UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
_________________________________
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) February 3, 2016
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Matador Resources Company
(Exact name of registrant as specified in its charter)
_________________________________
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)
_________________________________
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 February 3, 2016, announcing its 2015 proved oil and natural gas reserves and 2016 capital budget and guidance. The Press Release is incorporated by reference into this Item 2.02, and the foregoing description of the Press Release is qualified in its entirety by reference to this exhibit.
The Company is hosting an Analyst Day event on February 3, 2016 at which it intends to make a presentation concerning its 2016 capital investment plan and current operations. The materials to be utilized during the presentation (the “Materials”) are furnished as Exhibit 99.2 hereto and incorporated herein by reference.
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 Press Release and 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 Press Release and 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 Press Release and 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 February 3, 2016. | ||
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: February 3, 2016 | 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 February 3, 2016. | ||
99.2 | Presentation Materials. | ||
Exhibit 99.1
MATADOR RESOURCES COMPANY ANNOUNCES
YEAR-END 2015 RESERVES AND 2016 CAPITAL BUDGET
DALLAS, February 3, 2016 – 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 Delaware Basin operations in Southeast New Mexico and West Texas, today announced its 2015 year-end reserves and its 2016 capital budget and operating plan.
Year-End 2015 Proved Oil and Natural Gas Reserves
Matador is pleased to announce its proved oil and natural gas reserves were 85.1 million barrels of oil equivalent (“BOE”) at December 31, 2015, an all-time high for the Company and a 24% increase from 68.7 million BOE at December 31, 2014. The present value, discounted at 10%, of the estimated future net cash flows before income taxes (“PV-10”) of Matador’s total proved oil and natural gas reserves at December 31, 2015 was $541.6 million, as compared to a PV-10 of $1.04 billion at December 31, 2014, a 48% year-over-year decrease resulting from declines in oil and natural gas prices between the two periods. At December 31, 2015, Matador’s proved oil and natural gas reserves were 40% proved developed reserves, as compared to 45% at December 31, 2014.
For the year ended December 31, 2015, Matador’s proved oil and natural gas reserves were estimated using an average oil price of $46.79 per barrel and an average natural gas price of $2.59 per million British Thermal Unit (“MMBtu”), a decrease of 49% and 40%, respectively, as compared to an average oil price of $91.48 per barrel and an average natural gas price of $4.35 per MMBtu used to estimate Matador’s proved reserves for the year ended December 31, 2014.
Proved oil reserves increased 89% to 45.6 million barrels at December 31, 2015, as compared to 24.2 million barrels at December 31, 2014. Including Matador’s 2015 total oil production of approximately 4.5 million barrels, Matador effectively doubled its proved oil reserves year-over-year, despite an almost 50% year-over-year decline in the oil price required to be used to estimate proved oil reserves at December 31, 2015. Matador’s proved oil reserves in the Delaware Basin increased almost four-fold to 31.4 million barrels at December 31, 2015, as compared to 8.1 million barrels at December 31, 2014, resulting from the Company’s ongoing drilling and completion operations in the Delaware Basin. Proved oil reserves comprised 54% of the Company’s total proved reserves at December 31, 2015, as compared to 35% at December 31, 2014.
Proved natural gas reserves decreased 11% to 236.9 billion cubic feet at December 31, 2015, as compared to 267.1 billion cubic feet at December 31, 2014. The decline in year-over-year natural gas reserves resulted principally from the reclassification of proved undeveloped natural gas reserves to contingent resources, primarily in the Haynesville shale, as a result of the decline in natural gas prices during 2015. As long as the leasehold acreage associated with these previously classified proved undeveloped natural gas reserves is held by production from existing Haynesville wells, however, these natural gas volumes remain available to be developed by Matador or the operator at a future time should natural gas prices improve, drilling and completion costs decline or new technologies be developed that increase expected recoveries.
Matador’s natural gas reserves comprised 46% of Matador’s total proved reserves at December 31, 2015, as compared to 65% at December 31, 2014.
2016 Capital Budget, Operating Plan and Guidance
Matador is also pleased to announce its 2016 capital budget, operating plan and guidance. The Company’s 2016 capital budget is based on running three operated drilling rigs in the Delaware Basin throughout 2016, although Matador will consider reducing its Delaware Basin program to two operated drilling rigs as early as the second quarter of 2016 should oil prices drop back and remain below $30 per barrel.
Key elements of the Company’s 2016 capital budget, operating plan and guidance include the following:
• | 2016 capital budget of $325 million, including $260 million for drilling, completions, facilities and infrastructure costs, $40 million for midstream activities in the Delaware Basin and $25 million for discretionary land and seismic data; |
• | 2016 oil production guidance of 4.9 to 5.1 million barrels, an increase of approximately 11% from 2015 actual oil production of 4.5 million barrels to the midpoint of 2016 production guidance; |
• | 2016 natural gas production guidance of 26.0 to 28.0 billion cubic feet, a decrease of approximately 3% from 2015 actual natural gas production of 27.7 billion cubic feet to the midpoint of 2016 production guidance; |
• | 2016 total oil equivalent production guidance of 9.2 to 9.8 million BOE, an increase of approximately 4% from 2015 actual oil equivalent production of 9.1 million BOE to the midpoint of 2016 production guidance; and |
• | 2016 Adjusted EBITDA guidance of $120 to $130 million, a decrease of approximately 44% from estimated 2015 Adjusted EBITDA of $220 to $225 million (final number pending completion of 2015 audited financial statements) based on estimated average realized prices for 2016 of $34.00 per barrel for oil (West Texas Intermediate oil price of $37.00 per barrel less $3.00 per barrel, based on the forward strip for oil prices in late January 2016) and $2.37 per thousand cubic feet for natural gas (NYMEX Henry Hub natural gas price, based on the forward strip for natural gas prices in late January 2016 and assuming regional differentials and uplifts from natural gas processing roughly offset). These estimated 2016 realized prices compare to estimated 2015 realized oil and natural gas prices received of $45.27 per barrel and $2.71 per thousand cubic feet, respectively. |
Analyst Day Details
Management plans to provide its detailed 2016 operational plan, capital budget and forecasts, plus an update on its ongoing operations and continued improvements in each of its Delaware Basin focus areas, at the Company’s Analyst Day scheduled to be held on Wednesday, February 3, 2016 at 9:00 a.m. Central Time in the Fort Worth Ballroom at the Westin Galleria Dallas hotel, 13340 Dallas Pkwy, Dallas, Texas 75240. The presentation will conclude with a question and
answer session for those in attendance. Individuals who are unable to attend in person can participate in the live conference call or via virtual webcast. Following the presentation, lunch will be provided.
To access the Analyst Day conference call in a listen-only mode, domestic participants should dial (855) 875-8781 and international participants should dial (720) 634-2925. The participant passcode is 25027629. To access the virtual webcast, participants should use the following link: http://edge.media-server.com/m/p/gsoor954. All details can be accessed through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab.
A replay of the Analyst Day conference call will be made available through Friday, February 26, 2016 via webcast. A link to the replay webcast will be available through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab.
A copy of the Company’s Analyst Day presentation will be available prior to the event through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab.
Analyst Day Follow-up Conference Call
Management also plans to host a live follow-up conference call at 3:30 p.m. Central Time on Wednesday, February 3, 2016 following the Company’s Analyst Day presentation for anyone who has additional questions. To access the conference call, domestic participants should dial (855) 875-8781 and international participants should dial (720) 634-2925. The participant passcode is 25505768. To access the virtual webcast, participants should use the following link: http://edge.media-server.com/m/p/bshpb4om. All details can be accessed through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab.
A replay of the Analyst Day follow-up conference call will be made available through Friday, February 26, 2016 via webcast. A link to the replay webcast will be available through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab.
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 Wolfcamp and Bone Spring plays in the Delaware Basin in Southeast New Mexico and West Texas. Matador also operates in the Eagle Ford shale play in South Texas and the Haynesville shale and Cotton Valley plays in Northwest Louisiana and East 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,” “hypothetical,” “forecasted” 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; its ability to integrate acquisitions, including the HEYCO merger; 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.
Adjusted EBITDA
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, including stock option and grant expense and restricted stock and restricted stock units expense and net gain or loss on asset sales and inventory impairment. Adjusted EBITDA is not a measure of net income or cash flows as determined by GAAP. Adjusted EBITDA is a supplemental non-GAAP financial measure that is used by management and external users of consolidated financial statements, such as industry analysts, investors, lenders and rating agencies. “GAAP” means Generally Accepted Accounting Principles in the United States of America.
Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of 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. References in this press release to Adjusted EBITDA are pro forma, forward-looking, preliminary or prospective in nature, and not based on historical fact. The Company could not provide reconciliations of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively, without undue hardship because the Adjusted EBITDA numbers included in this press release are estimations, approximations or ranges. In addition, it would be difficult for us to present a detailed reconciliation on account of many unknown variables for the reconciling items.
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 our 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. The PV-10 at December 31, 2014 may be reconciled to the Standardized Measure of discounted future net cash flows at such date by reducing PV-10 by the discounted future income taxes associated with such reserves. The PV-10 value at December 31, 2014 was $1.04 billion and the discounted future income taxes at December 31, 2014 were $130.1 million.
We have not provided a reconciliation of PV-10 to Standardized Measure at December 31, 2015. We could not provide such a reconciliation without undue hardship because we have not completed the audit of our December 31, 2015 financial statements. In addition, it would be difficult for us to present a detailed reconciliation on account of many unknown variables for the reconciling items.
Contact Information
Mac Schmitz
Investor Relations
(972) 371-5225
mschmitz@matadorresources.com
February 3, 2016 2016 Analyst Day Presentation NYSE: MTDR Managing 2016... 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,” “hypothetical,” “forecasted,” 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 integrate the assets, employees and operations of Harvey E. Yates Company following its merger with one of Matador’s wholly-owned subsidiaries on February 27, 2015; Matador’s ability to make other 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. Estimated 2015 Results – Estimated 2015 results included herein are estimated at February 3, 2016 and subject to adjustments pending completion and release of the Company’s 2015 audited financial statements. 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. Type curves shown in this presentation are used to compare actual well performance to a range of potential production results calculated without regard to economic conditions; actual recoveries may vary from these type curves based on individual well performance and economic conditions.
Welcome and Opening Remarks Joseph Wm. Foran – Chairman and CEO
4 Today’s Agenda Welcome and Opening Remarks Joseph Wm. Foran, Chairman and CEO 2015 Summary and 2016 Capital Investment Plan David E. Lancaster, Executive Vice President and CFO Morning Break Delaware Basin Operations Update Matthew V. Hairford, President David E. Lancaster, Executive Vice President and CFO Midstream Operations and 2016 Plans Matthew V. Hairford, President Matthew D. Spicer, Vice President and General Manager of Midstream Summary and Closing Remarks; Question and Answer Session Joseph Wm. Foran, Chairman and CEO Operating Committee Members Lunch Austin Ballroom Afternoon Conference Call – 3:30 pm Central Time
5 Managing 2016 – The Elephants in the Room Today Continue with 3 rigs or drop a rig? Outspend? How to fund outspend? Maximizing shareholder value in a challenging environment?
Matador Has Made Tremendous Progress Since its IPO At IPO(1): February 7, 2012 Today(2) Difference Oil Production 414 Bbl/d (6% oil) 11,547 Bbl/d (49% oil) Proved Reserves 27 MMBOE (4% oil) 85 MMBOE (54% oil) Proved Oil Reserves 1.1 MMBbl 45.6 MMBbl Delaware Acreage ~7,500 net acres ~88,900 net acres(3) Leverage(4) 1.5x(5) 1.5x Share Price $12.00(6) $16.03(6) (1) Unless otherwise noted, at or for the nine months ended September 30, 2011. (2) Unless otherwise noted, at or for the three months ended December 31, 2015. (3) As of January 7, 2016. (4) Calculated as net debt divided by LTM Adjusted EBITDA. Net debt is equal to debt outstanding less available cash (including $43 million of restricted cash held in escrow at December 31, 2015). 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. (5) At December 31, 2011. (6) As of February 7, 2012 at time of IPO. (7) Closing share price as of January 29, 2016. 6 +28-fold +3-fold +41-fold +12-fold Flat +34%
Attractive Wolfcamp Economics – Yesterday, Today and in the Future 7 Note: Oil price is West Texas Intermediate. Natural gas price is Henry Hub. Differentials to these base prices applied to al l cases. Well costs reflect estimated drilling, completions, production and facilities costs for typical development wells in Q1 2016. Q1 2016* is based upon projected hypothetical oil prices of $30-$40/Bbl in 2016, $50/Bbl in 2017 and $60/Bbl in 2018 and years thereafter, and $2.50/Mcf for natural gas. Such prices are for illustrative purposes only and are not intended to represent the Company’s actual forecasts or expectations. 0% 20% 40% 60% 80% 100% 120% 140% 160% 180% 200% 220% 240% Wolfcamp A 1,000 MBOE (70% Oil) Wolfcamp B 1,000 MBOE (45% Oil) Rat e O f Re turn Q4 2014 - $75 oil $3.50 natural gas, $11.0 million average cost per well Q1 2016 - $35 oil $2.50 natural gas, $6.0 - $6.5 million average cost per well Q1 2016* - $30-$40 oil (2016), $50 oil (2017), $60 oil (2018…) Return to - $75 oil $3.50 natural gas, $8.5 million average cost per well Q4 2014 Q1 2016 Q1 2016 Q1 2016* Q1 2016* Return to $75 oil with 35% cost increase Return to $75 oil with 35% cost increase Q4 2014 (Loving County, TX) (Eddy County, NM)
29 32 35 39 43 47 49 53 56 60 64 69 20 30 40 50 60 70 80 800 840 880 920 960 1000 ROR, % EUR, MBOE $35/Bbl WTI Oil Price Increasing Oil Price Model 20 30 40 50 60 70 80 $5.0 $5.2 $5.4 $5.6 $5.8 $6.0 ROR, % Well Cost, millions $35/Bbl WTI Oil Price Increasing Oil Price Model ROR Relationship to Well Cost(1) Savings and Improved EUR(2) Every $100,000 saved increases ROR by 2% on average 8 Increasing Oil Price Model Year $30 1st 6 mo. 2016 $40 2nd 6 mo. 2016 $50 2017 $60 2018 for life Assumes $2.50/Mcf natural gas (1) Estimated well costs for a development well in Q1 2016, including drilling, completion, production and facilities costs. (2) Estimated ultimate recovery, thousands of barrels of oil equivalent. Every 5% increase in EUR increases ROR by 4% on average Better Costs Better Wells Rustler Breaks Wolfcamp A-X/Y $6.0 million Well Cost
2015 Summary and 2016 Capital Investment Plan David E. Lancaster – Executive Vice President and CFO
Matador Resources Company – Operations Overview Market Capitalization(1) ~$1.4 billion Avg Daily Production – YE 2015(2) 24,955 BOE/d Oil (% total) 12,306 Bbl/d (49%) Natural Gas (% total) 75.9 MMcf/d (51%) Proved Reserves @ 12/31/2015 85.1 million BOE % Proved Developed 40% % Oil 54% 2016E CapEx(3) $325 million % Delaware Basin ~97% Gross Acreage(4) ~223,700 acres Net Acreage(4) ~142,000 acres Engineered Drilling Locations(5) 4,313 gross / 1,804 net Delaware Basin 3,543 gross / 1,417 net Eagle Ford 260 gross / 228 net Haynesville/Cotton Valley 510 gross / 159 net * Note: Represents increase as compared to each respective figure at or for the year ended December 31, 2014. (1) Market capitalization based on closing share price as of January 29, 2016 and shares outstanding at December 31, 2015 as reported to the NYSE. (2) Average daily production for the twelve months ended December 31, 2015. (3) 2016 estimated capital expenditures, including all anticipated operations, midstream and land expenditures as of February 3, 2016, assuming a 3-rig program in the Delaware Basin in 2016. (4) As of January 7, 2016. Excludes ~75,700 gross (~35,700 net) acres still under lease in Wyoming, Utah and Idaho. (5) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2015, but including no locations at Twin Lakes. Includes all identified locations where Matador has an operated or non-operated working interest. 10 33% of total production Almost no oil 64% of total natural gas 41% of total production 62% of total oil 21% of total natural gas 26% of total production 38% of total oil 15% of total natural gas 55%* 24%* 48%* 32%*
Delaware Basin Inventory Continues to Increase Matador has identified up to 3,543 gross (1,417 net) potential locations(1) for future drilling on its Delaware Basin acreage Only 118 gross (72.3 net) locations are PUD locations at December 31, 2015 Matador anticipates operating up to 2,263 gross (1,284 net) of these potential locations(2) Inventory does not yet include any locations for Twin Lakes prospect area Formation Gross Net Delaware Group 276 100 Avalon 322 144 1st Bone Spring 556 177 2nd Bone Spring 657 243 3rd Bone Spring 489 203 Wolfcamp A-XY 280 122 Lower Wolfcamp A 339 164 Wolfcamp B 275 123 Wolfcamp D 349 140 TOTAL 3,543 1,417 11 Gross Net 178 90 233 136 290 152 381 215 325 186 187 111 256 154 191 113 222 126 2,263 1,284 Potential Matador Operated Locations(1)(2) Total Locations Identified(1)(3) (1) At December 31, 2015. (2) Includes any identified locations in which Matador’s working interest is at least 25%. (3) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2015, but including no locations at Twin Lakes. Includes all identified locations where Matador has an operated or non-operated working interest.
Despite Low Commodity Prices, 2015 Was an Excellent Year for Matador 12 Four key transactions improved our asset base and kept our balance sheet strong HEYCO merger in February 2015 added approximately 60,000 gross (20,000 net) acres in the Delaware Basin(1) Initial non-operated well results across acreage have been very encouraging Inaugural offering of $400 million in public bonds in April 2015 Follow-on equity offering in April 2015 7 million shares sold raising approximately $189 million Combined bond and equity transactions raised almost $600 million in capital to strengthen balance sheet Sold certain Loving County, Texas midstream assets to EnLink for ~$143 million(2) Further strengthened balance sheet and reduced debt levels to among the best in the industry for small- and mid-cap E&P companies Matador begins 2016 from a position of strength – excellent properties, proven Board and staff and strong financial position (1) Including additional acreage acquired through subsequent joint ventures with affiliates of HEYCO. (2) Excluding customary purchase price adjustments.
39.8 34.1 35.4 41.9 75.9 2011 2012 2013 2014 2015 422 3,317 5,843 9,095 12,306 2011 2012 3 2014 2015 Average Daily Oil Production (Bbl/d) Average Daily Natural Gas Production (MMcf/d) Average Daily Total Production (MBOE/d) Oil Production Mix (% of Average Daily Production) 13 Growth since IPO Growth since IPO Growth since IPO Growth since IPO Oil production up 35% YOY. Gas production up 81% YOY. BOE production up 55% YOY. Record Oil, Natural Gas and Total Production in 2015 6% 37% 50% 57% 49% 2011 2012 2013 2014 2015 7.0 9.0 11.7 16.1 25.0 2011 2012 2013 4 5
14 Matador’s Reserves Volumes at an All-Time High at Year-End 2015 Eagle Ford $540.4 million, 82% Haynesville/CV $82.9 million, 13% Delaware Basin $31.9 million, 5% YE 2013 51.7 million BOE 16.4 million Bbl oil (32% oil) PV-10(1): $655.2 million $93.42 oil / $3.67 gas 68.7 million BOE 24.2 million Bbl oil (35% oil) PV-10(1): $1,043.4 million $91.48 oil / $4.35 gas YE 2014 85.1 million BOE 45.6 million Bbl oil (54% oil) PV-10(1): $541.6 million $46.79 oil / $2.59 gas YE 2015 24% 89% 40% 49% 48% Eagle Ford $603.8 million, 58% Haynesville/CV $193.4 million, 18% Delaware Basin $246.2 million, 24% Eagle Ford $175.1 million, 32% Haynesville/CV $51.9 million, 10% Delaware Basin $314.5 million, 58% Note: Oil and natural gas prices noted are in $/Bbl and $/MMBtu, respectively. Prices reflect the arithmetic average of first-day-of-month oil and natural gas prices for the 12-month periods January 1 to December 31, 2013, 2014 and 2015, respectively, as per SEC guidelines for reserves estimation. (1) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix.
0.0x 0.0x 0.1x 1.5x 0.2x 0.7x 1.1x 1.3x 1.5x 1.6x 0.8x 1.0x 1.2x 0.6x 1.0x 1.3x 1.6x 1.4x 1.6x 1.5x 2008 2009 2010 2011 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 3Q14 4Q14 1Q15 2Q15 3Q15 4Q15 Net Debt / LTM EBITDA $76 $240 $256 $416 $340 In it ia l P u b lic O ff e ri n g Preserved and enhanced liquidity through April 2015 equity and Senior Notes offerings and sale of certain Loving County midstream assets for ~$143 million(1) in October 2015 – substantial liquidity to execute planned drilling program throughout 2016 Strong financial position with YE 2015 Net Debt/LTM Adjusted EBITDA(2)(3) of ~1.5x, well below peer average Committed to Maintaining Strong Balance Sheet 15 (4) E q u it y R a is e E q u it y R a is e N o te s O ff e ri n g + E q u it y R a is e (2)(3) Net Debt ($ millions) M id s tr e a m S a le (1) Excluding customary purchase price adjustments. (2) 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. (3) Net Debt is equal to debt outstanding less available cash (including $43 million of restricted cash held in escrow at December 31, 2015). (4) 4Q15 LTM Adjusted EBITDA and Net Debt are estimated at February 3, 2016 and subject to adjustment pending completion and release of 2015 audited financial statements.
84% 83% 79% 73% 71% 47% 42% 22% 21% 19% 14% 11% 8% Peer H Peer G Peer F Peer A Peer D Peer C Peer E Peer J Peer I Peer L MTDR Peer B Peer K 7.2x 5.2x 5.2x 4.5x 3.3x 3.2x 2.9x 2.8x 2.4x 2.0x 1.9x 1.9x 1.6x Peer I Peer K Peer J MTDR Peer B Peer C Peer A Peer E Peer L Peer G Peer H Peer F Peer D 4.8x 3.1x 3.0x 2.7x 2.5x 2.3x 2.0x 2.0x 1.7x 1.4x 1.0x 0.9x 0.9x Peer F Peer D Peer H Peer C Peer E Peer G Peer A Peer B Peer L Peer J MTDR Peer K Peer I $9.82 $9.30 $7.75 $7.75 $7.54 $5.41 $5.26 $4.85 $4.34 $3.80 $3.34 $2.63 $2.47 Peer F Peer D Peer E Peer H Peer G Peer C Peer L Peer A Peer B Peer K MTDR Peer J Peer I Strong Balance Sheet Metrics Relative to Peers(1) 16 Q3 2015 Net Debt / Proved Reserves ($ / BOE) Q3 2015 Net Debt / LTM Adjusted EBITDA(2) Proved PV-10(3) / Q3 2015 Net Debt Q3 2015 Net Debt / Enterprise Value(4) Average: $5.91 Average: 2.3x Average: 3.3x Average: 46.6% (1) Market analysis prepared by RBC Capital Markets. Average does not include Matador. Matador net debt figures are pro forma at September 30, 2015 for midstream sale on October 1, 2015. Peer group chosen by RBC includes BCEI, CRZO, CWEI, EGN, EPE, FANG, LPI, PDCE, PE, RSPP, SM, SN. Source: Company filings, metrics pro forma for announced acquisitions, capital markets transactions and divestitures. Market data as of January 29, 2016. (2) 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. (3) PV-10 is a non-GAAP financial measure. For a reconciliation of Standardized Measure (GAAP) to PV-10 (non-GAAP), see Appendix. (4) Enterprise value equals market capitalization plus net debt outstanding.
17 2015 Anticipated Results vs. 2015 Guidance (As Updated Nov. 4, 2015) Exchange: Ticker NYSE: MTDR Shares Outstanding(1) 85.6 million common shares Share Price(1) $16.03/share Market Capitalization(1) $1.4 billion Actual Original Updated Estimated % 2014 2015 Guidance 2015 Guidance(2) 2015 Results(3) Change Capital Spending $610 million $350 million $425 million ~$480 million(4) - 21% Total Oil Production 3.3 million Bbl 4.0 to 4.2 million Bbl 4.4 to 4.5 million Bbl 4.5 million Bbl + 35% Total Natural Gas Production 15.3 Bcf 24.0 to 26.0 Bcf 27.0 to 28.0 Bcf 27.7 Bcf + 81% Oil and Natural Gas Revenues $367.7 million $270 to $290 million $290 to $300 million(5) ~$275 to $280 million - 24% Adjusted EBITDA(6) $262.9 million $200 to $220 million $220 to $230 million(5) ~$220 to $225 million - 15% (1) Market capitalization based on closing share price as of January 29, 2016 and shares outstanding at December 31, 2015 as reported to the NYSE. (2) The Company raised certain of its full-year 2015 guidance estimates on August 4 and November 4, 2015. (3) Estimated 2015 financial results are estimated at February 3, 2016 and subject to adjustment pending completion and release of 2015 audited financial statements. (4) For operations only. Does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. (5) Oil and natural gas revenues and Adjusted EBITDA based upon the midpoint of 2015 guidance range as revised on November 4, 2015 and actual production results through October 31, 2015. Prices for oil and natural gas used in these estimates were $50.00/Bbl (WTI oil price of $55.00/Bbl less $5.00/Bbl differentials and transportation costs) and $3.00/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period October through December 2015 and weighted average realized prices for the period January through September 2015 of $47.36/Bbl and $2.83/Mcf. (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.
We will keep the focus on our Delaware Basin assets and opportunities with the intent of creating and preserving long-term shareholder value Plan to run 3 rigs in 2016, but will consider dropping to 2 rigs as early as Q2 2016 if oil prices drop back and remain below $30 per barrel Continue to improve drilling and completion efficiencies, lower costs, improve well recoveries and returns and upgrade our acreage position Continue to invest in Delaware midstream assets, particularly the cryogenic natural gas processing plant and gathering assets we are building in the Rustler Breaks prospect area in Eddy County, NM 18 2016 Capital Investment Plan – Summary N u m b e r o f O p e rate d Ri g s Ranger/Arrowhead Rustler Breaks Wolf Delaware Basin: 3-Rig Case
We will keep the focus on our Delaware Basin assets and opportunities with the intent of creating and preserving long-term shareholder value Plan to run 3 rigs in 2016, but will consider dropping to 2 rigs as early as Q2 2016 if oil prices drop back and remain below $30 per barrel Continue to improve drilling and completion efficiencies, lower costs, improve well recoveries and returns and upgrade our acreage position Continue to invest in Delaware midstream assets, particularly the cryogenic natural gas processing plant and gathering assets we are building in the Rustler Breaks prospect area in Eddy County, NM 19 2016 Capital Investment Plan – Summary N u m b e r o f O p e rate d Ri g s Delaware Basin: 2-Rig Case Rustler Breaks Wolf
20 We estimate our capital budget in 2016 to be approximately $325 million for the 3-rig case (down 32% from 2015(1)), declining to $277 million for the 2-rig case (down 42% from 2015(1)) We expect to have sufficient liquidity to fund our 2016 capital investments - ~$60 million in cash and $375 million in undrawn revolving credit facility at December 31, 2015 2016 Capital Investment Plan – Summary 21% 2014 CapEx $610 million 2015 CapEx 2016E CapEx – 3-Rig Scenario 3 Delaware Basin rigs throughout 2016 ~$480 million(1) $325 million Land, Seismic, Etc. $91 million 15% Drilling, Completions, Facilities & Infrastructure $507 million 83% Midstream Activities $12 million 2% Land, Seismic, Etc. ~$54 million 11% Drilling, Completions, Facilities & Infrastructure ~$352 million 74% Midstream Activities ~$74 million 15% Land, Seismic, Etc. $25 million 8% Drilling, Completions, Facilities & Infrastructure $260 million 80% Midstream Activities $40 million 12% 32% (1) For operations only. Does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. 2015 CapEx and related components are estimated at February 3, 2016 and are subject to adjustment pending the completion and release of 2015 audited financial statements.
21 We expect to grow oil production by about 11% and keep natural gas production close to flat; total BOE production growth of about 4% in the 3-rig program as compared to 2015 We expect to outspend cash flow by ~$205 million (2-rig) to ~$230 million (3-rig) in 2016, including outspend associated with midstream and land, but anticipate funding most or all of this outspend without incurring significant additional debt by year-end We anticipate funding most or all of this outspend through a combination of: Additional operational efficiencies and cost savings Improved well performance Potential rise in oil and natural gas prices throughout the year Certain asset sales, including midstream assets and other non-strategic properties Joint ventures and creative land deals Additional equity, as and if needed Additional borrowings under our undrawn credit facility 2016 Capital Investment Plan – Summary
Matador’s 2016 Delaware Basin Operated Drilling Plan: 3-Rig Case 22 Note: All acreage at January 7, 2016. Some tracts not shown on map. L E A LOVING WARD TWIN LAKES ~42,300 gross / ~29,900 net acres WOLF / LOVING AREA ~12,200 gross / ~7,500 net acres Jackson Trust RANGER ~32,500 gross / ~19,400 net acres ARROWHEAD ~47,400 gross / ~16,900 net acres E D D Y RUSTLER BREAKS ~21,200 gross / ~13,600 net acres Wolf/Loving Area − 21 gross (18.4 net) wells planned for 2016 − 17 gross (15.2 net) wells on production, including 14 Wolfcamp A-XY, 1 Wolfcamp A-Lower and 2 2nd Bone Spring wells Rustler Breaks − 20 gross (16.1 net) wells planned for 2016 − 18 gross (14.5 net) wells on production, including 8 Wolfcamp A-XY and 10 Wolfcamp B wells Ranger/Arrowhead − 7 gross (4.9 net) wells planned for 2016 − 5 gross (3.9 net) wells on production, including 2 2nd Bone Spring and 3 3rd Bone Spring wells Twin Lakes − 1 gross (1.0 net) well planned for 2016 and on production − Initial Wolfcamp D horizontal well Total 3-Rig Program − 49 gross (40.4 net) wells planned for 2016 − 41 gross (34.6 net) wells on production, including 34 Wolfcamp wells and 7 Bone Spring wells 17 # Matador Resources Acreage Gross wells on production in 2016 18 5 1
2015 Drilled, 2016 Anticipated Completion(1) 2016 Anticipated Drilling & Completion 2016 Anticipated Drilling, 2017 Anticipated Completion(2) 2016 Anticipated First Sales(2) 2016E CapEx Gross Wells(3) Net Wells(3) Gross Wells(3) Net Wells(3) Gross Wells(3) Net Wells(3) Gross Wells(3) Net Wells(3) (in millions) Delaware Basin Operated Activity Operated Activity - 3 Rig Scenario - - 41 34.6 8 5.8 41 34.6 $246.6 75.9% Operated Activity - 2 Rig Scenario - - 33 28.2 6 4.8 33 28.2 $198.6 Non-Operated Activity 5 0.7 8 1.2 - - 13 1.9 $5.4 1.7% Midstream Activities - - - - - - - - $40.0 12.3% Land/Seismic/Etc. - - - - - - - - $23.0 7.1% Area Total 3 Rig Scenario 5 0.7 49 35.8 8 5.8 54 36.5 $315.0 96.9% 2 Rig Scenario 5 0.7 41 29.4 6 4.8 46 30.1 $267.0 Eagle Ford Non-Operated Activity 2 0.0 - - - - 2 0.0 $0.1 0.0% Facilities/Pipelines/Etc. - - - - - - - - $3.5 1.1% Land/Seismic/Etc. - - - - - - - - $2.0 0.6% Area Total 2 0.0 - - - - 2 0.0 $5.6 1.7% Haynesville / Cotton Valley Haynesville Non-Op Activity 12 2.0 5 0.6 - - 17 2.6 $4.4 1.4% Total - 3 Rig Scenario 19 2.7 54 36.4 8 5.8 73 39.1 $325.0 100.0% Total - 2 Rig Scenario 19 2.7 46 30.0 6 4.8 65 32.7 $277.0 23 Detail of 2016E Capital Expenditures (1) A portion of the CapEx associated with some of these wells was incurred in 2015, as some wells were waiting on completion or were already being completed at December 31, 2015. (2) Some wells drilled in late 2016 will not be completed and turned to sales until early 2017. As a result, they do not contribute to our estimated oil and natural gas production volumes for 2016. (3) Includes Matador operated and non-operated wells. 97% of our 2016 capital investments directed toward the Delaware Basin
0 40 80 120 160 200 240 30 35 40 45 50 55 60 R O R, % WTI Oil Price, $/Bbl Rustler Breaks - Wolfcamp A-X/Y (85% oil) 800 MBOE, $5.0 MM 800 MBOE, $6.0 MM 600 MBOE, $5.0 MM 600 MBOE, $6.0 MM 24 0 50 100 150 200 250 300 30 35 40 45 50 55 60 R O R, % WTI Oil Price, $/Bbl Wolf - Wolfcamp A-X/Y (70% oil) 1,000 MBOE, $5.5 MM 1,000 MBOE, $6.5 MM 700 MBOE, $5.5 MM 700 MBOE, $6.5 MM 0 50 100 150 200 250 300 30 35 40 45 50 55 60 R O R, % WTI Oil Price, $/Bbl Ranger/Arrowhead - 2nd Bone Spring (90% oil) 700 MBOE, $4.5 MM 700 MBOE, $6.0 MM 400 MBOE, $4.5 MM 400 MBOE, $6.0 MM 0 20 40 60 80 100 120 140 30 35 40 45 50 55 60 R O R, % WTI Oil Price, $/Bbl Rustler Breaks - Wolfcamp B (45% oil) 1,000 MBOE, $5.5 MM 1,000 MBOE, $6.5 MM 800 MBOE, $5.5 MM 800 MBOE, $6.5 MM Note: $2.50/Mcf natural gas price used in all graphs, less differentials. Costs include total estimated drilling, completion, production and facilities costs for a typical development well in each area. Note: High end of cost range reflects Q1 2016 estimated costs; low end of cost range reflects 2016 target. (1) Oil price shown is West Texas Intermediate oil price (WTI). Differentials to WTI oil price are included in all graphs for each area. Delaware Basin – Sensitivities to Oil Price(1) and Cost Savings
Single Wolfcamp B Well at Rustler Breaks Holds Up To 15 Potential Locations 25 Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp B Wolfcamp A-X/Y One producing Wolfcamp B well holds 320 surface acres and up to 15 additional potential locations for future development 1/2 mile 1 mile Additional Locations Held With Wolfcamp B well 2 2 2 2 3 15 2 2 320 - Acre Development Spacing Pattern (Cross-Section View) 1 m ile 320 gross acres 1/2 mile 320 - Acre Development Spacing Pattern (Aerial View)
$75.0 $62.0 $62.0 $61.0 $22.0 $16.0 $2.0 $6.0 $6.0 $6.0 $7.0 $103.0 $84.0 $70.0 $68.0 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 1Q16 2Q16 3Q16 4Q16 D&C + Facilities Midstream Land, Seismic, Etc. (Discretionary) 2016E CapEx of ~$325 million − Decrease of ~32% from 2015 estimated capital expenditures of ~$480 million(1) − Includes estimated efficiency and cost savings of 15 to 20% throughout 2016, but additional savings may be realized Delaware Basin focus on Wolfcamp development at Wolf and Rustler Breaks, plus additional delineation of Ranger and Arrowhead prospect areas − Includes ~$40 million for midstream initiatives and ~$25 million for land and seismic - almost all in the Delaware Basin − Includes ~$5.5 million for anticipated non-op well participation 2016E CapEx highest in Q1 2016 – falls quickly thereafter − Almost all midstream CapEx incurred in first half of 2016 No operated Eagle Ford drilling activity in 2016 – over 90% of acreage HBP or not subject to near-term expirations(2) − Includes ~$6 million CapEx, primarily for rod pump installations and some lease extensions Haynesville development includes selective participation in non-operated wells, primarily Chesapeake drilling at Elm Grove; Haynesville acreage ~100% held by production − Includes ~$4 million in 2016 as we expect only 5 gross (0.6 net) wells in 2016 2016 Capital Investment Plan Summary – 3 Delaware Basin Rigs 26 Land, Seismic, Etc. (Discretionary) $25 million 8% Drilling, Completions, Facilities, Infrastructure $260 million 80% Permian Midstream Activities (Longwood) $40 million 12% 2016E CapEx – 3-Rig Case (3 rigs in the Delaware Basin throughout 2016) $325 million 2016E CapEx by Quarter – 3-Rig Case (3 rigs in the Delaware Basin throughout 2016) $ in m ill io n s (1) For operations only. Does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. 2015 CapEx and related components are estimated at February 3, 2016 and are subject to adjustment pending the completion and release of 2015 audited financial statements. (2) At December 31, 2015.
$75.0 $62.0 $62.0 $61.0 $22.0 $16.0 $2.0 $6.0 $6.0 $6.0 $7.0 $103.0 $84.0 $70.0 $68.0 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 1Q16 2Q16 3Q16 4Q16 D&C + Facilities Midstream Land, Seismic, Etc. (Discretionary) $75.0 $47.0 $50.0 $40.0 $22.0 $16.0 $2.0 $6.0 $6.0 $6.0 $7.0 $103.0 $69.0 $58.0 $47.0 $0.0 $20.0 $40.0 $60.0 $80.0 $100.0 $120.0 1Q16 2Q16 3Q16 4Q16 D&C + F cilities Midstream Land, S ismic, Etc. (Discretionary) 2016 Capital Investment Plan Summary – 3-Rig and 2-Rig Cases 27 Land, Seismic, Etc. (Discretionary) $25 million 8% Drilling, Completions, Facilities, Infrastructure $260 million 80% Permian Midstream Activities (Longwood) $40 million 12% 2016E CapEx – 3-Rig Case (3 rigs in the Delaware Basin throughout 2016) $325 million 2016E CapEx by Quarter – 3-Rig Case (3 rigs in the Delaware Basin throughout 2016) 2016E CapEx – 2-Rig Case (3 rigs in the Delaware Basin in Q1 2016; 2 rigs in Q2-Q4 2016) Land, Seismic, Etc. (Discretionary) $25 million 9% Drilling, Completions, Facilities & Infrastructure $212 million 77% Permian Midstream Activities (Longwood) $40 million 14% $277 million 2016E CapEx by Quarter – 2-Rig Case (3 rigs in the Delaware Basin in Q1 2016; 2 rigs in Q2-Q4 2016) $ in m ill io n s $ in m ill io n s
2,133 3,320 4,492 4,800 4,285 5,870 9,108 9,133 2013 2014 2015 2016E 7% 0% 56% 37% 35% 55% 2,133 3,320 4,492 5,000 4,285 5,870 9,108 9,500 2013 2014 2015 2016E 11% 4% 56% 37% 35% 55% Oil and Natural Gas Production – 3-Rig Case (3 rigs in the Delaware Basin throughout 2016) Oil 28 2016 Oil and Natural Gas Production Estimates 2016E CapEx: D&C / Facilities: $260 MM Midstream / Land: $65 MM Total: $325 MM Outspend: $230 MM Oil, MBbl Natural Gas, MBOE Total Oil and Natural Gas Production – 2-Rig Case (3 rigs in the Delaware Basin in Q1 2016; 2 rigs in Q2-Q4 2016) 2016E Oil Production – 3-Rig Case Estimated oil production of 4.9 to 5.1 million barrels − 11% increase from 2015 to midpoint of 2016 range − Declines about 200,000 barrels in 2-rig case Average daily oil production of 13,700 Bbl/d, up from 12,300 Bbl/d in 2015 − Delaware Basin ~9,600 Bbl/d (70%) − Eagle Ford ~4,100 Bbl/d (30%) Quarterly oil production more “lumpy” in 2016 due to additional multi-well pads − Q1 2016 down ~3% sequentially due to 3-well and 4-well pad drilling at Wolf; Q4 2016 up 34% over Q4 2015 2016E Natural Gas Production – 3-Rig Case Estimated natural gas production of 26.0 to 28.0 Bcf − 3% decrease from 2015 to midpoint of 2016 range − Declines about 1 Bcf in 2-rig case Average daily natural gas production of 74.0 MMcf/d, compared to 75.9 MMcf/d in 2015 − Haynesville/Cotton Valley ~33.4 MMcf/d (45%) − Delaware Basin ~29.6 MMcf/d (40%) − Eagle Ford ~11.0 MMcf/d (15%) − Q4 2016 up 5% over Q4 2015 Oil, MBbl Natural Gas, MBOE 2016E CapEx: D&C / Facilities: $212 MM Midstream / Land: $65 MM Total: $277 MM Outspend: $205 MM
$269 $368 $278 $225 $0 $100 $200 $300 $400 2013 2014 2015 2016E (19%) (24%) 37% Realized $45.27/Bbl $2.71/Mcf Realized $34.00/Bbl $2.37/Mcf Realized $99.79 Bbl $4.35/Mcf Realized $87.37/Bbl $5.08/Mcf $269 $368 $278 $235 $0 $100 $200 $300 $400 2013 2014 2015 2016E (15%) (24%) 37% 2016E Oil and Natural Gas Revenues Revenues impacted by lower estimated 2016 realized oil and natural gas prices – forecasts use strip commodity prices in late January 2016 − 2016E realized oil price of $34/Bbl vs ~$45/Bbl realized in 2015 − 2016E realized natural gas price of $2.37/Mcf vs $2.71/Mcf in 2015 − Assuming $3.00/Bbl average price differential from WTI for oil and Henry Hub for natural gas, assuming price differentials and processing revenues offset − Realized prices are unhedged Estimated oil and natural gas revenues of $230 to $240 million in 3-rig case − Decrease of ~15% from estimated $275 to $280 million(2) in 2015 − Oil and natural gas hedges estimated to contribute $20 million(3) in additional revenues in 2016, as compared to $77 million in 2015 Estimated oil and natural gas revenues decline by about $10 million in 2-rig case ~53% oil by volume, ~73% oil by revenue in 2016(1); compared to ~49% oil by volume, ~73% oil by revenue in 2015(2) 2016 Oil and Natural Gas Revenue Estimates (1) 2016E oil and natural gas revenues and Adjusted EBITDA based upon the midpoint of 2016 production guidance range as provided on February 3, 2016. Estimated average realized prices for oil and natural gas used in these estimates were $34.00/Bbl (WTI oil price of $37.00/Bbl less $3.00/Bbl) and $2.37/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period January through December 2016. (2) 2015E oil and natural gas revenues are estimated at February 3, 2016 and subject to adjustment pending completion and release of 2015 audited financial statements. (3) At strip oil and natural gas prices in late January 2016. 29 Oil and Natural Gas Revenues – 2-Rig Case (3 rigs in the Delaware Basin in Q1 2016; 2 rigs in Q2-Q4 2016) Oil and Natural Gas Revenues – 3-Rig Case (3 rigs in the Delaware Basin throughout 2016) $ in m ill io n s $ in m ill io n s Realized $45.27/Bbl $2.71/Mcf Realized $34.00/Bbl $2.37/Mcf Realized $99.79 Bbl $4.35/Mcf Realized $87.37/Bbl $5.08/Mcf (2) (2)
$223 $108 $192 $263 $331 $105 $0 $100 $200 $300 $400 2013 2014 2015 2016E 37% (15%) (53%) Realized $45.27/Bbl $2.71/Mcf Realized $34.00/Bbl $2.37/Mcf Realized $99.79 Bbl $4.35/Mcf Realized $87.37/Bbl $5.08/Mcf $223 $108 $192 $263 $331 $125 $0 $100 $200 $300 $400 2013 2014 2015 2016E 37% (15%) (44%) Realized $45.27/Bbl $2.71/Mcf Realized $34.00/Bbl $2.37/Mcf Realized $99.79 Bbl $4.35/Mcf Realized $87.37/Bbl $5.08/Mcf 2016E Adjusted EBITDA(1)(2) Estimated Adjusted EBITDA(1)(2) of $120 to $130 million in 3-rig case − Decrease of ~44% from estimated $220 to $225 million(3) in 2015 Estimated Adjusted EBITDA(1)(2) of $100 to $110 million in 2-rig case − Includes estimated rig release penalty 2016E Operating Cost Estimates (Unit Costs per BOE)(3) (unit costs per BOE) 2016E 2015 Production taxes and marketing $4.25 $3.90 Lease operating $6.00 $6.40 General and administrative $5.25 $5.50 Operating cash costs, excluding interest $15.50 $15.80 Depletion, depreciation and amortization $16.25 $19.60 Operating Cost Estimates 2016 Adjusted EBITDA Estimates (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) 2016E oil and natural gas revenues and Adjusted EBITDA based upon the midpoint of 2016 production guidance range as provided on February 3, 2016. Estimated average realized prices for oil and natural gas used in these estimates were $34.00/Bbl (WTI oil price of $37.00/Bbl less $3.00/Bbl) and $2.37/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period January through December 2016. (3) 2015E Adjusted EBITDA and operating costs are estimated at February 3, 2016 and subject to adjustment pending completion and release of 2015 audited financial statements. 30 Adjusted EBITDA(1)(2) – 2-Rig Case (3 rigs in the Delaware Basin in Q1 2016; 2 rigs in Q2-Q4 2016) Adjusted EBITDA(1)(2) – 3-Rig Case (3 rigs in the Delaware Basin throughout 2016) Shows impact of EnLink transaction in 2015 Shows impact of EnLink transaction in 2015 Projected to decline from $6.50 in Q1 to $5.50 in Q4 $ in m ill io n s $ in m ill io n s (3) (3)
$88 $104 $120 $125 $136 $153 $175 $196 $80 $100 $120 $140 $160 $180 $200 $25 $30 $35 Strip $40 $45 $50 $55 201 6E A dj us te d EB IT DA M id po in t ( $ m ill io ns ) WTI Oil Price ($/Bbl) Relatively small improvements in oil price and service cost reductions can significantly improve financial forecasts and reduce estimated CapEx $10/Bbl increase in oil price improves Adjusted EBITDA(1) by ~$33 million 10 to 15% decrease in well costs due to further drilling efficiencies and service cost savings reduces CapEx by $33 to $50 million $10/Bbl increase in oil price and additional 10% in CapEx reductions reduce operating cash outspend by ~$66 million – about 30% of estimated outspend in 3-rig case Matador technical teams focused on continuing to reduce both operating costs and capital expenditures in 2016 and continuing to improve well performance Commodity Price and CapEx Estimates Significantly Impact Forecasts (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) Estimated 2016 oil and natural gas revenues and Adjusted EBITDA based upon the midpoint of 2016 production guidance range as provided on February 3, 2016. Estimated average realized prices for oil and natural gas used in these estimates were $34.00/Bbl (WTI oil price of $37.00/Bbl less $3.00/Bbl) and $2.37/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period January through December 2016. 31 $325 $309 $293 $276 $260 $0 $50 $100 $150 $200 $250 $300 $350 0% 5% 10% 15% 20% 20 16 E Ca pE x ( $ m illi on s) Percentage Reduction in 2016E CapEx Midpoint of 2016E Guidance(2) Sensitivity of 2016E CapEx to Additional Cost Savings Sensitivity of 2016E Adjusted EBITDA(1) to Oil Price
390,000 390,000 390,000 390,000 $74.64 $74.64 $74.64 $74.64 $47.46 $47.46 $47.46 $47.46 $0 $20 $40 $60 $80 $100 $120 0 50,000 100,000 150,000 200,000 250,000 300,000 350,000 400,000 450,000 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Oil Vol ume He dg ed (B bl) 2.70 3.00 3.00 3.00 1.80 1.80 1.80 1.80 $3.60 $3.53 $3.53 $3.53 $3.57 $3.57 $3.57 $3.57 $2.64 $2.60 $2.60 $2.60 $2.25 $2.25 $2.25 $2.25 $1.00 $2.00 $3.00 $4.00 $5.00 $6.00 $7.00 0.00 0.50 1.00 1.50 2.00 2.50 3.00 3.50 Q1 2016 Q2 2016 Q3 2016 Q4 2016 Q1 2017 Q2 2017 Q3 2017 Q4 2017 Na tu ra l G as Vol umes He dg ed (B cf) Hedging Profile 2016 Hedges(1) Oil: ~1.6 million barrels of oil hedged for 2016 at weighted average floor and ceiling prices of $47/Bbl and $75/Bbl, respectively – Approximately 31% of oil hedged for 2016 Natural Gas: 11.7 Bcf of natural gas hedged for 2016 at weighted average floor and ceiling of $2.61/MMBtu and $3.54/MMBtu, respectively – Approximately 43% of natural gas hedged for 2016 2017 Hedges(1) Oil: No hedges in place for 2017 Natural Gas: 7.2 Bcf of natural gas ($2.25/MMBtu floor and $3.57/MMBtu ceiling) Oil and natural gas hedges estimated to add $20 million(2) to projected oil and natural gas revenues in 2016 32 Oil Hedges (Costless Collars) Natural Gas Hedges (Costless Collars) (1) At February 3, 2016. (2) At strip oil and natural gas prices in late January 2016.
Strong, supportive bank group led by Royal Bank of Canada Borrowing base reaffirmed on October 16, 2015 at $375 million based on June 30, 2015 reserves Maturity of credit facility extended from December 2016 to October 2020 Bank group unanimous in supporting borrowing base affirmation and maturity extension No borrowings outstanding at December 31, 2015 Net Debt/Adjusted EBITDA(1)(2) of 1.5x at December 31, 2015 Financial covenants Maximum Total Debt to Adjusted EBITDA(2) Ratio of not more than 4.25:1.00 33 Credit Agreement Status (1) Estimated Net Debt and LTM Adjusted EBITDA at December 31, 2015 are estimated at February 3, 2016 and subject to adjustments pending completion of 2015 audited financial statements. Net debt is equal to debt outstanding less available cash (including $43 million of restricted cash held in escrow at December 31, 2015). (2) Adjusted EBITDA is a non-GAAP financial measure. For a definition of Adjusted EBITDA an a reconciliation of Adjusted EBITDA to our net income (loss) and net cash provided by operating activities, see Appendix. TIER Conforming Borrowing Base Utilization LIBOR Margin BASE Margin Commitment Fee Tier One x < 25% 150 bps 50 bps 37.5 bps Tier Two 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
34 Summary and Initial 2016 Guidance (1) Estimated 2015 financial results are estimated at February 3, 2016 and subject to adjustment pending completion and release of 2015 audited financial statements. (2) Estimated 2016 Adjusted EBITDA is based upon the midpoint of 2016 production guidance range as provided on February 3, 2016. Estimated average realized prices for oil and natural gas used in these estimates were $34.00/Bbl (WTI oil price of $37.00/Bbl less $3.00/Bbl) and $2.37/Mcf (NYMEX Henry Hub natural gas price assuming regional differentials and uplifts from natural gas processing roughly offset), respectively, for the period January through December 2016. (3) For operations only. Does not include capital expenditures associated with the HEYCO transaction or two associated joint ventures. (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. Plan to run 3 rigs in the Delaware Basin throughout 2016, but will reduce to 2 rigs as early as Q2 2016 if oil prices drop back and remain below $30 per barrel Delaware Basin drilling focused on Wolf and Rustler Breaks Wolfcamp development and further delineation of Ranger, Arrowhead and Twin Lakes prospect areas No Eagle Ford and minimal Haynesville non-operated drilling activity in 2016 Initial 2016 guidance based on assumption of running 3 rigs throughout 2016 Estimated 2015 Results(1) 2016 Guidance(2) % Change Capital Spending ~$480 million(3) $325 million - 32% Total Oil Production 4.5 million Bbl 4.9 to 5.1 million Bbl + 11% Total Natural Gas Production 27.7 Bcf 26.0 to 28.0 Bcf - 3% Adjusted EBITDA(4) ~$220 to 225 million(1) $120 to $130 million(2) - 44%
Delaware Basin Operations Update Matthew V. Hairford – President David E. Lancaster – Executive Vice President and CFO
Understanding the Opportunities 3rd Bone Spring L. Avalon 800’ Most current unconventional plays target one or two zones across a trend area. The Delaware Basin has over a dozen unique targets between the top of the Brushy Canyon and the Woodford. All logs plotted at same scale Delaware Basin Wolfcamp A Wolfcamp B Wolfcamp C Wolfcamp D Strawn Atoka Barnett Miss Lime Woodford U. Avalon 1st Bone Spring 2nd Bone Spring 36 Brushy Cyn. O v erp re s s ur e Tested by MTDR Tested by others Objective: To drill and complete better wells for less money Challenge: To identify the best targets within multiple prospective intervals across a geologically complex basin Matador’s geoscience staff is committed to bringing the best targets forward!
Improved Wolfcamp Drilling Times Significantly in 2015 37 43 32 35 26 18 15 0 5 10 15 20 25 30 35 40 45 50 Dril ling Da y s 2014 Average 2015 Planned 2015 Best Well Note: Best wells are Johnson 44-02S-B53 #206H in Loving County (Wolfcamp) and Tiger 14-24S-28E RB #204H in Eddy County (Wolfcamp). Loving County Wolfcamp Eddy County Wolfcamp
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 H2 2014 Rigs Labor/ Supply Rentals Directional Fluids Casing/ Cement YE 2015 20% 9% 8% 6% 3% 24% 10% 22% 19% 12% 12% 17% 38 2015 Wolf Area Drilling Cost Improvements $7.4 $3.6 D ri ll in g C o s ts, m il li o n s Rigs Labor/ Supply Rentals Directional Fluids Casing/ Cement
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 $6.0 $7.0 $8.0 H2 2014 YE 2015 YE 2016 51% Savings 17% Savings 2016 Anticipated Wolf Area Drilling Cost Improvements 39 Service Costs Service Costs Efficiencies Efficiencies $7.4 $3.6 $3.0 41% 59% 50% 50% D ri ll in g C o s ts, m il li o n s
Stimulation Location Surface Rentals CTU Drillout Wireline $0.0 $1.0 $2.0 $3.0 $4.0 $5.0 H2 2014 Stimulation Location Surface Rentals CTU/Drillout Wireline YE 2015 15% 12% 12% 9% 52% 40 2015 Wolf Area Completion Cost Improvements $4.6 $2.4 C omple ti o n C o s ts, m il li o n s
$0.0 $1.0 $2.0 $3.0 $4.0 $5.0 H2 2014 YE 2015 YE 2016E 2016 Anticipated Wolf Area Completion Cost Improvements 41 $4.6 Service Costs 83% Service Costs 83% 75% 25% Efficiencies Efficiencies $2.4 $1.8 C omple ti o n C o s ts, m il li o n s More to come? 48% Savings 25% Savings 17% 75%
$0.0 $2.0 $4.0 $6.0 $8.0 $10.0 $12.0 H2 2014 YE 2015 YE 2016E 25% 2016 Anticipated Wolf Area Total Drilling and Completion Cost Improvements 42 $12.0 $6.0 $4.8 D ri ll in g a n d C omple ti o n C o s ts , m il li o n s $100,000 Cost Reduction ROR Increase ~2% More to come? Service Costs Service Costs Efficiencies Efficiencies 56% 44% 63% 37% 50% Savings 20% Savings Note: Does not include production and facilities costs.
43 Wolf Prospect Area – Continued Focus on Wolfcamp Development in 2016 Matador Acreage Wolfcamp A-X/Y 2nd Bone Spring Recently Added 2016 Focus Area Norton Schaub 84-TTT-B33 WF #201 Cumulative BOE: 360 MBOE EUR (BOE): ~1,000 MBOE Dorothy White #1H Cumulative BOE: 480 MBOE EUR (BOE): >1,000 MBOE 2015 Accomplishments Reduced drilling times by 58% Reduced drilling and completion costs by 50% Generating “repeatable” results Norton Schaub ESP test a success First use of diverting technology encouraging 2016 Plans Focus on Wolfcamp development 21 gross (18.4 net) wells planned for 2016 17 gross (15.2 net) wells on production All wells to be drilled from multi-well pads in batch mode Note: All acreage at January 7, 2016.
2nd Bone Spring Wolfcamp X/Y Wolf Inventory – Multi-Pay Development Potential ~660’ Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A-X/Y Wolfcamp A Full Development Location 1 mile MRC Spacing Test Completed Full Development Spacing Pattern (Cross-Section View) 44 A-X/Y Wolfcamp A 4 72 Eval. Ongoing 70 72 70 51 339 Formation Development Well Costs(1)(2) (millions) EUR(3) (MBOE) % Oil 2nd Bone Spring $4.0 – $5.0 400 – 500 50 – 65% Wolfcamp A-X/Y $5.5 – $6.5 650 – 1,100 65 – 80% (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent. (4) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2015. (5) Includes any identified locations in which Matador’s working interest is at least 25%. Matador Acreage Note: All acreage at January 7, 2016. Total Gross Locations(4) Est. Operated Locations(5) 4 68 Eval. Ongoing 66 68 66 47 319
Drilling Wells in Batch Mode / Central Production Facilities 45 Dick Jay / Barnett Development (Top-Down View) Dick Jay / Barnett Development (Cross-Section View) Dick Jay Pad Barnett Pad 2nd Bone Spring 3rd Bone Spring Wolfcamp A “Fat” Wolfcamp A-X/Y Dick Jay 124H Dick Jay 204H Dick Jay 203H Dick Jay 212H Barnett Dick Jay Drilled/Drilling 2016 Planned Wells Central Tank Battery ~660’ $200,000 to $400,000 in savings/well by batch drilling!
Wolf Area Wolfcamp A-X/Y Wells Continue Strong Performance Across Acreage 46 10 100 1,000 10,000 0 50 100 150 200 250 300 350 400 450 500 550 600 650 700 P roduction R a te, BO E /d Time, Days Dorothy White #1H Norton Schaub #201H Billy Burt #203H Johnson #204H Barnett #201H Dorothy White #1H has produced 480 MBOE (69% oil) in 24 months Norton Schaub 84-TTT-B33 WF #201H has produced 360 MBOE (68% oil) in 18 months Billy Burt 90-TTT-B33 WF #203H has produced 123 MBOE (74% oil) in 8 months Johnson 44-02S-B53 WF #204H has produced 266 MBOE (65% oil) in 15 months Barnett 90-TTT-B01-WF #201H has produced 179 MBOE (64% oil) in 10 months Well put on ESP 600 MBOE Type Curve 1,200 MBOE Type Curve 900 MBOE Type Curve Note: Production from selected Wolfcamp A-X/Y wells in Wolf prospect area as of January 2016.
Wolf – Estimated Returns by Formation 47 Formation Development Well Cost(1)(2) (millions) EUR(3) (MBOE) % Oil 2nd Bone Spring $4.0 - $5.0 400 – 500 50 – 65% Wolfcamp A-X/Y $5.5 - $6.5 650 – 1,100 65 – 80% 0 50 100 150 200 $30 $35 $40 $45 $50 $55 $60 R OR % WTI Oil Price, $/Bbl Wolfcamp A-X/Y 1,000 MBOE $5.5MM D&C ROR % 1,000 MBOE $6.5 MM D&C ROR % 700 MBOE $5.5 MM D&C ROR % 700 MBOE $6.5 MM D&C ROR % 0 25 50 75 100 $30 $35 $40 $45 $50 $55 $60 R OR % WTI Oil Price, $/Bbl 2nd Bone Spring 500 MBOE $4.0 MM D&C ROR % 500 MBOE $5.0 MM D&C ROR % 400 MBOE $4.0 MM D&C ROR % 400 MBOE $5.0 MM D&C ROR % Note: Assumes $2.50/Mcf flat natural gas price with -$0.73/Mcf natural gas differential and -$1.75/Bbl oil differential. (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent.
Stacked Horizon Test at Jackson Trust Jackson Trust C 12-TTT-C24 #021H Preparing to run ESP Jackson Trust C 12-TTT-C24 #121H 24 hr. IP: 800 BOE/d (72% oil) Jackson Trust C 12-TTT-C24 #211H 24 hr. IP: 702 BOE/d (82% oil) Jackson Trust C 12-TTT-C24 #101H Testing at 331 BOE/d on ESP (80% oil) and improving 48 Multi-Well Pad Delaware Basin Brushy Cyn. Avalon 2nd Bone Spring Wolfcamp A Matador Acreage Note: All acreage at January 7, 2016. 3rd Bone Spring 1st Bone Spring
Rustler Breaks – Focus on Wolfcamp Development in 2016 49 Wolfcamp A-X/Y Wolfcamp B Matador Acreage Dr K #203H 24 hr IP: 1,241 BOE/d (69% oil) Scott Walker #204H 24 hr IP: 504 BOE/d (70% oil) Rustler Breaks #224H 24 hr IP: 987 BOE/d (44% oil) Guitar #202H 24 hr IP: 1,274 BOE/d (79% oil) Tiger #224H 24 hr IP: 1,533 BOE/d (42% oil) Tiger #204H 24 hr IP: 1,405 BOE/d (75% oil) 2015 Accomplishments Identified multiple new horizons, particularly in the Wolcamp A-X/Y and Wolfcamp B Reduced drilling times and well costs significantly Tested next generation frac design up to 3,000 lbs/ft 2016 Plans Focus on Wolfcamp development 20 gross (16.1 net) wells planned for 2016 18 gross (14.5 net) wells on production 8 Wolfcamp A-X/Y 10 Wolfcamp B Complete 60 MMcf/d cryogenic processing plant and gathering system to support operations Complete 3D seismic shoot across prospect area Note: All acreage at January 7, 2016. Janie Conner #224H 24 hr IP: 1,703 BOE/d (59% oil)
Rustler Breaks Inventory – Multi-Pay Development Potential Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A-X/Y Wolfcamp B ~ 80 0’ 171 178 183 188 173 235 167 1,637 Full Development Location Total Gross Locations(4) Formation Development Well Costs(1)(2) (millions) EUR(3) (MBOE) % Oil Bone Spring $3.0 – $4.0 300 – 600 80 – 85% Wolfcamp A-X/Y $5.0 – $6.0 600 – 800 80 – 85% Wolfcamp B $5.5 – $6.5 800 – 1,000 40 – 50% 1 mile MRC Horizontal Drilled Full Development Spacing Pattern (Cross-Section View) 50 Wolfcamp A-X/Y Wolfcamp B 2nd Bone Spring Matador Acreage Est. Operated Locations(5) 1,135 115 123 125 127 120 177 114 Note: All acreage at January 7, 2016. (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent. (4) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2015. (5) Includes any identified locations in which Matador’s working interest is at least 25%.
Rustler Breaks – 5 Wells Producing From 3 Zones on Multi-Well Pad Bone Spring Lime Upper Avalon Shale Lower Avalon Shale First Bone Spring Sand Second Bone Spring Carbonate Third Bone Spring Carbonate Wolfcamp / Pennsylvanian Strawn Wolfcamp “C” Third Bone Spring Sand Gamma Ray INTER-Formational Stacked Pay Second Bone Spring Sand Wolfcamp “A” Wolfcamp “B” Wolfcamp “X/Y” Tiger 14-24S-28E RB #224H IP: 1,533 BOE/d (42% oil) Tiger 14-24S-28E RB #204H IP: 1,405 BOE/d (75% oil) Tiger 14-24S-28E RB #124H IP: 702 BOE/d (83% oil) Multi-Well Pad Resistivity EUR: ____ Mboe EUR: ____ Mboe 51 Janie Conner 13-24S-28E RB #224H IP: 1,703 BOE/d (59% oil) Janie Conner 13-24S-28E RB #124H IP: 640 BOE/d (83% oil) Janie Conner 13-24S-28E RB #204H On 2016 Drill Schedule West (Section 14) 3 producing wells East (Section 13) 2 producing wells TVD: 8,200’ 9,600’ 10,500’ Additional Wolfcamp B Targets Wolfcamp B – Upper Wolfcamp B – Lower Drilled by Matador in Rustler Breaks Being tested by other operators
8.3 8.6 5.1 5.9 6.9 3.9 5.0 5.5 3.0 $0 $1 $2 $3 $4 $5 $6 $7 $8 $9 $10 Guitar #202H Tiger #224 Tiger #124H Tiger #204H Janie Conner #224 Janie Conner #124 Wolfcamp A 2016 Target Wolfcamp B 2016 Target 2nd Bone Springs 2016 Target C o m p le te d W el l C o st , $m ill io n s 52 Rustler Breaks Well Cost Achievements Wolfcamp A Wolfcamp B 2nd Bone Spring 2016 could result in $13.5 million total costs $9.00/BOE net(1) Tiger 3 well stack costs: $19.5 million Combined Gross EUR: ~2 MMBOE $13.00/BOE net(1) 2015 wells (1) Assumes 75% NRI (net revenue interest) for each well.
Rustler Breaks Wolfcamp B Wells Performing Above Expectations 53 10 100 1,000 10,000 0 50 100 150 200 250 300 350 400 450 500 550 600 P roduction R a te, BO E /d Time, Days Rustler Breaks #224H Tiger #224H Janie Conner #224H Rustler Breaks 12-24S-27E #224H has produced 233 MBOE (41% oil) in 20 months Tiger 14-24S-28E RB #224H has produced 218 MBOE (43% oil) in 9 months Janie Conner 13-24S-28E RB #224H has produced 72 MBOE (58% oil) in 2 months 700 MBOE Type Curve 1,000 MBOE Type Curve Note: Production as of January 2016.
Rustler Breaks Wolfcamp A-X/Y Wells Performing Above Expectations 54 10 100 1,000 10,000 0 20 40 60 80 100 120 140 160 180 200 220 240 260 280 300 P roduction R a te, BO E /d Time, Days Guitar #202H Tiger #204H Scott Walker #204H Guitar 10-24S-28E RB #202H has produced 164 MBOE (78% oil) in 10 months Tiger 14-24S-28E RB #204H has produced 132 MBOE (81% oil) in 6 months Scott Walker 36-22S-27E RB #204H has produced 37 MBOE (73% oil) in 4 months Well put on compression Note: Production as of January 2016. 800 MBOE Type Curve 500 MBOE Type Curve
0 40 80 120 160 30 35 40 45 50 R O R, % WTI Oil Price, $/Bbl Rustler Breaks - Wolfcamp A-X/Y (85% oil) 800 MBOE, $5.0 MM 800 MBOE, $6.0 MM 600 MBOE, $5.0 MM 600 MBOE, $6.0 MM 0 20 40 60 80 100 30 35 40 45 50 R O R, % WTI Oil Price, $/Bbl Rustler Breaks - Wolfcamp B (45% oil) 1,000 MBOE, $5.5 MM 1,000 MBOE, $6.5 MM 800 MBOE, $5.5 MM 800 MBOE, $6.5 MM Rustler Breaks – Estimated Returns by Formation 55 Formation Development Well Cost(1)(2) (millions) EUR(3) (MBOE) % Oil Wolfcamp A-X/Y $5.0 – $6.0 600 – 800 80 – 85% Wolfcamp B $5.5 – $6.5 800 – 1,000 40 – 50% Note: Assumes $2.50/Mcf flat natural gas price with -$0.70/Mcf natural gas differential and -$3.26/Bbl oil differential. (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent.
Single Wolfcamp B Well at Rustler Breaks Holds Up To 15 Potential Locations 56 Brushy Canyon Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp B Wolfcamp A-X/Y One producing Wolfcamp B well holds 320 surface acres and up to 15 additional potential locations for future development 1/2 mile 1 mile 320 - Acre Development Spacing Pattern (Cross-Section View) 1 m ile 320 gross acres 1/2 mile 320 - Acre Development Spacing Pattern (Aerial View) Additional Locations Held With Wolfcamp B well 2 2 2 2 3 15 2 2
57 2nd Bone Spring 3rd Bone Spring Wolfcamp D Wolfcamp A Cimarron State RN #133H, 804 - 804 BOE/d (94% oil). Matador Acreage Ranger/Arrowhead – Bone Spring and Wolfcamp Development in 2016 2015 Accomplishments Merged with HEYCO adding ~60,000 gross and ~20,000 net acres(1) 12 gross (4.5 net) wells Drilled Twin Lakes vertical data well Applied for 10 new Federal drilling permits 2016 Plans Further delineate and develop Bone Spring 7 gross (4.9 net) wells with 5 gross (3.9 net) wells on production Drill and complete horizontal in Wolfcamp D at Twin Lakes Submit 50 to 75 Federal drilling permits for approval and future development Gobbler 5 B2PM 1H - Tested 2,300 BOE/d (80% oil) CTA State Com 3H, 4H, 5H, 6H - Avg. 956 BOE/d (85% oil) Mallon 27 Fed Com #2H, #3H, #4H - To Spud Q3 2016 (3rd Bone Spring w/7,500 ft laterals) Pickard State RN #124H - On flowback after frac Hibiscus RN #124H - On flowback after frac Iggles 21 State Com #1H - 1,300 BOE/d (90% oil) Ranger 33 #122H - Avg. 330 BOE/d (90% oil) Conine 03-20S-35E RN #121H - 578 BOE/d (91% oil) Note: All acreage at January 7, 2016. (1) Including additional acreage acquired through subsequent joint ventures with affiliates of HEYCO. Non-Op Matador Operated
Formation Development Well Costs(1)(2) (millions) EUR(3) (MBOE) % Oil Bone Spring $4.5 – $6.0 400 – 700 90 – 95% Wolfcamp $6.5 – $8.0 200 – 800* 80 – 85% Ranger Inventory – Multi-Well Development Potential 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A-D * Based on Volumetrics and 4-8% Recovery Factor 58 2nd Bone Spring 3rd Bone Spring Wolfcamp D Matador Acreage Wolfcamp A ~1,320’ Wolfcamp A- X/Y ~ 750’ 155 169 89 194 48 655 1 mile MRC Horizontal Drilled Full Development Location Full Development Spacing Pattern (Cross-Section View) MRC Horizontal Planned Note: All acreage at January 7, 2016. Total Gross Locations(4) Est. Operated Locations(5) 342 80 90 43 114 15 (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent. (4) Identified and engineered locations for potential future drilling, including specified production units and estimated lateral lengths, costs and well spacing using objective criteria for designation. Locations identified as of December 31, 2015. (5) Includes any identified locations in which Matador’s working interest is at least 25%.
Arrowhead Inventory – Multi-Well Development Potential 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A-D Formation Development Well Costs(1)(2) (millions) EUR(3) (MBOE) % Oil Bone Spring $4.5 – $6.0 400 – 700 80 – 90% Wolfcamp $6.5 – $8.0 200 – 800* 80 – 85% * Based on Volumetrics and 4-8% Recovery Factor 59 2nd Bone Spring ~1,320’ Wolfcamp A-X/Y 210 210 120 88 14 642 1 mile Full Development Location Full Development Spacing Pattern (Cross-Section View) MRC Horizontal Planned Stebbins Fed 20-20S-29E AH #123H Spud Q4 2016 Matador Acreage Note: All acreage at January 7, 2016. Total Gross Locations(4) Est. Operated Locations(5) ~ 75 0’ 269 77 78 59 44 11 (1) Well costs include drilling, completion, production and facilities costs. (2) High end of well cost range reflects estimated costs in Q1 2016; lower end of cost range reflects 2016 target. (3) Estimated ultimate recovery, thousands of barrels of oil equivalent. (4) Gross locations identified as of December, 31, 2015. (5) Includes any identified locations in which Matador’s working interest is at least 25%.
60 Ranger Area Bone Spring Wells Continued Strong Performance Note: Production as of January 2016. 700 MBOE Type Curve 400 MBOE Type Curve 10 100 1,000 10,000 0 100 200 300 400 500 600 700 Production R ate, BO E/ d Time, Days Ranger 33 #121H Ranger 33 #122H Pickard State #1H Cimarron State #134H Bone Spring Horizontals in Ranger Area - Lea County, NM Ranger State 33-20S-35E RN #121H has produced 238 MBOE (91% oil) in 26 months (2nd Bone Spring) Ranger State 33-20S-35E RN #122H has produced 60 MBOE (91% oil) in 8.5 months (2nd Bone Spring) Pickard State 20-18S-34E RN #1H has produced 205 MBOE (89% oil) in 18 months (2nd Bone Spring) Cimarron State #134H has produced 123 MBOE (94% oil) in 8.5 months (3rd Bone Spring) Well shut in for offset fracs
Testing New Oil Shale Play in Twin Lakes Prospect 61 Olivine State 5-16S-37E TL #1 Matador Resources Acreage M ic ro -C o u p le d C o u p le d One of the primary source rocks for Twin Lakes prospect area (~42,300 gross and ~29,900 net acres) Super-charged area having produced 1.3 billion Bbl oil and 2.2 trillion cubic feet natural gas Drilled initial data collection well (Olivine State #1) to obtain full set of whole cores and geophysical logs Horizontal well to test Wolfcamp D planned in Q4 2016 after analyzing data for optimal landing target M ic ro -C o u p le d Porous Intervals > 8% Multiple “Hybrid” Reservoir Targets Over 400 ft Interval P en n s y lv anian S h al e Cored Interval Top Strawn Pennsylvanian-Lower Wolfcamp D Oil Shale Note: All acreage at January 7, 2016.
One of the primary source rocks for Twin Lakes prospect area (~42,300 gross and ~29,900 net acres) Super-charged area having produced 1.3 billion Bbl oil and 2.2 trillion cubic feet natural gas Drilled initial data collection well (Olivine State #1) to obtain full set of whole cores and geophysical logs Horizontal well to test Wolfcamp D planned in Q4 2016 after analyzing data for optimal landing target Testing New Oil Shale Play in Twin Lakes Prospect 62 M ic ro -C o u p le d C o u p le d M ic ro -C o u p le d Porous Intervals > 8% Multiple “Hybrid” Reservoir Targets Over 400 ft Interval P en n s y lv anian S h al e Cored Interval Top Strawn Core chip from Wolfcamp D Shale with oil fluorescence Pennsylvanian-Lower Wolfcamp D Oil Shale
Midstream Operations and 2016 Plans NYSE: MTDR Matthew D. Spicer – Vice President and General Manager of Midstream Matthew V. Hairford – President
64 Longwood Gathering and Disposal Systems(1) in Delaware Basin Loving County, TX Gas gathering Water gathering Salt water disposal Oil gathering Cryogenic gas processing plant Sold to EnLink Eddy County, NM Gas gathering and compression Cryogenic gas processing plant Water gathering (under evaluation) Salt water disposal (under evaluation) (1) Longwood Gathering and Disposal Systems, LP is an indirect wholly owned subsidiary of Matador Resources Company.
65 Wolf - Loving County, TX – Significant Midstream Footprint Gas Gathering Water Gathering Salt Water Disposal Oil Gathering Matador Acreage Note: All acreage at January 7, 2016.
66 Rustler Breaks - Eddy County, NM – Repeating the Proven Wolf Model Gas gathering and compression Cryogenic gas processing plant Water gathering (under evaluation) Salt water disposal (under evaluation) Matador Acreage Note: All acreage at January 7, 2016.
Midstream Initiatives Growing into Respectable Business 67 Expect to spend ~$40 million on midstream initiatives in the Delaware Basin in 2016 Matador expects Longwood to be able to support its own sources of financing Monetization of midstream assets could be a significant source of funding for Matador in 2016 Projected 2016 cash flow for Midstream is expected to be approximately $20 million(1) (1) Estimated cash flow excludes allocations for general and administrative and certain other expenses. Cash flow presented is not necessarily incremental to Matador’s other businesses.
Summary; Q&A NYSE: MTDR
February 3, 2016 2016 Analyst Day Presentation NYSE: MTDR
Appendix
71 Eagle Ford – “Oil Bank” Note: All acreage at January 7, 2016. Some tracts not shown on map. Karnes Uvalde Medina Zavala Frio Dimmit La Salle Webb Atascosa McMullen Live Oak Bee Goliad Dewitt Gonzales Wilson 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 Harris Newman Pena ZLS Carroll Lloyd Hurt Sojourner Sickenius Lyssy Falls City Pawelek Danysh Bishop-Brogan Campbellton-Haverlah Matador Resources Acreage Thiel Martin EAGLE FORD ACREAGE TOTALS ~39,000 gross / ~29,300 net acres EAGLE FORD “EAST” Measured Depth: 17,000’ – 18,000’ 80-acre spacing EAGLE FORD “CENTRAL” Measured Depth: 15,500’ – 16,500’ 40-50 acre spacing EAGLE FORD “WEST” Measured Depth: 12,500’ – 14,500’ 40-50 acre spacing
Haynesville Operations 72 5 gross (0.6 net) wells expected to be drilled and completed in the Haynesville in 2016 Estimated capital expenditures of ~$4 million 9 gross (1.9 net) Elm Grove wells operated by Chesapeake turned to sales in early 2016 ˗ Initial rates of ~13 MMcf/d of natural gas with drilling and completion costs of ~$7 million per well Haynesville and Cotton Valley average daily natural gas production currently ~50 MMcf/d(1) with recent well additions 2016 Haynesville Non-Op Program 2015 Haynesville Non-Op Program 22 gross (1.9 net) wells turned to sales throughout Tier 1 Haynesville in 2015 Includes 9 gross (1.6 net) wells turned to sales on Elm Grove properties operated by Chesapeake in 2015 (shown on map at left) ˗ Chesapeake deferred first production on 9 gross (1.9 net) wells drilled and completed in 2015 until early Q1 2016 Note: All acreage at January 7, 2016. (1) As of January 31, 2016. Currently Producing Currently Drilling Anticipated Future Wells Producing Wells Currently Drilling or Completing Anticipated Future Wells 14N 12W 15N 11W Elm Grove Development – Chesapeake Operated Matador Acreage
0 25 50 75 100 125 150 175 200 $2.00 $2.25 $2.50 $2.75 $3.00 $3.25 $3.50 $3.75 $4.00 R a te o f R e turn (% ) Natural Gas Price ($/Mcf) $6 MM D&C Cost $7 MM D&C Cost $8 MM D&C Cost Economics of Tier 1 Haynesville Well (10 Bcf) in Elm Grove 73 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. 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 of ~$0.48/MMBtu due to taking gas in kind Longer laterals and better completion techniques
Board of Directors – Expertise and Stewardship 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 & Development 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 Carlos M. Sepulveda, Jr. Director - Executive 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 Don C. Stephenson Director - Retired Partner, Baker Botts L.L.P. Law and Tax Strategy George M. Yates Director - Chairman & CEO of HEYCO Energy Group, Inc. Oil and Gas Exploration & Development 74
Special Board Advisors Professional Experience Business Expertise Ronney F. Coleman - Retired President – North America, Archer - Former Vice President North America Pumping, BJ Services Co. Oilfield Services Marlan W. Downey - Retired President, ARCO International - Former President, Shell Pecten International - Past President of American Association of Petroleum Geologists Oil and Gas Exploration John R. Gass - VP, Eastern Hemisphere Operations, Nabors Drilling International Limited based in Dubai, UAE - Previously spent 28 years with Parker Drilling Company in various management roles Oil and Gas Drilling David F. Nicklin - Retired Executive Director of Exploration, Matador Resources Company Oil and Gas Exploration Wade I. Massad - Managing Member, Cleveland Capital Management, LLC - Formerly with KeyBanc Capital Markets and RBC Capital Markets Capital Markets Greg L. McMichael - Retired Vice President and Group Leader – Energy Research of A.G. Edwards Capital Markets Dr. James D. Robertson - Retired VP Exploration, Chief Geophysicist, ARCO International Oil and Gas Exploration Michael C. Ryan - Partner, Berens Capital Management - Former Director, Matador Resources Company International Business and Finance W.J. “Jack” Sleeper, Jr. - Retired President, DeGolyer and MacNaughton (Worldwide Petroleum Consultants) Oil and Gas Executive Management Special Board Advisors – Expertise and Stewardship 75
Proven Management Team – Experienced Leadership Management Team Background and Prior Affiliations Industry Experience Matador Experience Joseph Wm. Foran Founder, Chairman and CEO - Matador Petroleum Corporation, Foran Oil Company, James Cleo Thompson Jr. 35 years Since Inception Matthew V. Hairford President, Chair of Operating Committee - Samson, Sonat, Conoco 31 years Since 2004 David E. Lancaster EVP and CFO - Schlumberger, S.A. Holditch & Associates, Inc., Diamond Shamrock 36 years Since 2003 Craig N. Adams EVP – Land, Legal & Administration - Baker Botts L.L.P., Thompson & Knight LLP 22 years Since 2012 Van H. Singleton, II EVP – Land - Southern Escrow & Title, VanBrannon & Associates 19 years Since 2007 Bradley M. Robinson VP – Reservoir Engineering and CTO - Schlumberger, S.A. Holditch & Associates, Inc., Marathon 38 years Since Inception Billy E. Goodwin VP – Drilling - Samson, Conoco 31 years Since 2010 G. Gregg Krug VP and Head of Marketing and Midstream - Williams Companies, Samson, Unit Corporation 32 years Since 2005 Matthew D. Spicer VP and General Manager of Midstream - Matador Resources Company 2 years Since 2014 Trent W. Green VP – Production - HEYCO, Bass Enterprises, Schlumberger, S.A. Holditch & Associates, Inc., Amerada Hess 26 years Since 2015 Robert T. Macalik VP and CAO - Pioneer Natural Resources, PricewaterhouseCoopers (PwC) 13 years Since 2015 Kathryn L. Wayne Controller and Treasurer - Matador Petroleum Corporation, Mobil 31 years Since Inception 76
77 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 pro forma, forward-looking, preliminary estimates or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. The Company could not provide such reconciliations without undue hardship because such Adjusted EBITDA numbers 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.
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. 78 (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 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 Interest expense 106 184 171 222 308 1 144 549 1,271 1,609 2,038 768 Total income tax provision (benefit) (6,906) (46) - 1,430 3,064 (3,713) (593) (188) 46 32 2,563 7,056 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 Accretion of asset retirement obligations 39 57 62 51 53 58 59 86 81 80 86 100 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 Stock-based compensation expense 53 128 1,234 991 (363) 191 (51) 363 492 1,032 1,239 1,134 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 (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 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 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) Interest expense, net of non-cash portion 106 184 171 222 308 1 144 549 1,271 1,609 2,038 768 Current income tax (benefit) provision - (45) (1) - - - 188 (188) 46 32 902 (576) Net (income) loss attributable to non-controlling interest in subsidiary - - - - - - - - - - - - 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 (In thousands) 1Q 2014 2Q 2014 3Q 2014 4Q 2014 1Q 2015 2Q 2015 3Q 2015 Unaudited Adjusted EBITDA reconciliation to Net (loss) Income: Net (loss) income $ 16,363 $ 18,226 $ 29,619 $ 46,563 $ (50,234) $ (157,091) $ (242,059) Interest expense 1,396 1,616 673 1,649 2,070 5,869 7,229 Total income tax provision (benefit) 9,536 10,634 16,504 27,701 (26,390) (89,350) (33,305) Depletion, depreciation and amortization 24,030 31,797 35,143 43,767 46,470 51,768 45,237 Accretion of asset retirement obligations 117 123 130 134 112 132 182 Full-cost ceiling impairment - - - - 67,127 229,026 285,721 Unrealized (gain) loss on derivatives 3,108 5,234 (16,293) (50,351) 8,557 23,532 (6,733) Stock-based compensation expense 1,795 1,834 1,038 857 2,337 2,794 1,755 Net loss on asset sales and inventory impairment - - - - 97 - - Adjusted EBITDA $ 56,345 $ 69,464 $ 66,814 $ 70,320 $ 50,146 $ 66,680 $ 58,027 (In thousands) 1Q 2014 2Q 2014 3Q 2014 4Q 2014 1Q 2015 2Q 2015 3Q 2015 Unaudited Adjusted EBITDA reconciliation to Net Cash Provided by Operating Activities: Net cash provided by operating activities $ 31,945 $ 81,530 $ 66,883 $ 71,123 $ 93,346 $ 20,043 $ 72,535 Net change in operating assets and liabilities 21,729 (15,221) (586) 56 (45,234) 40,843 (20,846) Interest expense, net of non-cash portion 1,396 1,616 673 1,649 2,070 5,869 6,678 Current income tax (benefit) provision 1,275 1,539 (156) (2,525) - - (295) Net (income) loss attributable to non-controlling interest in subsidiary - - - 17 (36) (75) (45) Adjusted EBITDA $ 56,345 $ 69,464 $ 66,814 $ 70,320 $ 50,146 $ 66,680 $ 58,027
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. 79 Note: LTM is last 12 months. LTM at (In thousands) 2008 2009 2010 2011 2012 2013 2014 9/30/2015 Unaudited Adjusted EBITDA reconciliation to Net Income (Loss): Net income (loss) $103,878 ($14,425) $6,377 ($10,309) ($33,261) $45,094 $110,771 ($402,821) Interest expense - - 3 683 1,002 5,687 5,334 16,817 Total income tax (benefit) provision 20,023 (9,925) 3,521 (5,521) (1,430) 9,697 64,375 (121,344) Depletion, depreciation and amortization 12,127 10,743 15,596 31,754 80,454 98,395 134,737 187,242 Accretion of asset retirement obligations 92 137 155 209 256 348 504 560 Full-cost ceiling impairment 22,195 25,244 - 35,673 63,475 21,229 - 581,874 Unrealized loss (gain) on derivatives (3,592) 2,375 (3,139) (5,138) 4,802 7,232 (58,302) (24,995) Stock-based compensation expense 665 656 898 2,406 140 3,897 5,524 7,743 Net (gain) loss on asset sales and inventory impairment (136,977) 379 224 154 485 192 - 97 Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $262,943 $245,173 LTM at (In thousands) 2008 2009 2010 2011 2012 2013 2014 9/30/2015 Un udited 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 $251,481 $257,047 Net change in operating assets and liabilities (17,888) 15,717 (2,230) (12,594) (9,307) 6,210 5,978 (25,181) Interest expense, net of non-cash portion - - 3 683 1,002 5,687 5,334 16,266 Current income tax (benefit) provision $10,448 ($2,324) (1,411) (46) - 404 133 (2,820) Net (income) loss attributable to non-controlling interest in subsidiary - - - - - - 17 (139) Adjusted EBITDA $18,411 $15,184 $23,635 $49,911 $115,923 $191,771 $262,943 $245,173 Year Ended December 31, Year Ended December 31,
80 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. We have not provided a reconciliation of PV-10 to Standardized Measure at December 31, 2015. We could not provide such a reconciliation without undue hardship because we have not completed the audit of our December 31, 2015 financial statements. In addition, it would be difficult for us to present a detailed reconciliation on account of many unknown variables for the reconciling items. At December 31, 2013 At December 31, 2014 At September 30, 2015 PV-10 (in millions) $655.2 $1,043.4 $692.7 Discounted Future Income Taxes (in millions) $(76.5) $(130.1) $(18.9) Standardized Measure (in millions) $578.7 $913.3 $673.8