Citi MLP / Midstream Infrastructure Conference

Transcription

1 Citi MLP / Midstream Infrastructure Conference August 20-21, 2014 John A. Weinzierl Chairman and CEO Robert L. Stillwell, Jr. Vice President, Finance

2 Forward-Looking & Other Cautionary Statements This presentation contains forward-looking statements. All statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Memorial Production Partners LP ( MEMP ) expects, believes or anticipates will or may occur in the future are forward-looking statements. These statements are based on certain assumptions made by MEMP based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate. Such statements are subject to risks and uncertainties. A number of factors, many of which are beyond the control of MEMP, could cause actual results to differ materially from those implied or expressed by the forward-looking statements. These factors include, but are not limited to, the following risks and uncertainties: the uncertainty inherent in the development and production of oil and natural gas and in estimating reserves; potential difficulties in the marketing of, and volatility in the prices for, oil, natural gas and natural gas liquids; competition in the oil and natural gas industry; potential shortages of, or increased costs for, drilling and production equipment and supply materials for production; risks related to acquisitions, including MEMP s ability to integrate acquired properties; risks related to MEMP s ability to generate sufficient cash flow to pay distributions, to make payments on its notes and to execute its business plan; MEMP s ability to access funds on acceptable terms, if at all, because of the terms and conditions governing MEMP s indebtedness or otherwise; and the risk that MEMP s hedging strategy may be ineffective or may reduce its income. You are cautioned not to place undue reliance on any forward-looking statements, which speak only as of the date of this presentation. All forward-looking statements are qualified in their entirety by this cautionary statement. Please read MEMP s Annual Report on Form 10-K for the year ended December 31, 2013 and other filings with the SEC, which are available on MEMP s Investor Relations website at or on the SEC s website at for a list of certain risk factors that may affect forward-looking statements. MEMP undertakes no obligation and does not intend to update these forwardlooking statements to reflect future events or circumstances. This presentation also includes non-gaap measures, including Adjusted EBITDA and Distributable Cash Flow. reconciliations of those measures to comparable GAAP measures. Please see the Appendix for The SEC permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC s definitions for such terms. Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation and judgment. The estimates of reserves with respect to certain completed acquisitions in this presentation were prepared by MEMP s internal reserve engineers and are based on various assumptions, drilling and operating expenses, capital expenditures, taxes and availability of funds. MEMP s internal estimates of reserves may not be indicative of or may differ materially from the year end estimates of MEMP s reserves prepared by a third party as a result of assumptions employed by an independent reserve engineering firm. This presentation also contains estimates of or references to original oil in place ( OOIP ) attributable to MEMP s offshore California properties and the assets associated with the Wyoming acquisition. OOIP is merely an indication of the size of a hydrocarbon reservoir and is not an indication of reserves or the quantity of oil that is likely to be produced. You should not assume that estimates of OOIP are comparable to proved or probable reserves or representative of estimates of future production from such properties. It is not possible to measure OOIP in an exact way, and estimating OOIP is inherently uncertain and based on a subjective analysis of geological and other relevant data applicable to such properties, including assumptions regarding area, thickness, porosity and saturation. Changes in these factors or inaccuracies in our assumptions could materially alter the estimates of OOIP. 2

3 Overview of Memorial Production Partners LP Upstream MLP headquartered in Houston, Texas Diverse portfolio of mature, long-lived producing properties Focus on acquiring, exploiting and developing oil and gas properties Assets in East Texas / North Louisiana, Rockies, Permian, South Texas and California Strategy of growing and maintaining production and distributions through acquisitions and lowrisk development Extensive hedge portfolio helps protect production and cash flow through 2019 Since IPO, successfully completed twelve accretive transactions; largest acquisition closed in July 2014 Relationship with parent and sponsor further drives growth Total Proved Reserves: 1,578 Bcfe 61% proved developed 61% liquids Key Statistics (1) 2014 Estimated Production (2) : Bcfe R/P of 19 years (3) 3,279 gross (1,950 net) producing wells (1) MEMP base assets reflect estimated proved reserves as of December 31, 2013 per Netherland, Sewell & Associates, Inc. ( NSAI ) reserve report; Pro forma for the recently completed East Texas and Eagle Ford acquisitions per MEMP internal estimates and the Wyoming acquisition per MEMP internal estimates audited by Ryder Scott Company, L.P. (2) As per MEMP guidance issued on May 5, 2014 (3) Based on MEMP s current average pro forma net production of 231 MMcfe/d for the three months ended June 30, 2014; Pro forma for the recently completed Wyoming acquisition per MEMP internal estimates audited by Ryder Scott Company, L.P. 3

4 MEMP Diverse, Long-Lived Assets (1) California Proved Reserves (MMBbls) 14.3 % Oil Reserves 100% Production (MBbls/d) 1.6 Reserve Life (R/P) 24.0 Total Partnership Proved Reserves (Bcfe) 1,578 % Proved Developed 61% % Liquids Reserves 61% PF 2Q14 Production (MMcfe/d) Total Proved Reserve Life (R/P) 18.7 Rockies Proved Reserves (MMBoe) 94 % Liquids Reserves 91% Production (MBoe/d) 7.7 Reserve Life (R/P) 33.2 East Texas / North Louisiana Proved Reserves (Bcfe) 614 % Gas Reserves 68% Production (MMcfe/d) Reserve Life (R/P) 13.0 Permian Proved Reserves (MMBoe) 18.1 % Liquids Reserves 92% Production (MBoe/d) 2.1 Reserve Life (R/P) 23.4 South Texas Proved Reserves (Bcfe) 208 % Gas Reserves 68% Production (MMcfe/d) 32.6 Reserve Life (R/P) 17.5 (1) MEMP base assets reflect estimated proved reserves as of December 31, 2013 per NSAI reserve report; Pro forma for the recently completed East Texas and Eagle Ford acquisitions per MEMP internal estimates and the Wyoming acquisition per MEMP internal estimates audited by Ryder Scott Company, L.P. 4

5 Acquisition Strategy Drives Growth & Diversification Acquisitions Since IPO Proved Reserves (1) Net Production (1) Purchase Price (1) Date Transaction Structure Location (Bcfe) (MMcfe/d) ($MM) May 14 Third Party Acquisition Rockies $935 March 14 Third Party Acquisition South Texas March 14 MRD Drop Dow n East Texas September 13 Third Party Acquisitions East Texas / Rockies July 13 MRD Drop Dow n / Acquisition from NGP Permian / East Texas / Rockies March 13 MRD Drop Dow n East Texas / North Louisiana December 12 Acquisition from NGP California September 12 Third Party Acquisition East Texas May 12 MRD Drop Dow n East Texas May 12 Third Party Joint Bid w ith MRD East Texas / North Louisiana April 12 MRD Drop Dow n East Texas Total 1, $2,421 Evolution of Reserve Base MEMP at IPO (2) 325 Bcfe R/P of 17 Years MEMP PF 2013 (3) 1,578 Bcfe R/P of 19 Years 53% 47% 36% 39% 7% 5% 13% ETX STX ETX / NLA STX CA Permian Rockies 4% 8% 39% 42% 88% 19% 5 Oil NGL Gas Oil NGL Gas (1) Reflects proved reserves, average production and purchase price as announced at the time of each acquisition (2) Reflects estimated proved reserves as of December 2011 IPO (3) MEMP base assets reflect estimated proved reserves as of December 31, 2013 per NSAI reserve report; Pro forma for the recently completed East Texas and Eagle Ford acquisitions per MEMP internal estimates and the Wyoming acquisition per MEMP internal estimates audited by Ryder Scott Company, L.P.

6 Strong, Aligned Sponsor (1) Sponsorship Allows for Growth NGP Funds Third Party Acquisitions MRD Holdco LLC (2) 52.1% Joint Bid with MRD Memorial Resource Development Corp. (NASDAQ: MRD) 100% Acquisitions from NGP 7.5% Limited Partner Interest (5.4 MM subordinated units) Memorial Production Partners GP LLC Drop Downs from MRD 0.1% GP interest 50% IDR interest Memorial Production Partners LP (NASDAQ: MEMP) Public Unitholders 92.4% Limited Partner Interest (66.4 MM common units) 9 (1) Ownership percentages reflect 9.89 MM common units offering on 7/10/2014, including over-allotment option (2) As of August 18, 2014 MRD Holdco LLC owns 52.1% of MRD, public stockholders own 26.0% and certain former management members of WildHorse Resources, LLC own 21.9%. 6

7 East Texas / North Louisiana: Diversity and Upside Asset Overview Asset Location Key Fields: Joaquin, Carthage, Willow Springs, East Henderson and the Terryville fields Primary Formations: Cotton Valley, Travis Peak Field Characteristics: Fields discovered as early as 1936 Production depth ranges between 6,000 10,000 feet Produced over 13.7 Tcfe since initial discoveries Estimated Net Proved Reserves: 614 Bcfe (1) 68% gas 55% proved developed Production: MMcfe/d R/P of 13 years Producing Wells: 1,282 gross (657 net) 799 operated wells (2) Average working interest: 51% Drilling and Recompletion Opportunities: 118 PDNPs and 200 PUDs (1) Attractive rates of returns due to high liquids yields East TX / North LA Proved Reserves Overview 6% 45% 52% 69% 3% 25% (1) Reflects estimated proved reserves as of December 31, 2013 per NSAI reserve report; Pro forma for the recently completed East Texas acquisition per MEMP internal estimates (2) Represents wells operated by MEMP and MRD PDP PDNP PUD Oil NGL Gas 7

8 Rockies: Concentrated, Long-Lived Assets Asset Overview Asset Location Bairoil Rockies Proved Reserves Overview Key fields: Lost Soldier and Wertz in Sweetwater and Carbon Counties, WY Properties discovered in the early 1900 s; began secondary recovery in the 1970 s and tertiary recovery under CO 2 flood in the late 1980 s Key formations for tertiary oil recovery: Darwin Madison, Cambrian and Tensleep Other production from the Muddy, Lakota, Bucksprings and Pre-Cambrian 100% operated position with WI and NRI of 100% and 88%, respectively, in Bairoil properties Large number of CO 2 development projects and opportunities Legacy, conventional production coming from the Fort Collins and Moxa Arch Fields Estimated Net Proved Reserves: 94 MMBoe (1) 91% liquids 62% proved developed Production: 7.7 MBoe/d (2) R/P of 33 years Producing Wells: 745 gross (365 net) 335 operated wells (3) Average working interest: 49% Drilling and Recompletion Opportunities: 71 PDNPs and 86 PUDs (1) 9% 38% 22% 49% 13% 69% PDP PDNP PUD Oil NGL Gas 8 (1) Reflects estimated aproved reserves as of December 31, 2013 per NSAI reserve report and the Bairoil acquisition per MEMP internal estimates audited by Ryder Scott Company, L.P. (2) Average net production is estimated for the three months ended June 30, 2014, pro forma for the Bairoil acquisition (3) Represents wells operated by MEMP and MRD

9 Permian Basin: Long-Lived Oil Asset Overview Key Fields: Anita, Atoka, Dimmitt, Elkhorn, Kingdom Abo and North Square Lake Primary Formations: Abo Reef, Cherry Canyon, Clearfork and Palo Pinto Field Characteristics: Fields discovered as early as 1920 One of the largest structural basins in North America with a surface area of over 75,000 square miles Produced over 42 Billion Boe since initial discoveries Estimated Net Proved Reserves: 18.1 MMBoe (1) 92% liquids 45% proved developed Production: 2,117 Boe/d (2) R/P of 23 years Producing Wells: 532 gross (480 net) 495 operated wells (3) Average working interest: 90% Drilling and Recompletion Opportunities: 15 PDNPs and 253 PUDs (1) Asset Location Permian Basin Proved Reserves Overview 8% 42% 55% 3% 92% (1) Reflects estimated proved reserves as of December 31, 2013 per NSAI reserve report (2) Average net production is estimated for the three months ended June 30, 2014 (3) Represents wells operated by MEMP and MRD PDP PDNP PUD Oil NGL Gas 9

10 South Texas: Stable Production with Liquids Asset Overview Asset Location Eagle Ford acreage position in the core of the Eagle Ford play in Karnes County Area recognized as the volatile oil window Eagle Ford Producing Wells: 117 gross (7.5 net in 2014) Producing wells are 100% non-op with primary operator, Murphy Oil Corporation In addition, MEMP has 30% interest in seller s net leasehold interest Legacy South Texas Key Fields: NE Thompsonville, Laredo and East Seven Sisters Primary Formations: Lobo, Wilcox Estimated Net Proved Reserves: 208 Bcfe (1) 68% gas 78% proved developed South Texas Proved Reserves Overview Production: 32.6 MMcfe/d (2) R/P of 18 years Total Producing Wells: 668 gross (421 net) 493 operated wells (3) Average working interest: 63% Drilling and Recompletion Opportunities: 220 PDNPs and 194 PUDs (1) 22% 19% 59% 68% 20% 12% (1) Reflects estimated proved reserves as of December 31, 2013 per NSAI reserve report for South Texas and per internal estimates for the Eagle Ford acquisition (2) Average net production is estimated for the three months ended June 30, 2014 (3) Represents wells operated by MEMP and MRD 10 PDP PDNP PUD Oil NGL Gas

11 California: Significant Original Oil in Place Asset Overview Located ~11 miles offshore Port of Long Beach, California 2 wellhead platforms each with a permanent drilling rig; 1 processing platform; associated pipelines and onshore facilities Field Characteristics: Key field: Beta Field Estimated OOIP of 940 MMBbls with 9% recovered to date (1) Estimated Net Proved Reserves: 14.3 MMBbls (2) 100% oil 70% proved developed Production: 1,633 Bbls/d (3) R/P of 24 years Producing Wells: 52 gross (27 net) 52 operated wells Average working interest: 52% Drilling and Recompletion Opportunities: 4 PDNPs and 23 PUDs (2) High operating margins and modest maintenance capex requirements Asset Location Los Angeles Long Beach Ellen and Elly Huntington Beach Eureka Newport Beach California California Proved Reserves Overview 30% 100% 2% 68% (1) OOIP estimate as per third-party reservoir consultant; recovery factor based on cumulative production of 88 MMBbls (2) Reflects estimated proved reserves as of December 31, 2013 per NSAI reserve report (3) Average net production is estimated for the three months ended June 30, 2014 PDP PDNP PUD Oil NGL Gas 11

12 Financial Strategy Preserve Financial Flexibility Liquidity of $695 MM (as of August 1, 2014) provided by a $1,315 MM borrowing base 2014 FY projected DCF coverage ratio of 1.10x x Expect to fund acquisitions on a conservative debt / equity basis over the long term Hedge to Secure Cash Flows Aim for 65-85% of targeted production to be hedged on a rolling 3-6 year basis Execute additional hedges with acquisitions to lock-in accretion 100% hedged to the appropriate basis differential for gas through 2014 and oil basis exposure to 2015 Ability to fund maintenance capital expenditure requirements from existing cash flow Re-Investment Strategy Conservative capex profile with multiple organic growth opportunities Capital projects characterized by low-risk development activities Maintenance capex forecasted at ~25% of mid-point EBITDA guidance 12

13 MEMP Hedging Overview: Protected through 2019 MEMP s commodity risk management policy provides for hedging approximately 65-85% of estimated production from total proved reserves on a rolling three to six year period Policy reduces MEMP s exposure to movements in commodity prices and provides stability to distributable cash flow All of MEMP s trading counterparties have credit ratings of A- (S&P) or A3 (Moody s) or higher All of MEMP s current hedges are costless, fixed price swaps and collars MEMP s targeted average net production estimate represents the production required to reach the lower boundary of the annual production range in the 2014 full year guidance Hedge Summary Year Ending December 31, Natural Gas Derivative Contracts: Total weighted-average fixed/floor price $4.41 $4.32 $4.40 $4.31 $4.51 $4.75 Percent of 2014 production hedged 88% 89% 81% 74% 65% 57% Crude Oil Derivative Contracts: Total weighted-average fixed/floor price $94.83 $90.79 $85.44 $83.96 $83.24 $85.52 Percent of 2014 production hedged 81% 84% 79% 75% 72% 42% Natural Gas Liquids Derivative Contracts: Total weighted-average fixed/floor price $42.96 $43.02 Percent of 2014 production hedged 84% 74% Total Derivative Contracts: Total weighted-average fixed/floor price $8.50 $8.36 $8.34 $8.30 $8.54 $7.92 Percent of 2014 production hedged 85% 85% 66% 61% 56% 42% 13

14 Steady and Prudent Growth Since IPO Daily Production (MMcfe/d) Reserves (Bcfe) 205 1, A IPO Forecast 2012A 2013A 2014E (1) 2011A 2012A PF 2013 (2) Adjusted EBITDA ($ millions) in Millions) $365 Quarterly Distribution per LP Unit ($ / Unit) $ $ $ $ $222 $ $ $ $110 $ $45 $62 $ $ $ A IPO Forecast 2012A 2013A 2014E (3) (1) (4) 4Q11 1Q12 2Q12 3Q12 4Q12 1Q13 2Q13 3Q13 4Q13 1Q14 2Q14 14 (1) As per MEMP guidance issued on May 5, 2014 (2) Pro forma for the recently completed Eagle Ford, East Texas and Wyoming acquisitions (3) Per MEMP K; see MEMP K for reconciliation to GAAP measure (4) Reflects annualized distribution of $ / unit which is the prorated distribution from IPO closing to December 31, 2011

15 Industry Leading Cost Structure (1) F&D / Mcfe LOE / Mcfe (2) $3.00 $4.50 $4.21 $4.28 $2.50 $2.43 $2.56 $4.00 $3.50 $2.00 $1.50 $1.26 $1.52 $1.66 $1.79 $1.89 $3.00 $2.50 $2.00 $1.76 $1.77 $1.80 $1.86 $1.98 $1.00 $1.50 $0.50 $1.00 $0.50 $- VNR MEMP ARP EVEP BBEP LINE LGCY $- ARP VNR LINE MEMP EVEP BBEP LGCY G&A / Mcfe Total Cost / Mcfe $1.20 $1.00 $1.04 $9.00 $8.00 $7.00 $6.62 $7.88 $0.80 $6.00 $0.60 $0.40 $0.39 $0.50 $0.52 $0.54 $0.63 $5.00 $4.00 $3.00 $3.27 $3.89 $4.05 $4.16 $4.77 $0.20 $0.23 $2.00 $ $- VNR EVEP MEMP BBEP LINE ARP LGCY Source: Public filings (1) Peers F&D cost data as of FY 2013, BBEP pro forma for QRE acquisition; MEMP F&D cost calculated as PDNP & PUD capex divided by PDNP and PUD reserves per NSAI reserve report, pro forma for the recently completed East Texas and Eagle Ford acquisitions per MEMP internal estimates and the Wyoming acquisition per MEMP internal estimates audited by Ryder Scott Company, L.P.; LOE and G&A costs as of 2Q14 public filings (2) LOE includes production and ad valorem taxes $- VNR MEMP ARP EVEP LINE BBEP LGCY

16 Full Year 2014 Guidance Full Year 2014 Guidance Low High For Year Ending For Year Ending December 31, 2014 December 31, 2014 Annual Production (Bcfe) Adjusted EBITDA ($MM) (1) $355 $375 Distributable Cash Flow ($MM) (1) $183 $203 DCF Coverage 1.10x 1.20x Maintenance Capex ($MM) $90 $90 Growth Capex ($MM) $85 $115 Note: As of May 5, 2014 (1) Adjusted EBITDA and Distributable Cash Flow are non-gaap financial measures. Please see the reconciliation to the most comparable measure calculated in accordance with GAAP in the Appendix 16

17 Safety, Growth and Returns High quality assets MLP-appropriate asset profile Strong sponsorship with aligned interests Clear and achievable growth strategy Seasoned management team Cash flow visibility and security 17

18 Appendix

19 Cash Margin Per Mcfe Three Months Ended 6/30/2014 (1) Net production volumes Oil (MBbls) 617 NGLs (MBbls) 524 Natural gas (MMcf) 10,965 Total (MMcfe) 17,806 Average net production (MMcfe/d) Average sales prices before hedges Oil (per Bbl) $98.81 NGLs (per Bbl) Natural gas (per Mcf) 4.20 Average sales prices per Mcfe before hedges $6.87 Average sales prices per Mcfe after hedges $6.43 Average cash unit costs per Mcfe: Lease operating expenses $1.46 Production and ad valorem taxes 0.40 General and administrative expenses (excl. non-cash based comp) 0.50 Cash margin before hedges ($/Mcfe) (2) $4.51 % Margin 66% Cash margin after hedges ($/Mcfe) (2) $4.07 % Margin 63% 19 (1) Not pro forma for the recently completed Wyoming Acquisition (2) Average sales price less lease operating expenses, production and ad valorem taxes and general and administrative expenses

20 Low Development Costs Maximize Margins Identified Production Replacement PDNP + PUDs 753 Bcfe Total PUDs Only 620 Bcfe Total Project Types Control and reduce costs through low-risk drilling, recompletions and operational enhancements 8% 4% 11% 39% 38% ETX / NLA Rockies STX Permian CA Estimated F&D Costs by Region: PDNP + PUDs (1) $2.50 $2.27 $2.00 $1.92 $1.49 $1.49 $1.52 $1.50 $1.37 $ % 4% 7% 44% 35% ETX / NLA Rockies STX Permian CA Estimated F&D Costs by Region: PUDs Only (2) $2.50 $2.37 $2.04 $2.00 $1.82 $1.66 $1.66 $1.50 $1.43 $1.00 Field exploitation Infill drilling Optimize production Artificial lift methods Gathering system enhancements Recomplete bypassed pay Well reactivations Repeatable lifting cost reductions Intense focus on cost analysis Maximize economies of scale Supplies Services Aggregate utility contracts $0.50 $0.50 $0.00 Permian CA Rockies STX ETX / NLA Total MEMP $0.00 Permian STX CA Rockies ETX / NLA Total MEMP 20 Note: MEMP base assets reflect estimated proved reserves as of December 31, 2013 per NSAI reserve report; Pro forma for the recently completed East Texas and Eagle Ford acquisitions per MEMP internal estimates and the Wyoming acquisition per MEMP internal estimates audited by Ryder Scott Company, L.P. (1) F&D costs calculated as PDNP & PUD capex divided by PDNP and PUD reserves per NSAI reserve reports and MEMP internal estimates (2) F&D costs calculated as PUD capex divided by PUD reserves per NSAI reserve reports and MEMP internal estimates

21 2014 Adjusted EBITDA & Distributable Cash Flow Guidance Reconciliation Low For Year Ended High For Year Ended (In millions) December 31, 2014 December 31, 2014 Calculation of Adjusted EBITDA: Net income $ 154 $ 174 Interest expense Depletion, depreciation and amortization Adjusted EBITDA $ 355 $ 375 Reconciliation of Net Cash From Operating Activities to Adjusted EBITDA: Net cash provided by operating activities $ 273 $ 293 Changes in working capital - - Interest expense Adjusted EBITDA $ 355 $ 375 Reconciliation of Adjusted EBITDA to Distributable Cash Flow: Adjusted EBITDA $ 355 $ 375 Cash interest expense (82) (82) Estimated maintenance capital expenditures (90) (90) Distributable Cash Flow $ 183 $

22 EBITDA Reconciliation Year Ended December 31, (In thousands) 2013 Calculation of Adjusted EBITDA: Net income $ 20,268 Interest expense, net 41,901 Income tax expense 308 Depletion, depreciation and amortization 97,269 Impairment 54,362 Accretion of AROs 4,853 (Gain) loss on commodity derivative instruments (26,281) Cash settlements on commodity derivative instruments 19,879 Acquisition related costs 6,729 Unit-based compensation expense 3,558 Non-cash compensation expense 1,057 Gain on sale of properties (2,848) Exploration costs 1,130 Amortization of investment premium - Adjusted EBITDA $ 222,185 Reconciliation of Net Cash From Operating Activities to Adjusted EBITDA: Net cash provided by operating activities $ 193,697 Changes in working capital (16,644) Interest expense 41,901 Premiums paid for derivatives - Premiums received for derivatives - Gain (loss) on interest rate derivative instruments 548 Cash settlements on interest rate derivative instruments 960 Acquisition related costs 6,729 Amortization of premium / (discount) (504) Amortization of deferred financing fees (5,845) Income tax expense - current portion 308 Exploration costs 1,035 Adjusted EBITDA $ 222,185 22

23 Non-GAAP Measures Use of Non-GAAP Financial Measures. This presentation includes the non-gaap financial measures of Adjusted EBITDA and Distributable Cash Flow. The accompanying schedules provide a reconciliation of these non-gaap financial measures to their most directly comparable financial measure calculated and presented in accordance with GAAP. MEMP 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. MEMP 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 MEMP does. Adjusted EBITDA. MEMP defines Adjusted EBITDA as net income or loss, plus interest expense, including realized and unrealized losses on interest rate derivative contracts; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived assets; accretion of asset retirement obligations; losses and cash settlements received on commodity derivative contracts; losses on sale of assets; unit-based compensation expenses; exploration costs; acquisition related costs; amortization of investment premium; and other non-routine items, less interest income; income tax benefit; gains and cash settlements paid on commodity derivative contracts; gains on sale of assets and other non-routine items. Adjusted EBITDA is commonly used as a supplemental financial measure by management and external users of MEMP's financial statements, such as investors, research analysts and rating agencies, to assess: (1) the financial performance of its assets without regard to financing methods, capital structures or historical cost basis; (2) the ability of its assets to generate cash sufficient to pay interest, support MEMP's indebtedness and make distributions on its units; and (3) the viability of projects and the overall rates of return on alternative investment opportunities. Since Adjusted EBITDA excludes some, but not all, items that affect net income or loss and because these measures may vary among other companies, the Adjusted EBITDA data presented in this presentation may not be comparable to similarly titled measures of other companies. The GAAP measure most directly comparable to Adjusted EBITDA is net cash flows provided by operating activities. Distributable Cash Flow. MEMP defines distributable cash flow as Adjusted EBITDA, less cash income taxes; cash interest expense; and estimated maintenance capital expenditures. Management compares the distributable cash flow MEMP generates to the cash distributions it expects to pay MEMP s partners. Using this metric, management computes MEMP s distribution coverage ratio. Distributable cash flow is an important non-gaap financial measure for MEMP s limited partners since it serves as an indicator of MEMP s success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not MEMP is generating cash flows at a level that can sustain or support an increase in its quarterly cash distributions. Distributable cash flow is also a quantitative standard used by the investment community with respect to publicly traded partnerships because the value of a partnership unit is, in part, measured by its yield, which is based on the amount of cash distributions a partnership can pay to a unitholder. The GAAP measure most directly comparable to distributable cash flow is net cash flows provided by operating activities. 23

24 MEMP Reserve Details (1) Oil Gas NGLs Total % Gas MBBL MMCF MBBL MMCFE % Proved Developed Producing 51, ,929 27, ,940 43% Proved Developed Unproducing 8,061 43,730 6, ,216 33% Proved Undeveloped 49, ,852 16, ,952 36% Total Proved 108, ,510 50,947 1,578,108 39% 1P Reserves by Category (1) 1P Reserves by Commodity (1) 39% 52% 39% 42% 9% 19% PDP PDNP PUD Oil NGL Gas 24 (1) MEMP base assets reflect estimated proved reserves as of December 31, 2013 per NSAI reserve report; Pro forma for the recently completed East Texas and Eagle Ford acquisitions per MEMP internal estimates and the Wyoming acquisition per MEMP internal estimates audited by Ryder Scott Company, L.P.

25