BAML Energy Credit Conference New York

Transcription

1 BAML Energy Credit Conference New York John A. Weinzierl CEO June 7-8, 2016 Robert L. Stillwell, Jr. CFO

2 Forward-Looking & Other Cautionary Statements This presentation and the oral statements made in connection therewith contain forward-looking statements. All statements, other than statements of historical facts, included in this presentation or made in connection therewith 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. Terminology such as will, would, should, could, expect, anticipate, plan, project, intend, estimate, believe, target, continue, potential, the negative of such terms or other comparable terminology are intended to identify forward-looking statements. These statements include, but are not limited to, statements about estimates of MEMP s oil and natural gas reserves, MEMP s future capital expenditures (including the amount and nature thereof), expectations regarding future cash flows, distributions and distribution rates, and expectations of plans, strategies, objectives and anticipated financial and operating results of MEMP, including as to production, lease operating expenses, hedging activities, commodity price realizations, capital expenditure levels and other guidance included in this presentation. 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 in the circumstances, but such assumptions may prove to be inaccurate. Such statements are also subject to a number of risks and uncertainties, many of which are beyond the control of MEMP, which may cause MEMP s actual results to differ materially from those implied or expressed by the forward-looking statements. These include risks and uncertainties relating to, among other things, the uncertainty inherent in the development and production of oil, natural gas and natural gas liquids and in estimating reserves; risks associated with drilling activities; risks related to MEMP s ability to generate sufficient cash flow to pay distributions, to make payments on its notes or its other debt obligations 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; potential difficulties in the marketing of, and volatility in the prices for, oil, natural gas and natural gas liquids, including a further or extended decline in commodity prices; competition in the oil and natural gas industry; potential failure or 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 or entities; 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 included in this presentation or made in connection therewith are qualified in their entirety by these cautionary statements. Please read MEMP s filings with the Securities and Exchange Commission ( SEC ), including Risk Factors in MEMP s Annual Report on Form 10-K, and if applicable, MEMP s Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, which are available on MEMP s Investor Relations website at or on the SEC s website at for a discussion of risks and uncertainties that could cause actual results to differ from those in such forward-looking statements. Except as required by law, MEMP undertakes no obligation and does not intend to update or revise any forward-looking statements, whether as a result of new information, future results or otherwise. 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. Please read MEMP s filings with the SEC, including Risk Factors in MEMP s Annual Report on Form 10-K and if applicable, MEMP s Quarterly Reports on Form 10-Q and Current Reports on Form 8-K, for a discussion of the risks and uncertainties involved in the process of estimating reserves. This presentation also contains estimates of or references to original oil in place ( OOIP ) attributable to MEMP s offshore California properties. 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 reserves, including proved, probable or possible reserves, under SEC rules 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 Diverse portfolio of mature, long-lived producing properties with development upside Assets in East Texas / North Louisiana, Rockies, California, South Texas and Permian $134 million of revolver availability as of April 29, 2016 Best-in-class hedge portfolio helps protect production and cash flow through % of total production hedged through 2017; 72% of total production hedged through 2019 Mark-to-market hedge book value of approximately $605 million as of April 29, 2016 Significant free cash flow generation expected in 2016 No near term debt maturities senior notes mature in 2021 and 2022 Key Statistics (1) Total Proved Reserves: 1,268 Bcfe 63% proved developed 64% liquids 1Q16 Average Production: MMcfe/d R/P of 14.3 years 3,357 gross (1,960 net) producing wells (1) MEMP base assets reflect estimated proved reserves as of December 31, 2015 per MEMP internal estimates audited by Ryder Scott 3

4 Update on Current Events and 2016 Road Map 2016 Business Plan Maximize free cash flow generation and continue execution on cost reduction program Divest non-core properties Reduce debt and enhance liquidity for the Partnership GP Tuck-In Closed on June 1, 2016 Simplifies corporate and organizational structure Increases focus of MEMP management team and employee base solely on its portfolio of assets MEMP controls its own general partner with minimal impact on liquidity Amended Credit Facility Maximum first lien secured leverage covenant of 3.25x Restricted payments basket: Limit on distributions of up to $4.15 MM per quarter if over 4.0x total leverage No restriction if under 4.0x total leverage and greater than 15% liquidity on revolver Permitted debt repurchases of up to $100 MM subject to availability and first lien leverage test 4

5 Diverse, Long-Lived Assets (1) Total Partnership Proved Reserves (Bcfe) 1,268 % Proved Developed 63% % Liquids Reserves 64% 1Q16 Avg. Production (MMcfe/d) Total Proved Reserve Life (R/P) 14.3 Wyoming Rockies Proved Reserves (MMBoe) 82 % Liquids Reserves 96% 1Q16 Avg. Production (MBoe/d) 6.2 Reserve Life (R/P) 36.0 California Colorado New Mexico East Texas / North Louisiana Proved Reserves (Bcfe) 535 % Gas Reserves 71% 1Q16 Avg. Production (MMcfe/d) Reserve Life (R/P) 10.0 Texas Permian Proved Reserves (MMBoe) 3.1 % Oil Reserves 99% 1Q16 Avg. Production (MBoe/d) 1.2 Reserve Life (R/P) 7.0 Louisiana South Texas Proved Reserves (Bcfe) 88 % Gas Reserves 66% 1Q16 Avg. Production (MMcfe/d) 29.4 Reserve Life (R/P) 8.2 (1) MEMP base assets reflect estimated proved reserves as of December 31, 2015 per MEMP internal estimates audited by Ryder Scott 5

6 East Texas / North Louisiana: Diversity and Upside Asset Overview Asset Location Key Fields: Joaquin, Carthage, Willow Springs and East Henderson fields Primary Formations: Cotton Valley, Travis Peak Estimated Net Proved Reserves: 535 Bcfe (1) 71% gas 61% proved developed Production: MMcfe/d (2) R/P of 10 years Producing Wells: 1,537 gross (905 net) Average working interest: 59% East TX / North LA Proved Reserves Overview Drilling and Recompletion Opportunities: 95 PDNPs and 42 PUDs (1) Estimated 7 years of drilling inventory based on 2016 budget activity (1) Reflects estimated proved reserves as of December 31, 2015 audited by Ryder Scott (2) Average net production for the three months ended March 31, % 3% 58% 71% 4% 25% PDP PDNP PUD Oil NGL Gas 6

7 Rockies: Concentrated, Long-Lived Assets Asset Overview Asset Location 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 Bairoil 100% operated position with WI and NRI of 100% and 88%, respectively, in Bairoil properties with large number of CO 2 development projects and opportunities Legacy, conventional production coming from the Fort Collins, Moxa Arch and Wattenberg Fields Estimated Net Proved Reserves: 82 MMBoe (1) Rockies Proved Reserves Overview 96% liquids 61% proved developed Production: 6.2 MBoe/d (2) R/P of 36 years Producing Wells: 757 gross (339 net) 39% 48% 24% 5% Average working interest: 45% Drilling and Recompletion Opportunities: 22 PDNPs and 19 PUDs (1) 13% 71% (1) Reflects estimated proved reserves as of December 31, 2015 audited by Ryder Scott (2) Average net production for the three months ended March 31, 2016 PDP PDNP PUD Oil NGL Gas 7

8 South Texas: Stable Gas Production with Eagle Ford Liquids Asset Overview Eagle Ford acreage position in the core of the Eagle Ford play in Karnes County Approximately 15,200 gross acres Area recognized as the volatile oil window Eagle Ford Producing Wells: 203 gross (14 net at YE 2015) Producing wells are 100% non-op with primary operator, Murphy Oil Corporation Legacy South Texas Key Fields: NE Thompsonville, Laredo and East Seven Sisters Primary Formations: Lobo, Wilcox Estimated Net Proved Reserves: 88 Bcfe (1) 66% gas 88% proved developed Production: 29.4 MMcfe/d (2) R/P of 8 years Total Producing Wells: 718 gross (418 net) Average working interest: 58% Drilling and Recompletion Opportunities: 154 PDNPs and 101 PUDs (1) Asset Location South Texas Proved Reserves Overview 12% 11% 66% 77% 23% 11% (1) Reflects estimated proved reserves as of December 31, 2015 audited by Ryder Scott (2) Average net production for the three months ended March 31, 2016 PDP PDNP PUD Oil NGL Gas 8

9 California: Significant Original Oil in Place Asset Overview Asset Location Beta Field 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 Los Angeles Long Beach Ellen and Elly Huntington Beach Eureka Newport Beach Estimated OOIP of 940 MMBbls with 10% recovered to date (1) Latest well had peak production of approximately 2,100 Bbls/d Estimated Net Proved Reserves: 22.7 MMBbls (2) 100% oil 57% proved developed California California Proved Reserves Overview Production: 3.8 MBbls/d (3) R/P of 16 years 0% Producing Wells: 60 gross (60 net) Average working interest: 100% 43% 55% 100% Drilling and Recompletion Opportunities: 3 PDNPs and 33 PUDs (2) (1) OOIP estimate as per third-party reservoir consultant; recovery factor based on cumulative production of 91 MMBbls (2) Reflects estimated proved reserves as of December 31, 2015 audited by Ryder Scott (3) Average net production for the three months ended March 31, % PDP PDNP PUD Oil NGL Gas 9

10 Permian Basin: Long-Lived Oil Asset Overview Asset Location Key Fields: Anita, Deadwood, Dimmitt, Elkhorn and Kingdom Abo Primary Formations: Abo Reef, Cherry Canyon, Clearfork and Palo Pinto Estimated Net Proved Reserves: 3.1 MMBoe (1) 99% oil 92% proved developed Production: 1.2 MBoe/d (2) R/P of 7 years Producing Wells: 285 gross (238 net) Average working interest: 84% Permian Basin Proved Reserves Overview 0% Drilling and Recompletion Opportunities: 14 PDNPs and 47 PUDs (1) 19% 8% 1% 73% 99% (1) Reflects estimated proved reserves as of December 31, 2015 audited by Ryder Scott (2) Average net production for the three months ended March 31, 2016 PDP PDNP PUD Oil NGL Gas 10

11 2016 Capex Overview $70 MM (Guidance Midpoint) Capex by Area ($MM) Capex by Project Type ($MM) $14 20% $6 9% $2 3% $2 3% $26 38% $20 29% $19 27% $50 71% ETX / NLA California Rockies Eagle Ford South TX Permian Non-D&C Capex by Category ($MM) Drilling Non-D&C and Capex Completion Drilling Capexand Completion Non-D&C Capex Updated 2016 Completions Schedule $8 16% $7 13% $3 7% $20 41% Approximately two-thirds of 2016 planned capital to be invested in 1H16 Two remaining wells to be brought online in 3Q Operated Wells Online (1) Q1 Q2 Q3 Q4 Total Facilities and Equipment Beta Decomm Fund Seismic and Land $12 23% Recompletions / Well Work Non-Op and Misc ETX / NLA Total (1) Does not include Eagle Ford non-operated properties and regions without planned development activity 11

12 MEMP Hedging Overview: $605 MM MTM Value 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 BBB+ (S&P) or A3 (Moody s) or higher All of MEMP s current hedges are costless, fixed price swaps and collars Best-in-class hedge portfolio helps protect production and cash flow through 2019 Mark-to-market hedge book value of approximately $605 million as of April 29, 2016 (1)(2) Hedge Summary Year Ending December 31, (3) Natural Gas Derivative Contracts: Total weighted-average fixed/floor price $4.14 $4.06 $4.18 $4.31 Percent of expected remaining 2016 production hedged 92% 86% 79% 72% Crude Oil Derivative Contracts: Total weighted-average fixed/floor price $85.59 $85.00 $83.74 $85.52 Percent of expected remaining 2016 production hedged 82% 92% 95% 49% Natural Gas Liquids Derivative Contracts: Total weighted-average fixed/floor price $34.43 $37.55 Percent of expected remaining 2016 production hedged 93% 20% Total Derivative Contracts: Total weighted-average fixed/floor price $7.00 $7.54 $7.89 $6.84 Percent of expected remaining 2016 production hedged 89% 76% 69% 53% (1) Updated hedge schedule as of May 4, 2016 (2) MEMP s targeted average net production estimate represents the midpoint of the annual production range in the 2016 full year guidance (3) Represents April to December 2016 (1)(2) 12

13 Realized Significant Operating Cost Reductions Significant Progress in Cost Containment $50.0 Lease Operating Expense ($MM) $45.0 $40.0 $35.0 $45.4 (18)% QoQ $37.4 (5)% QoQ $35.7 $30.0 $0.0 3Q15 4Q15 1Q16 1Q16 LOE was $35.7 MM, which was 14% lower than 2H15 average 1Q16 LOE/Mcfe was $1.61, which compared to 2015 LOE/Mcfe of $1.82 and 2016 guidance (1) LOE/Mcfe range of $1.85 to $2.00 LOE improvements are a result of multiple efforts including service provider negotiations, headcount reductions, lower saltwater disposal costs and reduced activity levels due to current commodity prices 13 (1) As of January 27, 2016

14 Low Cost Structure Drives High Margins (1)(2) F&D / Mcfe Lifting Cost / Mcfe (3) $7.00 $6.00 $5.57 $6.21 $3.50 $3.00 $2.84 $3.09 $5.00 $4.46 $2.50 $2.12 $4.00 $2.00 $1.66 $1.67 $1.79 $3.00 $2.34 $1.50 $1.18 $2.00 $1.00 $1.39 $1.51 $1.64 $1.00 $0.50 $- MEMP EVEP VNR LGCY ARP BBEP MCEP G&A / Mcfe $0.79 $0.80 $0.73 $0.70 $0.60 $0.55 $0.49 $0.50 $- VNR ARP EVEP MEMP LGCY MCEP BBEP Total Cost / Mcfe $12.00 $10.00 $9.21 $9.78 $8.00 $6.91 $0.40 $0.30 $0.20 $0.18 $0.31 $0.37 $6.00 $4.00 $3.00 $3.55 $3.67 $4.77 $0.10 $2.00 $- VNR LGCY EVEP MEMP BBEP MCEP ARP $- VNR EVEP MEMP LGCY ARP BBEP MCEP 14 Source: Public filings (1) Lifting cost and G&A data for the 3 months ended March 31, 2016; F&D cost data as of FY 2015; Peers F&D costs represent average of FY ; MEMP F&D cost calculated as PDNP & PUD capex divided by PDNP and PUD reserves per estimated proved reserves as of December 31, 2015 per MEMP internal estimates audited by Ryder Scott (2) Excludes LINE, not yet reported 1Q16 results (3) Lifting costs include LOE, production and ad valorem taxes

15 Fiscal Year 2016 Guidance (1) FY 2016 Guidance as of January 27, FY Guidance January 27, 2016 Low High Net Average Daily Production Oil (MBbls/d) NGL (MBbls/d) Natural Gas (MMcf/d) Total (MMcfe/d) Commodity Price Differential / Realizations (Unhedged) Crude Oil Differential ($ / Bbl) $ $6.25 NGL Realized Price (% of WTI NYMEX) 32% - 36% Natural Gas Realized Price (% of NYMEX to Henry Hub) 96% - 100% Gathering, Processing and Transportation Costs Crude Oil ($ / Bbl) $ $0.25 NGL ($ / Bbl) $ $3.30 Natural Gas ($ / Mcf) $ $0.55 Average Costs Lease Operating ($ / Mcfe) $ $2.00 Taxes (% of Revenue) (2) 6.8% - 7.2% Cash General and Administrative ($ / Mcfe) $ $0.50 Capital Expenditures ($MM) $65 - $75 15 Adjusted EBITDA ($MM) (3) $285 - $310 Cash Interest Expense ($MM) $110 - $115 Estimated Maintenance Capital Expenditures ($MM) $70 Distributable Cash Flow ($MM) (3) $105 - $125 (1) Guidance based on NYMEX strip pricing as of January 22, 2016; Average prices of $36.30 / Bbl for crude oil and $2.37 / Mcf for natural gas for 2016 (2) Includes production and ad valorem taxes (3) Adjusted EBITDA and Distributable Cash Flow are non-gaap financial measures. Please see Use of Non-GAAP Financial Measures for a description of Adjusted EBITDA and Distributable Cash Flow and the reconciliation to the most comparable GAAP financial measure

16 Investment Highlights High quality assets MLP-appropriate asset profile Clear and achievable growth strategy Seasoned management team Significant hedge portfolio Cash flow visibility and security 16

17 Appendix

18 MEMP Org. Structure Simplified Following GP Purchase MEMP Structure: Pre-GP Purchase MEMP Structure: Post-GP Purchase NGP Funds and Management Public Unitholders MRD Holdco LLC Memorial Resource Development Corp. (NASDAQ: MRD) Market Cap: $2,699.2 million (1) Unconsolidated Net Debt (12/31/15): $1,021.3 million Credit Ratings: B2 / B 100.0% Interest 49.0% interest Public Shareholders 100% LP interest Memorial Production Partners LP (NASDAQ: MEMP) Market Cap: $240.7 million (1) Net Debt (12/31/15): $1,988.4 million Credit Ratings: Caa2 / B- Memorial Production Partners GP LLC 50.0% IDR interest 0.1% GP interest 50.0% IDR interest Memorial Production Partners GP LLC Memorial Production Partners LP (NASDAQ: MEMP) Market Cap: $240.7 million (1) Net Debt (12/31/15): $1,988.4 million Credit Ratings: Caa2 / B- 99.9% LP interest Public Unitholders Revolving Credit Facility: $789 MM Drawn (1) $700 MM 7.625% Senior Notes due 2021 $497 MM 6.875% Senior Notes due 2022 Revolving Credit Facility: $789 MM Drawn (1) $700 MM 7.625% Senior Notes due 2021 $497 MM 6.875% Senior Notes due (1) Data as of April 29, 2016

19 MEMP Reserve Details (1) Oil Gas NGLs Total % of Proved MBBL MMCF MBBL MMCFE % PDP 43, ,866 25, ,283 55% PDNP 7,671 19,281 5,058 95,654 8% PUD 40, ,379 13, ,634 37% Total Proved 90, ,526 43,395 1,267, % 1P Reserves by Category (1) 1P Reserves by Commodity (1) 21% 37% 36% 55% 8% 43% PDP PDNP PUD (1) MEMP base assets reflect estimated proved reserves as of December 31, 2015 per MEMP internal estimates audited by Ryder Scott Gas Oil NGL 19

20 Use of Non-GAAP Financial 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; income tax expense; depreciation, depletion and amortization; impairment of goodwill and long-lived assets; accretion of asset retirement obligations; losses on commodity derivative contracts; cash settlements received on commodity derivative instruments; 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 on commodity derivative contracts; cash settlements paid on commodity derivative instruments; 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. 20

21 2016 Adjusted EBITDA & Distributable Cash Flow Guidance Reconciliation Mid-Point For Year Ended (in millions) 12/31/2016 Calculation of Adjusted EBITDA: Net income ($8) Interest expense 113 Depletion, depreciation, and amortization 193 Adjusted EBITDA $298 Reconciliation of Net Cash From Operating Activities to Adjusted EBITDA: Net cash provided by operating activities $185 Changes in working capital - Interest expense 113 Adjusted EBITDA $298 Reconciliation of Adjusted EBITDA to Distributable Cash Flow: Adjusted EBITDA $298 Cash Interest Expense (113) Estimated maintenance capital expenditures (70) Distributable Cash Flow $115 21

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