the first quarter of 2011. The decrease in our natural gas revenues reflects a decline in our natural gas production by about 3% to approximately 3.2 Bcf for the three months ended March 31, 2012 as compared to approximately 3.3 Bcf for the three months ended March 31, 2011. This decline in natural gas production is due to several factors, including (i) our decision not to drill any operated Haynesville shale wells in 2012, (ii) the partial curtailment of natural gas production from some of our non-operated Haynesville shale wells in north Louisiana and (iii) the . . .

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