8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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FORM 8-K

_________________________________

CURRENT REPORT

Pursuant to Section 13 or 15(d)

of the Securities Exchange Act of 1934

Date of Report (Date of Earliest Event Reported) October 14, 2014

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Matador Resources Company

(Exact name of registrant as specified in its charter)

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Texas	001-35410	27-4662601
(State or other jurisdiction of incorporation)	(Commission File Number)	(IRS Employer Identification No.)

5400 LBJ Freeway, Suite 1500, Dallas, Texas	75240
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (972) 371-5200

Not Applicable

(Former name or former address, if changed since last report)

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Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

o Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

o Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

o Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Item 2.02 Results of Operations and Financial Condition.

Attached hereto as Exhibit 99.1 is a press release (the “Press Release”) issued by Matador Resources Company (the “Company”) on October 14, 2014, providing an operational update.

The Company expects to make presentations concerning its business to potential investors. The materials to be utilized during the presentations (the “Materials”) are furnished as Exhibit 99.2 hereto.

The Press Release and the Materials are incorporated by reference into this Item 2.02, and the foregoing descriptions of the Press Release and the Materials are qualified in their entirety by reference to the respective exhibits.

The information furnished pursuant to this Item 2.02, including Exhibits 99.1 and 99.2, shall not be deemed to be “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended (the “Securities Act”), unless specifically identified therein as being incorporated therein by reference.

In the Materials, the Company has included as “non-GAAP financial measures,” as defined in Item 10 of Regulation S-K of the Exchange Act, (i) earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non-cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment (“Adjusted EBITDA”) and (ii) present value discounted at 10% (pre-tax) of estimated total proved reserves (“PV-10”). In the Materials, the Company has provided reconciliations of the non-GAAP financial measures to the most directly comparable financial measures calculated and presented in accordance with generally-accepted accounting principles (“GAAP”) in the United States. In addition, in the Materials, the Company has provided the reasons why the Company believes those non-GAAP financial measures provide useful information to investors.

Item 7.01 Regulation FD Disclosure.

Item 2.02 above is incorporated herein by reference.

The information furnished pursuant to this Item 7.01, including Exhibits 99.1 and 99.2, shall not be deemed to be “filed” for the purposes of Section 18 of the Exchange Act and will not be incorporated by reference into any filing under the Securities Act unless specifically identified therein as being incorporated therein by reference.

Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

Exhibit No.	Description of Exhibit
99.1	Press Release, dated October 14, 2014.
99.2	Presentation Materials.

SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	MATADOR RESOURCES COMPANY
Date: October 14, 2014	By:	/s/ Craig N. Adams
	Name:	Craig N. Adams
	Title:	Executive Vice President

Exhibit Index

Exhibit No.	Description of Exhibit
99.1	Press Release, dated October 14, 2014.
99.2	Presentation Materials.

EX-99.1

Exhibit 99.1

NEWS RELEASE

MATADOR RESOURCES COMPANY PROVIDES OPERATIONAL UPDATE AND INCREASES 2014 OIL PRODUCTION GUIDANCE

DALLAS, Texas, October 14, 2014 - Matador Resources Company (NYSE: MTDR) (“Matador” or the “Company”), an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources, with an emphasis on oil and natural gas shale and other unconventional plays and with a current focus on its Eagle Ford operations in South Texas and its Permian Basin operations in Southeast New Mexico and West Texas, today is pleased to provide the following update of its ongoing operations.

Production Update and Oil Production Guidance Increase

Matador is pleased to announce today its quarterly production results for the three months ended September 30, 2014, which were the best quarterly oil equivalent production and quarterly oil production results in the Company’s history.

• Oil equivalent production increased 19% year over year from approximately 1.24 million barrels of oil equivalent (“BOE”) (50% oil) or an average of about 13,500 BOE per day in the third quarter of 2013 to approximately 1.5 million BOE (57% oil) or an average of about 16,100 BOE per day in the third quarter of 2014. Oil equivalent production increased approximately 6% sequentially quarter over quarter from approximately 1.4 million BOE (57% oil) or an average of about 15,400 BOE per day in the second quarter of 2014 and increased 38% from approximately 1.1 million BOE (62% oil) or an average of about 11,900 BOE per day in the first quarter of 2014. Oil equivalent production year over year increased 24% from 3.2 million BOE for the nine months ended September 30, 2013 or about 11,700 BOE per day to 4.0 million BOE for the nine months ended September 30, 2014 or about 14,500 BOE per day.

• Oil production increased 36% year over year from 617,000 barrels (“Bbl”) of oil or about 6,700 Bbl of oil per day in the third quarter of 2013 to 839,000 Bbl of oil or about 9,100 Bbl of oil per day in the third quarter of 2014. Oil production increased about 5% sequentially quarter over quarter from 802,000 Bbl of oil or about 8,800 Bbl of oil per day in the second quarter of 2014 and increased 27% from 661,000 Bbl of oil or about 7,300 Bbl of oil per day in the first quarter of 2014. Oil production year over year increased 51% from 1.5 million Bbl for the nine months ended September 30, 2013 or about 5,600 Bbl of oil per day to 2.3 million Bbl for the nine months ended September 30, 2014 or about 8,400 Bbl of oil per day.

• Natural gas production increased 3% year over year from approximately 3.7 billion cubic feet (“Bcf”) of natural gas, or about 40.7 million cubic feet of natural gas per day in the third quarter of 2013 to approximately 3.85 Bcf of natural gas, or about 41.8 million cubic feet of natural gas per day in the third quarter of 2014. Natural gas production increased about 7% sequentially quarter over quarter from approximately 3.6 Bcf of natural gas per day or about 39.7 million cubic feet of natural gas in the second quarter of 2014 and increased 56% from approximately 2.5 Bcf of natural

gas or about 27.4 million cubic feet of natural gas per day in the first quarter of 2014. Natural gas production year over year remained essentially flat at approximately 10.0 Bcf for the nine months ended both September 30, 2013 and 2014 or about 36.4 million cubic feet of natural gas per day.

• In early October 2014, Matador’s average daily oil equivalent production increased to more than 20,000 BOE per day for the first time in the Company’s history as a result of temporarily shut-in wells being returned to production along with initial production from several new wells.

• Matador expects a sequential quarter over quarter percentage increase of 25 to 33% in its total oil equivalent production in the fourth quarter over the third quarter of 2014, as compared to the 6% sequential increase achieved in the third quarter over the second quarter of 2014.

Matador’s third quarter production results were consistent with its production estimates for the third quarter of 2014, as outlined in its August 6, 2014 press release, of a 6 to 8% increase in oil equivalent production. For the nine months ended September 30, 2014, Matador’s total oil equivalent production was approximately 4.0 million BOE, including about 2.3 million barrels of oil and about 10.0 Bcf of natural gas. This growth in the third quarter of 2014 was limited in part as a result of the timing of Matador’s completion operations, particularly in the Eagle Ford shale during the quarter, and the planned temporary shut-ins of certain of its Eagle Ford and Haynesville wells while Matador and its partners on Matador’s non-operated properties conducted hydraulic fracturing operations on multi-well pads. Matador had up to 15 to 20% of its production temporarily shut in at various times during the third quarter of 2014 and particularly so in the month of September. In the first few days of October, Matador’s daily production surged as most of these temporarily shut-in wells, particularly in the Eagle Ford shale, were returned to production, along with the initial production from several newly completed Eagle Ford shale wells. In addition, Chesapeake Energy Corporation (“Chesapeake”) placed four new Haynesville shale wells on production in early October. This increased Eagle Ford and Haynesville production, as well as the initial production from one new Permian Basin well in Matador’s Wolf prospect area and the continued strong early performance of its other Permian Basin wells, resulted in an increase in Matador’s average daily oil equivalent production to more than 20,000 BOE per day for the first time in the Company’s history. Matador expects to maintain its average daily oil equivalent production at or above 20,000 BOE per day for the remainder of 2014.

Matador is pleased to announce that based on its projections for the remainder of 2014, the Company currently anticipates that its total oil equivalent production for 2014 will be between 5.9 and 6.0 million BOE, representing an anticipated increase of between 25 and 33% in the fourth quarter of 2014 as compared to the third quarter, and the sequential quarter to quarter increase of about 6% between the second and third quarter of 2014.

Matador is also pleased today to announce that it is increasing its 2014 oil production guidance range from the high end of 2.8 to 3.1 million barrels to 3.2 to 3.3 million barrels. Matador further guides its investors to the middle or lower half of its 2014 natural gas guidance range of 16.0 to 17.5 Bcf, primarily as a result of better visibility around the expected timing of initial natural gas production from several new Haynesville wells on its Elm Grove properties in northwest Louisiana to be completed and placed on production by Chesapeake in the latter portion of the fourth quarter. Matador is very pleased by the initial results of the wells completed and placed on production by Chesapeake thus far. At October 14, 2014, Chesapeake had completed and placed nine new Haynesville wells on production, and each of these nine wells continued to produce between 8 and 12 million cubic feet (gross) of natural gas per day, representing a total of approximately 17 million cubic feet of natural gas per day net to Matador’s interest. In early October, including the addition of these new Haynesville wells, Matador’s natural gas production had increased to approximately 58 million cubic feet of natural gas per day, more than double the average

daily natural gas production of 27.4 million cubic feet of natural gas per day reported for the first quarter of 2014. Matador currently expects eight additional Haynesville wells to be completed and placed on production by Chesapeake later in the fourth quarter.

Permian Basin Update - Southeast New Mexico and West Texas

Wolf Prospect Area

Matador is pleased to announce the 24-hour initial potential test results of three of its most recent wells completed in the Permian Basin - the Johnson 44-02S-B53 #204H, the Arno #1H and the Pickard State 20-18-34 #2H wells. These 24-hour initial potential tests were conducted over a full 24-hour stabilized flow period on a constant choke size, typically after several days of cleanup following stimulation, and reflect the average production rates and pressures achieved during that 24-hour period. In the Wolf prospect area of Loving County, Texas, the Johnson 44-02S-B53 #204H well flowed 1,286 BOE per day, including 793 Bbl of oil per day and 3.0 million cubic feet of natural gas per day (62% oil), at approximately 4,000 pounds per square inch (“psi”) surface pressure on a 24/64^th inch choke during its 24-hour initial potential test. This well was completed in the upper portion of the geopressured Wolfcamp formation, the Wolfcamp “A,” at approximately 11,200 feet true vertical depth. Matador drilled a 4,600-ft horizontal lateral in the Johnson 44-02S-B53 #204H well and completed the well with 19 frac stages, including approximately 200,000 Bbl of fluid and 9.4 million pounds of sand.

Also in the Wolf prospect area, the Arno #1H well flowed 1,110 BOE per day, including 300 Bbl of oil per day and 4.9 million cubic feet of natural gas per day (27% oil), at approximately 4,100 psi surface pressure on a 26/64^th inch choke during its 24-hour initial potential test using the same practices described above. This well was also completed in the Wolfcamp “A” bench at approximately 10,600 feet true vertical depth. Matador drilled a 5,400-ft horizontal lateral in the Arno #1H well and completed the well with 22 frac stages, including 226,000 Bbl of fluid and 10.6 million pounds of sand.

The Johnson 44-02S-B53 #204H and the Arno #1H wells, each of which has produced less than 30 days, are the third and fourth successful tests of the Wolfcamp “A” bench in Matador’s Wolf prospect area, along with the Dorothy White #1H and the Norton Schaub #1H wells. The Dorothy White #1H has produced approximately 226,000 BOE, including 153,000 Bbl of oil (68% oil) in nine months of production and is currently producing about 550 Bbl of oil per day and 1.4 million cubic feet of natural gas per day at almost 2,100 psi flowing surface pressure. As previously reported, Matador estimates this well is on track for an estimated ultimate recovery of approximately 1,000,000 BOE. The Norton Schaub #1H has produced almost 70,000 BOE, including 48,000 Bbl of oil (70% oil), in three months of production and is currently producing about 475 Bbl of oil per day and 1.2 million cubic feet of natural gas per day at almost 2,000 psi flowing surface pressure. The Company estimates that this well is on track for an estimated ultimate recovery of approximately 700,000 BOE. Obviously, Matador is pleased with both the early test results and the longer-term performance of its initial wells in the Wolf prospect area and expects comparable performance from the Arno #1H and Johnson 44-02S-B53 #204H wells. The Company expects to continue operating one of its two Permian rigs continuously in the Loving County area in development mode given these encouraging results.

Ranger Prospect Area

In the Ranger prospect area in Lea County, New Mexico, the Pickard State 20-18-34 #2H well flowed 270 BOE per day, including 232 Bbl per day of oil and 225 thousand cubic feet per day of natural gas (86% oil) at 1,150 psi surface pressure on an 18/64^th inch choke during its 24-hour initial potential test. This well was completed in the Wolfcamp “D” bench at approximately 12,000 feet true vertical depth. Matador drilled a 4,300-ft horizontal lateral in the Pickard State 20-18-34 #2H well and completed the well with 17 frac stages, including 192,000 Bbl of fluid and 8.2 million pounds of sand. The Pickard State 20-18-34 #2H well has produced approximately 16,000 BOE in almost three months of production and is still producing approximately 200 BOE per day, including 160 Bbl per day of oil and 260 thousand cubic feet of natural gas per day, at approximately 220 psi surface pressure with gas-lift assist.

This initial test result on the Pickard State 20-18-24 #2H well, while modest when compared to Matador’s Wolfcamp “A” results in Loving County, is still considered by the Company to be an important and positive development. The Wolfcamp formation in the northern part of the Delaware Basin has proven to be productive, at times prolifically, from a number of different porous and permeable zones within the upper portion of the Wolfcamp formation. The oil and natural gas produced from these zones is believed to be sourced by organic-rich mudstones and shales within the lowermost portion of the Wolfcamp, or the Wolfcamp “D” bench, which was the target for the Pickard State 20-18-24 #2H well. Matador believes this test of the Wolfcamp “D” formation may be the northernmost horizontal test of the Wolfcamp formation in the Delaware Basin. The horizontal landing target chosen for the Pickard State 20-18-34 #2H well was the most organically rich portion of the mudstones and shales within the Wolfcamp “D.” Matador considers the initial test results from this well to be both significant and encouraging because they demonstrate, for perhaps the first time, the ability to produce oil and natural gas from these organically rich source rocks in the Wolfcamp “D” in the northern Delaware Basin. Further, the Wolfcamp “D” bench in the Pickard State 20-18-34 #2H well and other wells in the area, including in Matador’s Twin Lakes area, is composed not only of highly organic-rich mudstones and shales, but also contains multiple, interbedded sandy and silty intervals that may prove to be more optimal drilling and completion targets in future Wolfcamp “D” wells. Given these positive and indicative results, Matador expects to continue to explore and test the Wolfcamp “D” in future wells in the northern Delaware Basin. In fact, Matador’s exploration concept for its Twin Lakes area targets a porous and permeable interbedded sandy and silty interval within the organically rich Wolfcamp “D.” This concept is similar to that Matador is using in Loving County in its Wolf prospect area targeting the interbedded “X” sand within the Wolfcamp “A” interval. Matador now anticipates drilling its first Twin Lakes test in early 2015.

Elsewhere in the Ranger prospect area, Matador’s first two Second Bone Spring completions continue to perform very well. The Ranger 33 State Com #1H well has produced 150,000 BOE, including 137,000 Bbl of oil (91% oil), after eleven months of production and continues to produce 300 to 350 Bbl of oil per day with gas-lift assist. As previously reported, Matador estimates this well is on track for an estimated ultimate recovery of approximately 500,000 BOE. The Pickard State 20-18-34 #1H well has produced 33,000 BOE, including 30,000 Bbl of oil (91% oil), after about 2.5 months of production. Given the early success of the gas-lift assist on the Ranger 33 State Com #1H and in its Eagle Ford shale program, the Pickard State 20-18-34 #1H well was also equipped with gas-lift assist within about 30 days following its initial completion. Since that time, the well’s production has remained relatively flat, averaging between 400 and 450 Bbl of oil per day. The Company continues to be very encouraged by the early performance of these initial Second Bone Spring wells, and in particular, the way that these wells have responded to the early implementation of gas-lift assist. Matador is currently completing its Jim Rolfe 22-18-34 RN State #131Y well, the Company’s first test of the Third Bone Spring formation, in the northern portion of its Ranger prospect area.

Acreage Additions

Matador began 2014 with approximately 70,800 gross (44,800 net) acres in the Permian Basin in Southeast New Mexico and West Texas. Between January 1 and October 1, 2014, Matador acquired an additional approximately 27,700 gross (20,200 net) acres in this area, primarily in Lea and Eddy Counties, New Mexico and Loving County, Texas. Including these acreage acquisitions, at October 1, 2014, Matador’s total Permian Basin acreage position was approximately 98,400 gross (65,000 net) acres. This leasehold position includes 11,200 gross (7,200 net) acres in Loving County, Texas (including a few small tracts in Reeves and Ward Counties), 14,900 gross (10,800 net) acres in the Ranger prospect area in Lea County, New Mexico, 21,000 gross (14,800) net acres in the Rustler Breaks prospect area in Eddy County, New Mexico, 39,000 gross (27,500 net) acres in the Twin Lakes prospect area in Lea County, New Mexico, and 4,000 gross (3,400 net) acres in Howard and Dawson Counties, Texas.

Eagle Ford Shale Update - South Texas

At October 14, 2014, Matador is operating two drilling rigs in the Eagle Ford shale, and both are currently drilling in La Salle County. Both rigs are “walking” rigs, and Matador plans to conduct batch drilling on its Eagle Ford properties using these two rigs for the remainder of 2014. Matador continues to achieve improvements in both drilling times and costs with these “walking” rigs. One recent well on Matador’s western acreage in La Salle County, was drilled from spud to a total depth of 12,300 feet, including an approximate 5,100-foot lateral, in 7.4 days, which was a new Company record. Costs have also continued to move somewhat lower, primarily as a result of continued drilling efficiencies, and several wells on Matador’s western acreage have been drilled and completed for between $5.5 and $6.0 million. The Company has continued to observe small decreases in overall service costs in the areas it operates in the Eagle Ford shale.

Matador’s downspacing efforts in the Eagle Ford shale have continued to achieve very positive results. Since the beginning of the third quarter, the Company drilled, completed and placed on production six gross (6.0 net) wells on its Danysh and Pawelek leases at 40 to 50-acre spacing. The initial flow rates and flowing pressures on these newer wells completed with Generation 7 fracture treatment designs have been consistently better than those results observed on the initial 80-acre wells completed with earlier generation fracture treatment designs, and the flowing pressures on these wells suggest minimal pressure depletion at these locations from earlier wells drilled and completed on the same leases. On its Danysh lease, 24-hour initial potential tests from Matador’s three most recent wells averaged 880 BOE per day, including 770 Bbl of oil per day and 650 thousand cubic feet of natural gas per day (88% oil), at 2,400 to 2,500 psi flowing surface pressure on a 14/64^th inch choke. On its Pawelek lease, 24-hour initial potential tests from Matador’s three most recent wells averaged 790 BOE per day, including 694 Bbl of oil per day and 575 thousand cubic feet of natural gas per day (88% oil), at 2,700 to 3,000 psi flowing surface pressure on a 14/64^th inch choke.

On the Company’s Northcut lease in La Salle County, 40-acre infill wells have also delivered comparable to better initial results than the previous 80-acre wells drilled on this lease using earlier generation fracture treatment designs, and initial flowing pressures on these wells also suggest minimal pressure depletion at these locations. Initial potential tests from Matador’s three most recent Northcut wells averaged about 440 BOE per day, including 405 Bbl of oil per day and 230 thousand cubic feet of natural gas per day (91% oil), at flowing pressures from 760 to 1,520 psi on 12/64^th to 14/64^th inch chokes. The most recent three wells drilled and placed on production on Matador’s Martin Ranch lease were also drilled at 40-acre spacing with strong initial test results. These wells were drilled on the western portion of Matador’s Martin Ranch lease and completed with Generation 7 fracture treatments. The 24-hour initial potential

tests from these three wells averaged approximately 790 BOE per day, including 730 Bbl of oil per day and 380 thousand cubic feet of natural gas per day (92% oil), at flowing surface pressures ranging from 1,900 to 2,750 psi on a 14/64^th inch choke. Matador will also continue to test 40 to 50-acre spacing on its other properties in northwest La Salle County throughout the remainder of 2014. Given the results from its leases in both the central and western portions of the Eagle Ford play thus far, Matador currently expects to develop its remaining acreage in these areas on 40 to 50-acre spacing.

Haynesville Shale Update - Northwest Louisiana

During the first quarter of 2014, Matador was notified by Chesapeake of its intent to drill up to a total of 30 gross (6.3 net) Haynesville wells on Matador’s Elm Grove acreage in southern Caddo Parish, Louisiana during 2014. The Company retains the right to participate for up to a 25% working interest in all wells drilled on this property, with its working interest proportionately reduced to the leasehold position in any individual drilling unit. Chesapeake has been actively drilling on these properties since the second quarter of 2014, and at October 14, 2014, is currently operating three drilling rigs on the properties. On September 8, 2014, Matador reported that Chesapeake had completed and placed on production the first five of these Elm Grove Haynesville wells. In the first week of October, Chesapeake placed another four new Haynesville wells on production, making a total of nine wells on production. Drilling and completion costs for these initial wells have been between $7.0 and $8.0 million. At October 13, 2014, these nine gross wells (2.0 net to Matador) each continue to produce between 8 and 12 million cubic feet (gross) of natural gas per day, representing a total of approximately 17 million cubic feet of natural gas per day net to Matador’s interest. With the addition of these new Haynesville wells in early October, Matador’s natural gas production has risen to approximately 58 million cubic feet of natural gas per day, more than double the Company’s average daily production of 27.4 million cubic feet of natural gas per day during the first quarter of 2014. Matador currently expects eight additional Haynesville wells to be completed and placed on production by Chesapeake later in the fourth quarter. The benefits of this new natural gas production coming on line later in the third quarter and in the fourth quarter of 2014 will be primarily realized in 2015. Matador expects these new Haynesville wells to have rates of return of 60 to 100% or higher, due in part to Matador’s higher net revenue interests (often 85 to 90%) and improved natural gas price realizations on these wells resulting from taking its natural gas production in kind from these wells.

2014 Guidance Affirmation

As previously noted in this press release, Matador today increased its full year 2014 oil production guidance range from the high end of 2.8 to 3.1 million barrels to 3.2 to 3.3 million barrels. Matador reaffirms its remaining full year 2014 guidance as revised upwards on May 6 and May 22, 2014 for (1) estimated capital expenditures of $570 million, (2) estimated natural gas production of 16.0 to 17.5 Bcf (although pointing investors to the middle or lower half of this range), (3) estimated total oil and natural gas revenues of $380 to $400 million and (4) estimated Adjusted EBITDA of $270 to $290 million.

Should oil prices remain in the mid-to-low $80 per barrel range, Matador will be cautious in its spending and anticipates presently that its 2015 capital expenditures could remain relatively flat as compared to 2014, with the Company continuing to rely on only a modest amount of debt to fund any outspend of capital. Even with relatively flat capital expenditures in 2015 and primary reliance on cash flows, Matador would still expect its total oil equivalent (BOE) production to increase by approximately 50% in 2015, particularly as a result of the strong growth in both oil and natural gas production anticipated in the fourth quarter of 2014. As is its practice, Matador will remain alert to economic circumstances and expects to adjust its capital expenditures as the situation requires.

About Matador Resources Company

Matador is an independent energy company engaged in the exploration, development, production and acquisition of oil and natural gas resources in the United States, with an emphasis on oil and natural gas shale and other unconventional plays. Its current operations are focused primarily on the oil and liquids-rich portion of the Eagle Ford shale play in South Texas and the Wolfcamp and Bone Spring plays in the Permian Basin in Southeast New Mexico and West Texas. Matador also operates in the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East Texas. Currently, Matador has two drilling rigs operating in South Texas and two drilling rigs operating in Southeast New Mexico and West Texas.

For more information, visit Matador Resources Company at www.matadorresources.com.

Forward-Looking Statements

This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-looking statements” are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as “could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,” “potential,” “project” and similar expressions that are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but not limited to, the following risks related to financial and operational performance: general economic conditions; the Company’s ability to execute its business plan, including whether its drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; its ability to replace reserves and efficiently develop current reserves; costs of operations; delays and other difficulties related to producing oil, natural gas and natural gas liquids; its ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute its business plan, including from future cash flows, increases in its borrowing base and otherwise; weather and environmental conditions; and other important factors which could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador's SEC filings, including the “Risk Factors” section of Matador's most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. Matador undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this press release, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. All forward-looking statements are qualified in their entirety by this cautionary statement.

Contact Information

Mac Schmitz

Investor Relations

(972) 371-5225

mschmitz@matadorresources.com

EX-99.2

October 2014 Investor Presentation NYSE: MTDR Exhibit 99.2

2 Disclosure Statements Safe Harbor Statement – This presentation and statements made by representatives of Matador Resources Company (“Matador” or the “Company”) during the course of this presentation include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-looking statements” are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as “could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,” “potential,” “project” and similar expressions that are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward- looking statements involve certain risks and uncertainties, including, but not limited to, the following risks related to Matador’s financial and operational performance: general economic conditions; Matador’s ability to execute its business plan, including whether Matador’s drilling program is successful; changes in oil, natural gas and natural gas liquids prices and the demand for oil, natural gas and natural gas liquids; Matador’s ability to replace reserves and efficiently develop its current reserves; Matador’s costs of operations, delays and other difficulties related to producing oil, natural gas and natural gas liquids; Matador’s ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute Matador’s business plan, including from its future cash flows, increases in Matador’s borrowing base and otherwise; weather and environmental conditions; and other important factors which could cause actual results to differ materially from those anticipated or implied in the forward-looking statements. For further discussions of risks and uncertainties, you should refer to Matador’s SEC filings, including the “Risk Factors” section of Matador’s most recent Annual Report on Form 10-K and any subsequent Quarterly Reports on Form 10-Q. Matador undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after the date of this presentation, except as required by law, including the securities laws of the United States and the rules and regulations of the SEC. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. All forward-looking statements are qualified in their entirety by this cautionary statement. Cautionary Note – The Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. Potential resources are not proved, probable or possible reserves. The SEC’s guidelines prohibit Matador from including such information in filings with the SEC. Definitions – Proved oil and natural gas reserves are the estimated quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. Matador’s production and proved reserves are reported in two streams: oil and natural gas, including both dry and liquids-rich natural gas. Where Matador produces liquids-rich natural gas, the economic value of the natural gas liquids associated with the natural gas is included in the estimated wellhead natural gas price on those properties where the natural gas liquids are extracted and sold. Estimated ultimate recovery (EUR) is a measure that by its nature is more speculative than estimates of proved reserves prepared in accordance with SEC definitions and guidelines and is accordingly less certain.

Company Summary

 Founded by Joe Foran in 1983 – most participants are still shareholders today  Foran Oil funded with $270,000 in contributed capital from 17 friends and family members  Sold to Tom Brown, Inc.(1) in June 2003 for an enterprise value of $388 million in an all-cash transaction Foran Oil & Matador Petroleum 4 Matador History Matador Resources Company Timeline Predecessor Entities (1) Tom Brown acquired by Encana in 2004. Matador Today 2003 2008 2003 Founded by Joe Foran with $6 million, a proven management and technical team and board of directors 2008 Sold Haynesville rights in ~9,000 net acres to CHK for ~$180 million; retained 25% participation interest, carried working interest and overriding royalty interest 2010-2011 Redeployed capital into the Eagle Ford early in the play, acquiring over 30,000 net acres for ~$100 million 2012, 2013 and 2014E capital spending focused primarily on developing Eagle Ford and transitioning to oil February 2012 IPO at $12.00; net cash proceeds of ~$136 million May 2014 Follow-on Offering at $25.00; net cash proceeds of ~$181 million September 2013 Follow-on Offering at $15.25; net cash proceeds of ~$142 million 2010 2012 2014 Matador has grown entirely through the drill bit, with focus on unconventional reservoir plays, initially in Cotton Valley and Haynesville Assembling Permian acreage position; begin delineation drilling program

5 Company Overview Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 73.3 million common shares Share Price(2) $19.57/share Market Capitalization(1)(2) $1.4 billion (1) Shares outstanding as reported in the Form 10-Q for the quarter ended June 30, 2014 filed on August 8, 2014. (2) As of October 13, 2014. (3) As reaffirmed on October 14, 2014. The Company guided investors to the middle or lower half of its natural gas guidance range on October 14, 2014. (4) The Company raised its 2014 oil production guidance range from 2.8 to 3.1 million barrels to 3.2 to 3.3 million barrels on October 14, 2014. (5) Estimated 2014 oil and natural gas revenues and Adjusted EBITDA based on production guidance range. Estimated average realized prices for oil and natural gas used in these estimates were $95.00/Bbl and $5.00/Mcf, respectively, for the period July through December 2014. (6) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. 2012 Actual 2013 Actual 2014 Guidance Capital Spending $335 million $374 million $570 million(3) Total Oil Production 1.214 million Bbl 2.133 million Bbl 3.2 to 3.3 million Bbl(4) Total Natural Gas Production 12.5 Bcf 12.9 Bcf 16.0 to 17.5 Bcf(3) Oil and Natural Gas Revenues $156.0 million $269.0 million $380 to $400 million(3)(5) Adjusted EBITDA(6) $115.9 million $191.8 million $270 to $290 million(3)(5)

Matador’s Execution History – “Doing What We Say” Oil Production  414 Bbl/d of oil  6% oil  4,916 Bbl/d of oil  46% oil  ~9,100 Bbl/d of oil(10)  57% oil(10) Proved Reserves  27 MMBOE  1.1 MMBbl of oil  4% oil  39 MMBOE  12.1 MMBbl of oil  31% oil  57 MMBOE  18.6 MMBbl of oil  33% oil PV-10(2)  $155.2 million  24% of PV-10 in Eagle Ford  $522.3 million  90% of PV-10 in Eagle Ford  $826.0 million  72% of PV-10 in Eagle Ford LTM Adjusted EBITDA(3)  $50 million(4)  $148 million  $236 million Acreage  ~7,500 net Permian acres  ~32,900 net Permian acres  ~65,000 net Permian acres(11) Enterprise Value (“EV”)(5)  $0.65 billion(6)  $1.2 billion(8)  $1.7 billion(12) 12x growth in oil production 11x growth in oil reserves ~200% growth Doubled EV Over 4x growth in Permian acres 6 At IPO(1) 2013 Follow-On(7) Over 3x growth in PV-10 (1) Unless otherwise noted, at or for the nine months ended September 30, 2011. (2) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. (3) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. (4) For the twelve months ended December 31, 2011. (5) Enterprise value equals market capitalization plus borrowings under our revolving credit agreement. (6) As of February 7, 2012 at time of IPO. (7) Unless otherwise noted, at or for the three months ended June 30, 2013. (8) As of September 1, 2013. (9) Unless otherwise noted, at or for the three months ended June 30, 2014. (10) For the three months ended September 30, 2014. (11) As of October 1, 2014. (12) As of October 13, 2014. ~85% growth in oil production 54% growth in oil reserves 59% growth ~42% EV growth 98% growth in Permian acres ~60% growth in PV-10 Today(9) Matador continues to execute on its core strategy of acquiring great assets, retaining a best-in-class workforce, maintaining a strong balance sheet and generating significant shareholder returns

Delivering Strong Results 7 Q2 2014 Achievements Oil Production(2) 2014 Capital Budget and Guidance  Oil Production – Company Record!  8,809 Bbl/d; 79% growth versus Q2 2013  Oil & Natural Gas Revenues  $99.1 million; 70% growth versus Q2 2013  Adjusted EBITDA(1)  $69.5 million; 70% growth versus Q2 2013  $570 million capital budget for 2014  Adjusted EBITDA(1) of $270 to $290 million  Oil and natural gas revenues of $380 to $400 million  Estimated oil production of 3.2 to 3.3 million Bbl(2)  Estimated natural gas production of 16.0 to 17.5 Bcf(4) Oil & Natural Gas Revenues(3) Adjusted EBITDA(1)(3) (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. (2) The Company raised its 2014 oil production guidance range from 2.8 to 3.1 million barrels to 3.2 to 3.3 million barrels on October 14, 2014. (3) 2014 estimates at midpoint of guidance range as reaffirmed on October 14, 2014. Estimated average realized prices for oil and natural gas used in these estimates were $95.00/Bbl and $5.00/Mcf, respectively, for the period July through December 2014. (4) The Company guided investors to the middle to lower half of its natural gas guidance range on October 14, 2014. (MBbl) ($ in millions) ($ in millions) 30 33 154 1,214 2,133 3,250 2009 2010 2011 2012 2013 2014E $19 $34 $67 $156 $269 $390 2009 2010 2011 2012 2013 2014E $15 $24 $50 $116 $192 $280 2009 010 2011 2012 2013 2014E

8 Matador Resources Company Overview Market Capitalization(1) $1.4 billion Average Daily Production(2) 16,100 BOE/d Oil (% total) 9,100 Bbl/d (57%) Natural Gas (% total) 41.8 MMcf/d (43%) Proved Reserves @ 6/30/14 57.2 million BOE % Proved Developed 35% % Oil 33% 2014E CapEx $570 million % South Texas ~56% % Permian ~33% % Oil and Liquids ~89% Gross Acreage(3) 242,054 acres Net Acreage(3) 155,179 acres Engineered Drilling Locations(4)(5) 1,112 gross / 570.8 net Eagle Ford 273 gross / 229.3 net Permian 241 gross / 177.7 net Haynesville/Cotton Valley 598 gross / 163.8 net (1) Market capitalization based on shares outstanding as reported in the Form 10-Q for the three months ended June 30, 2014 filed on August 8, 2014 and closing share price as of October 13, 2014. (2) Average daily production for the three months ended September 30, 2014. (3) At October 1, 2014. (4) Presented as of December 31, 2013. (5) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation.

Asset Highlights 9  Currently running a two-rig drilling program (177.7 net drilling locations(1))  ~65,000 net acres(2) in Lea and Eddy Counties, NM and Loving County, TX in the Permian Basin with multi-zone drilling potential  Successful performance of three initial horizontal wells  Ranger 33: Almost 150,000 BOE (91% oil) in eleven months; producing 300 to 350 Bbl/d of oil(3); shallower than expected decline  Dorothy White: Approx. 226,000 BOE in nine months (68% oil); producing 550 Bbl/d of oil and 1.4 MMcf/d of natural gas(3); shallower than expected decline  Rustler Breaks: 86,000 BOE in four months; producing 200 Bbl/d of oil and 1.7 MMcf/d of natural gas(4); shallower than expected decline  Successfully drilled horizontal wells targeting five separate benches  Currently running a two “walking” rig drilling program in South Texas (229.3 net drilling locations(1))  Net oil production of ~7,600 Bbl/d in Q3 2014 (up 14% as compared to Q3 2013)(5)  ~29,200 net acres(6) primarily located in the oil window  Expect batch drilling operations to continue to improve drilling times and costs  Fracture stimulation techniques continue to improve  Gas lift operations adding value and reducing costs  Continuing to acquire new leasehold interests at attractive prices to replace developed acreage and replenish inventory  Encouraging 40 to 50-acre downspacing results  ~25,000 net acres in NW Louisiana and East Texas(6)(7)  ~6,900 net Tier 1 acres in the core of the play with 6 to 12 Bcf EURs  Estimated ROR ranges from 60 to 100% or higher at $4.00 to $4.50/Mcf and above in Elm Grove area  Increased industry activity as a result of higher natural gas prices leading to additional non-operated participation opportunities  Expect up to 56 gross (7.8 net) non- operated wells to be drilled on Matador’s acreage in 2014  Anticipate Chesapeake to drill up to 30 gross (6.3 net) Haynesville wells in Elm Grove area in 2014; nine wells on production in early October  Drilled and tested one of the first Haynesville wells Permian Basin Exploratory and Delineation Program Eagle Ford Shale Development Program Haynesville Shale Natural Gas Bank Applying our Expertise (1) As of December 31, 2013. (2) At October 1, 2014. Includes small amounts of acreage in Reeves, Ward, Howard and Dawson Counties, TX. (3) As of October 14, 2014. (4) As of September 8, 2014. (5) Includes two wells producing small quantities of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. (6) At October 1, 2014. (7) Includes acreage prospective for Cotton Valley.

Keys to Matador’s Success 10  People  We have a strong, committed technical and financial team in place, and we continue to make additions and improvements to our staff, our capabilities and our process  Board and Special Advisor additions have strengthened Board skills and stewardship  Properties  Matador’s acreage positions and multi-year drilling inventory are significant and located in three of the industry’s best plays – Eagle Ford, Permian and Haynesville  Our property mix provides us with a balanced opportunity set for both oil and natural gas  Process  Continuous improvement in all aspects of our business leading to better production and financial results and increased shareholder value  Gaining experience in being a publicly-held company  Execute  Increase oil production from 2.1 million barrels of oil to over 3.2 million barrels of oil  Maintain quality acreage position in the Eagle Ford, Permian and Haynesville  Maintain strong financial position, technical team and approach  Reduce drilling and completion times

Eagle Ford South Texas

2014 South Texas Plan Details 12  2014 projected capital expenditures of ~$318 million or ~56% of total  2-rig program with almost all of the 2014 South Texas capital budget directed to the Eagle Ford shale  Drill and/or complete or participate in 50 gross (47.0 net) wells; 43 gross (40.0 net) wells turned to sales  2014 Eagle Ford program is development drilling, with most locations planned at 40 to 50-acre spacing  No Upper Eagle Ford tests currently planned for 2014  Key objectives of 2014 South Texas plan  Further improvement in operational efficiencies and well performance in the Eagle Ford  Batch drilling with two “walking” rigs to continue reducing drilling times and costs  Continue to improve and optimize stimulation operations – increased fluid and proppant volumes, reduced cluster spacing and increased number of stages, as needed  Continue to optimize artificial lift program – gas lift to rod pump and plunger lift implementations  Reduce LOE throughout all properties  Four solid quarters of LOE improvement  Successful implementation of 40 to 50-acre downspacing across acreage position  Testing 40 to 50-acre spacing at Sickenius, Danysh, Pawelek in Eagle Ford Central and Martin Ranch and Northcut in Eagle Ford West with encouraging results  Continue to add to acreage position as opportunities arise, particularly in and near existing properties  Added 3,100 gross (2,900 net) acres(1) prospective for the Eagle Ford (up to 75 potential well locations) since January 1, 2014, more than replacing current year drilling inventory (1) At October 1, 2014.

13 Eagle Ford Overview (1) At July 30, 2014. Includes two wells producing small volumes of oil from the Austin Chalk formation and two wells producing small quantities of natural gas from the San Miguel formation in Zavala County, Texas. (2) For the twelve months ended December 31, 2011. (3) For the three months ended September 30, 2014. (4) Presented as of December 31, 2013. (5) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. (6) At October 1, 2014. Proved Reserves @ 6/30/14 21.4 million BOE % Proved Developed 59% % Oil 73% Daily Oil Equivalent Production(3) 10,400 BOE/d (73% Oil) Gross Acres(6) 39,243 acres Net Acres(6) 29,165 acres % HBP(4) 82% 2014E CapEx Budget $318 million Engineered Drilling Locations(4)(5) 273 gross (229.3 net) Operations Summary  94 gross (80.6 net) wells(1) producing from the Eagle Ford  An increase in oil production from ~330 Bbl/d(2) in 2011 to ~7,600 Bbl/d(3)  273 gross (229.3 net) engineered drilling locations identified for potential future drilling(4)(5)  2014 South Texas Drilling Plan  Continuing a 2-rig program in the Eagle Ford  All H2 2014 drilling in Eagle Ford Central and West  $318 million CapEx (including facilities, land and seismic)  Drill 50 gross wells (45 operated); complete 45 gross wells (43 operated)  Turn 43 gross wells to sales (38 operated)  Approximately 5 to 10% of yearly production capacity shut-in during 2014; up to 20% at various times

14 Eagle Ford Measured Depths and Well Costs Note: All acreage at October 1, 2014. Some tracts not shown on map. Karnes Uvalde Medina Zavala Frio Dimmit La Salle Webb Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson Matador Resources Acreage San Antonio Glasscock Ranch Martin Ranch Northcut Affleck Troutt Sutton Love Cowey Lewton Hennig Nickel Ranch COMBO LIQUIDS / GAS FAIRWAY DRY GAS FAIRWAY OIL FAIRWAY EAGLE FORD “WEST” Measured Depth: 13,500’ – 14,500’ Well Costs: $6-7 million Testing 40-50 acre spacing EAGLE FORD “EAST” Measured Depth: 17,000’ – 18,000’ Well Costs: $8-10 million 80-acre spacing EAGLE FORD “CENTRAL” Measured Depth: 15,500’ – 16,500’ Well Costs: $7-8 million Testing 40-50 acre spacing EAGLE FORD ACREAGE TOTALS 39,243 gross / 29,165 net acres Harris Newman Pena ZLS Carroll Lloyd Hurt Sojourner Sickenius Lyssy Repka Falls City Pawelek Danysh Bishop-Brogan Campbellton-Haverlah

Overview 15 Operational Improvements (Normalized) Eagle Ford Drilling Costs / Drilled Foot(1) Eagle Ford Completion Costs / Completed Foot(2) West Central East West Central East  Over the past two years, made significant progress and increased knowledge of how to drill, complete and produce Eagle Ford wells  Experience and operational improvements have led to significant reductions in drilling and completion costs  In 2013, began drilling from batch drilled pads using a drilling rig equipped with a “walking” package  Realized cost savings of approx. $325,000 per well on initial wells drilled using this rig  Expect the use of batch drilling and the “walking” rig will lead to total cost savings of approx. $400,000 per well or more going forward Note: “Q1 2014” – As of March 1, 2014. Year classification is based on spud date. (1) Drilled foot is the measured depth from surface to total depth. Excludes any/all wells drilled with a pilot hole, any/all wells drilled outside the West, Central and East and any/all wells drilled with three strings of casing. (2) Completed foot is the completed length of the lateral. Excludes any/all wells drilled with a pilot hole. Excludes any/all wells in the West and Central where premium proppant was used. $1,280 $1,322 2012 2013 $1,132 $908 $845 2011 2012 2013 $1,129 $874 $854 2011 2012 2013 $260 $203 2012 2013 $271 $258 $186 2011 2012 2013 $242 $209 $193 $153 2011 2012 2013 Q1 2014

Gen 2 Gen 3 Gen 4 Gen 5 5,770 Bbl 7,825 Bbl 9,550 Bbl 11,750 Bbl 375 Mlbs 500 Mlbs 405 Mlbs 515 Mlbs 0 ft. 300 ft. 11,750 Bbl 650 Mlbs Gen 6 Evolution of Matador Eagle Ford Frac Design 16 Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal wellbore. (1) Mlbs = thousands of pounds of proppant pumped. Fluid Volume Pumped Proppant Pumped(1) Geometry of the Frac

0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 120,000 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 Cum ula tiv e P ro du cti on (B bl) Time (Days) GEN 2 (80 Acre) GEN 4 (80 Acre) GEN 5 (80 Acre) 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 120,000 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 Cum ula tiv e P ro du cti on (B bl) Time (Days) GEN 2 (80 Acre) GEN 4 (80 Acre) GEN 5 (80 Acre) 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 120,000 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 Cum ula tiv e P ro du cti on (B bl) Time (Days) GEN 2 (80 Acre) GEN 4 (80 Acre) GEN 3 (80 Acre) 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 80,000 90,000 100,000 110,000 120,000 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 320 340 360 Cu mu lati ve Pr od ucti on (B bl) Time (Days) GEN 2 (80 Acre) GEN 5 (40 Acre) GEN 3 (80 Acre) 17 Frac Generation Comparison (all wells normalized to 5,000’ horizontal) EF “CENTRAL” EF “CENTRAL” EF “WEST” EF “WEST”

0 10000 20000 30000 40000 50000 60000 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 C u m u la ti v e Oil P ro d u c tio n ( B b l) Days Online Average 40 Acre (Gen 5-6) Average 80 Acre (Gen 2-4) 0 10000 20000 30000 40000 50000 60000 0 10 20 30 40 50 60 70 80 90 100 110 120 130 140 150 C u m u la ti v e Oil P ro d u c tio n ( B b l) Days Online Average 40 Acre (Gen 5-6) Average 80 Acre (Gen 2-4) 18 Downspacing Comparison (all wells normalized to 5,000’ horizontal) Eagle Ford “CENTRAL” Martin Ranch & Northcut Note: Production is time and lateral length normalized to 5,000’ perforated lateral length. The average 40-acre cumulative production is a combination of actual data and a smoothing trend representing possible future average results.

0 50,000 100,000 150,000 200,000 250,000 300,000 2014 2013 2012 2011 2010 Lateral Feet Drilled 19 La eral Fee Single Well Drilling PAD Drilling BATCH Drilling EXPLORATION DEVELOPMENT 1/3 RIG 2/3 RIG 2 RIGS 1 1/2 RIGS 2 RIGS 60 to 70% increase in Rig Efficiency from 2012 to 2014E! Improvement in Drilling Efficiency – Moving Towards Batch Drilling E

Compressing Drill Times  Improving rig fleet  High tech, fast moving, faster drilling, walking style rigs  Improving Rate of Penetration (ROP)  Bit selection and development  Bottom Hole Assembly (BHA) selection  Rotary steerable systems  Vertical seeking  Directional drilling  Minimize directional work related to surface locations  Utilization of Managed Pressure Drilling  Development Phase  Pre-setting surface casing  Simultaneous operations 20

Progression of Drilling Rig Technology from 2010 to 2014 21 RIG # ELECTRIC 1600 HP PUMPS INTEGRATED TOP DRIVE APEX RIG (FAST MOVE) HYDRAULIC CATWALK AC DRIVE SYSTEM TECHNOLOGY ROUND BOTTOM MUD PITS WALKING PACKAGE BOP HANDLER THREE SHAKERS 521 135   534   203      250        239         279         Advancing Rig Technology

22 Flowing Rod Pumping Gas Lifting 300 Bbl/d 100 Bbl/d Accelerated Production Benefits of Gas Lift • Accelerates production • Reduces LOE • Lower maintenance • Helps wells recover faster from offset fracs Artificial Lift Reducing Natural Production Declines Time Note: Graph and data is for illustrative purposes only and not meant to reflect historical or forecasted data from actual well.

23 Buda Wells Activity Since January 1, 2010 – Potential Test Note: All acreage at October 1, 2014. Well information from public sources available as of August 2014. TX American Resources Buchanan-1H 5/3/2013 14 mo avg: 285 Bbl/d 466 Mcf/d Cum: 119 MBbl 1.9 Bcf Dan A. Hughes Heitz Lease 7 Buda Completions Dec. 2011 – May 2014 Cum: 960 MBbl 1.8 Bcf Crimson Exploration Beeler-6H Spud on 2-13-14 Peak early 24-hr flow back rate of 1,185 BOE/d (91% oil yield) 2 mo avg: 586 Bbl/d 1,091 Mcf/d Cum: 35,180 Bbl 65,473 Mcf Pearsall Field and Pearsall Arch Blackbrush O&G Oppenheimer-101H Comp May 2013 14 mo avg: 137 Bbl/d 376 Mcf/d Cum: 57 MBbl 158,013 Mcf Matador Resources Acreage Trend of Austin Chalk and Buda Production Blackbrush O&G 10 Buda Completions May 2011 – May 2014 Cum: 250 MBbl 1.4 Bcf CML Jessica-1 2 mo avg: 485 Bbl/d 244 Mcf/d Cum: 29,071 Bbl 14,627 Mcf

Permian Basin Southeast New Mexico and West Texas

25  2014 projected capital expenditures of ~$190 million or ~33% of total  Continue 2-rig program working in Lea and Eddy Counties, NM and Loving County, TX  Drill and/or complete or participate in 14 gross (12.3 net) wells; several Wolf area wells drilled with second Permian rig on production in Q4 2014 or early 2015  Completion targets include various Bone Spring and Wolfcamp intervals across acreage position  Initial and recently completed wells exceeding expectations  $80 million allocated to land, seismic and facilities  Key objectives of Permian Basin plan  Further evaluate our acreage position and completion targets to define an expanded development program for 2015 and beyond  Planning to add at least one additional rig at the beginning of 2015  Validate and convert acreage position to held by production (“HBP”)  Leverage and transfer knowledge from Eagle Ford and Haynesville experience to improve operating efficiencies in the Permian Basin  Continue to add to acreage position as opportunities arise, particularly in and near existing properties  Added 27,700 gross (20,200 net) acres (1) in Permian Basin since January 1, 2014  Doubled Loving County acreage position to 11,200 gross (7,200 net) acres (1) 2014 Permian Basin Plan Details (1) At October 1, 2014.

Cumulative Production Current Production Oil Eq. % Oil Natural Gas EUR(2) Well Months (BOE) Oil (Bbl/d) (Mcf/d) (MBOE) Ranger 33 State Com #1H (2nd Bone Spring) 11 150,000 91% 300-350 190 500 Dorothy White #1H (Wolfcamp "A") 9 226,000 68% 550 1,400 1,000 Rustler Breaks 12-24-27 #1H (Wolfcamp "B") 4 86,000 45% 200 1,700 600 Oil Eq. Oil Natural Gas % Pf (3) Choke Well Date (BOE/d) (Bbl/d) (Mcf/d) Oil (psi) (inches) Norton Schaub #1H (Wolfcamp "A") Mid-July 2014 1,026 706 1,922 69% 3,000 22/64th Pickard State 20-18-34 #1H (2nd Bone Spring) Mid-July 2014 592 535 340 90% 750 22/64th Pickard State 20-18-34 #2H Wolfcamp "D") Mid-July 2014 270 232 225 86% 1,150 18/64th Arno #1H (Wolfcamp "A") Mid-Sept 2014 1,110 300 4,900 27% 4,100 26/64th Johnson 44-02S-B53 #204H (Wolfcamp "A") Late Sept 2014 1,286 793 3,000 62% 4,000 24/64th Jim Rolfe 22-18-34 RN State #131Y (3rd Bone Spring) Currently completing. Barnett 90-TTT-B01-WF #2001H (Wolfcamp "A") Currently drilling. Successful performance of first 3 initial horizontal wells(1) Recent activity and 24-hour initial potential tests Current activity  Continue current 2-rig drilling program in Lea and Eddy Counties, NM and Loving County, TX  Added ~20,200 net acres YTD 2014(4) E D D Y L E A LOVING Matador Resources Acreage Location of Matador Well WARD TWIN LAKES 38,982 gross / 27,456 net acres INDIAN DRAW / RUSTLER BREAKS 21,023 gross / 14,785 net acres RANGER / QUERECHO PLAINS 14,875 gross / 10,776 net acres WOLF / LOVING AREA 11,183 gross / 7,155 net acres # 2 4 1 3 7 8 5 10 9 Permian Basin Total Gross Acres 98,440 acres Net Acres 64,982 acres Permian Basin Note: All acreage at October 1, 2014. Some tracts not shown on map. (1) As of October 14, 2014. Rustler Breaks 12-24-27 #1H as of September 8, 2014. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. (3) Flowing surface pressure. (4) At October 1, 2014. 26 1 2 3 4 5 6 7 8 9 10 6

27  New rigs arriving in 2015 have even more advanced technology than current Eagle Ford rigs  Walking packages, hydraulic catwalks, reconfiguration of rig layouts, high pressure circulating systems, etc.  New rig features designed to match drilling plans – i.e. reconfiguration of rig layout allows for simultaneous operations (hydraulic fracturing and drilling operations simultaneously, on same location)  Geosteering capabilities and techniques allowing us to stay within defined target zones  Staying in target window maximizes well productivity and optimizes stimulation consistency  Target windows can be relatively thin within formations – i.e. the “X-Sand” target within the Wolfcamp “A” formation in Loving County, TX  Continuous improvement in frac design  Bigger fracs making better, more economic wells, as compared to earlier offset completions  In particular, Wolfcamp has similar characteristics to Eagle Ford  using larger stimulation designs from the beginning  Frac designs will continue to evolve and improve  Production methods enhancing EURs, flattening declines and accelerating production  Flowing wells on restricted chokes has led to better bottomhole pressure management, keeping wells flowing longer and likely increasing EURs  Applying gas lift assist at optimal time is flattening decline rates and accelerating early production of hydrocarbons  Dorothy White #1H, Ranger 33 State Com #1H and Rustler Breaks 12-24-27 #1H are some of the best wells in their respective areas Technology Transfer and Application from Eagle Ford to Permian

28 Permian Basin Petroleum Systems and the Wolfcamp “Kitchens” DELAWARE BASIN CENTRAL BASIN PLATFORM MIDLAND BASIN Wolfcamp Simpson ~23,000’ Sediment Fill East West Source “Kitchens” Now Unconventional Resource Plays  70,000 square mile area  Up to 25,000 feet of multiple, stacked, petroleum systems  Extensive drilling, coring and geological studies since 1920s  >1,500 conventional reservoirs with cumulative production >1.0 million Bbl each  Cumulative production from 1,500 conventional reservoirs, as of year 2000 (pre- horizontal drilling) >30.0 billion Bbl(1) (1) Dutton et al, AAPG 2005

29 “Wolf-Bone” Geological Setting, Predicting Where the Better Rocks Are 265 mya End of Bone Springs – Warmer! Delaware Basin San Andres Yeso Abo Delaware Mountain Group 1st, 2nd, 3rd Bone Spring Sands Sands confined to channels and distributary systems 1st, 2nd, 3rd Bone Spring Carbonates Wolfcamp “A” Carbonates Wolfcamp “D” Carbonates More limited in areal extent Wolfcamp “A”, “B”, “D” = Oil & Gas Source Rocks and Resource Reservoir Rocks Extensively distributed basin-wide

2014 Wells Drilled Targeting Multiple Benches in Permian Appraisal Program 30 Sand Carbonates (Limestones and Dolomites) Shale/ Mudstone Bone Spring Lime Upper Avalon Shale Lower Avalon Shale First Bone Spring Sand Second Bone Spring Carbonate Second Bone Spring Sand Third Bone Spring Carbonate Wolfcamp “D” Strawn Wolfcamp “A” Wolfcamp “B” Wolfcamp “C” Third Bone Spring Sand GR RES Brushy Canyon Sand Pickard 20-18-34 #2H (IP: 270 BOE/d, 86% oil) Rustler Breaks 12-24-27 #1H (86,000 BOE in 4 mo.(2)) Dorothy White #1H (226,000 BOE in 9 mo.(1)) Ranger 33 State Com #1H (150,000 BOE in 11 mo.(1)) Matador has successfully drilled horizontal wells targeting five separate Bone Spring and Wolfcamp benches Potential Future Targets (1) As of October 14, 2014. (2) As of September 8, 2014 Jim Rolfe 22-18-34 RN #131Y (Currently completing(1))

Wolf / Loving Prospect Area 31  11,183 gross (7,155 net) acres  50 gross (35.4 net) locations(1)  Primary Targets  Wolfcamp “A”  3rd Bone Spring  Avalon  Other Potential Targets  1st Bone Spring  2nd Bone Spring  Wolfcamp “B”  6 wells planned for 2014  Approaching development status Location of Matador wells Note: All Matador acreage information as of October 1, 2014. Not all tracts shown on map. All Matador well information as of October 14, 2014. Other well information from public sources available as of August 2014. (1) Presented as of December 31, 2013. OXY Regan-McElvain #1H Wolfcamp “A” IP: 570 Bbl/d 2.6 MMcf/d 17 mo.cum: 140 MBbl; 357 MMcf Energen Grayling 1-69 #1H and #2H Wolfcamp “A” and “B”, resp. 19 mo.cum: 146 MBbl; 1 Bcf (commingled) Dorothy White #1H Wolfcamp “A” 9 mo.cum: 226,000 BOE (68% oil) Loving Matador Resources Acreage Norton Schaub #1H Wolfcamp “A” IP: 1,026 BOE/d 706 Bbl/d; 1.9 MMcf/d Arno #1H Wolfcamp “A” IP: 1,110 BOE/d 300 Bbl/d; 4.9 MMcf/d Johnson 44-02S-B53 #204H Wolfcamp “A” IP: 1,286 BOE/d 793 Bbl/d; 3.0 MMcf/d Barnett 90-TTT-B01-WF #2001H Wolfcamp “A” Currently drilling

Ranger / Querecho Plains Prospect Area 32  14,875 gross (10,776 net) acres  83 gross (59.6 net) locations(1)  Primary Targets  2nd Bone Spring  3rd Bone Spring  Wolfcamp “A”, “B” and “D”  Other Potential Targets  Delaware  Avalon  1st Bone Spring  Bone Spring Carbonates  3 wells planned for 2014 Location of Matador wells Note: All Matador acreage information as of October 1, 2014. All Matador well information as of October 14, 2014. Other well information from public sources available as of August 2014. (1) Presented as of December 31, 2013. Concho Stratojet 31 State #3H 2nd Bone Spring Sand 33 mo.cum: 402 MBbl; 488 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 34 mo.cum: 353 MBbl; 242 MMcf Ranger 12 State #1 Data Well Ranger 33 State Com #1H 2nd Bone Spring Sand 11 mo.cum: 150,000 BOE (91% oil) Matador Resources Acreage Three Rivers 3rd Bone Spring Eagle 2 State #6H 17 mo.cum: 133 MBbl; 80 MMcf Pickard State 20-18-34 #1H 2nd Bone Spring Sand IP: 592 BOE/d 535 Bbl/d; 340 Mcf/d Pickard State 20-18-34 #2H Wolfcamp “D” IP: 270 BOE/d 232 Bbl/d; 225 Mcf/d Jim Rolfe 22-18-34 RN State #131Y 3rd Bone Spring Sand Currently completing

33  21,023 gross (14,785 net) acres  108 gross (82.8 net) locations(1)  Primary Targets  Wolfcamp “B”  2nd Bone Spring  Delaware  Other Potential Targets  Avalon  1st Bone Spring  3rd Bone Spring  Wolfcamp “A”  4 wells planned for 2014 Indian Draw / Rustler Breaks Prospect Area Location of Matador wells Note: All Matador acreage information as of October 1, 2014. All Matador well information as of September 8, 2014. Other well information from public sources available as of August 2014. (1) Presented as of December 31, 2013. Concho R. Scary Fed #5H 2nd Bone Spring Sand 22 mo.cum: 121 MBbl; 361 MMcf Mewbourne Oil Co. San Lorenzo 15 DM #1H Wolfcamp 19 mo.cum: 68 MBbl; 421 MMcf Mewbourne Oil Co. Layla 35 MD Fee #1H Delaware 18 mo.cum: 156 MBbl; 757 MMcf Devon Energy 8 Drilling Permits Approved 2nd Bone Spring Sand Matador Resources Acreage Rustler Breaks 12-24-27 #1H Wolfcamp “B” 4 mo.cum: 86,000 BOE (45% oil) Mewbourne Oil Co. Malaga 30 MP Fed Com #1H 2nd Bone Spring Sand 8 mo.cum: 59 MBbl; 115 MMcf

Twin Lakes Prospect Area 34  38,982 gross (27,456 net) acres  Primary Targets  Wolfcamp “D”  Strawn  Abo  Other Potential Targets  Cisco/Canyon  Devonian  Glorieta/San Andres  1 vertical well planned for early 2015 − Vertical pilot hole to collect whole core and log data Location of Matador well Note: All acreage at October 1, 2014. Well information from public sources available as of August 2014. Vacuum Field Grayburg/ San Andreas/ABO 690 MMBbl, 1.1 Tcf Maljamar Field Grayburg/San Andreas/Yeso 185 MMBbl, 186 BCF Denton Wolfcamp/Devonian 157 MMBbl, 78 Bcf Lovington West San Andres 27 MMBbl, 45 Bcf Lovington Paddock 74 MMBbl, 35 Bcf Townsend Field Penn/Perm 26 MMBbl, 105 Bcf Saunders Penn/Perm 43 MMBbl, 62 Bcf Dean Penn/Perm 9.5 MMBbl, 6.0 Bcf Caudill Penn/Perm 8.1 MMBbl, 6.0 Bcf Kemnitz Lower Wolfcamp 20 MMBbl, 153 Bcf A A’ Matador Resources Acreage Historical Twin Lakes Area Production 1.3 Billion Barrels Cumulative Oil 2.2 Trillion Cubic Feet Cumulative Natural Gas

Twin Lakes Area Cross Section 35 A TEST VOLUMES: 268 Bbl/d oil 350 Mcf/d gas No water TEST VOLUMES: 118 Bbl/d oil 625 Mcf/d gas 1,155 Bbl/d water Wolfcamp “D” A’ ~400ft

Bone Spring 0 ft. 300 ft. Wolfcamp Matador Permian Basin – First Generation Frac Designs 36 Note: Figure depicts proppant and fluid volume pumped per 300 ft. of horizontal wellbore. (1) Mlbs = thousands of pounds of proppant pumped. 550 Mlbs 600 Mlbs 11,750 Bbl 11,750 Bbl Fluid Volume Pumped Proppant Pumped(1) Geometry of the Frac

Haynesville Shale

2014 Tier 1 Haynesville Shale Plan 38  2014 projected capital expenditures of ~$62 million or about 11% of total  Estimated participation in up to 56 gross (7.8 net) non-operated wells  Chesapeake may drill up to 30 gross (6.3 net to Matador) wells at Elm Grove in 2014; estimated CapEx of $50 million; 3 rigs currently running on Elm Grove properties(1)  Chesapeake recently placed nine wells (2.0 net to Matador) online(1)  Each well producing 8 to 12 MMcf (gross) natural gas per day – total of about 17 MMcf per day net to Matador’s interest  Drilling and completion costs between $7.0 to $8.0 million  2014 capital plan includes no Matador operated Haynesville wells  Haynesville/Cotton Valley acreage in Northwest Louisiana and East Texas is essentially all held by existing production  Operational flexibility to drill operated Haynesville shale well(s) in 2014 should natural gas prices improve sufficiently, but no plans to do so at present time  Completion of natural gas gathering agreement in December 2013 for a portion of our Haynesville natural gas should reduce transportation costs by an average of approximately $0.70 or more per MMBtu in 2014 and increase net gas realizations by the same amount  Haynesville/Cotton Valley continue to represent large “gas bank” providing significant and increasing value as natural gas prices improve above $4.00/Mcf  Highly competitive well economics for Tier 1 Haynesville at $4.00 to $4.50/Mcf and above, with estimated RORs of 60 to 100% or higher in Elm Grove area (1) At October 14, 2014.

Significant Option Value on Natural Gas  Significant acreage position in the Haynesville  Added 3 sections in 2014 to provide more operated drilling opportunities  Also prospective for the Cotton Valley, Travis Peak / Hosston and other shallow formations  Highly competitive well economics on Tier 1 Haynesville wells at $4.00 to $4.50/Mcf and above  Estimated ROR ranges from 60 to 100% or higher in Elm Grove area  Elm Grove natural gas gathering contract should reduce costs an average of approximately $0.70 or more per MMBtu – improved economics  Non-operated drilling activity increasing  CHK may drill up to 30 wells at Elm Grove in 2014; 21 wells already proposed or in progress; 9 wells producing(9)  Other operators continuing activity  Expect up to 7.8 net wells in 2014; production impact in late 3rd and 4th quarters of 2014  Cotton Valley horizontal EURs ~6 Bcf NW Louisiana / East Texas(1) Proved Reserves(2) 187.0 Bcfe Daily Production(3) 3,600 BOE/d (>99% natural gas) Net Acres(4) 25,028 acres Net Producing Wells(5) 77.7 Drilling Locations(6)(7) 163.8 net wells % HBP(6)(8) 97% (1) Includes both Haynesville and Cotton Valley acreage. Includes one well producing from the Frio formation in Orange County, Texas. (2) At June 30, 2014. (3) For the three months ended September 30, 2014. (4) At October 1, 2014. (5) Presented as of June 30, 2014. (6) Presented as of December 31, 2013. (7) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. (8) Acreage held by production or fee mineral interests owned by Matador. (9) As of October 14, 2014. 39 Note: All acreage at October 1, 2014. Matador acreage shown in red. HAYNESVILLE OPERATORS MATADOR CHESAPEAKE ENCANA EXCO GOODRICH - J W PETROHAWK / BHP QUESTAR SAMSON SHELL CADDO BOSSIER BIENVILLE RED RIVER DESOTO Elm Grove Cotton Valley: 49 Net Locations Matador Operated Acreage: 9,992 gross, 9,802 net Locations(6)(7): 71 gross, 49.3 net Tier 1 Haynesville: 63.6 Net Locations Acreage: 13,721 gross, 6,888 net Locations(6)(7): 452 gross, 63.6 net MTDR CV Horizontal T. Walker #1H MTDR Haynesville L.A. Wildlife #1H MTDR Haynesville Williams (BLM) #1H TIER 1: 6 – 10+ Bcf TIER 2: 4 – 6 Bcf TIER 3: 2 – 4 Bcf Elm Grove Area

0 25 50 75 100 125 150 175 200 225 250 275 300 $3.00 $3.50 $4.00 $4.50 $5.00 $5.50 $6.00 Es tim at ed R at e of R et ur n, % Natural Gas Price, $/Mcf 10 Bcf - $7.0mm D&C Cost 10 Bcf - $8.0mm D&C Cost 10 Bcf - $9.0mm D&C Cost 8 Bcf - $7.0mm D&C Cost 8 Bcf - $8.0mm D&C Cost 8 Bcf - $9.0mm D&C Cost Elm Grove Tier 1 Haynesville – Chesapeake Operated 40 Note: Individual well economics only. Excludes costs prior to drilling (i.e. acquisition or acreage costs). Economics use a NRI / WI of 85% but actual interests vary. Natural gas price differential = ($0.55)/Mcf. D&C cost = drilling and completion cost. Matador’s Advantaged Economics - NRI’s of 85% to 90% on many properties due to ORRI’s - Improved pricing/differentials due to taking gas in kind - Longer laterals and better completion techniques

2014 Capital Investment Plan

42 Summary and 2014 Guidance  Continue 4-rig program full-time in 2H 2014 – 2 rigs in the Eagle Ford and 2 rigs in the Permian  Eagle Ford development expected to be the major driver of our growth in 2014  Permian drilling program designed to further evaluate our acreage position and define an expanded development plan for 2015 and beyond 2012 Actual 2013 Actual 2014 Guidance Capital Spending $335 million $374 million $570 million(1) Total Oil Production 1.214 million Bbl 2.133 million Bbl 3.2 to 3.3 million Bbl(2) Total Natural Gas Production 12.5 Bcf 12.9 Bcf 16.0 to 17.5 Bcf(1) Oil and Natural Gas Revenues $156.0 million $269.0 million $380 to $400 million(1)(3) Adjusted EBITDA(4) $115.9 million $191.8 million $270 to $290 million(1)(3) (1) As reaffirmed on October 14, 2014. The Company guided investors to the middle to lower half of its natural gas guidance range on October 14, 2014. (2) The Company raised its 2014 oil production guidance range from 2.8 to 3.1 million barrels to 3.2 to 3.3 million barrels on October 14, 2014. (3) Estimated 2014 oil and natural gas revenues and Adjusted EBITDA based on production guidance range. Estimated average realized prices for oil and natural gas used in these estimates were $95.00/Bbl and $5.00/Mcf, respectively, for the period July through December 2014. (4) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix.

43 2014 Capital Investment Plan Summary  Continue 4-rig program full time in H2 2014: 2 rigs in the Eagle Ford and 2 rigs in the Permian  2014E capital expenditures of $570 million  Eagle Ford development expected to be the major driver of our growth in 2014 with growing Permian contribution  Permian drilling program designed to further evaluate our acreage position and define an expanded development plan for 2015 and beyond  Haynesville development assumes increased participation in non-operated wells 2014E CapEx by Region 2014E CapEx by Expense Type Haynesville Non-Op / Other $62 million 10.9% Permian $190 million 33.3% Eagle Ford $318 million 55.8% Land, Seismic, Etc. (Discretionary) $80 million 14.0% Facilities, Infrastructure, Etc. $20 million 3.5% Drilling and Completions $470 million 82.5% 2014E CapEx: $570 million

Funding for 2014 Capital Investment Plan 44  Anticipate funding 2014 capital expenditures through proceeds from May 2014 equity offering, operating cash flows and borrowings under revolving credit facility  0.7 million barrels of oil hedged for remainder of 2014, protecting cash flows below ~$88/Bbl oil price  2.2 Bcf of natural gas hedged for remainder of 2014, protecting cash flows below ~$3.50/MMBtu gas price  Simple capital structure  Strong liquidity position with Debt/LTM Adjusted EBITDA(1) ~1.1x  Increased borrowing capacity to $450 million with recent borrowing base determination  Flexibility to manage liquidity  Most drilling is operated; low non-operated drilling obligations  $80 million estimated for discretionary land/seismic acquisitions  Limited long-term drilling rig or service contract commitments (1) Assumes borrowings outstanding of approximately $250 million on October 14, 2014 and LTM Adjusted EBITDA of $236 million at June 30, 2014. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix.

45 Investment Highlights Strong Growth Profile with Increasing Focus on Oil / Liquids  YE2011 to 2014E oil production CAGR of ~176%(1) with expected year-over-year growth of ~52%(1) in 2014  ~89% of 2014E CapEx program focused on oil / liquids exploration and development High Quality Asset Base in Attractive Areas(2)  ~65,000 net acres in the Permian Basin prospective for the liquids-rich Wolfcamp, Bone Spring and other targets  ~29,200 net acres in the Eagle Ford in some of the most active counties in South Texas, including Atascosa, DeWitt, Gonzales, Karnes, La Salle, Wilson and Zavala Counties  Long-term option on natural gas with Haynesville, Cotton Valley and Bossier assets almost all HBP Multi-year Drilling Inventory(3)(4)  177.7 net drilling locations in the Permian Basin with escalating activity to de-risk the play; anticipate significant increase in locations with further delineation drilling  229.3 net drilling locations in the Eagle Ford  163.8 net drilling locations in the Haynesville and Cotton Valley Low Cost Operations  Substantially reduced Eagle Ford drilling days and well costs since IPO  Batch drilling program and other improvements have potential to further reduce well costs and improve spud to sales times Strong Financial Position  Low leverage(5) of ~1.1x allows for operational flexibility  Liquidity available to execute planned drilling program Proven Management and Technical Team and Active Board of Directors  Management and senior technical team average over 25 years of industry experience  Board with extensive industry knowledge, business experience and company ownership  Strong record of stewardship (1) Represents the growth to the midpoint of 2014 oil production guidance of 3.2 to 3.3 million barrels. (2) At October 1, 2014. (3) Presented as of December 31, 2013. (4) Identified and engineered Tier 1 and Tier 2 locations identified for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. (5) Assumes borrowings outstanding of approximately $250 million on October 14, 2014 and LTM Adjusted EBITDA of $236 million at June 30, 2014. Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix.

Appendix

 Strong, supportive bank group led by RBC  Borrowing base at $450 million, based on July 31, 2014 reserves, increased from $385 million based on December 31, 2013 reserves, and increased from $125 million at time of IPO in February 2012  Borrowings outstanding of $250 million at October 14, 2014  Ability to request quarterly borrowing base increases with growth in oil and natural gas reserves throughout 2015, as needed  Financial covenants  Maximum Total Debt to Adjusted EBITDA(1) Ratio of not more than 4.25:1.00  No Current Ratio test TIER Conforming Borrowing Base Utilization LIBOR Margin BASE Margin Commitment Fee Tier One x < 25% 150 bps 50 bps 37.5 bps Ti r T o 25% < or = x < 50% 175 bps 75 bps 37.5 bps Tier Three 50% < or = x < 75% 200 bps 100 bps 50 bps Tier Four 75% < or = x < 90% 225 bps 125 bps 50 bps Tier Five 90% < or = x < 100% 250 bps 150 bps 50 bps Tier Six 100% < or = x < 110% 300 bps 200 bps 50 bps Tier Seven x = or > 110% 375 bps 275 bps 50 bps 47 Credit Agreement Status (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix.

48 SEC Proved Reserves Value Growth By Area Eagle Ford $467.2 million, 89% Permian $2.9 million, 1% June 30, 2014 PV-10(1): $826.0 million $96.75 oil(2), $4.10 natural gas(2) (Standardized Measure = $723.0 million) (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. (2) Oil prices in $/Bbl; natural gas prices in $/MMBtu. Eagle Ford $540.4 million, 82% Haynesville/CV $82.9 million, 13% Permian $31.9 million, 5% December 31, 2013 PV-10(1): $655.2 million $93.42 oil(2), $3.67 natural gas(2) (Standardized Measure = $578.7 million) June 30, 2013 PV-10(1): $522.3 million $88.13 oil(2), $3.44 natural gas(2) (Standardized Measure = $477.6 million) Eagle Ford $595.6 million, 72% Haynesville/CV $147.3 million, 18% Permian $83.1 million, 10% Haynesville/CV $52.2 million, 10%

$0.47 $0.83 $1.57 $2.89 $4.58 $5.55 2009 2010 2011 2012 2013 2014E $1.75 $2.92 $5.82 $7.84 $11.15 2009 2010 2011 2012 2013 $0.38 $0.58 $1.17 $2.15 $3.26 $3.99 2009 2010 2011 2012 2013 2014E Matador Provides Growth on a Per Share(1) Basis 49 Oil and Natural Gas Revenues(4) per Share ($ per share) PV-10(2) per Share ($ per share) Adjusted EBITDA(3)(4) per Share ($ per share) (1) Weighted Average Basic Shares Outstanding. Value for 2014E assumes no shares issued for remainder of 2014. (2) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. (3) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. (4) 2014 estimates at midpoint of guidance range reaffirmed on October 14, 2014. Estimated average realized prices for oil and natural gas used in these estimates were $95.00/Bbl and $5.00/Mcf, respectively, for the period July through December 2014. (in thousands) Shares (1) PV-10 (2) Adj. EBITDA (3)(4) Oil & Natural Gas Revenues (4) 2009 40,123 $70,359 $15,184 $19,039 2010 41,037 $119,869 $23,635 $34,042 2011 42,718 $248,700 $49,911 $67,000 2012 53,957 $423,200 $115,923 $155,998 2013 58,777 $655,200 $191,771 $269,030 2014E 70,218 $280,000 $390,000

$18.4 $15.2 $23.6 $49.9 $115.9 $191.8 2008 2009 2010 2011 2012 2013 $30.6 $19.0 $34.0 $67.0 $156.0 $269.0 2008 2009 2010 2011 2012 2013 7% 4% 2% 6% 37% 50% 2008 2009 2010 2011 2012 2013 1.5 2.3 3.9 7.0 9.0 11.7 2008 2009 2010 2011 2012 2013 Matador’s Continued Growth Average Daily Production (MBOE/d) Oil Production Mix (% of Average Daily Production) Oil & Natural Gas Revenues ($ in millions) Adjusted EBITDA(1) ($ in millions) 50 Growth since IPO Growth since IPO Growth since IPO Growth since IPO (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix.

84 485 729 908 1,225 1,463 1,787 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E Semi-Annual Performance Metrics Through 2014 Oil Production (Bbl in thousands) Oil Equivalent Production (BOE in thousands) Oil and Natural Gas Revenues ($ in millions) Adjusted EBITDA(1) ($ in millions) (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net (loss) income and net cash provided by operating activities, see Appendix. (2) 2H 2014E values are estimated based on the midpoint of 2014 guidance for each metric as confirmed on October 14, 2014. (3) 2H 2014E value is estimated based on the midpoint of 2014 projections of 5.9 to 6.0 million BOE, as disclosed on October 14, 2014. (2) $32.4 $65.2 $90.8 $117.5 $151.5 $178.0 $212.0 2H 2011 1H 2012 2H 2012 1H 2013 2H 2013 1H 2014 2H 2014E $24.4 $49.3 $66.7 $81.5 $110.3 $125.8 $154.2 2H 011 1H 201 2H 01 1H 2013 2H 2013 1H 2014 2H 2014E 1,277 1,525 1,768 1,944 2,341 2,475 3,475 2H 011 1H 20 2H 01 1H 2013 2H 2013 1H 2014 2H 2014E (3) (2) (2) 51

52 MTDR Trading versus BOE/d Production since IPO Note: Matador closing share price through October 13, 2014. 0 2,500 5,000 7,500 10,000 12,500 15,000 17,500 20,000 $0.00 $4.00 $8.00 $12.00 $16.00 $20.00 $24.00 $28.00 $32.00 IPO 3/ 31 /2 01 2 6/ 30 /2 01 2 9/ 30 /2 01 2 12 /3 1/ 20 12 3/ 31 /2 01 3 6/ 30 /2 01 3 9/ 30 /2 01 3 12 /3 1/ 20 13 3/ 31 /2 01 4 6/ 30 /2 01 4 To da y Dail y O il E qu ivalen t P ro du cti on , BO E/ d MT DR Cl os ing Pric e BOE/d MTDR

53 MTDR Trading versus PV-10 Growth since IPO $0.0 $100.0 $200.0 $300.0 $400.0 $500.0 $600.0 $700.0 $800.0 $900.0 $0.00 $4.00 $8.00 $12.00 $16.00 $20.00 $24.00 $28.00 $32.00 IPO 3/3 1/2 01 2 6/3 0/2 01 2 9/3 0/2 01 2 12 /31 /20 12 3/3 1/2 01 3 6/3 0/2 01 3 9/3 0/2 01 3 12 /31 /20 13 3/3 1/2 01 4 6/3 0/2 01 4 To da y PV -10, $ i n mi llio ns MT DR Cl os ing Pric e PV-10 MTDR Note: Matador closing share price through October 13, 2014.

54 MTDR Trading versus Growing Permian Acreage since IPO 0 10,000 20,000 30,000 40,000 50,000 60,000 70,000 $0.00 $4.00 $8.00 $12.00 $16.00 $20.00 $24.00 $28.00 $32.00 Per mia n Acr eage Po siti on , N et Acr es MT DR Cl os ing Pric e MTDR Permian Net Acreage Note: Matador closing share price through October 13, 2014.

55 Hedging Profile – Hedges in Place for Remainder of 2014 and 2015 At October 14, 2014, Matador had:  0.7 million barrels of oil hedged for remainder of 2014 at weighted average floor and ceiling of $88/Bbl and $99/Bbl, respectively  2.2 Bcf of natural gas hedged for remainder of 2014 at weighted average floor and ceiling of $3.50/MMBtu and $4.93/MMBtu, respectively  1.9 million gallons of natural gas liquids hedged for remainder of 2014 at weighted average price of $1.25/gal  1.7 million barrels of oil, 9.0 Bcf of natural gas and 3.8 million gallons of natural gas liquids hedged for 2015 Note: Hedged volumes shown in table for 2014 are for remainder of 2014. Oil Hedges (Costless Collars) 2014 2015 Total Volume Hedged by Ceiling 663,800 Bbl 1,680,000 Bbl Weighted Average Price $98.95 /Bbl $99.75 /Bbl Total Volume Hedged by Floor 663,800 Bbl 1,680,000 Bbl Weighted Average Price $87.82 /Bbl $83.00 /Bbl Natural Gas Hedges (Costless Collars) 2014 2015 Total Volume Hedged by Ceiling 2.2 Bcf 9.0 Bcf Weighted Average Price $4.93 /MMBtu $4.79 /MMBtu Total Volume Hedged by Floor 2.2 Bcf 9.0 Bcf Weighted Average Price $3.50 /MMBtu $3.77 /MMBtu Natural Gas Liquids (NGLs) Hedges (Swaps) 2014 2015 Total Volume Hedged 1,911,000 gal 3,816,000 gal Weighted Average Price $1.25 /gal $1.02 /gal

Board of Directors and Special Advisors – Expertise and Stewardship 56 Board Members Professional Experience Business Expertise David M. Laney Lead Director - Past Chairman, Amtrak Board of Directors - Former Partner, Jackson Walker LLP Law and Investments Reynald A. Baribault Director - Vice President / Engineering and Co-founder, North Plains Energy, LLC - President and CEO, IPR Energy Partners, LLC - Former Vice President, Netherland, Sewell & Associates, Inc. Oil and Gas Exploration Gregory E. Mitchell Director - President and CEO, Toot’n Totum Food Stores Petroleum Retailing Dr. Steven W. Ohnimus Director - Retired Vice President and General Manager, Unocal Indonesia Oil and Gas Operations Michael C. Ryan Director - Partner, Berens Capital Management International Business and Finance Carlos M. Sepulveda, Jr. Director - Chairman of the Board, Triumph Bancorp, Inc. - Retired President and CEO, Interstate Battery System International, Inc. - Director and Audit Chair, Cinemark Holdings, Inc. Business and Finance Margaret B. Shannon Director - Retired Vice President and General Counsel, BJ Services Co. - Former Partner, Andrews Kurth LLP Law and Corporate Governance Special Board Advisors Professional Experience Business Expertise Marlan W. Downey Special Board Advisor - Retired President, ARCO International - Former President, Shell Pecten International - Past President of American Association of Petroleum Geologists Oil and Gas Exploration Wade I. Massad Special Board Advisor - Managing Member, Cleveland Capital Management, LLC - Former Executive Vice President – Capital Markets, Matador Resources Company - Formerly with KeyBanc Capital Markets and RBC Capital Markets Capital Markets Edward R. Scott, Jr. Special Board Advisor - Former Chairman, Amarillo Economic Development Corporation - Law Firm of Gibson, Ochsner & Adkins Law, Accounting and Real Estate Development W.J. “Jack” Sleeper, Jr. Special Board Advisor - Retired President, DeGolyer and MacNaughton (Worldwide Petroleum Consultants) Oil and Gas Executive Management

Proven Management Team – Experienced Leadership 57 Management Team Background and Prior Affiliations Industry Experience Matador Experience Joseph Wm. Foran Founder, Chairman and CEO - Matador Petroleum Corporation, Foran Oil Company and James Cleo Thompson Jr. 33 years Since Inception Matthew V. Hairford President - Samson, Sonat, Conoco 29 years Since 2004 David E. Lancaster EVP, COO and CFO - Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 34 years Since 2003 David F. Nicklin Executive Director of Exploration - ARCO, Senior Geological Assignments in UK, Norway, Indonesia, China and the Middle East 42 years Since 2007 Craig N. Adams EVP – Land & Legal - Baker Botts L.L.P., Thompson & Knight LLP 21 years Since 2012 Ryan C. London VP and General Manager - Matador Resources Company (Began as intern) 10 years Since 2004 Bradley M. Robinson VP and CTO - Schlumberger, S.A. Holditch & Associates, Inc., Marathon 36 years Since Inception Billy E. Goodwin VP of Drilling - Samson, Conoco 29 years Since 2010 William F. McMann VP of Production & Facilities - Independent Consultant, Wagner Oil Company, Denbury Resources 28 years Since 2011 Van H. Singleton, II VP of Land - Southern Escrow & Title, VanBrannon & Associates 17 years Since 2007 G. Gregg Krug VP of Marketing - Williams Companies, Samson, Unit Corporation 30 years Since 2005 Sandra K. Fendley VP and CAO - J-W Midstream, Crosstex Energy 22 years Since 2013 Kathryn L. Wayne Controller and Treasurer - Matador Petroleum Corporation, Mobil 29 years Since Inception

12.0 15.8 13.8 10.9 7.6 6.7 7.9 10.1 10.6 13.5 17.6 14.4 15.3 20.6 0.0 6.0 12.0 18.0 24.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 58 Oil Production and Revenues Through Q2 2014 Average Daily Natural Gas Production (MMcf/d) Natural Gas Revenues ($ in mm) Oil Revenues ($ in mm) Average Daily Oil Production (Bbl/d) All-time high oil production in Q2 Q2 increase with NM, non-op production Reflects increased production and better pricing All-time high oil revenues in Q2 209 563 465 448 2,200 3,130 3,291 4,630 5,115 4,916 6,703 6,612 7,344 8,809 0 1,500 3,000 4,500 6,000 7,500 9,000 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 1.7 5.1 3.7 4.0 21.5 29.4 30.1 42.6 48.7 44.6 64.2 55.3 63.7 78.5 0.0 20.0 40.0 60.0 80.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 36.5 44.6 38.8 39.0 34.8 33.7 33.7 34.5 33.7 33.7 40.2 32.1 27.4 39.7 0.0 10.0 20.0 30.0 40.0 50.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14

6,300 8,004 6,931 6,953 8,023 8,738 8,838 10,385 10,897 10,582 13,482 11,968 11,904 15,424 0 1,500 3,000 4,500 6,000 7,500 9,000 10,500 12,000 13,500 15,000 16,500 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 59 Quarterly Performance Metrics Through Q2 2014 Oil and Natural Gas Revenues ($ in mm) Total Realized Revenues ($ in mm) Adjusted EBITDA(1) ($ in mm) Average Daily Equivalent Production (BOE/d) 10 to 15% shut-in at times during Q2 All-time high in Q2 All-time high in Q2 $49.9 $74.1 $67.0 (1) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA and a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. $13.7 $20.9 $17.4 $15.0 $29.2 $36.1 $38.0 $52.7 $59.3 $57.7 $81.9 $69.7 $78.9 $99.1 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 $10.1 $15.3 $12.1 $12.4 $21.3 $27.9 $28.6 $38.0 $40.7 $40.8 $61.5 $48.8 $56.3 $69.5 $0.0 $10.0 $20.0 $30. $40.0 $50.0 $60.0 $70.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 $15.5 $21.8 $18.9 $17.9 $32.2 $40.8 $41.4 $55.6 $59.7 $58.4 $80.7 $69.3 $77.1 $96.1 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14

$2.2 9 $2. 27 $2. 90 $2. 31 $2. 95 $3. 29 $3. 47 $4. 26 $4 .18 $4. 62 $5. 29 $5. 33 $5. 61 $6. 50 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 60 Quarterly Expense Metrics Through Q2 2014 Lease Operating (per BOE) General and Administrative (per BOE) Depletion, Depreciation and Amortization (per BOE) Production Taxes and Marketing (per BOE) Reflects growth in oil production/revenues; some quarter-specific items Another solid LOE quarter in Q2 DD&A remains steady G&A down on per BOE basis $2. 83 $2. 70 $3. 24 $2. 51 $6. 36 $8 .02 $7. 98 $1 1.1 7 $11 .11 $10 .53 $6. 91 $8. 28 $8. 73 $8. 34 $0.00 $2.00 $4.00 $6.00 $8.00 $10.00 $12.00 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14$12 .54 $11 .23 $11 .43 $14 .34 $15 .35 $25 .04 $26 .66 $2 8.9 5 $28 .79 $2 1.0 1 $21 .06 $21 .62 $22 .43 $22 .66 $0.00 $5.00 $10.00 $15.00 $2 .00 5.00 .00 $35.00 1Q11 2Q11 3Q11 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 $4.6 2 $4. 25 $6. 60 $5. 43 $5. 19 $5 .15 $4. 23 $3. 37 $4.6 9 $4. 31 $4. 35 $6. 02 $6. 74 $5. 77 $0.00 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 $8.00 1Q11 2Q11 3Q11 4Q11 Q12 2Q1 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14

61 PV-10 Reconciliation 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 the Company's properties. Matador 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. PV-10 may be reconciled to the Standardized Measure of discounted future net cash flows at such dates by reducing PV-10 by the discounted future income taxes associated with such reserves. At December 31, 2009 At December 31, 2010 At September 30, 2011 At December 31, 2011 At March 31, 2012 At June 30, 2012 At September 30, 2012 PV-10 (in millions) $70.4 $119.9 $155.2 $248.7 $329.6 $303.4 $363.6 Discounted Future Income Taxes (in millions) $(5.3) $(8.8) $(11.8) $(33.2) $(42.2) $(21.9) $(29.7) Standardized Measure (in millions) $65.1 $111.1 $143.4 $215.5 $287.4 $281.5 $333.9 At December 31, 2012 At March 31, 2013 At June 30, 2013 At September 30, 2013 At December 31, 2013 At March 31, 2014 At June 30, 2014 PV-10 (in millions) $423.2 $438.1 $522.3 $538.6 $655.2 $739.8 $826.0 Discounted Future Income Taxes (in millions) $(28.6) $(31.1) $(44.7) $(52.5) $(76.5) $(86.2) $(103.0) Standardized Measure (in millions) $394.6 $407.0 $477.6 $486.1 $578.7 $653.6 $723.0

62 Adjusted EBITDA Reconciliation This investor presentation includes the non-GAAP financial measure of Adjusted EBITDA. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. “GAAP” means Generally Accepted Accounting Principles in the United States of America. The Company believes Adjusted EBITDA helps it evaluate its operating performance and compare its results of operations from period to period without regard to its financing methods or capital structure. The Company defines Adjusted EBITDA as earnings before interest expense, income taxes, depletion, depreciation and amortization, accretion of asset retirement obligations, property impairments, unrealized derivative gains and losses, certain other non-cash items and non- cash stock-based compensation expense, and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income (loss) or net cash provided by operating activities as determined by GAAP. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income (loss) or net cash provided by operating activities as determined in accordance with GAAP or as an indicator of the Company’s 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. 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 the calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively, that are of a historical nature. Where references are forward-looking or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliation without undue hardship because the forward-looking Adjusted EBITDA numbers included in this investor presentation are estimations, approximations and/or ranges. In addition, it would be difficult for the Company to present a detailed reconciliation on account of many unknown variables for the reconciling items.

63 Adjusted EBITDA Reconciliation 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. Note: LTM is last 12 months LTM at LTM at (In thousands) 2008 2009 2010 2011 2012 2013 6/30/2013 6/30/2014 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): Net income (loss) $103,878 ($14,425) $6,377 ($10,309) ($33,261) $45,094 ($20,771) $70,068 Interest expense - - 3 683 1,002 5,687 3,574 5,819 Total income tax (benefit) provision 20,023 (9,925) 3,521 (5,521) (1,430) 9,697 (703) 29,789 Depletion, depreciation and amortization 12,127 10,743 15,596 31,754 80,454 98,395 97,801 105,756 Accretion of asset retirement obligations 92 137 155 209 256 348 307 428 Full-cost ceiling impairment 22,195 25,244 - 35,673 63,475 21,229 51,499 - Unrealized loss (gain) on derivatives (3,592) 2,375 (3,139) (5,138) 4,802 7,232 13,945 18,275 Stock-based compensation expense 665 656 898 2,406 140 3,897 1,836 6,002 Net (gain) loss on asset sales and inventory impairment (136,977) 379 224 154 485 192 617 - Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $148,105 $236,137 LTM at LTM at I thousands) 2008 2009 2010 2011 2012 2013 6/30/2013 6/30/2014 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $25,851 $1,791 $27,273 $61,868 $124,228 $179,470 $156,614 $209,033 Net change in operating assets and liabilities (17,888) 15,717 (2,230) (12,594) (9,307) 6,210 (12,161) 18,145 Interest expense - - 3 683 1,002 5,687 3,574 5,819 Current income tax (benefit) provision 10,448 (2,324) (1,411) (46) - 404 78 3,140 Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $148,105 $236,137 Year Ended December 31, Year Ended December 31,

64 Adjusted EBITDA Reconciliation 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. (In thousands) 1Q 2011 2Q 2011 3Q 2011 4Q 2011 1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 Unaudited Adjusted EBITDA reconciliation to Net (Loss) Income: Net (loss) income $ (27,596) $ 7,153 $ 6,194 $ 3,941 $ 3,801 $ (6,676) $ (9,197) $ (21,188) $ (15,505) $ 25,119 $ 20,105 $ 15,374 $ 16,363 $ 18,226 Interest expense 106 184 171 222 308 1 144 549 1,271 1,609 2,038 768 1,396 1,616 Total income tax provision (benefit) (6,906) (46) - 1,430 3,064 (3,713) (593) (188) 46 32 2,563 7,056 9,536 10,634 Depletion, depreciation and amortization 7,111 8,180 7,287 9,176 11,205 19,914 21,680 27,655 28,232 20,234 26,127 23,802 24,030 31,797 Accretion of asset retirement obligations 39 57 62 51 53 58 59 86 81 80 86 100 117 123 Full-cost ceiling impairment 35,673 - - - - 33,205 3,596 26,674 21,230 - - - - - Unrealized (gain) loss on derivatives 1,668 (332) (2,870) (3,604) 3,270 (15,114) 12,993 3,653 4,825 (7,526) 9,327 606 3,108 5,234 Stock-based compensation expense 53 128 1,234 991 (363) 191 (51) 363 492 1,032 1,239 1,134 1,795 1,834 Net loss on asset sales and inventory impairment - - - 154 - 60 - 425 - 192 - - - - Adjusted EBITDA $ 10,148 $ 15,324 $ 12,078 $ 12,361 $ 21,338 $ 27,926 $ 28,631 $ 38,029 $ 40,672 $ 40,772 $ 61,485 $ 48,840 $ 56,345 $ 69,464 I th sa s) 1Q 2011 2Q 2011 3Q 2011 4Q 2011 1Q 2012 2Q 2012 3Q 2012 4Q 2012 1Q 2013 2Q 2013 3Q 2013 4Q 2013 1Q 2014 2Q 2014 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $ 12,732 $ 6,799 $ 14,912 $ 27,425 $ 5,110 $ 46,416 $ 28,799 $ 43,903 $ 32,229 $ 51,684 $ 43,280 $ 52,278 $ 31,945 $ 81,530 Net change in operating assets and liabilities (2,690) 8,386 (3,004) (15,286) 15,920 (18,491) (500) (6,235) 7,126 (12,553) 15,265 (3,630) 21,729 (15,221) Interest expense 106 184 171 222 308 1 144 549 1,271 1,609 2,038 768 1,396 1,616 Current income tax (benefit) provision - (45) (1) - - - 188 (188) 46 32 902 (576) 1,275 1,539 Adjusted EBITDA $ 10,148 $ 15,324 $ 12,078 $ 12,361 $ 21,338 $ 27,926 $ 28,631 $ 38,029 $ 40,672 $ 40,772 $ 61,485 $ 48,840 $ 56,345 $ 69,464

65 Adjusted EBITDA Reconciliation 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. (In thousands) 12/31/2011 6/30/2012 12/31/2012 6/30/2013 12/31/2013 6/30/2014 Unaudited Adjusted EBITDA reconciliation to Net (Loss) Income: Net (loss) income 10,135$ (2,875)$ (30,385)$ 9,615$ 35,479$ 34,589$ Interest expense 393 309 693 2,881 2,806 3,012 Total income tax (benefit) provision 1,430 (649) (781) 78 9,619 20,170 Depletion, depreciation and amortization 16,463 31,119 49,335 48,466 49,929 55,827 Accretion of asset retirement obligations 113 111 145 162 186 241 Full-cost ceiling impairment 0 33,205 30,270 21,229 - - Unrealized loss (gain) on derivatives (6,474) (11,844) 16,646 (2,701) 9,933 8,342 Stock-based compensation expense 2,225 (172) 312 1,524 2,373 3,629 Net loss on asset sales and inventory impairment 154 60 425 192 - - Adjusted EBITDA 24,439$ 49,264$ 66,660$ 81,446$ 110,325$ 125,810$ (In thousands) 12/31/2011 6/30/2012 12/31/2012 6/30/2013 12/31/2013 6/30/2014 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities 42,337$ 51,526$ 72,702$ 83,912$ 95,558$ 113,475$ Net change in operating assets and liabilities (18,290) (2,571) (6,735) (5,425) 11,635 6,509 Interest expense 393 309 693 2,881 2,806 3,012 Current income tax provision (benefit) (1) - - 78 326 2,814 Adjusted EBITDA 24,439$ 49,264$ 66,660$ 81,446$ 110,325$ 125,810$ Six Months Ended Six Months Ended