PROSPECTUS SUMMARY

This summary provides a brief overview of information contained elsewhere in this prospectus. You should read the entire prospectus carefully before making an investment decision, including the information presented under the headings “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. Unless otherwise indicated, information presented in this prospectus assumes that the underwriters’ option to purchase additional common shares is not exercised. We have provided definitions for certain oil and natural gas terms used in this prospectus in the “Glossary of Oil and Natural Gas Terms” beginning on page A-1 of this prospectus.

In this prospectus, unless the context otherwise requires, the terms “we,” “us,” “our,” and 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. See “Organizational Structure” on page 13 and “Corporate Reorganization” on page 168 of this prospectus.

In this prospectus, 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 this offering, as the Class A common stock will be the only class of common stock authorized after this offering, 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 this offering. See “Description of Capital Stock.” In addition, in this prospectus, we have assumed that 285,000 shares of common stock will be issued to certain holders of stock options prior to consummation of this offering and 262,500 of these shares will be sold by the option holders as selling shareholders in this offering.

Matador Resources Company

Overview

Matador Resources Company is 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. These plays are a key part of our growth strategy, and we believe they currently represent two of the most active and economically viable unconventional resource plays in North America. We expect the majority of our near-term capital expenditures will focus on increasing our production and reserves from the Eagle Ford and Haynesville shale plays as we seek to capitalize on the relative economics of each play. 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 in Utah and Idaho where we continue to identify new oil and natural gas prospects.

We were founded in July 2003 by Joseph Wm. Foran, Chairman, President and CEO, and Scott E. King, Co-Founder and Vice President, Geophysics and New Ventures, with an initial equity investment of approximately $6.0 million. Shortly thereafter, investors contributed approximately $46.8 million to provide a total initial capitalization of approximately $52.8 million. Most of this initial capital was provided by the same institutional and individual investors who helped capitalize Mr. Foran’s previous company, Matador Petroleum Corporation.

Mr. Foran began his career as an oil and natural gas independent in 1983 when he founded Foran Oil Company with $270,000 in contributed capital from 17 friends and family members. Foran Oil Company was later contributed to Matador Petroleum Corporation upon its formation by Mr. Foran in 1988. Mr. Foran served as Chairman and Chief Executive Officer of that company from its inception until it was sold in June 2003 to Tom Brown, Inc. in an all cash transaction for an enterprise value of approximately $388.5 million.

With an average of more than 25 years of oil and natural gas industry experience, our management team has extensive expertise in exploring for and developing hydrocarbons in multiple U.S. basins. Members of our management team have participated in the assimilation of numerous lease positions and in the drilling and completion of hundreds of vertical and horizontal wells in unconventional resource plays.

Since our first well in 2004, we have drilled or participated in drilling 213 wells through September 30, 2011, including 83 Haynesville and six Eagle Ford wells. From December 31, 2008 through September 30, 2011, we grew our estimated proved reserves from 20.0 Bcfe to 161.8 Bcfe. At September 30, 2011, 35% of our estimated proved reserves were proved developed reserves and 96% of our estimated proved reserves were natural gas. We also grew our average daily production by approximately 162% from 9.0 MMcfe per day for the year ended December 31, 2008 to 23.6 MMcfe per day for the year ended December 31, 2010. In addition, as a result of production from new wells that were completed in 2011, our daily production for the nine months ended September 30, 2011 averaged approximately 42.5 MMcfe per day. We have achieved this growth while lowering operating costs (consisting of lease operating expenses and production taxes and marketing expenses) from $1.91 per Mcfe for the year ended December 31, 2008, to $0.90 per Mcfe for the nine months ended September 30, 2011, or a decrease of approximately 53%.

The following table presents certain summary data for each of our operating areas as of and for the nine months ended September 30, 2011:

At September 30, 2011, our properties included approximately 52,000 gross acres and 29,000 net acres in the Eagle Ford shale play in Atascosa, DeWitt, Dimmit, Karnes, La Salle, Gonzales, Webb, Wilson and Zavala Counties in south Texas. We believe that approximately 85% of our Eagle Ford acreage is prospective predominantly for oil or liquids production. In addition, portions of the acreage are also prospective for other targets, such as the Austin Chalk, Olmos and Buda, from which we expect to produce predominantly oil and liquids. Approximately 80% of our Eagle Ford acreage is either held by production or not burdened by lease expirations before 2013. We have begun to explore and develop our Eagle Ford position and from November 2010 through December 2011, we completed our first seven operated wells in this area (see “— Recent Developments”). We have identified 197 gross locations and 157 net locations for potential future drilling on our Eagle Ford acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from nearby wells based on available public data, drilling densities observed from other operators, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface considerations, among others. At September 30, 2011, we have identified potential drilling locations on approximately 75% of our net Eagle Ford acreage. As we explore and develop our Eagle Ford acreage further, we believe it is possible that we may identify additional

locations for drilling. At September 30, 2011, these identified potential future drilling locations in the Eagle Ford shale play included 2 gross and 2 net locations to which we have assigned proved undeveloped reserves.

In addition, at September 30, 2011, we had approximately 23,000 gross acres and 15,000 net acres in the Haynesville shale play in northwest Louisiana and east Texas. Based on our analysis of geologic and petrophysical information (including total organic carbon content and maturity, resistivity, porosity and permeability, among other information), well performance data and information available to us related to drilling activity and results from wells drilled across the Haynesville shale play, almost 5,500 of our net acres are located in what we believe is the core area of the play. We believe the core area of the play includes that area in which the most Haynesville wells have been drilled by operators and from which we anticipate natural gas recoveries would likely exceed 6 Bcf per well. Just over 90% of our Haynesville acreage is held by production from the Haynesville or other formations, and we believe much of it is also prospective for the Cotton Valley, Hosston (Travis Peak) and other shallower formations. In addition, we believe approximately 1,700 of these net acres are prospective for the Middle Bossier shale play.

At September 30, 2011, we have identified 545 gross locations and 104 net locations for potential future drilling in our Haynesville acreage. These locations have been identified on a property-by-property basis and take into account criteria such as anticipated geologic conditions and reservoir properties, estimated recoveries from our producing Haynesville wells and other nearby wells based on available public data, drilling densities observed from other operators including on some of our non-operated properties, estimated drilling and completion costs, spacing and other rules established by regulatory authorities and surface conditions, among others. Of the 545 gross locations identified for future drilling, 470 of these locations (53 net locations) have been identified within the 5,500 net acres that we believe are located in the core area of the Haynesville play. As we explore and develop our Haynesville acreage further, we believe it is possible that we may identify additional locations for future drilling. At September 30, 2011, these identified potential future drilling locations in the Haynesville shale play included 95 gross and 15 net locations to which we have assigned proved undeveloped reserves.

We also have a large unevaluated acreage position in southwest Wyoming and adjacent areas in Utah and Idaho where we began drilling our initial well in February 2011 to test the Meade Peak natural gas shale. We reached a depth of 8,200 feet, approximately 300 feet above the top of the Meade Peak shale, before having operations suspended for several months due to wildlife restrictions. We resumed operations on this initial test well in September 2011 and completed drilling and coring operations on this well in November 2011. In addition, we have leasehold interests in the Delaware and Midland Basins in southeast New Mexico and west Texas where we are developing new oil and natural gas prospects.

We are active both as an operator and as a co-working interest owner with larger industry participants including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and others. Of the 213 gross wells we have drilled or participated in drilling, we drilled approximately half of these wells as the operator. At September 30, 2011, we were the operator for approximately 80% of our Eagle Ford and 70% of our Haynesville acreage, including approximately 22% of our acreage in what we believe is the core area of the Haynesville play. A large portion of our acreage in that core area is operated by a subsidiary of Chesapeake Energy Corporation. We also operate all of our acreage in southwest Wyoming and the adjacent areas of Utah and Idaho, as well as the vast majority of our acreage in southeast New Mexico and west Texas.

Our net proceeds from this offering, after repaying the then outstanding borrowings under our revolving credit agreement ($123.0 million at January 27, 2012, excluding outstanding letters of credit), when taken together with our cash flows and future potential borrowings under our credit agreement, will be used to fund our 2012 capital expenditure requirements and for potential acquisitions of interests and acreage (none of which have been identified). We anticipate that we may need to access future borrowings under our credit agreement within 60 to 90 days following completion of this offering to fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows and the net proceeds of this offering. See “Use of Proceeds.”

The following table presents our 2012 anticipated capital expenditure budget of approximately $313.0 million segregated by target formations and by whether the wells are considered to be exploration or development wells.

Although we intend to allocate a portion of our 2012 capital expenditure budget to financing exploration, development and acquisition of additional interests in the Haynesville shale play, we currently intend to allocate approximately 84% of our 2012 capital expenditure budget 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 play, 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. Since at September 30, 2011, just over 90% of our Haynesville acreage was held by production and approximately 80% of our Eagle Ford acreage was either

held by production or not burdened by lease expirations before 2013, we possess the financial flexibility to allocate our capital when we believe it is economical and justified.

Recent Developments

Recent Results

At January 16, 2012, we had drilled an aggregate of 11 Eagle Ford horizontal wells as operator. Seven of these wells have been completed and are producing. One of these wells, the Martin Ranch #8H in La Salle County, Texas, is currently undergoing completion operations, and we anticipate that two additional wells, the Martin Ranch #6H and the Martin Ranch #7H, will be completed in the near future. The Matador Sickenius ORCA #1H in Karnes County, Texas is also expected to be completed during the first quarter of 2012. At January 16, 2012, we had two contracted drilling rigs operating in the Eagle Ford play: one in La Salle County and the second in Karnes County.

For the month of December 2011, our daily production averaged approximately 43.4 MMcfe per day, including 39.8 MMcf of natural gas per day and 600 Bbl of oil per day. During the first 11 days of January 2012, our daily production averaged approximately 53.2 MMcfe per day, including 42.4 MMcf of natural gas per day and 1,800 Bbl of oil per day.

In December 2011, four of our Eagle Ford wells, the Martin Ranch #2H, #3H and #5H in La Salle County, Texas and the Lewton #1H in DeWitt County, Texas, began producing. In January 2012, we estimated that these four wells and six associated proved undeveloped locations increased our proved oil and natural gas reserves by approximately 2.8 million barrels of oil and 4.2 Bcf of natural gas as of December 31, 2011. These incremental estimates of proved reserves were prepared by our engineering staff and have been reviewed for their reasonableness by Netherland, Sewell & Associates, Inc., our independent reservoir engineers. These estimates were determined in accordance with guidelines established by the Securities and Exchange Commission for estimating and reporting oil and natural gas reserves. At January 16, 2012, we had not yet completed the estimates of our proved oil and natural gas reserves for the remainder of our properties at December 31, 2011.

Other Developments

Between November 2011 and January 2012, we entered into various costless collars to mitigate our exposure to oil price volatility and enhance predictability of our cash flows in 2012 and 2013. As of January 13, 2012, we have hedged a total of 1,060,000 Bbl of oil for 2012 and a total of 780,000 Bbl of oil for 2013. For 2012, all collars have a price floor of $90.00/Bbl and price ceilings that range from $104.20/Bbl to $113.75/Bbl. For 2013, all collars have price floors of $85.00/Bbl or $90.00/Bbl and price ceilings that range from $102.25/Bbl to $110.40/Bbl. These costless collars may limit our potential gains if oil prices rise above the specified price ceilings. For additional information, see “Risk Factors—Hedging Transactions, or the Lack Thereof, May Limit Our Potential Gains and Could Result in Financial Losses” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Quantitative and Qualitative Disclosures About Market Risk—Commodity Price Exposure.”

In December 2011, we amended and restated our senior secured revolving credit agreement. This amendment increased the maximum facility amount from $150 million to $400 million. Borrowings are limited to the lesser of $400 million or the borrowing base, which will be $100 million immediately following this offering. On January 25, 2012, we borrowed an additional $10.0 million under this agreement which brought our total borrowings to $123.0 million.

In November and December 2011, we completed three additional operated Eagle Ford horizontal wells, the Martin Ranch #2H, #3H and #5H in northeastern La Salle County, Texas. During initial flow tests on these wells, the Martin Ranch #2H tested at approximately 1,310 Bbls of oil and 1.8 MMcf of natural gas per day, the Martin Ranch #3H tested at approximately 620 Bbls of oil and 0.5 MMcf of natural gas per day, and the Martin Ranch #5H tested at approximately 810 Bbls of oil and 0.6 MMcf of natural gas per day. All three wells were turned to sales in late December 2011. We are the operator and have a 100% working interest in these three wells.

In August 2011, we completed our fourth operated Eagle Ford horizontal well, the Lewton #1H in DeWitt County, Texas. This well began producing to sales in late December 2011, and in early January 2012, the well was producing approximately 2.7 MMcf of natural gas and 600 Bbls of condensate per day. We are the operator of this well and paid 100% of the costs to drill and complete the well. We will receive 85% of the revenues attributable to the working interest in the well until we have recovered all of our acquisition, drilling and completion costs, after which time, our partner will receive 50% of the revenues attributable to the working interest in the well and we and our partner will each maintain a 50% working interest in the well.

Between March and July 2011, we acquired leasehold interests in approximately 6,300 gross and 4,800 net acres in DeWitt, Karnes, Wilson and Gonzales Counties, Texas in the Eagle Ford shale play from Orca ICI Development, JV. We believe that all of this acreage is in an oil and liquids prone area of the Eagle Ford play. We believe that the acreage in Wilson and Gonzales Counties and a portion of DeWitt County will be prospective for oil and liquids from the Austin Chalk formation in addition to the Eagle Ford. We paid approximately $31.5 million to acquire this acreage. We currently own a 50% working interest in the acreage (approximately 2,800 gross and 1,400 net acres) in DeWitt County and are the operator. We currently own a 100% working interest in the acreage (approximately 3,500 gross and 3,400 net acres) in Karnes, Wilson and Gonzales Counties and are the operator.

In March 2011, first sales of natural gas began from our Williams 17 H#1 well, located in what we believe to be the core area of the Haynesville shale play in northwest Louisiana. We began producing this well at a constrained rate of about 10.0 MMcf of natural gas per day. During November 2011, this well produced at an average daily rate of 4.5 MMcf of natural gas per day, and through November 30, 2011, had produced approximately 1.7 Bcf of natural gas. We are the operator and have a 100% working interest and a favorable 87.5% net revenue interest in this well.

In February 2011, we completed our third operated Eagle Ford horizontal well, the Affleck #1H, in eastern Dimmit County, Texas. This well tested at approximately 415 Bbls of oil and 5.4 MMcf of natural gas per day during an initial flow test. During November 2011, this well produced at an average daily rate of 0.9 MMcf of natural gas and 70 Bbls of oil per day. We are the operator and have a 100% working interest in this well.

In January 2011, we completed a private placement offering of 1,922,199 shares of our Class A common stock at $11.00 per share for an aggregate amount of $21,144,189.

In January 2011, we completed our second operated Eagle Ford horizontal well, the Martin Ranch #1H, in northeastern La Salle County, Texas. First sales of oil and natural gas from this well began in late March at approximately 700 Bbls of oil and 350 Mcf of natural gas per day. During November 2011, the well produced at an average daily rate of approximately 520 Bbls of oil and 0.6 MMcf of natural gas per

day, and through November 30, 2011, had produced a total of approximately 111,000 Bbls of oil and 135 MMcf of natural gas. We are the operator and have a 100% working interest in this well.

In January 2011, first sales of oil and natural gas began from our first operated Eagle Ford horizontal well, the JCM Jr. Minerals #1H, in southern La Salle County, at approximately 3.4 MMcf of natural gas and 135 Bbls of condensate per day. During November 2011, the well produced at an average daily rate of approximately 0.6 MMcf of natural gas and 12 Bbls of condensate per day, and through November 30, 2011, had produced a total of approximately 416 MMcf of natural gas and 10,900 Bbls of condensate. We are the operator and have a 100% working interest in this well.

In January 2011, we completed our first horizontal Cotton Valley well, the Tigner Walker H#1-Alt., in DeSoto Parish, Louisiana. First sales of natural gas from this well began in late January at approximately 4.6 MMcf of natural gas per day. During November 2011, the well produced at an average daily rate of approximately 1.9 MMcf of natural gas per day, and through November 30, 2011, had produced a total of approximately 900 MMcf of natural gas. We are the operator and have a 100% working interest in this well subject to a reversionary interest at payout.

On December 31, 2010, first sales of natural gas began from our L.A. Wildlife H#1 Alt. horizontal well, located in what we believe to be the core area of the Haynesville shale play in northwest Louisiana. We began producing this well at a constrained rate of about 10.0 MMcf of natural gas per day. During November 2011, the well produced at an average daily rate of approximately 10.0 MMcf of natural gas per day, and through November 30, 2011, had produced a total of approximately 3.2 Bcf of natural gas. We are the operator and have a 95% working interest in this well.

Business Strategies

Our goal is to increase shareholder value by building reserves, production and cash flows at an attractive return on invested capital. We plan to achieve our goal by executing the following strategies:

We have established core acreage positions in the Eagle Ford and Haynesville shale plays, which we believe are two of the most active and economically viable shale plays in North America. Although we intend to allocate a portion of our 2012 capital expenditure budget to financing exploration, development and acquisition of additional interests in the Haynesville shale play, we currently intend to allocate approximately 84% of our 2012 capital expenditure budget to the exploration, development and acquisition of additional interests in the Eagle Ford shale play. Since just over 90% of our Haynesville acreage was held by production and approximately 80% of our Eagle Ford acreage was either held by production or not burdened by lease expirations before 2013 at September 30, 2011, we have the flexibility to develop our acreage in a disciplined manner in order to maximize the resource recovery from these assets. We believe the economics for development in these two areas are attractive at current commodity prices.

Although most of our current proved reserves are classified as natural gas, we have been evaluating various oil plays to find and execute upon opportunities that would fit well with our exploration and operating strategies. 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. We believe oil and liquids opportunities represent about 94% of

our anticipated 2012 capital expenditure budget. We expect to continue to create and acquire additional prospects and opportunities for the exploration and production of oil and liquids.

We believe our management team’s familiarity with our key operating areas and its contacts with the operators and mineral owners in those regions enable us to identify high-return opportunities at attractive prices. We actively pursue opportunities to acquire unproved and unevaluated acreage, drilling prospects and low-cost producing properties within our core areas of operations where we have operational control and can enhance value and performance. We view these acquisitions as an important component of our business strategy and intend to selectively make acquisitions on attractive terms that complement our growth and help us achieve economies of scale.

As an operator, we leverage advanced technologies and integrate the knowledge, judgment and experience of our management and technical teams. We believe our team demonstrates financial discipline that is achieved by our approach to evaluating and analyzing prospects and prior drilling and completion results before allocating capital and is reflected in the improvements our team has attained on reducing unit costs. When we are not the operator, we proactively engage with the operators in an effort to ensure similar financial discipline. Additionally, we conduct our own internal geological and engineering studies on these prospects and provide input on the drilling, completion and operation of many of these non-operated wells pursuant to our agreements and relationships with the operators. Through these methods and practices, we believe we are well-positioned to control the expenses and timing of development and exploitation of our properties.

We believe maintaining proactive and ongoing relationships with other industry operators and vendors enhances our understanding of the shale plays and allows us to leverage their expertise without having to commit substantial capital. We currently participate in various drilling activities with larger industry participants, including affiliates of Chesapeake Energy Corporation, EOG Resources, Inc., Royal Dutch Shell plc and others. We are also active participants in three industry shale consortia: the North American Gas Shale, Haynesville and Bossier Shale and Eagle Ford Shale consortia organized by Core Laboratories, LP. As active members in various professional societies, our staff and board members also regularly interact on a professional basis with other industry participants.

Competitive Strengths

We believe our prior success is, and our future performance will be, directly related to the following combination of strengths that will enable us to implement our strategies:

We have key acreage positions in active areas of the Eagle Ford and Haynesville shale plays. We believe our assets in these plays are characterized by low geological risk and similar repeatable drilling opportunities that we expect will result in a predictable production growth profile. The commodity mix of our production and reserves is expected to become more balanced as a result of

our planned activities on our Eagle Ford and Austin Chalk acreage, which is located in oil and liquids prone areas of the plays. In addition to the Haynesville shale, our east Texas and north Louisiana assets have multiple, recognized geologic horizons, including the Middle Bossier shale, Cotton Valley and Hosston (Travis Peak) formations. We also believe there is additional resource potential in our oil and natural gas prospects in southeast New Mexico and west Texas, along with our natural gas prospects in southwest Wyoming and adjacent areas in Utah and Idaho.

Within our northwest Louisiana/east Texas and south Texas regions, we have identified 818 gross and 313 net drilling locations, including 197 gross and 157 net locations in the Eagle Ford shale play and 545 gross and 104 net locations in the Haynesville shale play. At September 30, 2011, these identified drilling locations included 2 gross and 2 net locations to which we have assigned proved undeveloped reserves in the Eagle Ford shale play and 95 gross and 15 net locations to which we have assigned proved undeveloped reserves in the Haynesville shale play. We have identified 28 gross and 26 net locations in the Eagle Ford shale play and 25 gross and 2 net locations in the Haynesville shale play that we expect to drill in 2012, the completion of which would represent approximately 14% and 5% of our identified gross drilling locations in these two areas at September 30, 2011, respectively. Additionally, we expect to identify and develop additional locations across our broad exploration portfolio as we evaluate our Cotton Valley, Austin Chalk, Meade Peak and Delaware and Midland Basin assets. We believe our multi-year, identified drilling inventory and exploration portfolio provide visible near-term growth in our production and reserves, and highlight the long-term resource potential across our asset base.

Historically, we have maintained financial flexibility by obtaining capital through shareholder investments and our operational cash flows while having access to additional borrowings, which has allowed us to take advantage of acquisition opportunities as they arise. At September 30, 2011, on an as adjusted basis to give effect to this offering and our use of proceeds, we expect to have at least $98.7 million available for borrowings under our credit agreement after giving effect to outstanding letters of credit. Excluding any possible acquisitions, we expect to maintain our current financial flexibility by funding our entire 2012 capital expenditure budget through the net proceeds we receive from this offering, together with our cash flows and future potential borrowings under our credit agreement. We anticipate that we may need to access future borrowings under our credit agreement within 60 to 90 days following completion of this offering to fund a portion of our 2012 capital expenditure requirements in excess of amounts available from our cash flows and the net proceeds of this offering. Our availability of capital as described above will also allow us to maintain our competitiveness in seeking to acquire additional oil and natural gas properties as opportunities arise. A strong balance sheet and interest savings should also reduce unit costs and increase profitability. In addition, since a large portion of our Eagle Ford and Haynesville acreage was held by production at September 30, 2011, we have the financial flexibility to allocate our capital when we believe it is economical and justified.

Our management and technical teams possess extensive oil and natural gas expertise with an average of over 25 years of relevant industry experience from companies such as Matador Petroleum Corporation, S. A. Holditch & Associates, Inc., Schlumberger Limited, Conoco and

ARCO, and we believe they have a demonstrated record of growth and financial discipline over many years. The management team has experience in drilling and completing hundreds of vertical and horizontal wells in unconventional resource plays, including the Cotton Valley, Bossier, Wilcox/Vicksburg, Austin Chalk, Haynesville and Eagle Ford plays. Our management team’s experience is complemented by a strong technical team with deep knowledge of advanced geophysical, drilling and completion technologies whose members are active in their professional societies. Additionally, we have a group of board members and special advisors with considerable experience and expertise in the oil and natural gas industry and in managing other successful enterprises who provide insight and perspective regarding our business and the evaluation, exploration, engineering and development of our prospects. In addition to its considerable experience, our management team currently owns and will continue to own a significant direct ownership interest in us immediately following the completion of this offering. We believe our management team’s direct ownership interest, as well as its ability to increase its holdings over time through our long-term incentive plan, aligns management’s interests with those of our shareholders.

The individuals on our technical team are highly experienced in analyzing unconventional reservoir plays and in horizontal drilling, completion and production operations in a number of geographic areas. Our geologists have extensive experience in analyzing unconventional reservoir plays throughout the United States, including our principal areas of interest, by using the latest imaging technology, such as 2-D and 3-D seismic interpretation, and petrophysical analysis. In addition, our technical team has been directly involved in over 26 different horizontal well drilling and/or operations programs in both onshore and offshore formations located in the United States and abroad. Our team’s diverse and broad horizontal drilling experience includes most, if not all, techniques used in modern day drilling. Additionally, our team has in-depth experience with various horizontal completion techniques and their applications in multiple unconventional plays. We intend to leverage our team’s geological expertise and horizontal drilling and completion experience to develop and exploit our large, multi-year development drilling inventory.

Our process for evaluating and developing new oil and natural gas prospects is a result of what we believe is an organizational philosophy that is dedicated to a systematic, multi-disciplinary approach to new opportunities with an emphasis on incorporating petroleum systems, geosciences, technology and finance into the decision-making process. We recognize the importance of consulting multiple individuals in our organization across all disciplines and all levels of responsibility prior to making exploration, acquisition or development decisions and the formulation of key criteria for successful exploration and development projects in any given play to enhance our decision-making. We also conduct a post-completion review of our major decisions to determine what we did right and where we need to improve. At times, this approach results in a decision to accelerate our drilling program or expand our positions in certain areas. Other times, this approach results in a decision to mitigate risk associated with our exploration and development programs by sharing operational risks and costs with other industry participants or exiting an area altogether. We believe this multi-disciplined approach underpins our track record of value creation and represents the best way to deliver consistent, year-over-year results to our shareholders.

Certain Risk Factors

An investment in our common stock involves risks that include the speculative nature of oil and natural gas exploration and production, competition, volatile oil and natural gas prices and other material factors. In particular, the following considerations may offset our competitive strengths or have a negative effect on both our business strategy as well as on activities on our properties, which could cause a decrease in the price of our common stock and result in a loss of all or a portion of your investment:

For a discussion of these risks and other considerations that could negatively affect us, including risks related to this offering and our common stock, see “Risk Factors” beginning on page 21 and “Cautionary Note Regarding Forward-Looking Statements.”

Organizational Structure

Matador Resources Company was formed as a Texas corporation in July 2003. Pursuant to the terms of the corporate reorganization that was completed on August 9, 2011, former Matador Resources Company, now known as MRC Energy Company, became a wholly owned subsidiary of current Matador Resources Company, formerly known as Matador Holdco, Inc. In connection with the reorganization, former Matador Resources Company changed its corporate name to MRC Energy Company, and Matador Holdco, Inc. changed its corporate name to Matador Resources Company.

The following diagram indicates our ownership structure and organizational structure after giving effect to our corporate reorganization and this offering. The shareholder ownership information set forth below is based on the beneficial ownership of our common stock after consummation of this offering based on the number of shares beneficially owned by our current shareholders at January 27, 2012.

Corporate Information

We are headquartered in Dallas, Texas. Our executive offices and mailing address are at One Lincoln Centre, 5400 LBJ Freeway, Suite 1500, Dallas, Texas 75240. Our telephone number is (972) 371-5200. We expect to have an operational website that meets Securities and Exchange Commission, or SEC, and New York Stock Exchange, or NYSE, requirements concurrently with, or prior to, the completion of this offering. Information on our website or any other website is not and will not be incorporated by reference herein and does not and will not constitute a part of this prospectus.

The Offering

Summary Financial, Reserves and Operating Data

You should read the following summary financial, reserves and operating data in conjunction with “Selected Historical Consolidated and Other Financial Data,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Business” and our audited and unaudited historical consolidated financial statements and related notes thereto included elsewhere in this prospectus. The financial information included in this prospectus may not be indicative of our future results of operations, financial position and cash flows.

Financial Data

The following tables set forth summary historical consolidated financial information for the company and its subsidiaries. The historical consolidated financial information is derived from the audited consolidated financial statements for the company and its subsidiaries at and for the years ended December 31, 2010, 2009 and 2008 and the unaudited condensed consolidated financial statements for the company and its subsidiaries at and for the nine months ended September 30, 2011 and 2010. The balance sheet data has also been adjusted to reflect the estimated net proceeds to be received by us from this offering. The audited consolidated financial statements for the company and its subsidiaries at and for the years ended December 31, 2010, 2009 and 2008 and the unaudited condensed consolidated financial statements for the company and its subsidiaries at and for the nine months ended September 30, 2011 and 2010 are contained elsewhere in this prospectus. Our consolidated financial statements for the years ended December 31, 2010, 2009 and 2008 were audited by Grant Thornton LLP.

Non-GAAP Financial Measures

We define Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, property impairments, unrealized derivative gains and losses, non-recurring

income and expenses and non-cash stock-based compensation expense, including stock option and grant expense and restricted stock grants. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of our consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. “GAAP” means Generally Accepted Accounting Principles.

Management believes Adjusted EBITDA is necessary because it allows us to evaluate our operating performance and compare the results of operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from net income (loss) in calculating Adjusted EBITDA because these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired.

Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components of understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure. Our Adjusted EBITDA may not be comparable to similarly titled measures of another company because all companies may not calculate Adjusted EBITDA in the same manner. The following table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively.

Reserves Data

The following table presents summary data with respect to our estimated net proved oil and natural gas reserves at the dates indicated. The reserves estimates at December 31, 2008 presented in the table below are based on evaluations prepared by our engineering staff, which have been audited by LaRoche Petroleum Consultants, Ltd., independent reservoir engineers. The reserves estimates at December 31, 2010 and 2009 and at September 30, 2011 are based on evaluations prepared by our engineering staff, which have been audited by Netherland, Sewell & Associates, Inc., independent reservoir engineers. These reserves estimates were prepared in accordance with the Securities and Exchange Commission’s rules regarding oil and natural gas reserves reporting that were in effect at the time of the preparation of the reserves report. Our total estimated proved reserves are estimated using a conversion ratio of one Bbl per six Mcf.