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

Quotes & Info
Enter Symbol(s):
e.g. YHOO, ^DJI
Symbol Lookup | Financial Search
MTDR > SEC Filings for MTDR > Form 10-Q on 14-Nov-2012All Recent SEC Filings

Show all filings for MATADOR RESOURCES CO

Form 10-Q for MATADOR RESOURCES CO


14-Nov-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:

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;


Table of Contents
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.

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 resource 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 natural gas prospects.

During the first nine months of 2012, our operations were primarily focused on the exploration and development of our Eagle Ford shale properties in South Texas, as we continued executing our plan to significantly increase our oil production and oil reserves during 2012. During the nine months ended September 30, 2012, we completed and began producing oil and natural gas from 18 gross/17.1 net operated and 2 gross/0.4 net non-operated Eagle Ford shale wells. We also completed and began producing natural gas from 21 gross/0.9 net non-operated Haynesville shale wells. As of September 30, 2012, we had also completed and begun producing oil and natural gas from 2 gross/2 net wells completed in the upper Austin Chalk and the lower Austin Chalk/upper Eagle Ford, or "Chalkleford," intervals, respectively. We had two contracted drilling rigs


Table of Contents

operating in South Texas throughout the first nine months of 2012 (except for a brief period near the end of the second quarter where we added a third rig to execute a two-well contract), and almost all of our operated drilling and completion activities were focused on the Eagle Ford shale. At November 14, 2012, we have two contracted drilling rigs operating in South Texas: one in LaSalle County and one in DeWitt County.

In the third quarter of 2012 specifically, our activities were almost entirely focused on our Eagle Ford shale properties. During the three months ended September 30, 2012, we completed and began producing oil and/or natural gas from 6 gross/5.3 net operated and 1 gross/0.2 net non-operated Eagle Ford shale wells. We completed two wells on our Love lease in DeWitt County, two wells on our Northcut lease in LaSalle County, one well on our Martin Ranch lease in LaSalle County and one well on our Sickenius lease in Karnes County. We also completed 2 gross/2 net wells on our Glasscock Ranch lease in Zavala County. These two wells were completed in the upper Austin Chalk and the lower Austin Chalk/upper Eagle Ford, or "Chalkleford," intervals, respectively. The two wells on the Love lease began producing in August 2012; the two wells on the Northcut lease and the well on the Sickenius lease began producing in September. The well drilled on the Martin Ranch lease did not begin producing until late September. As a result, these six wells did not contribute fully to our third quarter production volumes.

Our average daily production for the three months ended September 30, 2012 was 8,838 BOE per day, including 3,291 Bbl of oil per day and 33.3 MMcf of natural gas per day, as compared to 6,931 BOE per day, including 465 Bbl of oil per day and 38.8 MMcf of natural gas per day for the three months ended September 30, 2011. Both the average total daily production and the average daily oil production for the third quarter of 2012 were the best quarterly figures in our history. Our average daily oil production of 3,291 Bbl per day during the third quarter of 2012 was an increase of about 5% from an average daily oil production of approximately 3,131 Bbl per day during the second quarter of 2012 and an increase of over seven-fold from an average daily oil production of 465 Bbl per day in the third quarter of 2011. Our average daily production for the nine months ended September 30, 2012 was 8,534 BOE per day, including 2,876 Bbl of oil per day and 33.9 MMcf of natural gas per day, as compared to 7,081 BOE per day, including 414 Bbl of oil per day and 40.0 MMcf of natural gas per day for the nine months ended September 30, 2011. Our total oil production increased almost seven-fold to approximately 788,000 Bbl of oil during the first nine months of 2012 from approximately 113,000 Bbl of oil during the first nine months of 2011. This increased oil production is a direct result of our ongoing drilling operations in the Eagle Ford shale. Oil production comprised approximately 37% and 34% of our total production (using a conversion ratio of one Bbl of oil per six Mcf of natural gas) for the three and nine months ending September 30, 2012, respectively, as compared to approximately 7% and 6% of our total production for the three and nine months ended September 30, 2011, respectively.

Our oil and natural gas revenues were approximately $103.3 million, or an increase of about 99%, for the nine months ended September 30, 2012 as compared to $52.0 million for the nine months ended September 30, 2011. Our oil revenues increased almost eight-fold to $81.0 million for the nine months ended September 30, 2012 as compared to $10.5 million for the nine months ended September 30, 2011. Our oil and natural gas revenues of $103.3 million for the first nine months of 2012 were 154% of our total oil and natural gas revenues of $67.0 million reported for all of 2011. Our Adjusted EBITDA increased by approximately $40.3 million to approximately $77.9 million, or an increase of approximately 107%, for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011. This increase in our Adjusted EBITDA is primarily attributable to the increase in our oil production and the associated increase in our oil and natural gas revenues for the nine months ended September 30, 2012 as compared to the nine months ended September 30, 2011.

Our estimated proved oil reserves increased almost eight-fold to approximately 8.4 million Bbl of oil at September 30, 2012 from approximately 1.1 million Bbl of oil at September 30, 2011, based on the reserves audit by our independent reservoir engineers, Netherland, Sewell & Associates, Inc. At September 30, 2012, we had approximately 20.9 million BOE of estimated total proved reserves, including approximately 8.4 million Bbl of oil and 74.9 Bcf of natural gas, with a PV-10 of $363.6 million and a Standardized Measure of $333.9 million. At September 30, 2012, 61% of our estimated proved reserves were proved developed reserves, 40% of our estimated proved reserves were oil and 60% of our estimated proved reserves were natural gas. At September 30, 2011, based on the reserves audit by our independent reservoir engineers, we had approximately 27.0 million BOE of estimated total proved reserves, including 1.1 million barrels of oil and
155.3 Bcf of natural gas, with a PV-10 of $155.2 million and a Standardized Measure of $143.4 million. At September 30, 2011, 34% of our estimated proved reserves were proved developed reserves, 4% of our estimated proved reserves were oil and 96% of our estimated proved reserves were natural gas.

The unweighted arithmetic average of the first-day-of-the-month natural gas prices was $2.826 per MMBtu for the period from October 2011 to September 2012 and $4.158 per MMBtu for the period from October 2010 to September 2011.


Table of Contents

These average prices were the natural gas prices used to estimate our natural gas reserves at September 30, 2012 and 2011, respectively. As a result of declines in natural gas prices, at June 30, 2012, we removed 97.8 Bcf (or approximately 16.3 million BOE) of previously classified proved undeveloped natural gas reserves in the Haynesville shale in Northwest Louisiana from our estimated total proved reserves, most of which were attributable to non-operated properties. No similar reduction to our proved reserves was necessary at September 30, 2012. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by us or the operator at a future time when natural gas prices improve.

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. At September 30, 2012, we have incurred approximately $237.6 million or about 76% of our 2012 estimated capital expenditures of $313.0 million. This includes approximately $21.2 million incurred to acquire additional leasehold acreage primarily in the Eagle Ford shale near our existing properties and the Delaware Basin in West Texas. During the first nine months of 2012, our drilling and completion costs for new wells have been less than we budgeted, although our costs for production facilities, pipelines and other infrastructure have exceeded our initial estimates. Overall, at September 30, 2012, we are executing our 2012 capital expenditure program largely as planned and remain within our anticipated capital expenditure budget for 2012. 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, as well as other opportunities we may encounter during the remainder of 2012.

During the nine months ended September 30, 2012, natural gas prices have declined to their lowest levels in many years, with the NYMEX Henry Hub natural gas futures contract for the earliest delivery date reaching a low of $1.91 per MMBtu in mid-April. Although natural gas prices have rallied in the last several months, reaching a high of $3.32 per MMBtu in late September, 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 nine months of 2012 as the operators voluntarily curtailed a portion of the natural gas production from these wells.

As we continue to transition our operations to the Eagle Ford shale play in South Texas, we may face challenges associated with establishing operations in new areas 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 nine months 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 did experience temporary pipeline interruptions from time to time during the three and nine months ended September 30, 2012 associated with natural gas production from our Eagle Ford shale wells and elected to either shut in wells for brief periods or flare some of the natural gas we produced. To alleviate most of the pipeline interruptions and capacity constraints we experienced during 2012, effective September 1, 2012, we entered into a natural gas gathering, transportation and processing agreement that includes firm transportation and processing for most of our operated natural gas production in South Texas. The agreement has an initial term of five years. No assurance can be made that this agreement will alleviate these issues and if we were required to shut in our production for long periods of time due to pipeline interruptions, it could have a material adverse effect on our business, financial condition, results of operations and cash flows.

During the three months ended September 30, 2012, Matador and its partner finalized commercial arrangements related to the ongoing exploration of the Meade Peak shale. Operations are scheduled to begin in the fourth quarter of 2012 to conduct a horizontal test of the Meade Peak shale. The existing Crawford Federal #1 vertical wellbore was drilled and cored through the Meade Peak shale and then suspended in December 2011. Plans are to re-enter this existing wellbore, plug back to a sufficient depth to sidetrack and drill a horizontal lateral to test the Meade Peak formation. Matador's share of the anticipated costs of this operation will be carried by its partner. Matador and its partner also intend to renew leases that may be available for renewal and may acquire additional leasehold within their area of mutual interest.


Table of Contents

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 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.

Estimated Proved Reserves

The following table sets forth our estimated proved oil and natural gas reserves at September 30, 2012 and 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 September 30,(1)
                                                      2012           2011
          Estimated Proved Reserves Data:(2)
          Estimated proved reserves:
          Oil (MBbl)                                    8,411         1,083
          Natural Gas (Bcf)                              74.9         155.3

          Total (MBOE) (3)                             20,894        26,971

          Estimated proved developed reserves:
          Oil (MBbl)                                    3,783           519
          Natural Gas (Bcf)                              53.4          52.7

          Total (MBOE)                                 12,686         9,294

          Percent developed                              60.7 %        34.5 %
          Estimated proved undeveloped reserves:
          Oil (MBbl)                                    4,628           565
          Natural Gas (Bcf)                              21.5         102.7

          Total (MBOE)                                  8,208        17,677

          PV-10(4) (in millions)                   $    363.6      $  155.2
          Standardized Measure(5) (in millions)    $    333.9      $  143.4

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


Table of Contents
(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 October 2011 to September 2012 were $91.48 per Bbl for oil and $2.826 per MMBtu for natural gas and for the period from October 2010 to September 2011 were $91.00 per Bbl for oil and $4.158 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) Thousands of barrels of oil equivalent, estimated using a conversion ratio of one Bbl per six Mcf.

(4) 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 September 30, 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 September 30, 2012 and 2011 were, in millions, $29.7 and $11.8, respectively.

(5) 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.

. . .

  Add MTDR to Portfolio     Set Alert         Email to a Friend  
Get SEC Filings for Another Symbol: Symbol Lookup
Quotes & Info for MTDR - All Recent SEC Filings
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.