FILED BY RANGE RESOURCES CORPORATION PURSUANT TO RULE 425 UNDER THE SECURITIES ACT OF 1933 AND DEEMED FILED PURSUANT TO RULE 14a-12 UNDER THE SECURITIES EXCHANGE ACT OF 1934 SUBJECT COMPANY: MEMORIAL RESOURCE DEVELOPMENT CORP. (FILE NO. 001-36490) September 1, 2016 Company Presentation

Forward-Looking Statements This communication contains certain “forward-looking statements” within the meaning of federal securities laws, including within the meaning of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 that are not limited to historical facts, but reflect Range’s and MRD’s current beliefs, expectations or intentions regarding future events.  Words such as “may,” “will,” “could,” “should,” “expect,” ““plan,” “project,” “intend,” “anticipate,” “believe,” “estimate,” “predict,” “potential,” “pursue,” “target,” “continue,” and similar expressions are intended to identify such forward-looking statements. The statements in this presentation that are not historical statements, including statements regarding the expected timetable for completing the proposed transaction, benefits and synergies of the proposed transaction, costs and other anticipated financial impacts of the proposed transaction; the combined company’s plans, objectives, future opportunities for the combined company and products, future financial performance and operating results and any other statements regarding Range’s and MRD’s future expectations, beliefs, plans, objectives, financial conditions, assumptions or future events or performance that are not historical facts, are forward-looking statements within the meaning of the federal securities laws.  Furthermore, the statements relating to the proposed transaction are subject to numerous risks and uncertainties, many of which are beyond Range’s or MRD’s control, which could cause actual results to differ materially from the results expressed or implied by the statements. These risks and uncertainties include, but are not limited to: failure to obtain the required votes of Range’s or MRD’s shareholders; the timing to consummate the proposed transaction; satisfaction of the conditions to closing of the proposed transaction may not be satisfied or that the closing of the proposed transaction otherwise does not occur; the risk that a regulatory approval that may be required for the proposed transaction is not obtained or is obtained subject to conditions that are not anticipated; the diversion of management time on transaction-related issues; the ultimate timing, outcome and results of integrating the operations of Range and MRD; the effects of the business combination of Range and MRD, including the combined company’s future financial condition, results of operations, strategy and plans; potential adverse reactions or changes to business relationships resulting from the announcement or completion of the proposed transaction; expected synergies and other benefits from the proposed transaction and the ability of Range to realize such synergies and other benefits; expectations regarding regulatory approval of the transaction; results of litigation, settlements and investigations; and actions by third parties, including governmental agencies; changes in the demand for or price of oil and/or natural gas can be significantly impacted by weakness in the worldwide economy; consequences of audits and investigations by government agencies and legislative bodies and related publicity and potential adverse proceedings by such agencies; compliance with environmental laws; changes in government regulations and regulatory requirements, particularly those related to oil and natural gas exploration; compliance with laws related to income taxes and assumptions regarding the generation of future taxable income; weather-related issues; changes in capital spending by customers; delays or failures by customers to make payments owed to us; impairment of oil and natural gas properties; structural changes in the oil and natural gas industry; and maintaining a highly skilled workforce. Range’s and MRD’s respective reports on Form 10-K for the year ended December 31, 2015, Form 10-Q for the quarter ended March 31, 2016 and June 30 2016, recent Current Reports on Form 8-K, and other SEC filings, including the registration statement on Form S-4, as amended, that includes a joint proxy statement of Range and MRD and constitutes a prospectus of Range, discuss some of the important risk factors identified that may affect these factors and Range’s and MRD’s respective business, results of operations and financial condition.  Range and MRD undertake no obligation to revise or update publicly any forward-looking statements for any reason. Readers are cautioned not to place undue reliance on these forward-looking statements that speak only as of the date hereof. The SEC permits oil and gas companies, in filings made with the SEC, to disclose proved reserves, which are estimates that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions as well as the option to disclose probable and possible reserves. Range has elected not to disclose the Company’s probable and possible reserves in its filings with the SEC. Range uses certain broader terms such as "resource potential,” “unrisked resource potential,” "unproved resource potential" or "upside" or other descriptions of volumes of resources potentially recoverable through additional drilling or recovery techniques that may include probable and possible reserves as defined by the SEC's guidelines. Range has not attempted to distinguish probable and possible reserves from these broader classifications. The SEC’s rules prohibit us from including in filings with the SEC these broader classifications of reserves. These estimates are by their nature more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of actually being realized. Unproved resource potential refers to Range's internal estimates of hydrocarbon quantities that may be potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques and have not been reviewed by independent engineers. Unproved resource potential does not constitute reserves within the meaning of the Society of Petroleum Engineer's Petroleum Resource Management System and does not include proved reserves. Area wide unproven resource potential has not been fully risked by Range's management. “EUR,” or estimated ultimate recovery, refers to our management’s estimates of hydrocarbon quantities that may be recovered from a well completed as a producer in the area. These quantities may not necessarily constitute or represent reserves within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management System or the SEC’s oil and natural gas disclosure rules. Actual quantities that may be recovered from Range's interests could differ substantially. Factors affecting ultimate recovery include the scope of Range's drilling program, which will be directly affected by the availability of capital, drilling and production costs, commodity prices, availability of drilling and completion services and equipment, lease expirations, transportation constraints, regulatory approvals, field spacing rules, recoveries of gas in place, length of horizontal laterals, actual drilling and completion results, including geological and mechanical factors affecting recovery rates and other factors. Estimates of resource potential may change significantly as development of our resource plays provides additional data. In addition, our production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases. Investors are urged to consider closely the disclosure in our most recent Annual Report on Form 10-K, available from our website at www.rangeresources.com or by written request to 100 Throckmorton Street, Suite 1200, Fort Worth, Texas 76102. You can also obtain this Form 10-K on the SEC’s website at www.sec.gov or by calling the SEC at 1-800-SEC-0330.

Range’s Keys for Success High quality acreage position in core of Marcellus Low-cost structure with ability to continue to drive costs down Continual capital efficiency improvement Low-cost takeaway capacity improves realizations and enhances flexibility Strong hedge and liquidity profile with no near-term debt maturities

Gas In Place (GIP) Analysis Shows Greatest Potential in SW PA Note: Townships where Range holds ~2,000+ acres (as of January 2016) and estimated as prospective, are outlined green. GIP – Range estimates. When GIP analysis from the Marcellus, Upper Devonian and Point Pleasant are combined, the largest stacked pay resource is located in SW PA where Range has concentrated its acreage position

SW/NE Pennsylvania Stacked Pays Upper Devonian 335,000 180,000 515,000 335,000 280,000 615,000 - 400,000 400,000 670,000 860,000 1,530,000 Marcellus Utica/Point Pleasant Wet Acreage Dry Acreage Total Net Acreage (1) (1) Excludes Northwest PA - 280,000 net acres, largely HBP Stacked Pays Allow for Multiple Development Opportunities

Marcellus Wells – An Industry Leader See appendix for complete assumptions and data on each area SW Super-Rich SW Wet SW Dry NE Dry EUR 16.0 Bcfe 1,450 Mbbls & 7.3 Bcf 20.6 Bcfe 1,756 Mbbls & 10.1 Bcf 17.6 Bcf 20.5 Bcf EUR/1,000 ft. lateral 2.4 Bcfe 3.0 Bcfe 2.5 Bcf 2.5 Bcf EUR/stage 485 Mmcfe 589 Mmcfe 503 Mmcf 500 Mmcf Well Cost $5.9 MM $5.8 MM $5.2 MM $4.3 MM Cost/1,000 ft. lateral $881 K $832 K $743 K $518 K Stages 33 35 35 41 Lateral Length 6,660 ft. 6,970 ft. 7,000 ft. 8,200 ft. Strip (as of 6/30/16) 26% 25% 59% 70% F&D Cost/mcfe $0.44 $0.34 $0.36 $0.25 Range Marcellus 2016 Well Economic Summary

Existing Pads Enhance Future Development for Range Expansive inventory of over 200 pads 124 pads: 5 or fewer wells 59 pads: 6-9 wells New pads in progress Pads accommodate ~20 wells Flexibility to drill Marcellus, Utica / Point Pleasant or Upper Devonian formations Realization of significant time and cost savings Minimal permitting Existing roads, surface facilities and gathering system in place

Sustained Growth + Improving Capital Efficiency Market-Leading Capital Efficient Spending Program * 2016 production estimated at midpoint of guidance with capital budget of $495M $ Capex per incremental mcfe Production Production (Mmcfepd)

Driving Down Unit Costs $/mcfe 2011 2012 2013 2014 2015 2016E DD&A $1.69 $1.62 $1.44 $1.30 $1.14 $0.96 LOE (1) $0.60 $0.41 $0.36 $0.35 $0.26 $0.20 Prod. Taxes $0.14 $0.15 $0.13 $0.10 $0.07 $0.06 G&A (1) $0.56 $0.46 $0.42 $0.35 $0.27 $0.24 Interest $0.69 $0.61 $0.51 $0.40 $0.33 $0.29 Trans. & Gathering $0.62 $0.70 $0.75 $0.76 $0.78 $1.05 (3) Total $4.30 $3.95 $3.61 $3.26 $2.85 $2.55 $0.00 Excludes non-cash stock compensation Includes additional NGL & natural gas firm transport agreements. Propane transport costs were previously netted against NGL revenue. Incremental natural gas & NGL revenue, including additional ethane production, will more than offset the 2016 increase in transport expense (3) Expected improvement in differentials as a result of additional transportation capacity Unit Costs Down 41% ($0.25)(3) $1.05(2)

Near-Term Price Enhancements Ability to utilize full year of Spectra’s Uniontown to Gas City project, including ~200 Mmcf/day of gas production from local Appalachia M2 to Midwest markets Additional takeaway projects could strengthen local pricing differentials Gulf Expansion Phase 1 online in 4Q2016 Only producer with capacity on the fully operational Mariner East project to Marcus Hook 20,000 barrels per day of ethane transportation to fulfill contract with INEOS 20,000 barrels per day of propane transportation with access to international propane markets Initiated new marketing arrangements which improve Marcellus condensate realizations Natural Gas Differential NGL (Natural Gas Liquids) Differential Condensate Differential $0.00 Midpoint Midpoint Midpoint

Regional Direction Projected Avg. 2016 Projected Avg. 2017 Mmbtu/day Transport Cost per Mmbtu Mmbtu/day Transport Cost per Mmbtu Firm Transportation Appalachia/Local 390,000 $ 0.20 325,000 $ 0.21 Gulf Coast 295,000 $ 0.30 510,000 $ 0.31 Midwest/Canada 285,000 $ 0.28 330,000 $ 0.30 Northeast 210,000 $ 0.59 210,000 $ 0.59 Total Gross Takeaway Capacity 1,180,000 $ 0.31 1,375,000 $ 0.35 Total Net Takeaway Capacity 980,000 $ 0.31 1,140,000 $ 0.35 Estimated Marcellus Differential to NYMEX ($0.40) – ($0.45) ($0.25) – ($0.35) Appalachia Gas Transportation Arrangements Does not include current intermediary pipeline capacity (gathering) of >650,000 Mmbtu/day and assumes full utilization. Based on pipeline operator’s anticipated project start dates. (1) Based on expected utilization of capacity and forward pricing with differentials as of July 2016 (1) Additional capacity expected to improve differentials in 2016, 2017 and 2018

Strong Unhedged Recycle Ratio Pre-Hedge Price (Assuming 2017 NYMEX $3.10/$50) ~ $2.70 All-In Cash Unit Costs (2016 Expected) $1.84 Adjusted Margin ~ $0.86 Expected Future Development Cost for PUD Reserves $0.40 Unhedged Recycle Ratio ~ 2.0 Recycle Ratio: (Margin divided by F&D)

YE 2013 YE 2014 Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q2 2016 ($ in millions) Bank borrowings (1) $500 $723 $912 $364 $987 $95 $31 $3 Sr. Notes (1) 750 750 750 750 750 Sr. Sub. Notes (1) 2,641 2,350 2,350 2,350 1,850 1,850 1,850 1,850 Less: Cash (0) (0) (0) (0) (0) (0) (0) (0) Net debt 3,141 3,073 3,262 3,464 3,587 2,695 2,631 2,603 Common equity 2,414 3,456 3,490 3,381 3,085 2,760 2,672 2,464 Total capitalization $5,555 $6,529 $6,752 $6,845 $6,672 $5,455 $5,303 $5,067 Debt-to capitalization 57% 47% 48% 50% 54% 49% 50% 51% Debt/EBITDAX 2.8x 2.6x 2.9x 3.3x 3.7x 3.0x 3.3x 3.6x Liquidity (2) $1,166 $1,172 $980 $1,527 $876 $1,267 (3) $1,238 (3) $1,265 (3) Strong, Simple Balance Sheet Excludes unamortized debt issuance costs Liquidity based on bank commitment amount, which excludes additional liquidity under total borrowing base Liquidity currently limited based on senior subordinated notes indenture provision Lowest Debt Level Since 2012

Liquidity and Financial Capacity (pre-merger) ( $ Millions ) Senior Secured Revolving Credit Facility Senior Subordinated Notes Senior Notes Interest Rate 2.8% 5.75% 5.0% 5.0% 4.875% $3 Million Drawn Bank Commitment - $2 Billion Borrowing Base - $3 Billion Lowest debt since 2012 $4B credit facility unanimously reaffirmed by bank group $3B borrowing base $2B committed $0.003B drawn No note maturities until 2021 ~80% of 2016 remaining gas production hedged at ~$3.22, ~30% of 2017 gas production hedged at $2.94 Solid, stable coverage on debt covenants

Range’s Keys for Success – Assets, Team, Agreements & Strategy Low cost structure with ability to continue driving costs lower Improving capital efficiency Better realizations from additional takeaway capacity and sales agreements Low-cost takeaway capacity with built-in flexibility Strong hedges and ample liquidity High quality, large scale acreage position containing repeatable projects with good returns Unit costs down over 40% in the last 5 years Lower debt balances reduce interest expense Improved targeting and completions Ability to reach premium markets and deliver products outside Marcellus, including international exports First-mover advantage allowed Range to secure capacity on low-cost expansion projects Anticipated excess infrastructure build-out and avoided contracting for excessive firm transport Over 80% of expected 3 rd & 4 th quarter production hedged at a floor price of $3.22 per mcf At 06/30/16, only ~$3 million drawn on $2 billion credit facility Optionality and flexibility due to quality of acreage position, gathering system, available locations on existing pads Existing pad locations with facilities and gathering Longer laterals; 2016 plan average ~7,000 ft., 2017 plan est. to average ~8,000 ft. 2017 maintenance capex estimated at ~$300 million 2016 program expected to use cash flow and asset sales, preserving liquidity Further improvements expected High-grading asset sales have lowered operating costs Roughly ~30% of 2017 gas production hedged at $2.94 Marketing arrangements expected to improve netback pricing for all products

Proposed Merger with Memorial Resource Development Announcement Date: May 16, 2016 Special Meeting Date: September 15, 2016 Expected Closing Date: Late-Q3 2016

Highlights of Merger Core acreage positions in the two highest return, lowest cost natural gas plays Immediately cash flow accretive and credit enhancing Complementary assets positioned near expanding natural gas and NGL demand centers Combination of two low-cost gas producers with opportunities to drive costs lower, improve returns and increase cash flow Significant Lower Cotton Valley potential across acreage

Combining Two High Quality Assets Low risk and high repeatability Near-term focus primarily on Upper Red Stacked pay area with further potential development opportunity Prolific horizontal well performance Many of the top 30-day IP rates in the U.S. came from the Upper Red Upside from operational enhancements Improved lateral targeting and placement Cost reductions through service relationships and reduced drilling and completions time Low risk and high repeatability Near-term focus on Marcellus development in SW PA Stacked pay area with further potential development opportunity Prolific horizontal well performance EUR / 1,000 lateral length of ~2.5 to 3.0 Bcfe, on average Upside from operational efficiencies Targeting the most productive areas Utilizing existing pads and infrastructure to lower cost and maximize returns N. Louisiana - not to scale Terryville Acreage in Northern Louisiana Marcellus Acreage in Pennsylvania SW Pennsylvania - not to scale

Immediately Accretive & Credit Enhancing Annual Consensus Metrics* Existing RRC Pro Forma RRC % Change 2016E Production 520 Bcfe 670 Bcfe +29% 2016E Production per day 1,420 Mmcfe 1,830 Mmcfe +29% 2016E Cash Flow $375 Million $780 Million +108% 2016E Cash Flow per share $2.24 $3.20 +43% 2016E Cash Margin per Mcfe $0.72 $1.17 +62% YE 2016E Debt to EBITDAX 4.8x 3.5x +27% YE 2016E Debt to Cap 50% 37% +26% * Using 5/13/16 Consensus estimates Significant Enhancement to Cash Flow Per Share and Credit Metrics

Marketing and Operational Efficiencies Marketing MRD’s position gives Range a presence in the Gulf Coast in advance of additional transportation availability out of Appalachia MRD’s production receives near NYMEX pricing which will improve corporate differentials Opportunities to optimize Range’s transportation portfolio Creates an expanding and improved Range customer base in or near multiple demand areas Operational Modified drilling and targeting techniques Capital cost reductions through leveraging service provider relationships and reducing drilling or completion times Overhead efficiencies Marcellus Terryville Northeast Gulf Coast & LNG Midwest MX Exports LNG Southeast Gulf Coast

220,000 Acres of Lower Cotton Valley Potential The position is anchored to the north by Terryville Field, to the south by Vernon Field, to the east by Choudrant Field and to the west by Driscoll Field Multiple vertical Lower Cotton Valley wells show: Section exists across acreage Gas charged Good vertical production Good vertical wells should lead to good horizontal wells The Lower Cotton Valley gets thicker and higher pressured as you move south from Terryville Field MRD has drilled three vertical pilots (1) Assumes full exercise of an acreage option agreement to lease acreage in North Louisiana Terryville Driscoll Choudrant Vernon The over-pressured Lower Cotton Valley interval exists across the area

2017 Growth Trajectory 30% growth represents Range full-year 2016 production with one quarter of MRD (4Q16) and a 2017 organic growth rate of 10+% based on strip prices as of 07/27/2016 Assumes MRD in 4th Qt. 2016 Current estimates and strip pricing indicate that Range (post-merger) can grow 10+% organically in 2017 at or near cash flow, which represents 30+% growth y/y ~2 Bcfepd 30+% Growth (a)

Why Invest in Range? Ability to allocate capital between the two highest return, lowest cost natural gas plays Unhedged recycle ratio of ~2x near strip prices allows for efficient development of asset base 2017 growth of 30+% (spending at or near cash flow with strip pricing(a)); also positions Range well for growth in 2018 ~90% of natural gas production will be sold in favorable markets by end of 2017 Improving differentials expected on natural gas, NGLs and condensate from improved marketing agreements (a) Based on 10% organic growth at strip pricing on 7/27/16

Appendix

Range: Low-Cost, Large Scale Source: Wood Mackenzie as of February 2016 Lowest Breakeven Price in the SW Marcellus Per Wood Mackenzie

Appalachian Peers Well Cost Comparison Average Well Cost* ($000’s) Average Lateral Length (ft.) Cost (per 1,000 ft.) Range $5,630 6,876 $819 K Peer A 6,300 7,000 900 Peer B 8,100 9,000 900 Peer C 5,700 7,000 814 Peer D 7,350 7,500 980 Peer E 7,100 7,700 925 Peer Average $6,190 7,640 $904 K Peers included: AR, COG, EQT, RICE, SWN - data comes from presentations as of 07/26/16 * Costs should include surface facilities

Peers included: Antero, Cabot, Consol, EQT, Gulfport, Rice & Southwestern Negative Additions 2015 F & D per Mcfe Negative Additions Negative Additions Negative Additions Appalachia Producer’s 2015 F & D Costs Core Acreage Has Big Impact on Value of Reserves

71% decrease 55% decrease 63% decrease Cost & Efficiency Improvements – SW Pennsylvania 120% increase ' ' ' ' ' ' ' '

Cost & Efficiency Improvements – Northern Marcellus

Mariner East: Opening New Lanes First Shipments of Ethane & Propane – Faster Propane Loading Combined with VLGC Ships First VLGC Loading of Range Propane for Export Only producer with current capacity on Mariner East Historic first shipments of ethane from U.S. to Europe Optionality of selling propane internationally or in local markets Improved ethane and propane realizations in 2016 for Range Ethane loading in progress

Track Record of Impressive Reserve Replacement at Low Cost Includes performance and price revisions, excludes SEC required PUD removal due to 5-year rule From all sources, including price, performance and SEC required PUD removal due to 5-year rule Percentages shown are compounded annual growth rate 2011 2012 2013 2014 2015 3-Year Average 5-Year Average Reserve Replacement All sources – excluding PUD removals (1) 849% 680% 745% 793% 436% 638% 669% All sources (2) 849% 680% 636% 649% 207% 469% 546% Finding Costs Drill bit only – without acreage (1) $0.76 $0.76 $0.47 $0.44 $0.37 $0.43 $0.53 Drill bit only – with acreage (1) $0.89 $0.86 $0.52 $0.51 $0.40 $0.48 $0.60 All sources – excluding PUD removals (2) $0.89 $0.86 $0.52 $0.54 $0.40 $0.50 $0.61 All sources (2) $0.89 $0.76 $0.61 $0.67 $0.84 $0.68 $0.75

SW PA Super-Rich Area Marcellus Projected 2016 Well Economics Southwestern PA – (High Btu case) 110,000 Net Acres EUR / 1,000 ft. – 2.40 Bcfe EUR – 16.0 Bcfe (226 Mbbls condensate, 1,224 Mbbls NGLs & 7.3 Bcf gas) Drill and Complete Capital – $5.87 MM ($881 K per 1,000 ft.) Average Lateral Length – 6,660 ft. F&D – $0.44/mcfe NYMEX Gas Price ROR Strip - 26% $3.00 - 26% Estimated Cumulative Recovery for 2016 Production Forecast Condensate (Mbbls) Residue (Mmcf) NGL w/ Ethane (Mbbls) 1 Year 48 661 111 2 Years 73 1,142 192 3 Years 92 1,555 261 5 Years 120 2,246 378 10 Years 161 3,517 591 20 Years 195 5,157 867 EUR 226 7,279 1,224 Price includes current and expected differentials less gathering, transportation and processing costs For flat pricing, oil price assumed to be $40/bbl for 2016, $50/bbl for 2017 then $65/bbl to life with no escalation NGL is average price including ethane with escalation Ethane price tied to ethane contracts plus same comparable escalation Strip dated 06/30/2016 with 10-year average $55.42/bbl and $3.29/mcf

Southwest PA - Super-Rich Area 2016 Turn in Line Forecast System designed to maximize project economics

Southwest PA – Super-Rich Marcellus All comparisons based on Turned in Line (TIL) wells for each year

SW PA Wet Area Marcellus Projected 2016 Well Economics Southwestern PA – (Wet Gas case) 225,000 Net Acres EUR / 1,000 ft. – 2.95 Bcfe EUR – 20.6 Bcfe (56 Mbbls condensate, 1,700 Mbbls NGLs & 10.1 Bcf gas) Drill and Complete Capital – $5.8 MM ($832 K per 1,000 ft.) Lateral Length – 6,970 ft. F&D – $0.34/mcfe Price includes current and expected differentials less gathering, transportation and processing costs For flat pricing, oil price assumed to be $40/bbl for 2016, $50/bbl for 2017 then $65/bbl to life with no escalation NGL is average price including ethane with escalation Ethane price tied to ethane contracts plus same comparable escalation Strip dated 06/30/2016 with 10-year average $55.42/bbl and $3.29/mcf NYMEX Gas Price ROR Strip - 25% $3.00 - 25% Estimated Cumulative Recovery for 2016 Production Forecast Condensate (Mbbls) Residue (Mmcf) NGL w/ Ethane (Mbbls) 1 Year 20 1,211 204 2 Years 30 2,014 339 3 Years 36 2,665 449 5 Years 44 3,694 622 10 Years 51 5,470 921 20 Years 55 7,654 1,289 EUR 56 10,100 1,700

Southwest PA - Wet Area 2016 Turn in Line Forecast System designed to maximize project economics

Southwest PA – Wet Marcellus All comparisons based on Turned in Line (TIL) wells for each year

Southwestern PA – (Dry Gas case) 180,000 Net Acres EUR / 1,000 ft. – 2.52 Bcf EUR – 17.6 Bcf Drill and Complete Capital $5.2 MM ($743 K per 1,000 ft.) Average Lateral Length – 7,000 ft. F&D – $0.36/mcf NYMEX Gas Price ROR Strip - 59% $3.00 - 54% Estimated Cumulative Recovery for 2016 Production Forecast Residue (Mmcf) 1 Year 3,039 2 Years 4,674 3 Years 5,866 5 Years 7,609 10 Years 10,392 20 Years 13,633 EUR 17,641 Price includes current and expected differentials less gathering and transportation costs Strip dated 06/30/2016 with 10-year average $55.42/bbl and $3.29/mcf SW PA Dry Area Marcellus Projected 2016 Well Economics Based on Washington County well data

SW PA– Dry Area 2016 Turn in Line Forecast Based on Washington County well data

All comparisons based on Turned in Line (TIL) wells for each year Based on Washington County well data Southwest PA– Dry Marcellus

Normalized Production Results of Marcellus Tighter Spacing Projects Mcfe/day per 1,000 ft. Tighter spaced wells turned to sales in 2009 and 2010 Average lateral length of these wells is 2,861 feet Well performance not reflective of improved targeting and completion designs 500 foot spaced wells produced 77% of 1,000 foot spaced wells through the life of the current production

Targeting/Downspacing Test Results Encouraging

Returning to Existing Pads – SW Wet

Returning to Existing Pads – SW Dry Additional 3 wells Avg EUR/1000 ft.: 3.0+ Bcfe Ability to target our best areas with 3.0+ Bcfe/1,000 ft. New wells have EURs 20% higher than the average dry well Significant cost savings Drilled wells - 2015 Future Locations Drilled wells - 2014

Gas In Place (GIP) – Marcellus Shale GIP is a function of pressure, temperature, thermal maturity, porosity, hydrocarbon saturation and net thickness Two core areas have been developed in the Marcellus Condensate and NGLs are in gaseous form in the reservoir Note: Townships where Range holds ~2,000+ acres (as of January 2016) and estimated as prospective, are outlined green. GIP – Range estimates.

Gas In Place (GIP) – Point Pleasant Bold, outlined portion represents the area of the highest pressure gradients in the Point Pleasant Note: Townships where Range holds ~2,000+ acres (as of January 2016) and estimated as prospective, are outlined green. GIP – Range estimates.

Gas In Place (GIP) – Upper Devonian Shale The greatest GIP in the Upper Devonian is found in SW PA A significant portion of the GIP in the Upper Devonian is located in the wet gas window Note: Townships where Range holds ~2,000+ acres (as of January 2016) and estimated as prospective, are outlined green. GIP – Range estimates.

Utica Wells – Wellhead Pressure vs. Cumulative Production Early Time Production Data (Including Flowback/Test Data) RRC DMC Properties well one of the best in the Utica Wellhead Pressure (psi) Normalized Gas Cum (Mcf/1000 ft.) ~25 Mmcfd ~30 Mmcfd ~18 Mmcfd ~12 Mmcfd ~20 Mmcfd *TVD (total vertical depth) With an average pressure gradient of .85 to .95 for these wells, greater TVD equals higher cost and higher pressure 13,200 ft. TVD* 13,400 ft. TVD* 11,850 ft. TVD* 9,206 ft. TVD*

Utica/Point Pleasant Update Continued improvement in well performance for the 1st, 2nd and 3rd wells due to higher sand concentration and improved targeting 3rd well appears to be one of the best dry gas Utica wells in the basin 3rd well fully online in Q3 400,000 net acres in SW PA prospective Note: Townships where Range holds ~2,000+ or more acres are shown outlined above (as January 2016)

Macro Section

Significant Natural Gas Demand Growth Projected – Beginning in 2016 LONG TERM US NATURAL GAS DEMAND ROADMAP (BCF/D)   2016 2017 2018 2019 2020 Cumulative 2016-2020 LNG Exports     Sabine Pass 1.2 1.2 0.7   3.1 Freeport 0.5 1.0 1.5 Cove Point 0.8   0.8 Cameron 1.2 0.6   1.8 Corpus Christi 0.8 0.8 1.6 LNG Sub-Total 1.2 1.2 2.6 3.1 0.8 8.9 Mexico/Canada Exports     Mexico Net Exports 0.5 0.3 0.3 0.3 0.4 1.8 Canada net Exports 0.1 0.1 0.1 0.1 0.1 0.5 Mexico/Canada Sub-Total 0.6 0.4 0.4 0.4 0.5 2.3 Power Generation             Coal Plant Retirements 0.4 0.3 0.1 0.0 0.3 1.1 Nuclear Retirements - - 0.1 0.1 0.2 0.4 Incremental Electricity Demand 0.1 0.1 0.1 0.2 0.2 0.7 Power Generation Sub-Total 0.5 0.4 0.4 0.3 0.7 2.3 Industrial             Methanol 0.3 0 0 0 0 0.4 Ethylene 0 0.4 0.1 - 0.1 0.6 Ammonia 0.5 0.1 0.2 0.1 0.1 1.0 Industrial Sub-Total 0.8 0.4 0.3 0.1 0.2 2.0 Transportation             New Fueling Opportunities - - 0.1 0.1 0.1 0.3 Transportation Sub-Total - - 0.1 0.1 0.1 0.3               2016 2017 2018 2019 2020 2020 Total 3.1 2.5 3.7 4.0 2.2 15.8 Research report dated 07/07/2016

U.S. LNG Exports Expected to be ~8 Bcf/day by 2020 – per TPH Research report dated 10/08/2015

U.S. Natural Gas Exports to Mexico Source: PointLogic, Bloomberg as of August 2016 Mexican exports have been larger than forecast; trend expected to continue

U.S. Domestic Oil Production Appears to Have Peaked August EIA data for the 7 Major Growth Producing Regions – Marcellus, Eagle Ford, Permian, Haynesville, Niobrara, Utica & Bakken

Monthly Y/Y % Growth – Associated US Dry Gas Associated Gas Production Source: Jefferies as of August 2016 Year over Year % Growth Gas production from ‘oil plays’ expected to continue declining in 2016 due to lack of drilling

Source: Bentek, EIA as of August 2016 Non-Appalachian Gas Basins Growth by Area

Appalachian Pipeline Flow Data by Region (Mcf/d) Source: RS Energy Group, raw data from Ventyx Velocity Suite and Bloomberg, as of August 2016 Production plateauing NE PA production limited by current rig count in basin to maintain flat production DUC inventory declining

Source: Bentek, EIA as of August 2016 Total U.S. Natural Gas Production Growth by Area December 2015 Marked the First Y/Y Supply Decrease Since February 2010

Utica/Point Pleasant rig count down 71% from the peak in 2014 Marcellus rig count down 80% from the 2014 peak Appalachian Rig Counts Declining Source: RigData as of August 2016

Based on estimated NGL volumes in 2Q 2016 Based on Mont Belvieu NGL prices and weighted average barrel composition for Marcellus Marcellus NGL Pricing Realized Marcellus NGL Prices 2015 2016 1Q 2Q 3Q 4Q 1Q 2Q NYMEX – WTI (per bbl) $48.62 $57.88 $46.61 $42.22 $33.56 $45.31 Mont Belvieu Weighted Priced Equivalent $18.05 $18.32 $17.16 $17.24 $13.37 $15.75 Plant Fees plus Diff. (7.16) (10.64) (11.20) (8.43) (5.07) (5.14) Marcellus average price before NGL hedges $10.89 $7.71 $5.96 $8.81 $8.30 $10.61 % of WTI (NGL Pre-hedge / Oil NYMEX) 22% 13% 13% 21% 25% 23% (2)

    2015 2016 2017 2018   Appalachia Production Year End Exit Rate 20.6 22.0 24.0 26.5   Appalachia Consumption + Injections 14.4 14.4 14.9 15.4 A Appalachia Gas Surplus for Export 6.2 7.6 9.1 11.1   Takeaway Projects - Northeast (cumulative) 1.1 1.8 2.4 7.8   Takeaway Projects - Southwest (cumulative) 3.3 5.9 15.2 20.4 B Total Takeaway Projects (cumulative) 4.4 7.7 17.6 28.3   Excess Takeaway (B – A) (1.8) 0.1 8.5 17.1 Appalachian Production, Consumption & Takeaway - 2015-2018 Source: Analyst estimates LNG exports starting in early 2016 Appears to have sufficient takeaway capacity by 2017 Freely Flowing Overbuilt Summer Constrained

Northeast PA Operator Main Line Market Start-up* Capacity – Bcf/d Fully Committed Approved or with FERC 2015 Niagara Expansion Kinder Morgan TGP Canada Q4'15 0.2 Y Y Northern Access 2015 NFG National Fuel Canada Q4'15 0.1 Y Y Leidy Southeast Williams Transco Mid-Atlantic/SE Q4'15 0.5 Y Y East Side Expansion Nisource Columbia Mid-Atlantic/SE Q4'15 0.3 Y Y 2016 SoNo Iroquois Access Dominion Iroquois Canada Q2'16 0.3 N N Algonquin AIM Spectra Algonquin NE Q4'16 0.4 Y Y 2017 Northern Access 2016 NFG National Fuel Canada H2'17 0.4 Y Y Constitution Williams Constitution NE H2'18 0.7 Y Y Atlantic Bridge Spectra Algonquin NE H2'17 0.7 N Y 2018 Atlantic Sunrise Williams Transco Mid-Atlantic/SE H1'18 1.7 Y Y Access Northeast Spectra Algonquin NE H2'18 1.0 N Y Diamond East Williams Transco NE H2'18 1.0 N N PennEast AGT NE H2‘18 1.0 Y Y Southwest Operator Main Line Market Start-up Capacity – Bcf/d Fully Committed Approved or with FERC 2015 REX Zone 3 Full Reversal Tall Grass REX Midwest Q2'15 1.2 Y Y TGP Backhaul / Broad Run Kinder Morgan TGP Gulf Coast Q4'15 0.6 Y Y TETCO OPEN Spectra TETCO Gulf Coast Q4'15 0.6 Y Y Uniontown to Gas City Spectra TETCO Midwest Q3'15 0.4 Y Y 2016 Gulf Expansion Ph1 Spectra TETCO Gulf Coast Q4'16 0.3 Y Y Clarington West Expansion Tall Grass REX Midwest Q4'16 1.6 N N Zone 3 Capacity Enhancement Tall Grass REX Midwest Q4'16 0.8 Y Y Announced Appalachian Basin Takeaway Projects – 1 of 2 Note: Data subject to change as projects are approved and built. Highlighted projects where Range is participating. * Start-up dates reflect announced operator in-service dates

Southwest Operator Main Line Market Start-up* Capacity – Bcf/d Fully Committed Approved or with FERC 2017 Rover Ph1 ETP   Midwest/Canada/Gulf Coast Q2'17 1.9 Y Y Rayne/Leach Xpress Nisource Columbia Gulf Coast Q3'17 1.5 Y Y SW Louisiana Kinder Morgan TGP Gulf Coast Q3'17 0.9 Y Y Rover Ph2 ETP   Midwest/Canada/Gulf Coast Q3'17 1.3 Y Y Adair SW Spectra TETCO Gulf Coast Q4'17 0.2 Y Y Access South Spectra TETCO Gulf Coast Q4'17 0.3 Y Y Gulf Expansion Ph2 Spectra TETCO Gulf Coast Q4'17 0.4 Y Y NEXUS Spectra Midwest/Canada Q4'17 1.5 Y Y ANR Utica Transcanada ANR Midwest/Canada Q4'17 0.6 N N Cove Point LNG Dominion   NE Q4'17 0.7 Y Y 2018 TGP Backhaul / Broad Run Expansion Kinder Morgan TGP Gulf Coast Q2’18 0.2 Y Y Mountain Valley NextEra/EQT Mid-Atlantic/SE Q4'18 2.0 Y Y Western Marcellus Williams Transco Mid-Atlantic/SE Q4'18 1.5 N N Atlantic Coast Duke/Dominion   Mid-Atlantic/SE Q4'18 1.5 Y Y Total NE Appalachia to Canada 1.0 Total NE Appalachia to NE 4.4 Total NE Appalachia to Mid-Atlantic/SE 2.5 Total NE Appalachia Additions 7.8 Total SW Appalachia to Mid-Atlantic/SE 5.0 Total SW Appalachia to Midwest/Canada 8.2 Total SW Appalachia to Gulf Coast 6.5 Total SW Appalachia to NE 0.7 Total SW Appalachia Additions 20.4 Overall Total Additions for Appalachian Basin 28.3 Note: Data subject to change as projects are approved and built. Highlighted projects where Range is participating. * Start-up dates reflect announced operator in-service dates (2015 – 2018) Existing capacity added by YE 2014 2.8 SW .6 NE 3.4 Total Announced Appalachian Basin Takeaway Projects – 2 of 2

What Does the Future’s Strip Price Indicate for Regional Basis? TCO Pool 2015 -$0.12 2020 -$0.25 Dom South 2015 -$1.21 2020 -$0.58 TETCO M3 2015 -$0.44 2020 +$0.03 Chicago CG 2015 +$0.15 2020 $0.00 CG Mainline 2015 -$0.07 2020 -$0.06 Dawn 2015 +$0.30 2020 -$0.05 MichCon 2015 +$0.19 2020 -$0.03 Algonquin 2015 +$2.24 2020 +$1.20 Transco Z6 (NY) 2015 +$1.01 2020 +$1.12 Transco Z4 2015 -$0.01 2020 +$0.01 Source: Bloomberg, Inside-FERC Basis (08/23/16) Prices $/Mmbtu Northeast anticipated takeaway projects should improve future basis in the Appalachian Basin Leidy 2015 -$1.57 2020 -$0.72 Transco Z6 (NNY) 2015 +$0.51 2020 +$0.38

Financial Detail Appendix

Early, Continuous Action Taken to Prepare for Low Prices June 2014 Called high cost 8% notes, reducing annual interest expense by $24 million or $0.06 mcfe Redemption funded by an equal sized equity offering aimed at accelerating balance sheet improvement October 2014 Renewed bank credit agreement with larger facility size, borrowing base, bank group and enhanced flexibility Annual borrowing base redeterminations and a 5-year maturity March 2015 Unanimous reaffirmation of $3 billion borrowing base and $2 billion commitments Elimination of debt-to-ebitdax covenant; replaced with interest coverage test and a forward-looking asset coverage test Ability to release collateral during transition to investment grade May 2015 Opportunistically accessed a strong high yield debt market issuing $750 million 10-year notes at 4.875% Coupon remains the lowest of any high yield energy issuer of any rating year-to-date Issued senior notes continuing to lay foundation for an investment grade balance sheet August 2015 Portion of proceeds from 4.875% senior notes offering used to redeem 6.75% senior subordinated notes due 2020 Reduction in coupon on $500 million principal redeemed of 1.875% amounts to annual interest savings of ~$9.4 million Announced closure of Oklahoma City office, saving approximately $18 million annually in administrative costs 2016 Sold Nora field for $876 million on 12/30/15, paying down revolving credit facility ~$190 million in non-core asset sales completed in 2016 to date

Range Bonds Continue to Trade Well Source: Bloomberg as of 8/24/2016 Since December highs, Range bonds tightened significantly and continue to trade well relative to a group of high quality peer bonds of similar duration

Period Volumes Hedged (Mmbtu/day) Average Floor Price ($/Mmbtu) Gas Hedging 3Q 2016 Swaps 4Q 2016 Swaps 793,261 800,000 $3.21 $3.23 2017 Swaps 2018 Swaps 330,000 70,000 $2.94 $2.92 Oil Hedging 3Q 2016 Swaps 4Q 2016 Swaps 6,000 6,000 $58.40 $58.40 2017 Swaps 2,496 $51.29 Gas and Oil Hedging Status As of 07/22/2016 – For quarterly detail of hedges, see RRC website

Natural Gas Liquids Hedging Status (1) NGL hedges have Mont Belvieu as the underlying index Conversion Factor: One barrel = 42 gallons Period Volumes Hedged (bbls/day) Hedged Price (1) ($/gal) Ethane (C2) 2H 2016 Swaps 2017 Swaps 500 3,000 $0.22 $0.27 Propane (C3) 2016 Swaps 2017 Swaps 5,500 3,960 $0.60 $0.53 Normal Butane (NC4) 2H 2016 Swaps 2017 Swap 4,750 500 $0.66 $0.61 Natural Gasoline (C5) 2H 2016 Swaps 2017 Swaps 3,500 1,750 $1.11 $0.97 As of 07/22/2016 – For quarterly detail of hedges, see RRC website

Contact Information Range Resources Corporation 100 Throckmorton, Suite 1200 Fort Worth, Texas 76102 Laith Sando, Vice President – Investor Relations (817) 869-4267 lsando@rangeresources.com David Amend, Investor Relations Manager (817) 869-4266 damend@rangeresources.com Michael Freeman, Senior Financial Analyst (817) 869-4264 mfreeman@rangeresources.com Josh Stevens, Financial Analyst (817) 869-1564 jrstevens@rangeresources.com www.rangeresources.com

Important Additional Information/Participants in the Solicitation Important Additional Information This communication does not constitute an offer to sell or the solicitation of an offer to buy any securities or a solicitation of any vote or approval. This communication is being made in respect of the proposed merger transaction involving Range and MRD. In connection with the proposed transaction, Range has filed with the Securities and Exchange Commission (the "SEC") a registration statement on Form S-4 (333-211994) on June 13, 2016, as amended, which has been declared effective by the SEC and includes a joint proxy statement of Range and Memorial and also constitutes a prospectus of Range. Each of Range and Memorial also plan to file other relevant documents with the SEC regarding the merger. No offering of securities shall be made except by means of a prospectus meeting the requirements of Section 10 of the Securities Act. The definitive joint proxy statement/prospectus(es) for Range and/or Memorial will be mailed to shareholders of Range and/or Memorial, as applicable. BEFORE MAKING ANY VOTING OR INVESTMENT DECISIONS, INVESTORS AND SECURITY HOLDERS OF RANGE AND/OR MRD ARE URGED TO READ THE JOINT PROXY STATEMENT/PROSPECTUS REGARDING THE PROPOSED TRANSACTION AND ANY OTHER RELEVANT DOCUMENTS FILED OR TO BE FILED WITH THE SEC CAREFULLY AND IN THEIR ENTIRETY WHEN THEY BECOME AVAILABLE BECAUSE THEY CONTAIN OR WILL CONTAIN IMPORTANT INFORMATION ABOUT THE PROPOSED TRANSACTION. Investors and security holders may obtain free copies of the joint proxy statement/prospectus, any amendments or supplements thereto and other documents containing important information about Range and MRD, once such documents are filed with the SEC, through the website maintained by the SEC at www.sec.gov. Copies of the documents filed with the SEC by Range will be available free of charge on Range's website at http://www.rangeresources.com/under the heading "Investors" or by contacting Range's Investor Relations Department by email at lsando@rangeresources.com, damend@rangeresources.com, mfreeman@rangeresources.com,, or by phone at 817-869-4267. Copies of the documents filed with the SEC by MRD will be available free of charge on MRD's website at http://www.memorialrd.com under the heading "Investor Relations" or by phone at 713-588-8339.   Participants in the Solicitation Range, MRD and certain of their respective directors, executive officers and other members of management and employees may be deemed to be participants in the solicitation of proxies in connection with the proposed transaction. Information about the directors and executive officers of MRD is set forth in its proxy statement for its 2016 annual meeting of shareholders, which was filed with the SEC on April 1, 2016. Information about the directors and executive officers of Range is set forth in its proxy statement for its 2016 annual meeting of stockholders, which was filed with the SEC on April 8, 2016. These documents can be obtained free of charge from the sources indicated above. Other information regarding the participants in the proxy solicitation and a description of their direct and indirect interests, by security holdings or otherwise, will be contained in the joint proxy statement/prospectus and other relevant materials to be filed with the SEC when they become available. Investors should read the joint proxy statement/prospectus carefully before making any voting or investment decisions. Investors may obtain free copies of these documents from Range or MRD using the sources indicated above.