Johnson Rice Energy Conference

Transcription

1 Johnson Rice Energy Conference New Orleans, Louisiana William J. Scarff President September 28-29, 2015 Andrew J. Cozby SVP and CFO

2 Forward-Looking Statements This presentation 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 can be identified by terminology such as may, will, could, should, expect, plan, project, forecast, intend, anticipate, believe, estimate, predict, potential, pursue, target, outlook, continue, the negative of such terms or other comparable terminology. All statements, other than historical facts included in this presentation, that address activities, events or developments that Memorial Resource Development Corp. (MRD) expects or anticipates will or may occur in the future and such things as MRD s future capital expenditures (including the amount and nature thereof), business strategy and measures to implement strategy, future drilling locations and inventory, competitive strengths, goals, expansion and growth of MRD s business and operations, plans, market conditions, references to future success, references to intentions as to future matters and other such matters are forward-looking statements. All forward-looking statements speak only as of the date of this presentation. Although MRD believes that the plans, intentions and expectations reflected in or suggested by the forward-looking statements are reasonable, there is no assurance that these plans, intentions or expectations will be achieved. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecast in such statements. MRD cautions you that these forward-looking statements are subject to risks and uncertainties, most of which are difficult to predict and many of which are beyond MRD s control, incident to the exploration for and development, production, gathering and sale of natural gas and oil. These risks include, but are not limited to: ability to consummate pending acquisitions; commodity price volatility; inflation; lack of availability of drilling and production equipment and services; environmental risks; drilling and other operating risks; regulatory changes; the uncertainty inherent in estimating natural gas and oil reserves and in projecting future rates of production, cash flow and access to capital; and the timing of development expenditures. Information concerning these and other factors can be found in MRD s filings with the Securities and Exchange Commission ( SEC ), including its Forms 10-K, 10-Q and 8-K. Consequently, all of the forwardlooking statements made in this presentation are qualified by these cautionary statements and there can be no assurances that the actual results or developments anticipated by MRD will be realized, or even if realized, that they will have the expected consequences to or effects on MRD, its business or operations. MRD has no intention, and disclaims any obligation, to update or revise any forwardlooking statements, whether as a result of new information, future results or otherwise. Initial production rates are subject to decline over time and should not be regarded as reflective of sustained production levels. 2 2

3 The Premier Horizontal Development E&P Company Consolidated core position in and around the Terryville Complex of North Louisiana Prolific Asset Base Top tier returns highly economic single well IRRs projected at current commodity prices (1) High quality, repeatable stacked pays Conventional, tight gas reservoir provides predictable returns Significant Upside Potential >2,200 horizontal drilling locations in four primary zones (50+ years of inventory) (2) ~22 year drilling inventory inside of NSAI s 3P acreage Continue to increase already dominant acreage position in North Louisiana 193,915 net acres in the over-pressured Lower Cotton Valley up 276% since IPO (2) Additional over-pressurized, liquids-rich opportunities in North Louisiana Significant liquidity and low leverage Best-In-Class Financial Metrics Expect to fund growth predominately with internally generated cash flow Expect continued reduction in per unit costs Industry-leading hedge position First-in-class expertise in the over-pressured liquids rich Cotton Valley Focused Management Team Exceptional track record with horizontal development and completion Commitment to safety and environmental stewardship Public company experience and focused on operational execution 3 (1) See Appendix for information on our IRR calculation (2) Gives effect to (1) acquisition by MEMP of certain assets from MRD in East Texas and non-core Louisiana in February 2015 in exchange for cash and certain properties in North Louisiana, (2) divestiture by MRD of certain properties in April 2015 to a third-party in Colorado and Wyoming and (3) MRD s full exercise of the NLA Acreage Option, which allows MRD to lease acreage through February 2017, and the pending acquisition and organic leasing efforts. Does not include Other Louisiana acreage of 13,048 gross (7,833 net) acres

4 MRD Continues to Execute on its Core Strategy Increasing production through efficient drilling and expanding its asset footprint via accretive acquisitions while maintaining a strong balance sheet and generating strong shareholder returns MRD Key Statistics Gross Acres (1) 215,771 Net Acres (1) 193,915 Proved Reserves at December 31, 2014 (Bcfe) (2) 1,378 % Gas Reserves 72% Avg. Q2 Daily Production (MMcfe/d) (2) 268 Proved Reserve Life (R/P) 14.1 Production (MMcfe/d) (2) Net Acreage (1) 193,915 (3) 51,522 At IPO 2Q'15 At IPO PF 2Q'15 Proved Reserves (Bcfe) Horizontal Drilling Locations (2) 1,378 (1) 2,236 (3) 1,126 (3) 1,582 (1) Gives effect to (1) acquisition by MEMP of certain assets from MRD in East Texas and noncore Louisiana in February 2015 in exchange for cash and certain properties in North Louisiana, (2) divestiture by MRD of certain properties in April 2015 to a third-party in Colorado and Wyoming and (3) MRD s full exercise of the NLA Acreage Option, which allows MRD to lease acreage through February 2017, and the pending acquisition and organic leasing efforts. Does not include Other Louisiana acreage of 13,048 gross (7,833 net) acres (2) Proved, probable and possible reserves audited by Netherland, Sewell & Associates, Inc. (NSAI); report based on SEC pricing as of December 31, Reserves and production are pro forma for the asset swap with MEMP completed in February 2015 and Rockies divestiture completed in April See Cautionary Statements and Additional Disclosures in the 4 Appendix for more information regarding 3P reserves and PV-10 (3) As of 12/31/13 At IPO 2Q'15 At IPO PF 2Q'15

5 Bossier Caddo De Soto Sabine Webster Red River Bienville Natchitoches Claiborne Lincoln Jackson Winn Grant Union Ouachita La Salle Caldwell Morehouse Richland Catahoula Franklin Concordia West Feliciana West Carroll East Carroll Tensas Madison Madison 0 99,913 Transactions Overview Third-Party Acquisition Overview Map Acquired 45,121 net acres in Jackson and Lincoln Parishes, LA Highly contiguous acreage position adjacent to MRD s Terryville Field High working interest in a large portion of MRD s acquired acreage Expect one rig to be able to hold the acreage through production within 5 years 588 gross horizontal locations through three primary intervals (two Upper Red and one Lower Red) (1) Further upside potential associated with other Upper Cotton Valley, Lower Cotton Valley, Bossier and Smackover Gray Sand zones Similar geological characteristics to the Terryville Field Cotton Valley sandstone, over-pressured, multi-stacked pays Acreage Option Agreement Overview Legend North Louisiana Acreage Option Agreement provides MRD the right to lease up to 39,619 net acres from an undisclosed lessor through February 2017 Large acreage blocks primarily in Jackson Parish Option leases will be under primary term for up to four years after the option election date Terryville Field Third Party Acquisition Acreage Expansion Area 20 5 (1) See Cautionary Statements and Additional Disclosures in the Appendix for more information regarding management locations

6 Third-Party Acquisition Strategic Highlights Strategic Bolt-On Acquisition Strategic-fit with MRD s existing asset base Majority of acreage located adjacent to Terryville Field Large, concentrated acreage position Allows for immediate development without working interest ( WI ) partners High working interest in a large portion of MRD s acquired acreage Adds Drilling Locations to an Already Sizable Inventory Adds 588 horizontal gross drilling locations (1) Three primary intervals consisting of two Upper Red and one Lower Red zones Further upside potential associated with other Upper Cotton Valley, Lower Cotton Valley, Bossier and Smackover Gray Sand zones Highly economic at current strip pricing Ideal Horizontal Redevelopment Candidate Similar geological characteristics to the Terryville Field Lower Cotton Valley sandstone Over-pressured Multi-stacked pays 6 (1) See Cautionary Statements and Additional Disclosures in the Appendix for more information regarding management locations

7 Significant and Growing Acreage Position MRD has entered into separate transactions to add to its industry-leading position in North Louisiana through the following: A definitive purchase and sale agreement to acquire a third-party s acreage in Jackson and Lincoln Parishes, Louisiana; An acreage option agreement to lease acreage in Bienville, Claiborne, Jackson and Lincoln Parishes, Louisiana; and MRD s continued organic leasing efforts in North Louisiana year-to-date 2015 YTD, MRD has either added, acquired, agreed to acquire, or secured the option to lease, an additional 132,758 net acres for ~$374 million at attractive valuation metrics (1) Louisiana Acreage Details (2) 7 Historical Pro Forma Acreage Position As of December 31, 2014 As of September 21, 2015 Gross Net Gross Net Over-Pressured Lower Cotton Valley: Terryville Complex 73,737 61, , ,175 Third Party Acquisition ,807 45,121 NLA Acreage Option ,769 39,619 73,737 61, , ,915 Other: Other Louisiana 49,198 44,291 13,048 7,833 Total Acres 122, , , ,748 (1) Assumes the full option lease exercise cost (2) Pro Forma Acreage Position table gives effect to (1) acquisition by MEMP of certain assets from MRD in East Texas and non-core Louisiana in February 2015 in exchange for cash and certain properties in North Louisiana, (2) divestiture by MRD of certain properties in April 2015 to a third-party in Colorado and Wyoming and (3) MRD s full exercise of the NLA Acreage Option, which allows MRD to lease acreage through February 2017, and the pending acquisition and organic leasing efforts noted above

8 Best-in-Class Performance and Economics Exceptional Horizontal Well Results in Four Primary Zones (1) Average IP-30 per Quarter (MMcfe/d) Avg MMcfe/d High IRRs at Current Prices (2) 172% 73% Q1'13 Q2'13 Q3'13 Q4'13 Q1'14 Q2'14 Q3'14 Q4'14 Q1'15 Q2'15 Q3'15 (3) Q Prod. 268 MMcfe/d (4) 6% 5% 20% 17% 17% 13% 44% 12% 12% Q Prod. 39 MMcfe/d (4) Q1'12 Q2'12 Q3'12 Q4'12 Q1'13 Q2'13 Q3'13 Q4'13 Q1'14 Q2'14 Q3'14 Q4'14 Q1'15 Q2' Vertical Terryville Horizontal Terryville Highly prolific and liquids-rich production characteristics Top-tier cost structure Rapidly accelerating drilling program in the Terryville Complex Started 2013 with 2 rigs and expect to average ~8 9 rigs in 2015 Further upside to drilling economics as we transition to pad drilling with longer laterals and potential cost reductions (1) Excludes four delineation wells: Drewett 17 8H-2, Gleason 31H-1, Burnett 26H-1 and LUMCFS 211HC-1 ( LMO ) (2) IRRs assume a flat crude oil price of $50.00 per barrel and a natural gas price of $2.90, $3.18, $3.42, $3.52, $3.59, and $3.69 per MMBtu for years one through six respectively and held flat thereafter. Terryville IRRs based on MRD internal estimates. All other IRRs from Credit Suisse Equity Research. See Appendix for more information on Terryville IRR calculations. (3) Includes the 19 gross horizontal wells added in the Terryville Field during July and August 2015 (4) Includes only Terryville Field

9 Terryville Field Strong Horizontal Well Results (Unhedged) (1) MRD s drilling inventory projected to be highly economic across all commodity price environments $80 oil / $4.00 gas $70 oil / $3.50 gas $60 oil / $3.00 gas $50 oil / $2.50 gas NPV10 ($MM) $ % +200% +200% +200% IRR% 200% $36 $35.1 $32 $28 139% $ % 160% $24 $20 $20.6 $ % 120% $16 $12 $8 $4 $13.4 $16.1 $9.9 86% 86% $ % $6.4 $ % 47% $7.0 40% 25% $2.9 $0 0% ~75% of MRD 2015 Capex Directed to Upper Red Target 9 Source: MRD internal type curve estimates (1) Assumes 7,500 foot lateral length; 100% working interest / 78% net revenue interest; and well cost of ~$11.8MM; see Appendix for more information on our IRR calculation

10 Multi-Year Drilling Inventory Drives Upside Potential Terryville Complex Locations Terryville Complex Horizontal Locations by Pay-Zone (1) Zone Proved Prob. Poss. NSAI 3P Mgmt Total Upper Red Lower Red Lower Deep Pink Upper Deep Pink Total Four Primary Zones ,665 2,236 Other Zones Total MRD ,665 2,521 PV-10 ($ billion) $ Years of Inventory Multi-zone exploration opportunities which are being steadily delineated by MRD 2,236 identified potential drilling locations in four primary zones support substantial net asset value NSAI audited 3P Terryville future locations of 856 at YE 2014 significantly increased from 688 at YE 2013, with 588 locations associated to recent leasehold transactions NSAI audited 3P PV-10 of $6.2 billion at YE 2014 and 4.7 Tcfe of 3P reserves (3) 50+ year drilling inventory in four primary zones under current drilling program (2) Upper Red Lower Red Lower Deep Pink Upper Deep Pink 285 2,236 Other Zones 2,521 1,284 1,237 in NSAI 3P Acreage Total MRD = NSAI Locations = Management Locations 10 (1) Schedule includes 285 locations in Other Zones per NSAI. Other Zones category does not include additional management locations (2) Includes pending acquisition (3) Proved, probable and possible reserves audited by NSAI; report based on SEC pricing as of December 31, Reserves are pro forma for the asset swap with MEMP completed in February 2015; not pro forma for the Rockies divestiture completed in April See Cautionary Statements and Additional Disclosures in the Appendix for more information regarding 3P reserves, PV-10 and management locations

11 Results Outperform Type Curves Management Type Curves Management type curves based on well performance, spacing and lateral length Type curves supported by over 70 wells online MRD has consistently outperformed NSAI s assumptions NSAI type curves are based on historical lateral lengths of 4,700 to 5, expected average lateral length >7,000 MRD Management PUD Assumptions Upper Red Lower Red Lower Deep Pink Lateral Length (feet) 7,500 7,500 7,500 Capex ($MM) $11.8 $11.8 $11.8 EUR (Bcfe) EUR/1,000 (Bcfe) NGL Yield (Bbls/MMcf) Oil Yield (Bbls/MMcf) % Gas 71% 71% 71% IP-30 (MMcfe/d) IRR (%) >200% 86% 50% PV-10 ($MM) $22.1 $11.6 $6.4 Note: Assumptions are based on $60 / Bbl oil and $3.00 / Mcf natural gas Production Continues to Outperform Type Curves Upper Red Type Curve Lower Red Type Curve Lower Deep Pink Type Curve Wells Online: 53 Wells Online: 18 Wells Online: 3 Daily Production (MMcfe/d) Daily Production (MMcfe/d) Daily Production (MMcfe/d) 11 Days on Production Days on Production Days on Production Historical Production Normalized to 7,500 Management 7,500 Type Curve NSAI YE14 PUD NSAI Scaled to 7,500 Note: Historical production represents all wells online as of September 7, Historical average includes all wells drilled to date and represents unprocessed wellhead volumes. Average lateral length for Upper Red, Lower Red and Lower Deep Pink are 5,868, 5,554, 4,755, respectively. Data has been adjusted for shut-ins, downtime and normalized to a 7,500 lateral length.

12 Key Takeaways World-Class Asset High Rates of Return Over-pressurized reservoir with multi-stacked pays Highly concentrated and growing position in North Louisiana 50+ year drilling inventory in four primary zones under current drilling program (1) Liquids-rich High initial rates of production Shallower declines relative to typical shale plays Minimal Basis Differentials Proximity to Henry Hub Ample takeaway capacity Access to multiple interstate and intrastate gas pipelines Friendly Operating Environment Favorable regulatory environment Abundance of service providers Strong Capital Structure Industry leading hedge book Significant liquidity Low leverage 12 (1) Includes pending acquisition

13 14 Operations & Financial Summary

14 3P Polygon 2P Polygon 1P Polygon Operational Update Positive Recent Well Results (1) Completed 22 gross horizontal wells during 3Q 15 to-date 14 Completed 14 Upper Red wells with an average IP-30 rate of ~25 MMcfe/d 79 horizontal wells producing from MRD s four primary zones One-well Dowling pad achieved a peak 24- hour rate of 40.7 MMcfe/d Best peak 24-hour rate drilled in the field to-date Located 7,620 feet northwest of the Louisiana Methodist Orphanage ( LMO ) well Two-well Bellevue Timber pad achieved a combined 24-day IP rate of 61.8 MMcfe/d Bellevue Timber 16 9HC-1 single-well achieved a peak 24-hour rate of 40.1 MMcfe/d Second best peak 24-hour rate drilled in the field to-date Recent Well Results (2) Claiborne Bienville 19N 5W N 4W 8 Lincoln 19N 3W 18N 5W 18N 4W 18N 3W 17N 5W 17N 4W 17N 3W Jackson 1) TL McCrary 3) Dowling (3-well) 5) Hearne 7) Dowling (1-well) 2) Wright 4) Dunn Estate 6) Bellevue Timber 8) Lewis 7 30-Day IP Rate Per Thousand Foot of Lateral Avg. Peak 24-Hour Rate (MMcfe/d) (4) Well Wells Completed Avg. Well Lateral Length (Feet) Avg. Well 30-Day IP Rate (MMcfe/d) (3) Upper Red (5) 14 6, Lower Red 4 6, Upper Deep Pink 1 7, (1) As of September 15, 2015 (2) Does not include three wells associated with the Dowling (1-well) and Lewis (2-wells) pads brought to sales in September due to limited days on production (3) Average 30-day IP rates represent actual production rates incurred, which include various field and operational downtime events (4) Peak 24-hour rates represent the maximum 24-hour production rate reported within the 30-day IP rate period (5) Includes average 24-day IP for the Bellevue Timber pad (latest data available)

15 World Class Asset Productivity MRD Has Top Productive Wells Since 2012, 73 wells of ~17,200 horizontal gas wells in the U.S. have peak monthly production over 21 MMcfe/d 32 of those were drilled by Memorial Memorial has drilled 62 wells in the top 2% of the ~17,200 horizontal wells (46 wells in the top 1%) Completion IP-30 Date Well Name (MMcfe/d) Target Percentile Aug-15 Bellevue Timber 16 9HC Upper Red 0.0% Nov-14 Dowling HC Upper Red 0.0% Jul-15 TL McCrary HC Upper Red 0.0% Nov-14 DL Sanford 18 7 HC Upper Red 0.1% Apr-14 Wright HC Upper Red 0.1% Nov-14 Dowling HC Upper Red 0.1% Jul-15 Dowling HC Upper Red 0.1% Apr-15 Drewett 17 8HC Upper Red 0.1% Aug-14 Werner HC Upper Red 0.1% Mar-15 Davison 16 9HC Upper Red 0.1% Oct-14 Colvin Estate HC Upper Red 0.1% Apr-14 Wright HC Lower Red 0.1% Aug-15 Hearne 33 4 HC Upper Red 0.2% Aug-15 Hearne 33 4 HC Upper Red 0.2% Aug-15 Bellevue Timber 16 9HC Upper Red 0.2% Jul-15 Dowling HC Upper Red 0.2% May-14 LA Minerals HC Upper Red 0.2% Apr-14 Wright HC Upper Red 0.2% Jul-15 TL McCrary HC Upper Red 0.2% Jul-15 Wright HC Upper Red 0.2% Oct-14 Colvin Estate HC Upper Red 0.3% Sep-14 TL McCrary HC Upper Red 0.3% Jul-15 Dowling HC Upper Red 0.3% Jul-15 Wright HC Upper Red 0.3% Apr-14 TL McCrary HC Upper Red 0.3% Dec-13 Wright HC Upper Red 0.3% Nov-14 James R. Dowling HC Upper Red 0.3% Nov-13 Drewett 17 8H Upper Red 0.3% Jul-15 Wright HC Lower Red 0.4% Jun-14 LA Minerals HC Upper Red 0.4% Sep-14 TL McCrary HC Upper Red 0.4% Nov-12 Nobles 13H Upper Red 0.4% Jul-15 A Dunn Estate 17-8 HC# Upper Red 0.5% Dec-14 Daniels 17 8H Upper Red 0.5% May-13 Wright HC Upper Red 0.5% Nov-14 TL McCrary HC Lower Red 0.6% Top 100 Gas Wells by Operator Peak 30-Day Mcfe Production MRD Cabot EnCana Mewbourne Enervest EQT Chesapeake Cabot 32 Other 12 2% 0.9% 0.6% 0.5% Marcellus Mewbourne 2 7% 12% Cotton Valley MRD 36 Chesapeake EnCana 8 Enervest 4 EQT 3 2 Percentage of Operator s Total Wells in Top % 0% 10% 20% 30% 40% 50% 15 Source: HPDI and MRD data Note: Includes average 24-day IP for the Bellevue Timber pad (latest data available). MRD data shown includes NGLs after processing; all other well results based on data as reported per HPDI. MRD using estimated shrink and NGL yields for recent horizontal wells. Well percentile based on peak 30-day Mcfe production for over 17,200 horizontal gas wells in the U.S. drilled since 2012.

16 MRD Regional Advantage Proximity to Gulf Coast Provides High Gas Realizations and Access to Future Demand Growth Primary Demand Drivers (1) A A. Proximity to New LNG Exports Facilities - Five LNG exports facilities are FERC approved and under construction with four on the USGC - The capacity of these approved facilities is fully contracted with take-or-pay tolling agreements with end-users in Asia and Europe, and major LNG traders portfolio B Proximity to Expanding USGC Industrial Demand - Growth driven by projects exploiting the competitive & regional advantage of cheap natural gas & NGLs - Industrial demand growth is centered in the USGC petrochemical sector C Proximity to Increased Mexican Import Needs - Expansion of Mexico s gas pipeline and power transmission infrastructure - Progress in generation build out for underserved regions of Mexico ($1.32) Dominion South Marcellus (3) Terryville Complex Northern Louisiana Hub (2) ($0.06) C Exports to Mexico Incremental 3.5 Bcf/d by 2020 B USGC Industrial Demand Incremental 5.5 Bcf/d by 2020 A LNG Export Incremental 8.5 Bcf/d by 2020 $ = Discount to Henry Hub = Henry Hub Source: Mexico Secretaria de Energy (SENER), US Energy Information Administration (EIA), US Federal Energy Regulatory Commission (FERC), University of Texas Center for Energy Economics (CEE), Mobius Risk Group estimates 2. Northern Louisiana Hub reflects the historical 6 month average basis at Perryville Hub as of 9/15/15 3. Dominion South Marcellus reflects the historical 6 month average basis at Dominion South Hub as of 9/15/15

17 Superior Pricing Drives Shareholder Returns Peer Leading Realizations Across Products Natural Gas Realizations Uniquely positioned to benefit from attractive price realizations Mature and robust midstream infrastructure Geographic proximity to current and growing demand centers Allows MRD to continue to achieve high rates of return through the commodity cycle 100% 80% 60% 40% 20% 107% 103% 101% 101% 108% 96% 100% 95% 95% 0% 1Q'14 2Q'14 3Q'14 4Q'14 1Q'15 2Q' Guidance (1) NGL Realizations Oil Realizations 50% 40% 44% 52% 39% 41% 47% 36% 35% 100% 80% 97% 97% 99% 97% 98% 92% 100% 95% 95% 30% 30% 60% 20% 40% 10% 20% 0% 1Q'14 2Q'14 3Q'14 4Q'14 1Q'15 2Q' (1) Guidance 0% 1Q'14 2Q'14 3Q'14 4Q'14 1Q'15 2Q' Guidance (1) 17 (1) Guidance as of February 24, 2015

18 Financial Strategy and Capitalization Financial Update Capitalization MRD Segment (1) Preserve Financial Flexibility Operate towards free cash flow positive asset base Keep leverage at conservative levels Low Cost Operator Focus on low cost operations and maintaining strong margins Allocate capital among projects and areas that optimize drill-bit F&D Grow reserves and production by redeploying operating cash flows into high-returning Terryville Complex Hedge to Protect Cash Flows Lock in commodity prices to reduce cash flow volatility and ensure rate of return Protect drilling program to fund efficient production growth Maintain Liquidity to Support Future Growth Ensure ready access to the capital markets and maintain revolver liquidity Robust development program supports borrowing base growth Expect to fund 2015 drilling program largely from cash flow ($ in millions) 6/30/15 Pro Forma Adj. 6/30/2015 (5) Cash and Cash Equivalents $4.5 $0.0 $4.5 Senior Secured Credit Facility $165.0 $45.5 $ % Senior Notes due Total MRD Segment Debt $765.0 $45.5 $810.5 Total Stockholders Equity $486.1 $239.2 $725.2 Total Capitalization $1,251.1 $284.6 $1,535.7 Operating Statistics: Market Value of Equity at 9/23/15 $3,487.7 $251.3 $3,739.0 Quarterly Adj. EBITDA Annualized ($MM) (2) $331.3 $0.0 $331.3 Enterprise Value ($MM) (3) 4, ,545.0 Proved Reserves (Bcfe) (4) 1, ,378.4 Quarterly Production (MMcfe/d) Credit Statistics: Borrowing Base $725.0 $0.0 $725.0 Less: Outstanding Borrowings (165.0) (45.5) (210.5) Plus: Cash Liquidity $564.5 ($45.5) $519.0 Total Debt / 2Q15 Adj. EBITDA Annualized (x) 2.3x 2.4x Enterprise Value (%) 18% 18% Proved Reserves ($/Mcfe) $0.55 $0.59 2Q15 Production ($/Mcfe/d) $2,856.6 $3,026.4 (1) Does not include capitalization attributable to MEMP and its subsidiaries (2) Adjusted EBITDA is a non-gaap financial measure. Quarterly Adj. EBITDA Annualized is calculated using 2Q15 EBITDA (3) Market value of equity as of September 23, 2015 (4) Reserves audited by NSAI; report based on SEC pricing as of December 31, Reserves and production are pro forma for the asset swap with MEMP completed in February 2015 and the Rockies divestiture completed in April 2015 (5) Gives effect to the September 2015 equity offering and the third-party acquisition described above 18

19 Fiscal Year 2015 Guidance Highlights FY15 total D&C capital expenditures of ~$500MM 2015 daily production projected to average between MMcfe/d >50% FY YOY increase >75% PF YOY increase for East Texas divestiture Budget supported by 8 9 horizontal drilling rigs in 2015 All located in the Terryville Field Compares to 4 rigs at year-end 2013 Detailed Guidance 2015 FY Guidance Low High Net Average Daily Production (MMcfe/d) Natural Gas (MMcf/d) NGLs (Bbls/d) 10,900-12,300 Oil (Bbls/d) 3,200-3,600 Average Costs (per Mcfe) Lease Operating ($0.20) - ($0.15) Production and Ad Valorem Taxes (1) ($0.15) - ($0.10) Cash General and Administrative ($0.30) - ($0.25) Gathering, Processing and Transportation ($0.70) - ($0.55) and BTU Adjustment ($/Mcfe) (2) Commodity Price Realizations (Unhedged) (3) Natural Gas Realized Price (% of NYMEX to Henry Hub) (4) 95% - 100% NGL Realized Price (% of WTI NYMEX) 30% - 35% Crude Oil Realized Price (% of WTI NYMEX) 95% - 100% Drilling Program Terryville Field Wells Spud (Gross) Terryville Field Wells Completed (Gross) Terryville Field D&C Capital Expenditure ($MM) $475 - $ Note: Guidance as of February 24, 2015 (1) Amount varies based on abatement credits from newer horizontal wells (2) Previously, MRD s realized pricing varied from NYMEX due to revenue deductions for the net costs of gathering, transporting and processing and regional basis differentials. Beginning in the first quarter 2015, MRD reported gathering, processing and transportation charges as a separate expense line item (3) Based on strip pricing as of February 13, 2015 (4) Does not include gathering, processing and transportation costs

20 MRD Peer Comparison MRD Historical LOE Expense ($/Mcfe) (1) Q Total Cash Cost ($/Mcfe) $1.20 Historical LOE Expense ($/Mcfe) $1.01 $4.00 Cash G&A Other Expenses (2) $3.14 $0.80 $0.74 $3.00 $2.27 $2.75 $0.40 $0.00 $0.50 $0.32 $ E $2.00 $ Average $1.80 $1.63 $1.74 $2.30 $1.28 $1.37 $1.38 $1.16 $0.80 $2.04 $1.33 $0.95 $1.03 $1.23 $1.08 $0.64 $1.00 $0.84 $0.16 $0.08 $0.34 $0.34 $0.15 $0.30 $0.23 EQT COG RICE (3) MRD GPOR RRC AR GDP MHR 2015E YOY Production Growth (4) 100% 20 90% 80% 70% 60% 50% 40% 30% 20% 10% 0% NA 81% 77% 43% 27% 26% 20% Average: 32% 15% 13% ECR RICE MRD AR SWN EQT RRC UPL COG Q Debt / EBITDA (5) 8.0x 7.0x 6.0x 5.0x 4.0x 3.0x 2.0x 1.0x 8.0x 6.0x 5.2x 5.1x 4.3x 2.6x 2.4x 2.0x 0.7x (6) ECR AR UPL RRC RICE SWN MRD COG EQT Source: Company filings and Factset. Note: Averages exclude MRD (1) Includes effect of assets owned at the time of reporting (2) Other expenses includes lease operating expenses, production taxes, ad valorem taxes and gathering and processing fees where applicable (3) Excludes $0.09 / Mcfe of expenses associated with long-term incentive plan and transaction related costs (4) Production is pro forma for the asset swap with MEMP completed in February 2015 and the Rockies divestiture completed in April 2015 (5) Adjusted EBITDA is a non-gaap financial measure. Please see the Appendix for more information regarding MRD s Adjusted EBITDA, including the reconciliation to the most comparable measure calculated in accordance with GAAP (6) Pro forma for the acreage acquisition and equity offering announced on September 21, 2015 Average: 4.2x

21 MRD Has an Attractive Hedge Portfolio On a relative basis, MRD has larger hedge volumes and a longer dated hedge book than its peers Percent of Total Production Hedged (1) 2015 (2) 2016 % Hedged 100% 90% 80% 70% 60% 50% Median: 68% 57% 60% 75% 77% 88% 88% 89% % Hedged 100% 90% 80% 70% 60% 50% Median: 46% 43% 49% 61% 70% 81% 86% 40% 30% 27% 30% 31% 40% 30% 29% 20% 20% 10% 0% RSPP COG FANG EQT PE RRC MRD JONE RICE AR 10% 0% 0% 1% 7% RSPP COG FANG EQT RRC PE RICE JONE MRD AR % Hedged 80% % Hedged 90% 70% 60% 61% 80% 70% 74% 50% 40% 30% 20% 10% 0% 47% 43% 37% Median: 13% 17% 9% 0% 0% 0% 1% RSPP COG FANG RRC EQT PE JONE RICE MRD AR 60% 50% 40% 30% 20% 10% 0% 47% 30% 27% Median: 0% 0% 0% 0% 0% 0% 0% RSPP COG FANG EQT RRC RICE PE JONE MRD AR 21 (1) Based on Wall Street Research estimates for future production. 2016E production is held flat due to lack of research for 2017E and 2018E (2) Represents full-year 2015

22 MRD Hedging Overview: 3Q15 through 2018 MRD s commodity risk management policy provides for hedging estimated production from total proved reserves Proactive policy reduces MRD s exposure to movements in commodity prices and provides stability to cash flow All of MRD s trading counterparties have credit ratings of BBB (S&P) or Baa2 (Moody s) or higher MRD s current hedges include fixed price swaps, collars and deferred premium puts and calls Hedge Summary Year Ending December 31, (1) Natural Gas Derivative Contracts: Total natural gas volumes hedged (MMBtu) 45,780, ,040,000 98,040,000 96,600,000 Total weighted-average price $3.94 $3.76 $3.78 $3.87 Percent of expected production hedged (2) 84% Crude Oil Derivative Contracts: Total crude oil volumes hedged (Bbl) 498, , , ,500 Total weighted-average price $88.57 $88.64 $84.70 $84.50 Percent of expected production hedged (2) 77% Natural Gas Liquids Derivative Contracts: Total natural gas liquids volumes hedged (Bbl) 978,000 2,227,895 Total weighted-average price $41.52 $34.06 Percent of expected production hedged (2) 32% Total Derivative Contracts: Total Hedged Production (MMBtue) 54,636, ,963, ,056,000 98,877,000 Total weighted-average price $4.85 $4.17 $3.99 $4.10 Percent of expected production hedged (2) 71% (1) 2015 hedge volumes represent the period from July 1 through December 31, 2015 (2) Expected production represents the midpoint of the annual production range in MRD's 2015 full year guidance

23 Investment Highlights Best-in-Class Assets with Top Tier Growth Premier Drilling Economics with Extensive Inventory Secured Infrastructure Supports Growth Plans Conservative Balance Sheet with a Focus on Funding Growth Predominately with Internally Generated Cash Flow Experienced Management Team with Extensive Knowledge of the Cotton Valley 35 23

24 Appendix

25 Organizational Chart & Ownership (1) NGP Funds Headquarters: Houston, TX Employees: ~500 full-time Certain Former Management Members of WildHorse Resources MRD Holdco LLC Public 15% 36% 49% Memorial Resource Development Corp. (NASDAQ: MRD) 100% Memorial Production Partners GP LLC General Partner Units Incentive Distribution Rights MRD Operating LLC (Terryville Complex) 0.1% GP interest 50% IDR interest Memorial Production Partners LP (NASDAQ: MEMP) Public 9 25 (1) As of September 25, 2015

26 High Production Rates Throughout Cotton Valley Trend MRD has the Top 33 Wells in the Cotton Valley Trend 28 Active Cotton Valley Horizontal Rigs across +250 miles Terryville Complex Lloyd 5-6H 11.3 MMcfe/d Rogers 6H 11.3 MMcfe/d G Breffeilh 11 H 11.1 MMcfe/d Berry Etal 24H 11.1 MMcfe/d Walton 23H 10.6 MMcfe/d Hutchinson MMcfe/d Killen Alt 13.1 MMcfe/d Elm Grove Pltn. 063-Alt 12.6 MMcfe/d M.T. Peyton 12H 19.8 MMcfe/d Crenshaw 14H 19.3 MMcfe/d Neal 12H 18.0 MMcfe/d Henderson Field Crow Holland 2H MMcfe/d Roger King 1H 15.3 MMcfe/d Pone 7H 14.9 MMcfe/d South Carthage Gail King 25H 16.6 MMcfe/d Fullen GU 11H 14.5 MMcfe/d Fullen GU 4H 13.9 MMcfe/d 26 Ritter 4H 16.7 MMcfe/d Joaquin May 5H 13.2 MMcfe/d Wiener Estate F2H 12.1 MMcfe/d Sources: HPDI and Company data. MRD production rates include NGLs post-processing, all other operators based on reported peak monthly production. (1) Represents the average 24-day IP for the Bellevue Timber pad Bellevue Timber 16 9HC MMcfe/d(1) Dowling HC MMcfe/d TL McCrary HC MMcfe/d DL Sanford MMcfe/d Wright HC MMcfe/d Dowling HC MMcfe/d Dowling HC MMcfe/d

27 Horizontal Development of Multiple Producing Benches Legacy Vertical Production Focused on Commingling Sections, Horizontal Development Focused on Specific Zones Legacy Vertical Development ~8,500 CV Stacked Horizontal Targets Competitor Activity Discovery Late 50 s Vaughn Green (Davis) (Justiss) (Roseberry) Cotton Valley Normally Pressured 1 (Sexton) (Taylor) 2 Late 70 s Mid 80 s Lower Cotton Valley Overpressured ~11,500 Production Wells Since 2012 (1) 27 (1) As of September 15, 2015

28 Multi-Well Pads Greater Efficiencies Across All Stages of Development Drilling Reduced location cost Reduced mobilization time (no rig up and rig down) Batch drilling of hole sections Completion More effective zipper fracs Continuous and efficient use of frac service contractors Reduces offset well shut-ins for fracs Cost savings from common frac water sourcing Production Cost effective comingling of production facility, pipeline, and SWD systems Streamlined gas gathering and compression Completion of a Multi-Well Pad Site Illustrative Example of MRD s Drill & Completion Schedule for a 4-Well Pad Well 1 Vertical Lateral Frac Well 2 Vertical Lateral Frac Well 3 Vertical Lateral Frac Well 4 Vertical &/ Lateral Frac 28 MRD s 4-well pads generally take ~8-9 months from spud to completion

29 Secured Midstream Infrastructure Supports Development Plan Sufficient, Extensive Build Existing Out Takeaway Eliminates Potential Constraints Expect to have >1 Bcf/d of processing capacity by year-end 2015 Additional 200 MMcf/d of cryogenic processing from PennTex completed in September current major gas processors PennTex, Regency and DCP Gather and process both low pressure and high pressure systems >6 Bcf/d takeaway capacity by multiple purchasers with no firm contracts No expected basis differential issues Processing agreements are fee based with MRD retaining 100% of the proceeds on residue gas and liquids >1 Bcf/d of Processing Capacity Expected by Year-End ,200 Diverse Regional Takeaway Regency Dubberly Plant DCP Minden Plant PennTex Lincoln Parish Plant Regency Lisbon Plant Regency Dubach Plant PennTex Mt. Olive Plant >1 Bcf/d by YE 2015 Capacity (MMcf/d) 1, Q Q Q Q Q Q JT - 1 Plant Refridge - 3 Plants Cryo - 6 Plants

30 Terryville Drilling Inventory 35+ Year Inventory in Four Primary Zones Terryville Future Horizontal Locations by Reserve Category (1) Distribution of Locations Upper Red Lower Red Lower Deep Pink Upper Deep Pink 4 Primary Zones Total Other Zones Total MRD Proved NSAI Management Total Proved Probable NSAI Management Total Probable Possible NSAI Management Total Possible ,280 Total 3P NSAI Management Total 3P , ,825 Outside 3P NSAI Management Total , ,521 ~34 year drilling inventory located in MRD Upper and Lower Red reserve categories (3) MRD expects management locations to continue to move into NSAI 3P locations as well performance at 770 spacing and empirical data support more recoverable gas per section Further upside exists in Other Zones as management continues to evaluate prospectivity in normally pressured zones across all MRD acreage Vaughn Green (Davis) (Justiss) (Roseberry) (Sexton) (Taylor) Cotton Valley Normally Pressured Lower Cotton Valley Overpressured # of Locations (2) , (1) See Cautionary Statements and Additional Disclosures in the Appendix for more information regarding management locations (2) Schedule includes additional 285 locations in Other Zones per NSAI. Does not include additional management locations located in these intervals (3) Per MRD s Fiscal Year 2015 Guidance for Terryville Completed Wells

31 MRD NSAI Reserve Detail 2014 (1) Oil (MBbl) Natural Gas (MMcf) NGLs (MBbl) Total (MMcfe) % Gas (%) PV-10 ($M) PDP 3, ,795 18, ,800 74% $ 1,186,884 PDNP ,386 1,713 47,351 71% 102,958 PUD 8, ,748 42,665 1,096,928 72% 1,731,506 Total Proved 12,603 1,180,929 62,589 1,632,079 72% $ 3,021,348 Probable 8, ,363 40, ,470 67% 1,137,039 2P Reserves 21,051 1,791, ,159 2,536,548 71% $ 4,158,388 Possible 35,765 1,595,662 90,668 2,354,260 68% 2,341,832 3P Reserves 56,816 3,386, ,826 4,890,809 69% $ 6,500, (2) Oil (MBbl) Natural Gas (MMcf) NGLs (MBbl) Total (MMcfe) % Gas (%) PV-10 ($M) PDP 2, ,037 12, ,351 72% $ 610,304 PDNP ,760 1,645 44,290 67% 92,615 PUD 7, ,457 28, ,936 71% 766,033 Total Proved 11, ,254 42,577 1,125,577 71% $ 1,468,952 Probable 10, ,185 33, ,317 67% 1,052,243 2P Reserves 21,790 1,337,440 76,285 1,925,894 69% $ 2,521,195 Possible 36,376 1,080,540 68,686 1,710,914 63% 2,386,228 3P Reserves 58,166 2,417, ,972 3,636,808 66% $ 4,907, (1) Proved, probable and possible reserves audited by NSAI; report based on SEC pricing as of December 31, See Cautionary Statements and Additional Disclosures in the Appendix for more information regarding 3P reserves and PV-10 (2) Proved reserves are engineered by NSAI as of December 31, 2013; probable and possible reserves prepared by MRD and audited by NSAI; reports based on SEC pricing as of December 31, See Cautionary Statements and Additional Disclosures in the Appendix for more information regarding 3P reserves and PV-10

32 Adjusted EBITDA Reconciliation Adjusted EBITDA is a non-gaap financial measure. We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; debt extinguishment costs; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived properties; accretion of asset retirement obligations; losses on commodity derivative contracts and cash settlements received; losses on sale of properties; stock-based compensation; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP; cash distributions from MEMP; transaction related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP; gains on sale of assets and other nonroutine items. MRD s non-gaap financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other measure of financial performance calculated and presented in accordance with GAAP. MRD's non-gaap financial measures may not be comparable to similarly-titled measures of other companies because they may not calculate such measures in the same manner as MRD does. The following table presents the MRD Segment information for the periods indicated: 32 For the Three Months Ended June 30, (Amounts in $000s) MRD Segment net income (loss) $ (26,703) $ (957,747) Add (Deduct): Interest expense, net 9,613 16,494 Debt extinguishment costs - 37,248 Income tax expense (benefit) (24,664) (11,846) Depreciation, depletion and amortization 35,827 30,814 Accretion of asset retirement obligations (Gains) losses on commodity derivatives 30,463 3,244 Cash settlements received (paid) on commodity derivatives 37,539 (3,408) Transaction related costs Incentive-based compensation expense 18, ,992 (Gain) loss on sale of properties 50 3,167 Exploration costs 2, Equity (income) loss in MEMP 89 9,944 Cash distributions from MEMP 75 3,002 MRD Segment Adjusted EBITDA: $ 82,831 $ 81,471

33 Adjusted EBITDA Reconciliation Adjusted EBITDA is a non-gaap financial measure. We evaluate segment performance based on Adjusted EBITDA. Adjusted EBITDA is defined as net income (loss), plus interest expense; debt extinguishment costs; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived properties; accretion of asset retirement obligations; losses on commodity derivative contracts and cash settlements received; losses on sale of properties; stock-based compensation; incentive-based compensation expenses; exploration costs; provision for environmental remediation; equity loss from MEMP; cash distributions from MEMP; transaction related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains on commodity derivative contracts and cash settlements paid; equity income from MEMP; gains on sale of assets and other nonroutine items. MRD s non-gaap financial measures should not be considered as alternatives to GAAP measures such as net income, operating income, net cash flows provided by operating activities or any other measure of financial performance calculated and presented in accordance with GAAP. MRD's non-gaap financial measures may not be comparable to similarly-titled measures of other companies because they may not calculate such measures in the same manner as MRD does. The following table presents the MRD Segment information for the periods indicated: 33 For the Six Months Ended June 30, (Amounts in $000s) MRD Segment net income (loss) $ 23,668 $ (945,357) Add (Deduct): Interest expense, net 19,369 34,468 Debt extinguishment costs - 37,248 Income tax expense (benefit) 22,914 (11,821) Depreciation, depletion and amortization 76,359 55,943 Accretion of asset retirement obligations (Gains) losses on commodity derivatives (77,727) 15,960 Cash settlements received (paid) on commodity derivatives 70,288 (8,629) Transaction related costs 1,407 1,068 Incentive-based compensation expense 29, ,015 (Gain) loss on sale of properties 50 3,057 Exploration costs 2,956 1,080 Equity (income) loss in MEMP ,930 Cash distributions from MEMP 151 6,004 MRD Segment Adjusted EBITDA: $ 169,661 $ 146,223

34 Adjusted Net Income Reconciliation MRD Segment Adjusted Net Income is a supplemental non-gaap financial measure that is used by external users of MRD s financial statements. We define MRD Segment Adjusted Net Income as net income excluding the impact of certain items including gains or losses on commodity derivative instruments not yet settled, gains or losses on sales of properties, debt extinguishment costs, equity income in MEMP, stock-based compensation and incentive-unit compensation expense. We believe MRD Segment Adjusted Net Income is useful to investors because it provides readers with a more meaningful measure of our profitability before recording certain items for which the timing or amount cannot be reasonably determined. However, this measure is provided in addition to, not as an alternative for, and should be read in conjunction with, the information contained in our financial statements prepared in accordance with GAAP. The following table presents the MRD Segment information for the periods indicated: For the Three Months Ended June 30, (Amounts in $000s) MRD Segment net income (loss) $ (26,703) $ (951,747) Add (Deduct): (Gains) losses on commodity derivatives 30,463 3,244 Cash settlements (paid) received on commodity derivatives 37,539 (3,408) (Gain) loss on sale of properties 50 3,167 Stock-based compensation (LTIPs) 1, Incentive-based compensation expenses 16, ,817 Equity (income) loss in MEMP 89 9,944 Debt extinguishment costs - 37,248 MRD segment adjusted net income (loss) before tax effect 59,511 41,440 Tax effect related to adjustments (42,245) (1,206) MRD Segment Adjusted Net Income $ 17,266 $ 40,234 34

35 Cautionary Statements and Additional Disclosures Except as otherwise indicated, the description of MRD s business, properties, strategies and other information in this presentation relates solely to the MRD Segment, which excludes the business, properties, strategies and other information regarding Memorial Production Partners LP and its subsidiaries ( MEMP ). This presentation has been prepared by MRD and includes market data and other statistical information from sources believed by MRD to be reliable, including independent industry publications, government publications or other published independent sources. Some data is also based on MRD s good faith estimates, which are derived from its review of internal sources as well as the independent sources described herein. Although MRD believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. 3P Reserves and PV-10 MRD has disclosed PV-10 in this presentation based on its reserve reports. PV-10 is a non-gaap financial measure and represents the period-end present value of estimated future cash inflows from our natural gas and crude oil reserves, less future development and production costs, discounted at 10% per annum to reflect timing of future cash flows and using SEC pricing assumptions in effect at the end of the period. SEC pricing for natural gas and oil of $3.67 per MMBtu and $93.42 per Bbl and $4.35 per MMBtu and $91.48 per Bbl was based on the unweighted average of the first-day-of-the-month prices for each of the twelve months preceding December 2013 and December 2014, respectively. PV-10 differs from standardized measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes. Moreover, GAAP does not provide a measure of estimated future net cash flows for reserves other than proved reserves. Because PV-10 estimates of probable and possible reserves are more uncertain than PV-10 and standardized estimates of proved reserves, but have not been adjusted for risk due to that uncertainty, they may not be comparable with each other. Nonetheless, MRD believes that PV-10 estimates for reserve categories other than proved present useful information for investors about the future net cash flows of its reserves in the absence of a comparable GAAP measure such as standardized measure. Because of this, PV-10 can be used within the industry and by creditors and securities analysts to evaluate estimated net cash flows from proved reserves on a more comparable basis. In addition, investors should be cautioned that estimates of PV-10 for probable and possible reserves, as well as the underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. MRD s PV-10 estimates of proved reserves and its standardized measure for 2013 are equivalent because, prior to its initial public offering, MRD was not subject to entity level taxation. For 2014, MRD has included a reconciliation of the estimate of PV-10 for proved reserves to the most directly comparable GAAP measure, standardized measure, at the end of this Appendix. Neither PV-10 nor standardized measure represents an estimate of fair market value of MRD s natural gas and oil properties. MRD and others in the industry use PV-10 as a measure to compare the relative size and value of estimated reserves held by companies without regard to the specific tax characteristics of such entities. We have provided summations of our proved, probable and possible reserves and summations of our PV-10 for our proved, probable and possible reserves in this presentation. The SEC strictly prohibits companies from aggregating proved, probable and possible reserves in filings with the SEC due to the different levels of certainty associated with each reserve category. Investors should be cautioned that estimates of PV-10 of probable reserves, as well as the underlying volumetric estimates, are inherently more uncertain of being recovered and realized than comparable measures for proved reserves, and that the uncertainty for possible reserves is even more significant. Further, because estimates of probable and possible reserve volumes and PV-10 have not been adjusted for risk due to this uncertainty of recovery, their summation may be of limited use. Investors are cautioned to review any such summations together with the breakdown of our reserves by category as set forth in this presentation. On September 18, 2015, the prompt month NYMEX-WTI futures price for crude oil was $44.68 per Bbl and the prompt month NYMEX-Henry Hub futures price of natural gas was $2.61 per MMBtu. 35