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) December 6, 2012
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:
| ¨ | Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425) |
| ¨ | Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12) |
| ¨ | Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b)) |
| ¨ | Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c)) |
| Item 7.01 | Regulation FD Disclosure. |
Attached hereto as Exhibit 99.1 is a press release (the “Press Release”) issued by Matador Resources Company (the “Company”) on December 6, 2012 announcing its 2013 capital budget. The Press Release is incorporated by reference into this Item 7.01, 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 December 6, 2012 at which it intends to make a presentation concerning its 2013 capital investment plan. 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 7.01, 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, and will not be incorporated by reference into any filing under the Securities Act of 1933, as amended, unless specifically identified therein as being incorporated therein by reference.
| Item 9.01 | Financial Statements and Exhibits. |
(d) Exhibits
| Exhibit |
Description of Exhibit | |
| 99.1 | Press Release, dated December 6, 2012. | |
| 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: December 5, 2012 | By: | /s/ David E. Lancaster | ||||
| Name: | David E. Lancaster | |||||
| Title: | Executive Vice President | |||||
Exhibit Index
| Exhibit |
Description of Exhibit | |
| 99.1 | Press Release, dated December 6, 2012. | |
| 99.2 | Presentation Materials. | |
Exhibit 99.1
MATADOR RESOURCES COMPANY ANNOUNCES 2013 CAPITAL BUDGET
DALLAS, Texas, December 6, 2012 — Matador Resources Company (NYSE: MTDR) (“Matador” or the “Company”), an independent energy company currently focused on the oil and liquids rich portion of the Eagle Ford shale play in South Texas, today announced its 2013 capital budget and drilling plan, which include the following:
| • | 2013 capital budget of $310 million, including $260 million for drilling and completions, $25 million for pipelines and facilities, and $25 million for land and seismic data |
| • | 2013 guidance of 1.6 to 1.8 million barrels of oil production, up about 40% from 2012 |
| • | 2013 guidance of 11 to 12 Bcf of natural gas production, down about 8% from 2012 |
| • | 2013 oil and natural gas revenue guidance of $200 to $220 million, up about 40% from expected $145 to $155 million in 2012 |
| • | 2013 Adjusted EBITDA guidance of $140 to $160 million, up about 33% from expected 2012 Adjusted EBITDA of $110 to $115 million |
| • | The Company anticipates financing the 2013 capital budget through internal cash flows plus growth in borrowings under its previously announced bank facility |
Matador Analyst Day
This morning Matador will be hosting an Analyst Day at 10:00 a.m. Central Time at the Company’s headquarters in Dallas, Texas. Management will host a live conference call to provide its 2013 operational plan, capital budget and forecasts, plus an update on its current operations.
Joseph Wm. Foran, Matador’s Chairman, President and CEO, commented, “Our 2013 capital budget will allow us to continue our successful development program in our Eagle Ford acreage in South Texas, which will include about 80% of our drilling budget. We will also begin exploration of our Delaware Basin acreage in West Texas and Southeastern New Mexico. In the meantime, we will continue to monitor developments in the natural gas market, as our important acreage in the Tier 1 area of the Haynesville should generate very attractive drilling opportunities with modestly higher gas prices. This plan allows us to grow production and EBITDA meaningfully while spending slightly less money than we did in 2013, all anticipated to be financed through our own cash flows and increased borrowings under our bank facility.”
Conference Call Information and Investor Presentation
To access the conference call, domestic participants should dial (866) 356-4279 and international participants should dial (617) 597-5394. The participant passcode is 27539641. The Analyst Day presentation will also be available via live webcast by using the following link http://phoenix.corporate-ir.net/phoenix.zhtml?p=irol-eventDetails&c=248247&eventID=4876960 and through the Company’s website at www.matadorresources.com on the Presentations & Webcasts page under the Investors tab.
A replay of the Analyst Day presentation will be made available through Friday, January 4, 2012 via dial-in and webcast. Domestic participants should dial (888) 286-8010 and international participants should
dial (617) 801-6888. The replay dial-in participant passcode is 26549459. 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 is 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 a particular emphasis on oil and natural gas shale plays and other unconventional resource plays. Its current operations are located primarily in the Eagle Ford shale play in South Texas and the Haynesville shale play in Northwest Louisiana and East Texas.
For more information, visit Matador Resources Company at www.matadorresources.com.
Forward-Looking Statements
This press release includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-looking statements” are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as “could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,” “potential,” “project” and similar expressions that are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but not limited to, the following risks related to financial and operational performance: general economic conditions; our ability to execute our business plan, including whether our 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; 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; ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute our business plan, including from future cash flows, increases in borrowing base and otherwise; weather and environmental concerns; 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 Annual Report on Form 10-K for the year ended December 31, 2011. Matador undertakes no obligation and does not intend to update these forward-looking statements to reflect events or circumstances occurring after this press release, except as required by law. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the
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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 forward-looking 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. 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
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December 6, 2012 Matador Resources Analyst Day Exhibit 99.2
Safe Harbor Statement – This presentation and statements made by representatives of Matador Resources Company (“Matador” or the “Company”) during the course of this presentation include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. “Forward-looking statements” are statements related to future, not past, events. Forward-looking statements are based on current expectations and include any statement that does not directly relate to a current or historical fact. In this context, forward-looking statements often address expected future business and financial performance, and often contain words such as “could,” “believe,” “would,” “anticipate,” “intend,” “estimate,” “expect,” “may,” “should,” “continue,” “plan,” “predict,” “potential,” “project” and similar expressions that are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. Actual results and future events could differ materially from those anticipated in such statements, and such forward-looking statements may not prove to be accurate. These forward-looking statements involve certain risks and uncertainties, including, but not limited to, the following risks related to our financial and operational performance: general economic conditions; our ability to execute our business plan, including whether our 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; our ability to replace reserves and efficiently develop our current reserves; our costs of operations, delays and other difficulties related to producing oil, natural gas and natural gas liquids; our ability to make acquisitions on economically acceptable terms; availability of sufficient capital to execute our business plan, including from our future cash flows, increases in our borrowing base, joint venture partners 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 Annual Report on Form 10-K for the year ended December 31, 2011. 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. You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. All forward-looking statements are qualified in their entirety by this cautionary statement.
Cautionary Note – The Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves. Potential resources are not proved, probable or possible reserves. The SEC’s guidelines prohibit Matador from including such information in filings with the SEC.
Matador’s Continued Growth
TOTAL OIL AND
NATURAL GAS REVENUES
ADJUSTED EBITDA(1)
in millions
$14.0 $30.6 $19.0 $34.0 $67.0 $150.0 $210.0
in millions $8.1 $18.4$15.2$23.6 $49.9 $112.5 $150.0
Year Ended December 31,
Year Ended December 31,
(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
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2013 Capital Investment Plan
2013 Capital Investment Plan Highlights 5 2013 projected capital expenditures of approximately $310 million Drill and complete or participate in 48 gross/31.3 net wells in 2013 Includes approximately $25 million for pipelines/facilities and $25 million for land/seismic acquisition Maintain financial discipline by funding 2013 capital expenditures through operating cash flows and borrowings under revolving credit facility 2013 oil production volumes well hedged to protect cash flows below about $88/Bbl oil price 2013 Production Expectations Oil production of 1.6 to 1.8 million barrels – up about 40% from 2012 Natural gas production of 11.0 to 12.0 Bcf – down about 8% from 2012 2013 Financial Expectations Oil and natural gas revenues(1) of $200 to $220 million – up about 40% from estimated $145 to $155 million in 2012 Adjusted EBITDA(1)(2) of $140 to $160 million – up about 33% from estimated $110 to $115 million in 2012 Total borrowings outstanding estimated to be $310 to $320 million at YE 2013 * Estimated using a conversion ratio of 1 Bbl = 6 Mcf (1) Estimated 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range using late November 2012 strip prices for oil and natural gas, plus property-specific differentials. Estimated average realized prices for oil and natural gas were $94.00/Bbl and $4.43/Mcf, respectively (2) 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
6 2013 Oil Production(1) Estimated total oil production of 1.6 to 1.8 million barrels Increase of approximately 40% from 2012 Oil production expected to decline from current levels of 5,000 Bbl/d during first half of 2013 Production delays, shut-ins due to pad drilling, zipper fracs, etc. Oil production expected to return to above 5,000 Bbl/d during second half of 2013 2013 Natural Gas Production (1) Estimated total natural gas production of 11.0 to 12.0 Bcf Decrease of approximately 8% from 2012 Gas production expected to remain relatively flat during 2013, but should include higher percentage of liquids-rich gas 2013 Production Expectations (1)Estimated quarterly average oil and natural gas production at midpoint of guidance range Oil Production* (Bbl/d) Natural Gas Production* (MMcf/d)
7 2013 Revenue and Adjusted EBITDA(1)(2) Estimated oil and natural gas revenues of $200 to $220 million Increase of approximately 40% from estimated $145 to $155 million in 2012 Estimated Adjusted EBITDA(1) of $140 to $160 million Increase of approximately 33% from estimated $110 to $115 million in 2012 Adjusted EBITDA(1)(2) growth expected to be impacted by lower oil price realizations and an estimated decrease of about $13 million in realized hedging gains compared to 2012 2013 Operating Costs Estimated average unit costs per BOE Production taxes/marketing = $4.10 Lease operating = $8.20 G&A = $4.70 Operating cash costs, excluding interest = $17.00 DD&A = $29.50 2013 Financial Expectations (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 2013 oil and natural gas revenues and Adjusted EBITDA at midpoint of production guidance range using late November 2012 strip prices for oil and natural gas, plus property-specific differentials. Estimated average realized prices for oil and natural gas were $94.00/Bbl and $4.43/Mcf, respectively Oil and Natural Gas Revenues(2) (millions) Adjusted EBITDA(1)(2) (millions)
Funding for 2013 Capital Investment Plan 8 Maintain financial discipline by anticipated funding of 2013 capital expenditures through operating cash flows and borrowings under revolving credit facility Most of 2013 Eagle Ford program is development drilling and largely de-risked by 2012 results 1.5 million barrels of 2013 oil production hedged protecting cash flows below about $88/Bbl oil price Credit facility status at December 6, 2012 Borrowing base of $200 million; total facility size of $500 million; facility matures in December 2016 Negotiating borrowing base increase expected to close before December 31, 2012 Borrowings outstanding of $135 million Estimated borrowings outstanding of $150 to $160 million at December 31, 2012 Ability to request quarterly borrowing base increases with growth in oil and natural gas reserves throughout 2013 Estimated borrowings outstanding of $310 to $320 million at YE 2013 Additional flexibility to manage liquidity No long-term drilling rig or service contract commitments $25 million estimated for discretionary land/seismic acquisitions No significant non-operated well obligations Simple capital structure; no high-yield debt or convertibles on balance sheet
9 2013 Hedging Profile 1.5 million barrels of oil hedged for 2013 at weighted average floor and ceiling of $88/Bbl and $107/Bbl, respectively 4.7 Bcf of natural gas hedged at weighted average floor and ceiling of $3.34/MMBtu and $4.84/MMBtu, respectively 4.9 million gallons of natural gas liquids hedged at weighted average price of $0.79/gal
10 Continued Oil/Liquids Focus to Fuel 2013 Growth
2013 South Texas Plan 12 2013 projected capital expenditures of approximately $250 million or about 80% of total Drill and complete or participate in 34 gross/27.4 net wells Assumes about 33% of 2013 land/seismic budget will be directed to South Texas Most of 2013 Eagle Ford program is development drilling and largely de-risked by 2012 results Almost all of South Texas capital budget directed to Eagle Ford shale Three exploratory tests planned in Austin Chalk, Buda, Edwards at cost of about $8 million Austin Chalk test will be an operated well; Buda, Edwards tests are outside operated Key objectives of 2013 South Texas plan Capitalize on experience to improve well performance and operational efficiencies in the Eagle Ford Sequential drilling operations (e.g., pad drilling) on key properties to continue to reduce drilling costs Sequential, simultaneous stimulation operations (e.g., zipper fracs) to reduce costs, eliminate shut-in periods and reduce recovery times for existing wells and eliminate need to stimulate across wells multiple times Continue to study and test other horizons and to address lease maintenance issues, particularly on properties scheduled for further development in 2014 and beyond Leverage technology to increase recovery of hydrocarbons in place
Matador’s Producing Eagle Ford Wells in South Texas
EAGLE FORD ACREAGE TOTALS 44,326 gross / 29,555 net acres
EAGLE FORD EAST 7,568 gross / 6,171 net acres
EOG OPERATED, MTDR WI ~21% 13,055 gross / 2,515 net acres
GLASSCOCK (WINN) RANCH 8,891 gross / 8,891 net acres
# - Eagle Ford Wells completed and producing; Operated by Matador unless noted otherwise
Total of 34 gross/28.7 net wells completed and producing
EAGLE FORD WEST 14,812 gross / 11,978 net acres
Matador Resources Acreage
Note: All acreage values, number of producing wells and number of estimated Eagle Ford drilling locations at November 30, 2012. Net wells reflect Matador’s working interest ownership
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2013 South Texas Drilling Plan
EAGLE FORD ACREAGE TOTALS 44,326 gross / 29,555 net acres
EAGLE FORD EAST 7,568 gross / 6,171 net acres
EOG OPERATED, MTDR WI ~21% 13,055 gross / 2,515 net acres
GLASSCOCK (WINN) RANCH 8,891 gross / 8,891 net acres
Potential Remaining Eagle Ford Drilling Locations
214 gross/164 net locations
Tier 1 – 107 gross/78 net locations (80-acre spacing)
Tier 2 – 107 gross/86 net locations (primarily Glasscock Ranch and Sutton, both HBP, 80 to 120-acre spacing)
No Eagle Ford locations estimated for Atascosa acreage
Numbers do not include any potential locations for other horizons – e.g., Austin Chalk, “Chalkleford”, Buda, Pearsall
*At December 31, 2012
EAGLE FORD WEST 14,812 gross / 11,978 net acres
Matador Resources Acreage
Note: All acreage values, number of producing wells and number of estimated Eagle Ford drilling locations at November 30, 2012. Net wells reflect Matador’s working interest ownership
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2013 Delaware Basin Plan 15 2013 projected capital expenditures of approximately $48 million or about 15% of total Drill and complete 3 gross/3 net test wells Assumes about 50% of 2013 land/seismic budget will be directed to West Texas Key objectives of 2013 Delaware Basin plan Leverage and transfer knowledge from Eagle Ford and Haynesville experience to Delaware Basin and begin testing acreage position Multiple targets in Wolfcamp and Bone Spring and 3-well program will test both Drill wells, gather core and petrophysical data and monitor initial results; build necessary infrastructure before starting continuous drilling If tests are successful, would set up 2014 (and beyond) continuous drilling program Satisfy lease maintenance on Ranger prospect and acquire additional interests in Wolf and Ranger prospect areas Approximately 90% of Wolf prospect is HBP and the remaining 10% was leased in 2012, so no near-term time constraints Acquire additional interests in Delaware Basin with success on initial test wells
Delaware Basin Acreage and 2013 Drilling Plan RANGER EDDY LEA LOVING WOLF DELAWARE BASIN PROSPECTIVE ACREAGE 7,498 gross / 4,928 net acres RANGER 1,955 gross / 1,562 net acres WOLF 5,203 gross / 2,977 net acres #—Matador operated wells planned in 2013 3 gross/3 net horizontal wells planned in 2013 1 1 1 Ranger A1 Primary Target: 2nd Bone Spring Sand Wolf 1 Primary Target: Wolfcamp Shale Matador’s acreage position shown in red. Note: Certain additional Matador acreage in West Texas/Southeast New Mexico not considered prospective at November 30, 2012 Ranger A2 Primary Target: Wolfcamp Shale 16
2013 Tier 1 Haynesville Shale Plan 17 2013 projected capital expenditures of approximately $5 million or about 2% of total Estimated participation in 10 gross/0.5 net wells 2013 capital plan includes no Matador operated Haynesville wells Haynesville/Cotton Valley acreage in Northwest Louisiana and East Texas is essentially all held by existing production Operational flexibility to drill operated Haynesville shale well(s) in 2013 should gas prices continue to improve Haynesville/Cotton Valley represent large “gas bank” providing significant and increasing value if gas prices return to $4.00/Mcf and higher Tier 1 Haynesville potential resource(1) – 250 to 310 Bcf net to Matador Tier 1 + Tier 3 Haynesville potential resource(1) – 470 to 600 Bcf net to Matador Elm Grove Cotton Valley potential resource(1) – 135 to 170 Bcf net to Matador (1) Potential resource should not be considered proved natural gas reserves. Potential resource may be converted to proved natural gas reserves as a result of successful drilling operations and higher natural gas price, Matador does not include any of this potential resource in its proved natural gas reserves at September 30, 2012
Tier 1 Haynesville and Elm Grove Cotton Valley Acreage Positions Note: All acreage at November 30, 2012 CADDO BOSSIER BIENVILLE RED RIVER DESOTO Elm Grove Cotton Valley: 49 Net Locations Matador Operated Acreage: 9,980 gross, 9,800 net Locations: 71 gross, 49 net (@ 3-4 locations/section) Potential Resource(1): 135 – 170 Bcf net Tier 1 Haynesville: 50 Net Locations Acreage: 12,560 gross, 5,730 net Locations: 397 gross, 50 net (@ 7 locations/section) Potential Resource(1): 250 – 310 Bcf net MTDR CV Horizontal T. Walker #1H MTDR Haynesville L.A. Wildlife #1H MTDR Haynesville Williams (BLM) #1H TIER 1: 6 – 10+ Bcf TIER 2: 4 – 6 Bcf TIER 3: 2 – 4 Bcf (1) Potential resource should not be considered proved natural gas reserves. Potential resource may be converted to proved natural gas reserves as a result of successful drilling operations and higher natural gas price, Matador does not include any of this potential resource in its proved natural gas reserves at September 30, 2012 18
Eagle Ford Operations South Texas
2012 Drilling Program Takeaways Reduced drill times and costs related to operational efficiency Rotary steerable tools have specific advantages Improved fracture stimulation efficiency and cost reductions Fluid volume utilized in fracture stimulation affects well performance Improvements realized with closer perforation cluster spacing Benefits of bottom hole pressure management via restricted chokes Interference evident while fracture stimulating offset wells Artificial lift will be necessary and should add value Program style drilling and completing should be advantageous 20
Drilling Times and Efficiencies 21 First 4 Wells Last 4 Wells *Bold wells utilized rotary steerable systems
2012 Normalized Well Costs 21
2012 Normalized Well Costs
Eagle Ford East Total Well Costs
$14,000,000 $12,000,000 $10,000,000
Cost $8,000,000
Well al
Tot $6,000,000
$4,000,000
$2,000,000
Total Cost
5000’ Normalized Cost
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Geo-Steering—Conventional Directional Tools 23 Measured Depth (ft.) True Vertical Depth (ft.) Top Eagle Ford Top Britton Top Target Mid Target Base Target Pepper Sh. Buda Ls.
Geo-Steering—Rotary Steerable Directional Tools 24 Measured Depth (ft.) True Vertical Depth (ft.) Eagle Ford Top Britton Top Target Mid Target Base Target Pepper Sh. Buda Ls.
Average Frac Stage Cost per Well 25 Note: Wells are displayed in chronological order
Fracture Stimulation Comparison 26 #2H #1H
Stimulation Design Evaluation Well No. 1H – 5,200 BBL / 400,000 lb. frac. 49 foot cluster spacing Well No. 2H – 7,500 BBL / 350,000 lb. white sand + 50,000 lb. 100 mesh. 40 foot cluster spacing Well No. 2H communicated with Well No. 1H during frac Well No. 1H production temporarily went from 100 BOPD to 0 BOPD and from 10 BWPD to over 100 BWPD Well No. 1H production relatively normal after flow-back on Well No. 2H 27
Fluid Volumes/Tighter Spacing/Restricted Choke Cumulative Production Comparison 28 (CHART)
Note: Through November 30, 2012.
Offset Well Frac Effects
BWPD
Mcf/d
BOPD
2000 1800 1600 1400 1200 1000 800 600 400 200
2/1/2012 3/1/2012 4/1/2012 5/1/2012 6/1/2012 7/1/2012 8/1/2012 9/1/2012 10/1/2012 11/1/2012
1,400 1,200 1,000 800 600 400 200 0
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Zipper Frac/Back to Back and Associated Downtimes 30 (CHART) Downtime to Frac Offset
Artificial Lift and Production Management Artificial Lift Eleven wells on rod pump Evaluating gas lift and electrical submersible pumps Challenges Flow characteristics during flowing to pumping operations transition Mechanical issues related to rod pumping Scale and paraffin Offset frac effects Solutions Restricted choke flow delays need for artificial lift Installing pump-off controllers on pumping units to maintain fluid levels Treating frac fluid and pumping wellbores with chemical additions Evaluating shut-in times prior to offset fracs 39
Matador 2013 Planned Operated Drilling Schedule Drilling Stimulation Shut-in Producing 34 2-rig equivalent drilling program in 2013; Delaware Basin tests starting in Q2 2013 Note: The Company’s 2013 drilling schedule is based on management’s current expectations regarding the time necessary to drill, fracture and complete each well, as well as the time adjacent wells will be shut in as a result of fracking operations
2012 Matardor South Texas Operated Drilling Schedule Drilling Stimulation Shut-in Producing 33
Note: Includes wells drilled or completed by December 31, 2012. The Company’s 2013 drilling schedule is based on managements current expectations regarding the time necessary to drill, fracture and complete each well as well as the time adjacent wells will be shut in as a result of fracking operations
Martin Ranch Development Plan 35
Martin Ranch Development Plan 36
Martin Ranch Development Plan 37
Martin Ranch Development Plan 38
2013 Operational Plans Develop acreage blocks with program type drilling Pad drilling Reduced mobilization time and costs Limit offset well frac issues Manage shut-in periods for producing wells Provide for both drilling and completion optimization Continue to optimize completion design Evaluate current and future stimulation designs Optimize perforation cluster spacing Experiment and evaluate fluid types and volumes Continue completion technique evolution to maximize value Production Stay in front of drilling rigs with production facilities Utilize bottom hole pressure management via restricted choke sizes Continue to implement and optimize artificial lift operations 40
Geology Update
Continue the study of the Eagle Ford in South Texas: Help transform Tier 2 play areas to Tier 1 Focus on 3D seismic and fracture studies (e.g., Glasscock Ranch) Support operations through integrated, multi-disciplinary studies Evaluate additional prospective plays in South Texas: Buda Limestone, Austin Chalk, Pearsall Shale, Edwards Limestone: Drill three exploratory wells: One operated (Austin Chalk), two non-operated (Buda and Edwards) Obtain 3D seismic and sub-surface studies for production “sweet-spots” Begin the realization of potential in West Texas and New Mexico: Wolfcamp and Bone Spring Formations: Three exploratory wells Leverage our knowledge and experience gained in the Eagle Ford Evaluate what/where next: “Gracie”: Crawford Federal #1H horizontal well results Additional regional studies and “spear-point” play development: Proven petroleum systems; Tier map system consistent with the principles we have learned to date (e.g., TOC-Por-Perm relationships) Geoscience Goals and Objectives in 2013 42
South Texas Eagle Ford Trend—Multi-Play Fairway Historic Conventional Zones Olmos-Navarro Gas and oil fields in shallow section Austin Chalk Upper Austin Chalk horizontal drilling Fractured reservoir Buda Primarily productive on structure Fractured reservoir Edwards Productive on structure “New” Unconventional Zones “Chalkleford” (Eagle Ford / Austin Chalk transition zone) Recent results in Pearsall Field from other operators are positive Eagle Ford Lower costs combined with better completion techniques have improved initial results in northern oil window Horizontal Buda Drilling Exploratory play developing to exploit fracturing within the Buda both on and off structure Pearsall Shale Exploratory play, initial test wells now being drilled Conventional Unconventional Austin Chalk Eagle Ford Buda Georgetown Del Rio Edwards Glen Rose Rodessa Pearsall Sligo Olmos Navarro ANCC 41
Glasscock Ranch Study
GLASSCOCK (WINN) RANCH
8,891 gross / 8,891 net acres
Goal: Transform Tier 2 to Tier 1.5?
Multiple Target Study:
- Eagle Ford
- “Chalkleford”
- Buda
- Pearsall
- Olmos/San Miguel
Eagle Ford and “Chalkleford” production history and logs indicate large oil volumes in place
Actively trading data, logs very comparable with offset producers
Fractures play significant role
Increased stimulated rock volume may lead to higher recovery
3D Seismic should enable accurate fracture mapping; to be acquired in June-August
Multi-disciplinary (geoscience/engineering/operations) studies expected to develop better drilling and stimulation models to increase recovery factors
- Petrophysics
- Rock characterization
- Production monitoring
- 3D seismic integration
Held by production, all rights, all depths
Chesapeake Winterbotham A 1H 22 Eagle Ford 4 mo.cum:
55 MBO; 14 MMcf
1.5 miles
GR #1H EGFD ~50 Bbl/d 5 mo.cum: 13,460 BO
Olmos Potential
San Miguel Gas Prod.
GR #2H CHKFD ~35 Bbl/d 4 mo.cum: 5,260 BO
Note: Production data obtained from public sources
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Delaware Basin Target Horizons Delaware Group Depth: 5,800’ – 8,000’ (Oil Window) Density Porosity: 10-16% Normal Pressure (0.45 psi/ft) Gross Thickness: 30-60 ft IP: 27-514 Bbl/d 10-606 Mcf/d Lower Wolfcamp Depth: 12,200’ – 12,500’ (Wet Gas Window) Density Porosity: 6-15% Geo Pressured (0.7–0.75psi/ft) Gross Thickness: 180-290 ft Total Organic Carbon (TOC) 3-5% Graphic source: Core Lab; other information from public sources 46 Middle Wolfcamp depth: 11,800’ – 12,200’ (Wet Gas Window) Density Porosity: 12-15% Geo Pressured (0.7psi/ft) Gross Thickness: 200-300 ft Total Organic Carbon (TOC) 2-4%
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Delaware Basin Acreage and 2013 Drilling Plan RANGER EDDY LEA LOVING WOLF DELAWARE BASIN PROSPECTIVE ACREAGE 7,498 gross / 4,928 net acres RANGER 1,955 gross / 1,562 net acres WOLF 5,203 gross / 2,977 net acres #—Matador operated wells planned in 2013 3 gross/3 net horizontal wells planned in 2013 1 1 1 Ranger A1 Primary Target: 2nd Bone Spring Sand Wolf 1 Primary Target: Wolfcamp Shale Ranger A2 Primary Target: Wolfcamp Shale 47 Matador acreage position shown in red. Note: Certain additional Matador’s acreage in West Texas/Southeast New Mexico not considered prospective at November 30, 2012
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Ranger Prospect Area: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Concho Stratojet 31 State #1H 2nd Bone Spring 11 mo.cum: 243 MBO; 276 MMcf Cimarex Energy Lynch 23 Fed #1H 3rd Bone Spring 9 mo.cum: 130 MBO; 99 MMcf Legacy Operating Lee Unit 4H 3rd Bone Spring 13 mo.cum: 57 MBO; 55 MMcf Concho AirCobra 12 #2H 3rd Bone Spring 12 mo.cum: 196 MBO; 132 MMcf XOG Operating (Vertical well) Jordan B #1 Wolfcamp 20 years cum: 386 MBO; 5 Bcf Concho (Vertical well) Neuhaus 14 Fed #2 Wolfcamp 8 years cum: 156 MBO; 2 Bcf Proposed location for Matador 2013 test well. 46
Wolf Leasehold: Proposed Wolfbone Multi-Zone Exploration Program and Surrounding Results Wolf Energy Wolf #1 (Vertical well) 3rd BS / Upr Wolfcamp Cum Produc: 58 MBO; 620 MMcf Wolf Energy Dorothy White #1 (Vertical well) 3rd BS / Upr Wolfcamp Cum Produc: 25 MBO; 93 MMcf Chesapeake Johnson 1-88 Lov #1H Wolfcamp 10 mo.cum: 72 MBO; 295 MMcf Chesapeake Johnson 1-86 (1H) Wolfcamp 17 mo.cum: 122 MBO; 344 MMcf OXY Reagan-McElvain 1H Currently drilling Chesapeake Johnson 1-76 (1H) Wolfcamp 22 mo.cum: 140 MBO; 475 MMcf Energen – Currently completing Energen Black Mamba 1-57 Wolfcamp 3 mo.cum: 61 MBO; 180 MMcf Proposed location for Matador 2013 test well Anadarko Black Tip Johnson 1-39(1H) Wolfcamp 29 mo.cum: 234 MBO; 323 MMcf 47
Matador Gracie Project Total Prospect Acreage IDAHO UTAH WYOMING WYOMING WYOMING IDAHO UTAH WYOMING 54,450 gross acres 26,908 net acres Crawford Federal #1H 48
Southwest Wyoming Stratigraphy and Target Zones Lamberson, Paul, 1982, The Fossil Basin and its Relationship to the Absaroka Thrust System, Wyoming and Utah, RMAG 13% TOC Meade Peak Shale Cretaceous Shales 2% TOC Crawford Federal #1: Drilled straight hole 10/11 Encountered 161’ Meade Peak with 46’ of main pay Recovered 50’ conventional core across pay zone. TOCave 4.52% (Maximum 14.2%) Thermally mature: Ro 1.69% Porosity Average: 3.0– 5.0% Micro-Darcy Permeability 49
Appendix
53 Adjusted EBITDA Reconciliation This presentation includes, and certain statements made during this presentation may include, the non- GAAP financial measure of Adjusted EBITDA. We believe Adjusted EBITDA helps us evaluate our operating performance and compare our results of operation from period to period without regard to our financing methods or capital structure. We define 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 (loss) income or cash flows as determined by GAAP. Adjusted EBITDA should not be considered an alternative to, or more meaningful than, net income or cash flows from operating activities as determined in accordance with GAAP or as an indicator of our operating performance or liquidity. The following table presents our calculation of Adjusted EBITDA and the reconciliation of Adjusted EBITDA to the GAAP financial measures of net income (loss) and net cash provided by operating activities, respectively, that are of a historical nature. Where references are forward-looking or prospective in nature, and not based on historical fact, the table does not provide a reconciliation. We could not provide such reconciliations without undue hardship because the Adjusted EBITDA numbers included in this presentation, and that may be included in certain statements made during the presentation, are estimations, approximations and/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.
54 Adjusted EBITDA Reconciliation The following table presents our calculation of Adjusted EBITDA and reconciliation of Adjusted EBITDA to the GAAP financial measures of net (loss) income and cash provided by operating activities, respectively.
$100mm Leasing Strategy That Rests on a “Fleck” “Prove to us that oil molecules can move in so tight a rock.” 55 Macro. Micro. Nano. Sample
Pore-Perm Architecture We Can Measure 56