CONFIDENTIAL Highly Confidential Subject to FRE 408 Subject to Express Confidentiality Agreement BREITBURN ENERGY PARTNERS LP PRELIMINARY DISCUSSION MATERIALS DECEMBER 6 2016 Exhibit 99.1
CONFIDENTIAL None of Breitburn, Lazard Frères & Co. LLC (“Lazard”) and Alvarez & Marsal North America, LLC (“A&M”), and each of their subsidiaries, affiliates, officers, directors, shareholders, employees, consultants, advisors, agents and representatives of the foregoing (collectively, “Representatives”), makes any representation or warranty, express or implied at law or in equity, in connection with any of the information made available either herein or subsequent to this presentation, including, but not limited to, the past, present or future value of the anticipated cash flows, income, costs, expenses, liabilities and profits, if any, of Breitburn. Accordingly, any person, company or interested party shall rely solely upon its own independent examination and assessment of the information in making any investment decision with respect to Breitburn (the “Transaction”), including, but not limited to, a restructuring of Breitburn’s balance sheet, and in no event shall any recipient party make any claim against Breitburn, Lazard, A&M or any of their respective Representatives in respect of, or based upon, the information contained either herein or subsequent to this document. None of Breitburn, Lazard or A&M, or any of their respective Representatives, shall have any liability to any recipient party or its respective Representatives as a result of receiving and/or evaluating any information concerning the Transaction (including, but not limited to, this presentation). This presentation contains forward-looking statements relating to Breitburn’s operations that are based on management’s current expectations, estimates and projections about its operations. Words and phrases such as “expected,” “guidance,” “expansion,” “opportunities,” “target,” “estimated,” “future,” “believe,” “potential,” “will be” and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond Breitburn’s control and are difficult to predict. These include risks relating to Breitburn’s financial performance and results, availability of sufficient cash flow and other sources of liquidity to execute Breitburn’s business plan, prices and demand for natural gas and oil, increases in operating costs, uncertainties inherent in estimating Breitburn’s reserves and production, Breitburn’s ability to replace reserves and efficiently develop Breitburn’s current reserves, Breitburn’s ability to obtain sufficient quantities of CO2 necessary to carry out Breitburn’s enhanced oil recovery projects, political and regulatory developments relating to taxes, derivatives and Breitburn’s oil and gas operations, and the risk factors set forth under the heading “Risk Factors” incorporated by reference from Breitburn’s Annual Report on Form 10-K filed with the Securities and Exchange Commission, and if applicable, Breitburn’s Quarterly Reports on Form 10-Q and Breitburn’s Current Reports on Form 8-K. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward- looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Breitburn undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements. Information in this presentation is dependent upon assumptions with respect to commodity prices, production, development capital, exploration capital, operating expenses, availability and cost of adequate capital and performance as set forth in this presentation. The production, transportation and marketing of oil and gas are subject to disruption due to transportation and processing availability, mechanical failure, human error, inclement weather and numerous other factors. Breitburn’s estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. The recipient hereby acknowledges that none of Breitburn, Lazard, A&M or any of their respective Representatives has any obligation to update any such projections or forecasts. References to “Breitburn,” “BBEP,” or like terms refer to Breitburn Energy Partners LP and its subsidiaries. These materials are confidential and intended solely for informational purposes. These materials are not intended for distribution to, or use by any person or entity in any jurisdiction or country where such distribution or use would be contrary to local law or regulation. This presentation is being made to the recipient on a confidential basis in accordance with the terms of the non-disclosure agreement (“NDA”) entered into between the recipient and Breitburn. This presentation and the information contained herein may only be used by the recipient as provided in the NDA. If you are not the intended recipient of this presentation, please delete and destroy all copies immediately. LEGAL DISCLOSURE pg. 2
CONFIDENTIAL AGENDA 1. Company Introduction Hal Washburn 2. Operations Overview and Plan Mark Pease 3. G&A and District Expense Reduction Efforts Jim Jackson 4. Financial Projections Jim Jackson 5. Next Steps Discussion Tim Pohl
CONFIDENTIAL COMPANY INTRODUCTION
CONFIDENTIAL pg. 5 MANAGEMENT – TEN YEARS OF CONTINUITY Halbert S. Washburn – Director and Chief Executive Officer Chief Executive Officer of Breitburn’s General Partner since April 2010 Served as Co-Chief Executive Officer and a director of Breitburn predecessor entities from May 1988 Currently serves on the boards of directors of Rentech, Inc. and Jones Energy, Inc. Past chair of the California Independent Petroleum Association and member of the All-American Wildcatters Mark L. Pease – President and Chief Operating Officer Chief Operating Officer and Executive Vice President of Breitburn’s General Partner since December 2007 Prior to Breitburn, served as Senior Vice President E&P - North America, and Senior Vice President, E&P Technology & Services for Anadarko Petroleum James G. Jackson – Executive Vice President and Chief Financial Officer Chief Financial Officer of Breitburn’s General Partner since July 2006 and Executive Vice President since October 2007 Prior to Breitburn, served as Managing Director of the Global Markets and Investment Banking Group for Merrill Lynch Previously served as director of Niska Gas Storage Partners LLC Gregory C. Brown – Executive Vice President, General Counsel, and Chief Administrative Officer General Counsel and Executive Vice President of Breitburn’s General Partner since December 2006 Prior to Breitburn, served as Partner at Bright and Brown, a law firm specializing in energy and environmental law that Mr. Brown co-founded in 1981 Current Treasurer of the California Independent Petroleum Association
CONFIDENTIAL OVER 28 YEARS OF OPERATORSHIP pg. 6 • Predecessor founded in 1988; IPO in 2006 • Value created - and capital returned - for numerous owners across commodity cycles • Seasoned team, proven innovative solution-finding capability, rich corporate action history KEY MESSAGES • Multi-faceted investment strategy: acquire, exploit, organically grow • Focus on operated positions in high OOIP/OGIP fields to maximize value creation opportunities • Unlock under-exploited resource utilizing state of the art engineering and geoscience • Prioritize returns – not production growth • Proven ability to realize outsized option value while paying no/low option premiums VALUE CREATION STRATEGY • Operatorship and minimally committed capital program enable flexibility to live within cash flow or scale up investment • Proven ability to find and develop resource organically • Efficient A&D effort that historically screened 300+, evaluated 20+ transactions annually NIMBLE ORGANIZATION • Aggressively realigned OpEx & G&A maximizes go-forward profit leverage • Deep inventory, with unique combination of high IP, quick payback (workovers), and LT value creation (H2O flood, EOR) project • Long-lived, oily assets plus significant low-carry gas optionality • Strong platform for significant value extraction from opportunistic acquisitions POISED FOR GROWTH
CONFIDENTIAL California Southeast Rockies Mid-Continent MI/IN/KY Ark-La-Tex Permian Basin 4.6 15.1 18.4 17.9 18.4 19.3 22.8 30.0 38.7 55.3 0 10 20 30 40 50 60 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 Mbo ep d Average Daily Reported Production pg. 7 STRONG HISTORY OF OPERATING AND FINANCIAL PERFORMANCE 32% CAGR (2006 – 2015)
CONFIDENTIAL ATTRACTIVE ASSETS IN 7 PRODUCING AREAS pg. 8 ARK-LA-TEX 2015 Avg. Daily Production 10,022 Boe/d Est. Proved Reserves 46.9 MMboe SOUTHEAST 2015 Avg. Daily Production 5,585 Boe/d Est. Proved Reserves 20.4 MMboe MI/IN/KY 2015 Avg. Daily Production 8,468 Boe/d Total Proved Reserves 51.5 MMboe MID-CONTINENT 2015 Avg. Daily Production 7,710 Boe/d Est. Proved Reserves 32.3 MMboe CALIFORNIA 2015 Avg. Daily Production 4,849 Boe/d Est. Proved Reserves 17.9 MMboe ROCKIES 2015 Avg. Daily Production 6,332 Boe/d Est. Proved Reserves 25.7 MMboe PERMIAN BASIN 2015 Avg. Daily Production 12,322 Boe/d Est. Proved Reserves 44.6 MMboe TOTAL TOTAL EST. PROVED RESERVES: 239.3 Mmboe PROVED RESERVE LIFE: ~12 years PERMIAN BASIN 19% ROCKIES 11% ARK-LA-TEX 20% MI/IN/KY 21% SOUTHEAST 9% CALIFORNIA 7% MID-CONTINENT 13% Estimated Proved Reserves By Area CALIFORNIA ROCKIES MI/IN/KY MID-CONTINENT PERMIAN BASIN ARK-LA-TEX SOUTHEAST Estimated reserves based on December 31, 2015 SEC Reserve Report
CONFIDENTIAL pg. 9 EXTENSIVE CAPABILITIES; BROAD AND DEEP ECONOMIC OPPORTUNITY SET Conventional and Unconventional Reservoirs • Shallow gas, natural water drive • Permian shale, tight gas Value via Drill-Bit • Horizontal drilling and completion • Infills, step-outs Secondary and Enhanced Oil Recovery Proficiency • Waterflood design/surveillance/optimization • CO2 flood, nitrogen flood, steam Regional Operational Knowhow • Complex environments (urban L.A., Florida Everglades) • Diverse landowners (Native American, BLM) Extensive IP & Data Access/Application • Seismic, completion/recovery technology • Regulatory, community relationships Proven Operational Efficiency • Cost-focused throughout organization • Supply chain, marketing Ability to Employ Range of Investment Strategies • Acquire and exploit producing properties • Lease and drill Proved Reserves by Region ArkLaTex California Florida MI/IN/KY Mid-Con Permian Rockies 3P Reserves by Category PDP PDNP PUD PROB POS Reserves by Commodity Oil Gas NGL Reserves by Recovery Mechanism Primary-Oil Primary-Gas Waterflood Miscible Flood Estimated reserves based on December 31, 2015 SEC Reserve Report
CONFIDENTIAL As market conditions continually deteriorated over the last two years, the company has maintained disciplined capital spending programs. Budgeting decisions have been influenced by critical factors such as: liquidity conservation, dynamic project economics and preservation of vested corporate interests Oil and gas development capital spending has been reduced ~88% or $516.0 million (vs. YE’14 levels). 2016 spending focused on 4 core principals: • Effectively maintain safe work conditions and environmental compliance • Properly maintain equipment, operational capability • Meet contractual obligations to participate in non-operated projects where non-consent would forfeit valuable ownership interests • Limit discretionary spending to only projects that clearly enhance liquidity, deliver high returns and rapid payouts Limited, but highly effective acquisition activity ~$10 million in 2016 • Market conditions present once-per-decade acquisition opportunities • Targeted bolt-on type assets with “no-cost” attractively economic upside projects (added ~50 locations in 2016) • Completed acreage trades and small asset purchases that leverage economics of keystone Permian Eastern Midland Basin horizontal play pg. 10 CAPITAL INVESTMENT REDUCTIONS Prudent Deployment of Investment Capital Reflective of Market Conditions (1) 2014 combines full-year QRE & BBEP operating results (2) 2016P includes 10 mos. actuals plus 2 mos. projected CAPITAL INVESTMENT - OIL & GAS DEV $ in millions $582.1 $210.6 $66.1 ( $371.5 ) ( $516.0 ) $- $100 $200 $300 $400 $500 $600 2014 (1) 2015 2016P (2) Investment Reduction 88% Decrease in Dev. Capital Costs (vs. YE '14)
CONFIDENTIAL Organizational structural changes placed the company’s best managers in a position to have maximum impact. The assets were broken into smaller divisions grouping together those with complimentary technical characteristics. Employees met the challenge of changing emphasis from intense capital project work to efficiency driven cost control. Achieved ~38% or $160.6 million reduction in total LOE (vs. YE’14 levels) while maintaining cost-effective production level • Each of 5 divisions contributed double-digit cost structure improvement • Reductions realized and sustained across all categories of spend Value driven approach to procurement of resources and key services integrated operating teams with specific Supply Chain professionals Evaluated and took action on all levels of spend • Eliminated overtime by adjusting scheduling • Bid all materials and services – often multiple times • Leveraged automation to make more efficient use of time by adopting control room/dispatch concept • Re-routed production to eliminate high cost facilities • Reduced workover frequency by improving system designs and deffering marginally economic repairs pg. 11 LEASE OPERATING EXPENSE REDUCTIONS Tactical Re-alignment of Personnel and Focus Delivered Substantial Improvement in Operational Efficiency (1) QRE 2014 LOE adjusted for capitalization of workover expenses. (+$14.8MM) (2) 2016P includes 10 mos. actuals plus 2 mos. projected LOE ANNUAL RUN-RATE COSTS $ in millions ( $75.3 ) ( $160.6 ) $425.7 $350.4 $265.0 $- $50 $100 $150 $200 $250 $300 $350 $400 $450 2014 (1) 2015 2016P (2) Run-Rate LOE Costs Reduction 38% Decrease in Run-Rate LOE Costs (vs. YE '14) LOE ANNUAL PER BBL COSTS $/BOE 20.64 17.42 14.51 3.23 6.14 $- $5.00 $10.00 $15.00 $20.00 $25.00 2014 (1) 2015 2016P (2) Run-Rate Lifting Cost Reduction 30% Decrease in Run-Rate LOE/BOE Costs (vs. YE '14)
CONFIDENTIAL Beginning in November 2014, Breitburn’s senior management team moved quickly to right-size the organization in light of the unprecedented deterioration of commodity prices and market conditions Instituted a hiring freeze on December 9, 2014 Achieved ~40% reduction in total G&A positions (vs. YE’14 levels) through multiple rounds of RIFs • 73 eliminated positions in 2Q’15 – 3Q’15 (2 waves of RIFs) • 53 eliminated positions in 1Q’16 – 2Q’16 (2 waves of RIFs) Achieved ~32% or $11.4 million reduction in non-payroll G&A annual run-rate costs (vs. YE’14 levels) Achieved ~33% or $29.1 million reduction in total G&A annual run- rate costs (vs. YE’14 levels) • Eliminated merit increases from 2015 and 2016 G&A budgets • Initiated an office rent reduction plan to sublease Houston office space • High-graded the team and right-sized the organization in anticipation of sustained lower activity levels and uncertain market conditions (1) Excludes PCEC Management Agreement fee; agreement terminated as of June 30, 2016. G&A annual run-rate costs include STIP and exclude LTIP awards. pg. 12 G&A EXPENSE REDUCTIONS G&A TOTAL POSITIONS # of Positions MMBOE 317 244 191 ( 73 ) ( 126 ) - 6 12 18 24 - 80 160 240 320 4Q 2014 4Q 2015 2Q 2016 G&A Positions Reduction Production 40% Decrease in G&A Positions (vs. YE '14) Focused on Implementing Significant G&A Cost Reductions G&A ANNUAL RUN-RATE COSTS (1) $ in millions $87.2 $70.6 $58.1 ( $16.6 ) ( $29.1 ) $- $25 $50 $75 $100 4Q 2014 4Q 2015 2Q 2016 Run-Rate G&A Costs Reduction 33% Decrease in Run-Rate G&A Costs (vs. YE '14)
CONFIDENTIAL District expenses are operating costs incurred to manage or supervise the company’s operating assets such that wells, leases, or facilities benefit proportionately. In practice, the company’s technical personnel reporting up to, and including, divisional VPs, who are responsible for day-to-day decision-making and supervision of the company’s areas, regions, and divisions are included in District expenses. Achieved ~32% reduction in total District positions (vs. YE’14 levels) through multiple rounds of RIFs • 35 eliminated positions in 2Q’15 – 3Q’15 (2 waves of RIFs) • 29 eliminated positions in 1Q’16 – 2Q’16 (2 waves of RIFs) Achieved ~18% or $1.4 million reduction in non-payroll District annual run-rate costs (vs. YE’14 levels) Achieved ~29% or $11.9 million reduction in total District annual run- rate costs (vs. YE’14 levels) • Eliminated merit increases from 2015 and 2016 District budgets • Initiated an office rent reduction plan to sublease Houston office space • High-graded the team and right-sized the organization in anticipation of sustained lower activity levels and uncertain market conditions pg. 13 DISTRICT EXPENSE REDUCTIONS Detailed Review of District Expenses Accomplished Significant Cost Reductions DISTRICT TOTAL POSITIONS # of Positions MMBOE 201 166 137 ( 35 ) ( 64 ) - 6 12 18 24 - 55 110 165 220 4Q 2014 4Q 2015 2Q 2016 District Positions Reduction Production 32% Decrease in District Positions (vs. YE '14) Note: District annual run-rate costs include STIP and exclude LTIP awards. DISTRICT ANNUAL RUN-RATE COSTS $ in millions $41.6 $34.2 $29.7 ( $7.4 ) ( $11.9 ) $- $15 $30 $45 4Q 2014 4Q 2015 2Q 2016 Run-Rate District Costs Reduction 29% Decrease in Run-Rate District Costs (vs. YE '14)
CONFIDENTIAL ACCESSING CAPITAL • Accessed $8bn+ of capital via multitude of sources: public and private equity, public and private preferred, public and private debt, at-the-market equity, equity issued as acquisition currency • Track record of innovative matching of assets with capital throughout predecessor history (e,g, royalty trust) • Fully evaluated alternative funding strategies (AcqCo, DevCo, etc.) RETURNING CAPITAL • Cumulative BBEP distributions of $13.35 per common unit since IPO at $18.50 • Multiples of investment returned to predecessor owners NAVIGATING CHALLENGING ENVIRONMENTS • Prudent distribution reduction/suspension • Meaningful G&A reductions • Continuous capital budget re-alignment • Opportunistic capital raise (early to 2L market) pg. 14 TRACK RECORD DEMONSTRATES BROAD ORGANIZATIONAL EXPERTISE FINDING DESIRABLE ASSETS • 20+ Acquisitions, including transformative (QRE, KWK, LA Basin) • Proactive strategic process to identify desired basin (e.g., Permian), platform (e.g., Postle EOR) entry • Proven ability to find, extract option value • Integration a core competency SIMULTANEOUSLY MANAGING MULTIPLE COMPANIES/CONSTITUENTS • Energetic, agile workforce with unmatched depth of experience • Comprehensive and validated conflict management process MANAGING RISK, PRIORITIZING SAFETY • Historically active, robust hedging program • Prudent management of counterparty exposure • Legacy of successful development in highly sensitive operating and regulatory environments • De minimis uninsured historical or current litigation liabilities • Strong safety record Organization composed of veterans, highly adept at creating value regardless of corporate structure:
CONFIDENTIAL pg. 15 PORTFOLIO OFFERS MAXIMUM VALUE CREATION AND MINIMAL INCREMENTAL CAPITAL EXPOSURE Accelerated Inventory Development Multiple Growth Avenues Embedded Funding Options Low-Risk Play Extension with Minimal Capital Exposure Bolt-on Acquisitions from Distressed Sellers Strategic Consolidation Asset Monetizations Yield Vehicles Regional Exit - Redeploy to “Core-Up” Partial Midstream Monetization Partnered, Asset-Level Finance High Value “Proprietary” Area Expansion
CONFIDENTIAL OPERATIONS OVERVIEW AND PLAN
CONFIDENTIAL MAINTAIN STRATEGIC FOCUS pg. 17 • Organized by Division for operating efficiency – but Breitburn to the core • Aim for full resource value capture (have grown inventory through technical enhancement and/or step-out expansion in core fields since entering) • Continue to drive efficiencies across the portfolio: small improvements add value, inventory • Prioritize returns using all means: acquisition, exploitation improvement, cost reduction, etc. ONGOING ORGANIZATIONAL PRIORITIES (NOT A NEW CHAPTER) • All-star bench with substantial experience applying conventional and unconventional exploitation techniques • Regular, comprehensive benchmarking to evaluate performance, identify opportunities for improvement • Frequent teach-ins and internal technology conferences to share best practices LEVERAGE EXTENSIVE INTELLECTUAL CAPITAL • Established operated positions in resource-rich basins enables numerous opportunities to capture incremental value • Numerous identified avenues to grow each core position and leverage regional expertise • Comprehensive collection of subsurface and seismic data EXPLOIT EXCEPTIONAL ASSET BASE • Rigorous Portfolio Management strategy, process, and toolset • Integrated process to rank inventory and allocate capital according to various constraints • Acquisitions evaluated against organic capital investment alternatives • Monetizations of non-premium inventory (e.g., Midcon) to upgrade the portfolio MAKE EVERY DOLLAR COUNT
CONFIDENTIAL DIVISION VI PERMIAN-EASTERN MIDLAND BASIN
CONFIDENTIAL DIVISION VI OVERVIEW • Spraberry Trend Acreage as of 9/30/16 – Total Acreage (including vertical/wellbore only & HZ rights): 24,670 gross / 21,580 net – Total HZ Acreage: 20,703 gross / 17,502 net • 6.3 MBoe/d of Q1 2016 net production – 401 gross producing wells • 2016 Capex: $3.3 MM – focusing on base production and LOE reduction – building-out horizontal infrastructure projects Asset Highlights Howard Co., TX City of Midland Eastern Shelf Midland Basin Platform Margin TX NM Core Area 85 bopd, peak month daily rate per 1000 ft Primary Area Breitburn leasehold position pg. 19
CONFIDENTIAL 1) Includes Jo Mill Sand, Middle Spraberry, Wolfcamp D/Cline, and a second row of infill wells in the Wolfcamp A and the Lower Spraberry HORIZONTAL MIDLAND BASIN DEVELOPMENT Lower Spraberry Wolfcamp A Wolfcamp B Add. Potential Benches (1) Total Net Locations Operated 53 53 53 207 365 Non-Operated 55 55 55 251 416 Total Net Locations 108 108 108 458 781 Horizontal Acreage Vertical rights only acreage Operated HZ’s Non-Operated HZ’s pg. 20
CONFIDENTIAL Operated Acreage Non-Operated Acreage INDUSTRY ACTIVITY AROUND BREITBURN ACREAGE Martin Howard Notes: Key horizontal wells; Lateral lengths are stimulated lengths. Lower Spraberry (28) Wolfcamp A (76) Wolfcamp B (20) November 11, 2016 Crownquest - Gratis 32-R 1HB Lateral Length: 9,953’ Peak 24hr/30 day IP (Boe/d): 1,343/1,063 Diamondback - Phillips-Hodnett Unit Lateral Length: 7,430‘ Peak 30 day IP (Boe/d): 1,374 (89% oil) Diamondback – Reed (LS, WCA, WCB) Lateral Length: 9,721’ IP24 (boe/d/1000’): 82 (89% oil) SM Energy – Tackleberry (LS, WCA, WCB) Length: NA‘ Flowing back Diamondback - Phillips-Hodnett Unit Lateral Length: 7,093‘ Peak 30 day IP (Boe/d): 1,225 (83% oil) Diamondback - Phillips-Hodnett Unit Lateral Length: 7,296’ EUR: 120+ Mboe/1000’ Surge – Allred Unit B 08-05 8AH Lateral Length: NA’ Flowing Back Diamondback – Reed (LS, WCA, WCB) Lateral Length: 9,727’ IP24 (boe/d/1000’): 185 (89% oil) Diamondback – Reed (LS, WCA, WCB) Lateral Length: 9.727’ IP24 (boe/d/1000’): 221 (89% oil) Diamondback – Asro Lateral Length: ~9,700’ Drilling Diamondback – Asro Lateral Length: ~9,700’ Waiting on completion Diamondback – Asro Lateral Length: ~9,700’ Waiting on completion Surge – Shroyer-Wilson Unit 1SH Lateral Length: 6,701’ Peak 24hr/30 day IP (Boe/d): 774/793 Oxy – Shields 3107 1WA Lateral Length: 9,377’ Peak 24hr/30 day IP (Boe/d): 894/478 Callon– Garrett Unit 37-48 3SH Lateral Length: 6,901’ Peak 24hr/30 day IP (Boe/d): 882/682 Surge - Elrod-Antell Unit A 11-02 4SH Lateral Length: 6,676‘ Peak 24hr/30 day IP (Boe/d): 1,272/780 Oxy - Shields 31051WA Lateral Length: 9,152’ Peak 24hr/30 day IP (Boe/d): 1,606/1,323 SM Energy– Ripley 10-2 A-15WA Lateral Length: 6,886’ Peak 24hr/30 day IP (Boe/d): 1,249/NA CrownQuest - Guitar Galusha 1H Lateral Length: 7,147’ Peak 24hr/30 day IP (Boe/d): 1,972/1,402 SM Energy– Falkor 4-8A 5LS Lateral Length: NA Peak 24hr/30 day IP (Boe/d): 1,111/NA Surge - Hamlin-Middleton Unit #3SH Lateral Length: 7,000’ Peak 24hr/30 day IP (Boe/d): 754/789 SM Energy – Ogre 47-2A 1WA Lateral Length: NA Peak 24hr/30 day IP (Boe/d): 1,033/NA Surge - Wolfe-McCann Unit 10-2SH Lateral Length 6,851’ Peak 24hr/30 day IP (Boe/d): 1,161/783 pg. 21
CONFIDENTIAL U. Spraberry Shale Clear Fork L. Spraberry Shale Dean Wolfcamp A Wolfcamp B Wolfcamp C Cline L. Spraberry Sands M. Spraberry Shale U. Spraberry Sands PRIMARY DEVELOPMENT AREA STRATIGRAPHY System Series Formation San Andres, GlorietaGuad. Cisco Canyon Strawn Bend (Atoka) Woodford Kinderhook Mississippian Lime Barnett Shale Leo n ar d ia n W o lf campi an Sp ra b err y Tr en d Ar ea Per m ia n P enn sylvan ia n Mi ss D ev Type Log: Fred Phillips 19 #2 Productive in Howard Co. Lo w er Spra b err y Wol fca m p A GR Res Eff. Poro. Wol fca m p B Productive Additional potential Key Points Stacked low porosity and low permeability pays from Permian age Clear Fork through the Mississippian Limestones Midland Basin operators are exploiting multiple organic rich benches in the Leonardian and Wolfcampian series of the Permian The Leonardian and Wolfcampian section is greater than 2,500’ thick Consists of thick organic rich shales, interbedded with thin sand and carbonate beds Horizontal exploitation targets in the core area include: ─ 300-350’ of proven Lower Spraberry ─ 400-550’ of proven Wolfcamp Other possible targets include: benches in the Spraberry, Cline, Pennsylvanian, and Mississippian pg. 22
CONFIDENTIAL DEVELOPMENT PLAN SUPPORTED BY SUBSURFACE MODEL Key Points Technical data includes: logs, cores and 2D seismic data ─ 590 wells with digital triple- combo data ─ Member of Core Lab’s Midland Basin consortium ─ Cored 800’ of section from Lower Spraberry into the Wolfcamp B in the Beall Unit 18 #1 well ─ In-house petrophysical model tied to core and used to analyze 474 wells ─ 115 linear miles of 2D seismic data 342 sq. mi. of 3D seismic data recently acquired by CGG ─ Available in June pg. 23
CONFIDENTIAL Surface Casing: 13 3/8", 54.5#, K-55, BT&C Hole Size: 17 1/2" set @ 450' ( cement to surface ) 9 5/8" Stage tool @ 3000' Intermediate Casing: 9 5/8", 40#, HCK-55, BT&C set @ 6,150' , 0 degs (special drift to 8.75") Hole Size: 12 1/4"" to 6,150' MD (6,150' TVD) (base of Clearfork) Production Casing: Start of Build Section Start of Horizontal Section 5½", P-110, 17#, GeoCon BT&C @ ~ 6,566' MD @ 7,901' MD set @ 14,850' MD (cement top to 5,800') Hole Size: 8 3/4" from 6,150' to TD Lower Spraberry Formation TD: 14850' MD 7,487' TVD Build Section: 10° per 100 ft WELLBORE DIAGRAM Key Points Drilling Plan ─ 3-string casing design ─ Closed-loop fresh water mud system ─ 7,250’ lateral 1 Frac Design ─ Water frac ─ Plug and perf method ─ 36 frac stages ─ 1,600 lbs/ft of proppant Single Well Capex M$ Drill 1,914 Complete 3,301 Total D&C 5,215 Pre-drill 200 Facilities 455 Equip / Artificial Lift 384 Total all-in cost 6,254 1) perf-to-perf length Updated cost for longer lateral length pg. 24
CONFIDENTIAL Pad and Facilities Design PAD AND FACILITIES OVERVIEW Key Points Pad Design ─ Designed for 2 - 6 wells ─ 450’ by 400’ ─ 2 well facility shown ─ Pad cost: $85,000 Facilities Design ─ HP Separator ─ LP Separator ─ Heater Treater ─ 3x500 bbl oil tanks ─ 2x750 bbl water tanks ─ Facility cost: $455,000 Oil sold via LACT at location 4 0 0 ’ 450’ pg. 25
CONFIDENTIAL FRAC WATER MANAGEMENT PLAN Key Points Frac Pit Water Storage ─ 2,200 Mbbls FW Pipeline Infrastructure ─ 7.4 miles buried 8” line ─ 30 MBWPD transfer capacity Frac Water Sources ─ Fresh water o BBEP:15-20 MBWPD o Non-op: 10-15 MBWPD ─ Other water o Recycled: ~10 MBWPD Water Requirements ─ 300 Mbbls / frac ─ 15 MBWPD per rig pg. 26
CONFIDENTIAL SALT WATER DISPOSAL SYSTEM Key Points Current Salt Water Disposal System ─ SWD pipeline in place ─ 1 operated SWD well ─ 3 tie-ins to 3rd party systems ─ Capacity of 38 MBWPD 2017 Plans ─ Drill 2 additional SWD wells ─ Capacity increase ~35 MBWPD Lloyd SWD pg. 27
CONFIDENTIAL pg. 28 HORIZONTAL WELL PROGRAM PRIMARY DEVELOPMENT AREA Key Points Development ─ 189 gross operated locations (LS, WCA,WCB) ─ Six wells across section (880’ spacing) ─ Pad drill initially the Wolfcamp A & Lower Spraberry Land ─ Acreage 100% HBP’d ─ 18 drill ready locations ─ Obtaining PSA’s on all wells ─ 90.2% ave. WI in operated wells Infrastructure ─ SWD pipeline system in-place ─ Building frac fresh water infrastructure ─ Securing fresh water sources
CONFIDENTIAL EASTERN MIDLAND BASIN pg. 29 SUMMARY INFORMATION Overview Operated Producing Wells (1) 355 Net Acreage Developed 11,001 3Q '16 Daily Production Undeveloped 6,501 Oil (bopd) 2,648 Total 17,502 Gas (mcfpd) 8,019 NGL (galpd) 70,594 Ownership Total (boepd) 5,665 Avg. W.I. 84.5% Avg. NRI 64.8% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 12.1 0.1 15.8 28.0 86.5% 196.9 11.8 236.8 91.9% 2,216.0 2,769.8 10,840.8 1,030.0 12/28/2016 Strip Pricing +10% 12.6 0.1 15.9 28.6 86.5% 198.1 20.4 247.2 92.0% 2,372.6 2,965.8 12,507.8 1,325.9 12/28/2016 Strip Pricing -10% 11.4 0.1 15.7 27.2 86.8% 194.6 11.8 233.7 92.0% 2,140.3 2,732.8 9,575.3 737.0 Note: Based on October 2016 Business Plan risked reserves. Certain wells categorized differently than in October 2016 Business Plan, per oral discussion. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL DIVISION V ENHANCED OIL RECOVERY
CONFIDENTIAL DIVISION V - EOR OVERVIEW Jay/LEC Unit – 0.30 HCPV Injected N2 flood began in 1981; 101 MMBBL tertiary recover to date Flexible OPEX program Robust PDNP Capital Program (RTP, RTI & CTI) Substantial drilling opportunities Postle Units – Range from 0.69-1.09 HCPV Injected CO2 flood began in 1995; 44 MMBBL tertiary recover to date NEHU – Range from 0.3-0.47 HCPV Injected CO2 flood began in 2014 Libby Ranch – CO2 Source field Supplies necessary CO2 for all PUD development Big Escambia Creek: Pressure Depletion Gas-Cond. August 2015 net production 11.0 MBoe/d from 500 wells 2016 Capex: $22.1 MM Asset Highlights Fields With Potential Future Projects Postle & NEHULibby Ranch Jay/LEC BEC pg. 31
CONFIDENTIAL * Morrow Sands - Net Isopach Maps – ‘A’, ‘A1’, ‘A2’ ** - New ‘A’ Patterns Include Lease Line and Interior Patterns Flooded ‘A’ / Floodable ‘A’ / Developed (MM STB) (MM STB) (%) HMAU – 59.3 / 59.3 / 100 HMU – 70.9 / 85.3 / 83 PUMU – 44.2 / 44.2 / 100 WHMU – 112.7 / 125.7 / 90 Total – 287.1 / 314.5 / 91 20-Ac ‘A1’ PilotExisting Patterns Future Patterns POSTLE DEVELOPMENT INVENTORY ‘A’ Sand ‘A1’ Sand ‘A2’ Sand Flooded ‘A2’ / Floodable ‘A2’ / Developed (MM STB) (MM STB) (%) WHMU – 2.1 / 53.2 / 4 Flooded ‘A1’ / Floodable ‘A1’ / Developed (MM STB) (MM STB) (%) WHMU – 19.2 / 115.7 / 17 • 16% recovery factor on tertiary (from typecurve), with unswept secondary recovery in A1/A2 as potential upside • 173 active Postle/NEHU patterns and 105 potential 3P patterns, one-half of which are economically viable at current commodity price • Sufficient CO2 available via Libby Ranch source field to complete current project queue at Postle/NEHU pg. 32
CONFIDENTIAL 100 1,000 10,000 100,000 G ro ss Dail y P ro d u cti o n ( B OPD ) Postle/NEHU Field Oil Production POSS PROB PUD PNP PDP Historic pg. 33 POSTLE HISTORICAL & PROJECTED PRODUCTION Start Waterflood Start CO2 flood – PUMU, HMAU, WHMU Start CO2 flood - HMU Unit OOIP, MMSTB Primary + Secondary Actuals and Forecast, MMBO Incremental Tertiary Actuals and Forecast, MMBO HMAU 59.3 20 10.7 HMU 70.9 13 12 PUMU 44.2 24 11.7 WHMU 112.7 35 19 Total 287.1 92 53.4
CONFIDENTIAL GREATER POSTLE FIELD pg. 34 SUMMARY INFORMATION Overview Operated Producing Wells (1) 248 Net Acreage Developed 32,094 3Q '16 Daily Production Undeveloped - Oil (bopd) 4,330 Total 32,094 Gas (mcfpd) 1,126 NGL (galpd) 38,711 Ownership Total (boepd) 5,440 Avg. W.I. 96.9% Avg. NRI 83.7% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 13.5 0.0 18.3 31.8 95.1% 5.9 - 37.7 95.1% 631.0 399.3 1,982.5 254.7 12/28/2016 Strip Pricing +10% 13.5 0.0 18.4 32.0 95.1% 6.2 - 38.2 95.1% 642.9 408.8 2,205.1 317.0 12/28/2016 Strip Pricing -10% 13.3 0.0 18.1 31.5 95.1% 5.5 - 37.0 95.0% 614.8 390.6 1,759.0 193.2 Note: Based on October 2016 Business Plan risked reserves. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL Future Drill Wells (35) JAY FIELD –INVENTORY Fraction of Pay - High Reservoir Quality 2014-2015 Drill Wells (5) Well Spacing (Prod. + Inj.) Peak Development 100 acres/well Current Active 200 acres/well Future Plan 140 acres/well 3-P View 110 acres/well Immature Miscible Flood N2 Injection only 0.3 Pore Volume Limited N2 Inj. on West & South Flank Oil Volumes OOIP 1,029 MMBO Cum Prod. 466 MMBO Current RF 45% pg. 35
CONFIDENTIAL 100 1,000 10,000 100,000 1,000,000 G ro ss D ai ly P ro d u ctio n ( B o p d ) Jay Field Oil Production POSS PROB PUD PNP PDP JAY HISTORICAL & PROJECTED PRODUCTION Unit OOIP, MMSTB Primary + Secondary Actuals and Forecast, MMBO Incremental Tertiary Actuals and Forecast, MMBO Jay/LEC 1029 417 116 Start Waterflood Start N2 WAG Reduced Staff & Maintenance Initiate Facility Redesign pg. 36
CONFIDENTIAL GREATER JAY FIELD pg. 37 SUMMARY INFORMATION Overview Operated Producing Wells (1) 47 Net Acreage Developed 13,871 3Q '16 Daily Production Undeveloped - Oil (bopd) 3,133 Total 13,871 Gas (mcfpd) 77 NGL (galpd) 13,987 Ownership Total (boepd) 3,479 Avg. W.I. 92.8% Avg. NRI 76.4% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 12.3 5.7 10.1 28.1 99.6% 4.1 - 32.3 99.7% 867.5 173.5 1,508.4 174.9 12/28/2016 Strip Pricing +10% 13.2 6.5 10.6 30.4 99.6% 6.8 - 37.2 99.7% 1,057.7 196.8 1,933.6 256.0 12/28/2016 Strip Pricing -10% 11.2 4.1 9.6 24.8 99.6% 1.2 - 26.0 99.6% 660.3 139.4 1,080.9 103.0 Note: Based on October 2016 Business Plan risked reserves. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL DIVISION IV ARK-LA-TEX
CONFIDENTIAL DIVISION IV OVERVIEW 116K gross, 73K net acres 2,024 Gross Producing wells (2105 Year End NSAI) Q1 2016 Net Production: 11,138 BOED (48% Liquids) 120 wells available for immediate reactivation with higher commodity prices yielding additional 200 BOPD Asset Mix: Low-decline oil and rich gas condensate fields Primary Producing horizons: Cotton Valley, Woodbine, Travis Peak, Pettit, Haynesville sands & Smackover Q1 2016 Unit LOE: $9.74/BOE vs Q1 2015 Unit LOE: $22.91/BOE Successful Overton Cotton Valley horizontal drilling JV Numerous Infill drilling, deepening and high ROR workover/RC opportunities Expanding acreage position in High-Liquid Hz Cotton Valley Capital Plan 2016: $20 MM Asset Highlights Blocker/Oakhill/Carthage Major Field Areas Gladewater & ETOF Overton Dorcheat Shongaloo Homer Neches pg. 39
CONFIDENTIAL ARK-LA-TEX LOE pg. 40 Reduced total LOE by 52% Q1 2016 vs Q1 2015 Reduced Workover Activity Vendor Price Reductions Shut in Uneconomic Wells Cost Saving projects (Overton SWD) Grew Production by 12% Q1 2016 vs Q1 2015 Overton Program Reduced Unit LOE by $13.18/BOE (58%) Source: LOS Accounting Month Actuals, Excludes ETSWD Variance % Variance Time Period Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q1'16 vs. Q1'15 Q1'16 vs. Q1'16 LOE (MM$) 20.4 17.3 15.6 12.2 9.7 -10.7 -52% Production (MBOE) 891 847 897 965 1000 109 12% Unit LOE ($/BOE) 22.91 20.41 17.43 12.64 9.74 -13.17 -58%
CONFIDENTIAL AMI G R E E N B A Y 1 6 H E CH A RD 9 H H A R M O N -C A M E R O N 1 H C A M E R O N -H A R M O N 1 H G R IM E S 2 H D A V ID W IL S O N 1 1 H M C E LR O Y -S W A NN 2 H M C E LR O Y -S W A NN -M O O R E 2 H M C E LR O Y -S W A NN -M O O R E 1 H E CH A RD 7 H N E O 4 H W G U2 -C -L 1 H M UR R A Y -P O ND -G R A Y 2 H M C E LR O Y "A "-W IL K IN S O N 1 H M C E LR O Y "A "-M UR R A Y 1 H M A L D O N A D O -M UR R A Y 1 H P O ND -G R A Y 1 H R E A G A N -B L A C K S T O N E -W IL K IN S O N 2 H P O ND 1 H FEET 0 2,747 PETRA 12/1/2016 10:15:43 AM pg. 41 OVERTON OVERVIEW Overton Cotton Valley Taylor Activity Map Drilled Inventory Overview • Acreage: Approximately 10,000 gross acres, including ~3,000 acres acquired from Windsor in 2015 • BBEP Q1 2016 Net Production: 4,486 BOED (28% Liquids) • Produces from Cotton Valley, Travis Peak and Pettit • Horizontal Target: Lower Cotton Valley Taylor Sands • Depth: 11,000 – 12,000’ • BBEP owns 100% WI & 75%+ NRI on Vertical wells. • Executed 50/50 JV with Tanos Exploration in 2014 to Horizontally develop the Lower Cotton Valley Taylor Sands – Tanos is a Low Cost Driller with Cotton Valley Expertise – Tanos D&C’s the wells – BBEP Takes over operations after wells are completed • JV has D&C’d 16 Horizontal wells through Q1 2016 • Drill 9 & Complete 6 wells : $22 MM • SWD System Upgrade: $840K • Tubing Installations: $500K • Facilities Maintenance: $412K • Total 2016 Capital Program: $23.75MM 2016 Plan East Texas Gas Region BBEP Windsor Newly Acq.
CONFIDENTIAL pg. 42 Previous Overton Operators Targeted Taylor 4 BBEP’s Southern Acreage has limited Taylor 4 but thicker Taylor 3 BBEP Southern Overton wells Typically land in Taylor 3 Micro-seismic surveys and well performance indicate fracs are contacting all intervals in Southern Overton Potential for additional Taylor 3 Target Bolt-On Acquisitions Taylor 3 Taylor 4 OVERTON COTTON VALLEY TARGET INTERVAL
CONFIDENTIAL EAST TEXAS OIL FIELD OVERVIEW Discovered in 1930 Woodbine Sands at ~ 3500’ Original Oil in Place > 7 billion bbls Cumulative Production > 5.5 billion barrels Shallow base decline Low-cost field SWD gathering and reinjection system (ETSWD) Hundreds of low cost/low risk uplift opportunities (Deepening's, RTPs, ESP’s) • Current 2016 Plan: $2,120M 20 ESP Uplift Projects : $977M P&As: $293M Facilities: $850M Uneconomic wells were shut-in during 2015 and early 2016 Recently began returning these wells to production as economics allow 2016 Plan Overview pg. 43
CONFIDENTIAL ARK-LA-TEX pg. 44 SUMMARY INFORMATION Overview Operated Producing Wells (1) 2,490 Net Acreage Developed 75,599 3Q '16 Daily Production Undeveloped 3,451 Oil (bopd) 3,448 Total 79,050 Gas (mcfpd) 34,310 NGL (galpd) 63,785 Ownership Total (boepd) 10,685 Avg. W.I. 75.1% Avg. NRI 58.9% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 32.5 10.9 11.8 55.1 53.2% 63.7 12.5 131.3 35.2% 1,353.7 667.9 3,699.6 482.4 12/28/2016 Strip Pricing +10% 33.9 11.2 11.8 56.9 53.7% 65.2 12.5 134.6 35.5% 1,435.3 684.1 4,157.3 606.4 12/28/2016 Strip Pricing -10% 30.8 10.3 11.6 52.7 52.6% 63.2 12.5 128.4 34.5% 1,269.4 658.0 3,261.8 360.3 Note: Based on October 2016 Business Plan risked reserves. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL DIVISION II CALIFORNIA, W. PERMIAN
CONFIDENTIAL CALIFORNIA pg. 46 • Concentrated in large oil fields in the Los Angeles Basin and San Joaquin Valley – Company has long history in region with unique operational capabilities – Mature fields (some producing over 100 years) with low risk development opportunities – 2.5 billion Bbl OOIP, 1.5 billion Bbl remaining • 4,300 BOEPD Q1 2016 net production – 705 active wells: 517 Producers, 188 Injectors • 2016 capex: $ 8.4 MM – Facilities Upgrades & Capacity Optimization - Santa Fe Springs – Recompletions, artificial lift upgrades and injector profile modification projects in SFS, E. Coyote, and Sawtelle Fields Asset Highlights
CONFIDENTIAL Highlights pg. 47 SANTA FE SPRINGS OVERVIEW • Field discovered in 1919; 2.0 BBbl OOIP • Peak production in 1920’s was 345,000 Bo/d • Cum oil production 640 MMBo (32%) • BBEP purchased from Texaco in 1999 for <$10mm; 1,400 Bo/d and 5.8 mmbo Reserves • 100% operated with 100% WI (~94% NRI) in the unit • 141 producers and 79 injectors; 3,500’- 9,100’ • BBEP acreage of 617 ac. current well spacing of 3-10 acres depending on zone • Waterflooding was implemented in the 1970’s, and is now conducted in the Bell, Meyer, Buckbee, Nordstrom, Clark- Hathaway and USF formations Metric Statistic Current net Production (100% oil) 2,300 Boe/d Proved Reserves (100% oil)(1) 8.3 MMBoe % PDP 71% Key Operating Statistics (1) 1P Reserves based on YE 2015 Reserve Report at SEC prices
CONFIDENTIAL pg. 48 SANTA FE SPRINGS FIELD PRODUCTION HISTORY Foix,Bell, Meyer Nordstrom,Buckbee,Clark-Hathaway,O’Connell Santa Fe, Bell100 Unitization Waterflood Meyer, Clark-Hathaway (1972) BBEP Purchased Field (1999)
CONFIDENTIAL pg. 49 SANTA FE SPRINGS PRODUCTIVE INTERVAL(S) • Productive interval consists of 6000’ of massive channelized fan deposits and interbedded sand/shale sequences Upper M io ce n e P li o ce n e A B MEYER NORDSTROM O’CONNELL BELL HATHAWAY SANTA FE BUCKBEE - 10,000 - 2,000 - 8,000 - 6,000 - 4,000 Reservoir Characteristics Depths 3,500 – 9,100 ft Initial Pressure 1,500 – 4,000 psi Porosity 15 – 25 % Permeability 16 – 820 md Viscosity 0.3 – 3.8 cp Gravity 35 API 6 ,000 Fee t Rese rvoir Colu m n
CONFIDENTIAL FIELD DEVELOPMENT PLAN • Upgrade current Production Handling facilities to maximize throughput and reliability • Optimize well performance through surveillance, pumping diagnostics and lift optimization • Recomplete idle/underperforming wells targeting stratigraphically isolated incremental reserves • Prepare groundwork to enable construction of additional 100,000 Bbl capacity facility in 400 Block (AQMD Permits received) 2016 Capital $2.7 MM Rate Generating Projects including 8 high-graded recompletions, 3 artificial lift optimization projects and Block 000 RTP $1.3 MM Fluid Throughput capacity increase including injector repairs, CTIs, facilities modifications $2.2 MM Mandatory capital including compliance upgrades, leak risk mitigation, LOE reduction Capex pg. 50
CONFIDENTIAL BELRIDGE PRODUCER RE-FRAC POTENTIAL D-E D-A D-B D-C D-D D-F D-G D-G1 D-H C-8C Spud 5/15/2013 153’ HCFT By-passed Pay pg. 51
CONFIDENTIAL 0 20 40 60 80 100 120 140 160 1 3 5 7 9 11 13 15 17 19 21 23 25 27 29 31 33 35 Number of Wells Drilled 2013 BELRIDGE DRILLING POTENTIAL Belridge Surface Map 2013 Drilling EURs Mean EUR = 53 MBO 2014 Drilling EURs Mean EUR = 36 MBO Belridge Surface Map Drilled 2014 Remaining Locations EU R p er W el l 56 Remaining Locations Identified BBEP Interest = 100% GWI, 83% NRI EUR Per Location = 45 MBO Drilling and Completion Cost per Well = 750 K$ @ 60 $/BO Flat = 25% IRR, 194 K$ PVP@10% pg. 52
CONFIDENTIAL CALIFORNIA pg. 53 SUMMARY INFORMATION Overview Operated Producing Wells (1) 538 Net Acreage Developed 3,216 3Q '16 Daily Production Undeveloped 41 Oil (bopd) 3,975 Total 3,257 Gas (mcfpd) 831 NGL (galpd) 69 Ownership Total (boepd) 4,115 Avg. W.I. 81.5% Avg. NRI 77.5% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 19.4 2.5 0.6 22.5 97.4% 0.2 1.4 24.1 97.5% 657.0 152.9 1,251.0 228.8 12/28/2016 Strip Pricing +10% 20.4 2.5 2.1 25.0 96.8% 0.2 1.4 26.7 97.0% 741.4 190.1 1,529.8 285.6 12/28/2016 Strip Pricing -10% 18.3 2.3 0.0 20.6 97.7% 0.2 1.3 22.1 97.8% 583.9 137.6 1,028.6 173.7 Note: Based on October 2016 Business Plan risked reserves. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL W PERMIAN • 98,951 Gross, 63,872 net acres across Permian Basin as of 9/30/16 • Mature waterflood properties including E. Fuhrman, N. Cowden, Howard Glasscock, and Turner Gregory Fields and OBO interests in Wasson, Westbrook, and Vacuum • Prolific gas properties in the Pegasus, Waha, Coyanosa, and Block 16 Fields held within a high WI JV with XTO • Vertical Spraberry Trend Area production at Garden City and Coahoma Fields with infill potential and HZ upside • ABO/Drinkard/Blinebry production at M State lease in NM with additional locations and significant deep potential • 4,900 BOEPD Q1 2016 net production • 30% net production outside operated • 1,042 active Operated wells • 747 producers and 295 injectors • 2016 Capex $5.2 MM • Development drilling at M State lease Asset Highlights pg. 54
CONFIDENTIAL pg. 55 M STATE LEASE – LEA COUNTY, NEW MEXICO Key Points: • 3,000 acre JV with XTO in Lea Co. NM • BPO 100%/75% • APO 65%/56.875% • 180 continuous development • Next spud date 11/1/2016 • Historically Blinebry, Drinkard, Tubb • Recently discovered deeper potential Leasehold Map Acreage Position Field Production
CONFIDENTIAL M STATE 18 DRILLING RESULTS • MSE technology applied to improve drilling efficiency, with great results • Cut 8 days or 40% off previous drilling performance • Results in better than 30% reduction in capital cost that leverages each additional location • Process and technology transfers readily to companies varied operating areas. M State 18 Days vs. Depth Drilling Summary pg. 56 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 0 5 10 15 20 25 M eas u re d D e p th , F ee t Days BREITBURN DRILLING PERFORMANCE Depth vs. Days Curve M State #18 Actual M State #19 Actual M Fee 21-1 Actual M State #1 M State #15 M State #16
CONFIDENTIAL pg. 57 EAST_FUHRMAN – GLORIETTA WATERFLOOD EXPANSION Phase 1A Phase 1B • Phase 1A – $3.3 MM – (2017) • 2 years to peak rate • 2 Injectors • 4 Recompletions/Workovers • Phase 1B – $11.6 MM • Assumes completion of Phase 1A • 2 years to peak rate • 5 Producers, • 4 Injectors • 4 Recompletions/Workovers • Reserves • Phase 1 – 1.2 MMBOE • Phase 2 Upside
CONFIDENTIAL WEST PERMIAN pg. 58 SUMMARY INFORMATION Overview Operated Producing Wells (1) 619 Net Acreage Developed 64,027 3Q '16 Daily Production Undeveloped 3,857 Oil (bopd) 2,666 Total 67,844 Gas (mcfpd) 8,600 NGL (galpd) 41,602 Ownership Total (boepd) 5,090 Avg. W.I. 84.3% Avg. NRI 64.6% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 15.9 2.3 8.1 26.3 74.9% 4.7 1.1 32.1 76.8% 533.5 261.5 1,295.1 175.6 12/28/2016 Strip Pricing +10% 16.9 2.3 9.1 28.2 69.8% 5.1 1.1 34.4 77.8% 603.5 286.5 1,554.6 228.4 12/28/2016 Strip Pricing -10% 14.9 2.2 7.8 24.9 74.2% 4.5 1.0 30.4 76.2% 478.1 251.3 1,089.2 123.2 Note: Based on October 2016 Business Plan risked reserves. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL DIVISION I
CONFIDENTIAL MICHIGAN OVERVIEW pg. 60 • Breitburn is the largest gas producer in Michigan and one of the top producers in the Antrim Shale as of 9/30/16 – Other Michigan reservoirs include: Praire du Chien, Richfield, Detroit River Zone III, and Niagaran pinnacle reefs – New Albany shale (IN/KY) • Acreage: 554,205 (gross) / 305,665 (net) as of 9/30/16 • Interests in 3,752 productive wells (60% operated) • 22% of total estimated proved reserves (1) – 91% gas / 8% oil / 1% NGLs • MichCon city-gate pricing; generally trades at a premium to Henry Hub Asset Highlights (1) Estimated reserves based on December 31, 2015 SEC Reserve Report
CONFIDENTIAL MI/IN/KY pg. 61 SUMMARY INFORMATION Overview Operated Producing Wells (1) 1,660 Net Acreage Developed 251,085 3Q '16 Daily Production Undeveloped 12,687 Oil (bopd) 797 Total 263,772 Gas (mcfpd) 41,956 NGL (galpd) 4,894 Ownership Total (boepd) 7,906 Avg. W.I. 65.0% Avg. NRI 52.3% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 55.7 7.1 2.2 65.0 11.1% 0.7 0.0 65.7 11.5% 722.4 100.9 1,479.3 198.9 12/28/2016 Strip Pricing +10% 57.4 7.5 3.1 68.1 12.0% 7.2 0.1 75.4 11.3% 816.2 160.4 1,854.8 244.2 12/28/2016 Strip Pricing -10% 52.8 1.4 2.2 56.5 12.7% 0.4 0.0 56.9 13.2% 603.6 77.7 1,184.0 155.2 Note: Based on October 2016 Business Plan risked reserves. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL ROCKIES OVERVIEW pg. 62 • Key basins include – Evanston and Green River Basins in southwestern Wyoming (primarily natural gas) – Big Horn and Wind River basins in central Wyoming (primarily oil) • Acreage: 207,778 (gross) / 112,865 (net) as of 9/30/16 • Interests in 970 productive wells (67% operated) • 11% of total estimated proved reserves (1) – 55% oil / 45% gas • Medium / heavy gravity crude and high BTU gas; generally trade at a discount to WTI and Henry Hub Asset Highlights (1) Estimated reserves based on December 31, 2015 SEC Reserve Report
CONFIDENTIAL WYOMING WATERFLOODS pg. 63 SW BIGHORN BASIN OIL FIELDS WATERFLOOD PILOT WF CANDIDATE WF CANDIDATE Ferguson Ranch Field • Two active injectors • Waterflood unit in place • Opportunity to expand to full field flood Hunt Field • Not unitized • Offset operator must be addressed Sheep Point Field • Not unitized • Phosphoria only Breitburn Properties
CONFIDENTIAL ROCKIES pg. 64 SUMMARY INFORMATION Overview Operated Producing Wells (1) 540 Net Acreage Developed 101,452 3Q '16 Daily Production Undeveloped 8,967 Oil (bopd) 2,771 Total 110,419 Gas (mcfpd) 17,079 NGL (galpd) 1,936 Ownership Total (boepd) 5,664 Avg. W.I. 54.2% Avg. NRI 44.2% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 27.2 0.2 0.4 27.9 49.7% 4.8 - 32.7 45.9% 387.4 81.4 1,003.8 193.0 12/28/2016 Strip Pricing +10% 27.9 0.2 0.4 28.6 49.8% 5.1 - 33.7 46.5% 411.9 85.8 1,157.4 234.4 12/28/2016 Strip Pricing -10% 26.4 0.2 0.3 26.8 49.1% 4.7 - 31.5 45.2% 360.7 77.5 852.1 152.3 Note: Based on October 2016 Business Plan risked reserves. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL SW FLORIDA pg. 65 SUMMARY INFORMATION Overview Operated Producing Wells (1) 17 Net Acreage Developed 33,322 3Q '16 Daily Production Undeveloped 3,694 Oil (bopd) 1,079 Total 37,016 Gas (mcfpd) - NGL (galpd) - Ownership Total (boepd) 1,079 Avg. W.I. 100.0% Avg. NRI 83.4% Estimated Reserves Summary Total Estimated Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 (3) PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 12/28/2016 Strip Pricing (2) 3.7 0.2 - 3.9 100.0% - - 3.9 100.0% 145.6 11.1 198.9 18.8 12/28/2016 Strip Pricing +10% 4.2 0.2 - 4.5 100.0% - - 4.5 100.0% 173.0 11.1 252.7 30.8 12/28/2016 Strip Pricing -10% 3.0 0.2 - 3.2 100.0% - - 3.2 100.0% 113.3 11.1 143.4 7.6 Note: Based on October 2016 Business Plan risked reserves. (1) Excludes injectors and other, as well as shut-in wells. (2) Strip pricing: WTI of $56.35, $56.60, $56.04, $55.86. $55.96 and HH of $3.70, $3.14, $2.87, $2.88, $2.90 for 2017-2021+, respectively. (3) Excludes G&A and District Expense burden.
CONFIDENTIAL G&A AND DISTRICT EXPENSE REDUCTION EFFORTS
CONFIDENTIAL Beginning in November 2014, Breitburn’s senior management team moved quickly to right-size the organization in light of the unprecedented deterioration of commodity prices and market conditions Instituted a hiring freeze on December 9, 2014 Achieved ~40% reduction in total G&A positions (vs. YE’14 levels) through multiple rounds of RIFs • 73 eliminated positions in 2Q’15 – 3Q’15 (2 waves of RIFs) • 53 eliminated positions in 1Q’16 – 2Q’16 (2 waves of RIFs) Achieved ~32% or $11.4 million reduction in non-payroll G&A annual run-rate costs (vs. YE’14 levels) Achieved ~33% or $29.1 million reduction in total G&A annual run- rate costs (vs. YE’14 levels) • Eliminated merit increases from 2015 and 2016 G&A budgets • Initiated an office rent reduction plan to sublease Houston office space • High-graded the team and right-sized the organization in anticipation of sustained lower activity levels and uncertain market conditions (1) Excludes PCEC Management Agreement fee; agreement terminated as of June 30, 2016. G&A annual run-rate costs include STIP and exclude LTIP awards. pg. 67 G&A EXPENSE REDUCTIONS G&A TOTAL POSITIONS # of Positions MMBOE 317 244 191 ( 73 ) ( 126 ) - 6 12 18 24 - 80 160 240 320 4Q 2014 4Q 2015 2Q 2016 G&A Positions Reduction Production 40% Decrease in G&A Positions (vs. YE '14) Focused on Implementing Significant G&A Cost Reductions G&A ANNUAL RUN-RATE COSTS (1) $ in millions $87.2 $70.6 $58.1 ( $16.6 ) ( $29.1 ) $- $25 $50 $75 $100 4Q 2014 4Q 2015 2Q 2016 Run-Rate G&A Costs Reduction 33% Decrease in Run-Rate G&A Costs (vs. YE '14)
CONFIDENTIAL G&A Position Reductions Division 4Q 2014 Positions Net Reductions 4Q 2015 Positions Net Reductions 2Q 2016 Positions Total Net Reductions CEO 19 (6) 13 (4) 9 (10) CAO 98 (23) 75 (13) 62 (36) CFO 129 (12) 117 (20) 97 (32) COO 40 (9) 31 (10) 21 (19) Subtotal 286 (50) 236 (47) 189 (97) G&A Headcount % Change (vs. YE '14) --- (17%) (34%) (34%) Open Positions 31 (23) 8 (6) 2 (29) Total G&A Positions 317 (73) 244 (53) 191 (126) Total G&A Positions % Change (vs. YE '14) --- (23%) (40%) (40%) G&A Cost Reductions Notes 2014 Run-Rate [1] Net Cost Reductions [2] 2015 Run-Rate [3] Net Cost Reductions [2] 2016 Budget Run-Rate [4] Total Cost Reductions [2] G&A Payroll Total [5] 56.1$ (9.7)$ 46.4$ (8.1)$ 38.3$ (17.9)$ G&A Non-Payroll Total 35.8 (7.4) 28.4 (4.0) 24.4 (11.4) G&A OH Recoveries (4.7) 0.5 (4.1) (0.4) (4.5) 0.2 PCEC Management Fee (9.8) (0.1) (9.8) 9.8 - 9.8 Total G&A Expenses (incl. netting of PCEC Mgmt Fee) 77.4$ (16.6)$ 60.8$ (2.7)$ 58.1$ (19.3)$ ( + ) PCEC Management Fee [6] 9.8 0.1 9.8 (9.8) - (9.8) Total G&A Expenses (excl. netting of PCEC Mgmt Fee) 87.2$ (16.6)$ 70.6$ (12.5)$ 58.1$ (29.1)$ Total G&A Expenses % Change (vs. YE '14) --- (19%) (33%) (33%) MBOE Production [7] 20,206 (26) 20,180 (1,930) 18,250 (1,956) G&A $/BOE 4.32$ (0.82)$ 3.50$ (0.32)$ 3.18$ (1.13)$ Total G&A $/BOE % Change (vs. YE '14) --- (19%) (26%) (26%) [1] 2014 G&A run rates primarily derived from Q1 '15. STIP amounts represented at 100% of target [2] Net cost reductions are calculated based on annualized run rate amounts and may materially vary from published f inancials [3] 2015 G&A run rates primarily derived from Q4 '15 . STIP amounts represented at 100% of target [4] 2016 G&A run rates derived from the second half '16 budget. STIP amounts represented at 100% of target [5] Payroll total excludes non-cash employee incentive compensation [6] PCEC Management Agreement fee applied against G&A only; agreement terminated as of June 30, 2016 [7] 2014 production run-rate is estimated utilizing Q1'15 in order to reflect the QRE merger, 2015 production f igure is a full-year actual, and 2016 is a full-year forecast pg. 68 G&A EXPENSE REDUCTIONS ($ millions, unless otherwise stated)
CONFIDENTIAL pg. 69 CURRENT G&A EXPENSE PROFILE Right-sized G&A structure supports an asset base consisting of producing and non-producing oil, NGL and natural gas reserves located across 12 states • Michigan, Indiana, Kentucky, Arkansas, Louisiana, Texas, New Mexico, Wyoming, Colorado, Florida, Alabama, and California Current headcount levels facilitate multifaceted administrative oversight of working interests in ~11,900 oil and gas wells, of which ~8,100 are operated by Breitburn • Monthly revenue distributions issued to over 60,000 individual royalty/working interest owners (~16,000 payments issued per month) • Monthly non-operated revenue reconciliation with ~150 operating partners • Monthly JIB receivable reconciliation with ~2100 non-op partners • Monthly JIB payable reconciliation with ~100 operating partners Land team responsible for over 30,000 leases with over 60,000 separate lessors Reduced G&A departments absorbed operational burden of unique EH&S, regulatory, environmental, tax, and governmental affairs issues and compliance stemming from the diverse nature of the asset base • Company currently manages over 20,600 individual regulatory and EH&S licenses and permits G&A Level Adequate for Complexity & Scope of Operations
CONFIDENTIAL With continued efforts toward driving down administrative costs, management is targeting 2017 G&A costs to be lower than 2016 run-rate Initiatives underway have and will continue to result in run-rate savings, further driving down G&A costs • Reject unfavorable leases - Relocate Houston office from 5HC to Rosetta - Reject Chase Tower lease • Change in internet/phone service providers • Review of potential semi-public entity cost savings related to reduced tax and reporting requirements • Potential to reduce Board of Director fees • Potential to reduce Insurance G&A budget supports the development of the Permian Basin under the current business plan with modest additional hires Management believes G&A profile is appropriate for current market environment and business plan pg. 70 G&A EXPENSE INITIATIVES FOR 2017 Further G&A Reductions & Efficiencies2017 Budget G&A Bridge 2016 Fcst Inflationary Business Plan Run-Rate 2017 ($MM) Run-Rate Growth Hires Savings Budget Payroll 38.3$ 1.1$ 0.6$ -$ 40.0$ Non-Payroll 24.4 0.5 - (2.9) 21.9 OH Recoveries (4.5) - - - (4.5) Total G&A Exp 58.1$ 1.7$ 0.6$ (2.9)$ 57.5$ $58.1 $57.5 $1.7 $0.6 $(2.9) 55.0 57.0 59.0 61.0 ($MM)
CONFIDENTIAL District expenses are operating costs incurred to manage or supervise the company’s operating assets such that wells, leases, or facilities benefit proportionately. In practice, the company’s technical personnel reporting up to, and including, divisional VPs, who are responsible for day-to-day decision-making and supervision of the company’s areas, regions, and divisions are included in District expenses. Achieved ~32% reduction in total District positions (vs. YE’14 levels) through multiple rounds of RIFs • 35 eliminated positions in 2Q’15 – 3Q’15 (2 waves of RIFs) • 29 eliminated positions in 1Q’16 – 2Q’16 (2 waves of RIFs) Achieved ~18% or $1.4 million reduction in non-payroll District annual run-rate costs (vs. YE’14 levels) Achieved ~29% or $11.9 million reduction in total District annual run- rate costs (vs. YE’14 levels) • Eliminated merit increases from 2015 and 2016 District budgets • Initiated an office rent reduction plan to sublease Houston office space • High-graded the team and right-sized the organization in anticipation of sustained lower activity levels and uncertain market conditions pg. 71 DISTRICT EXPENSE REDUCTIONS Detailed Review of District Expenses Accomplished Significant Cost Reductions DISTRICT TOTAL POSITIONS # of Positions MMBOE 201 166 137 ( 35 ) ( 64 ) - 6 12 18 24 - 55 110 165 220 4Q 2014 4Q 2015 2Q 2016 District Positions Reduction Production 32% Decrease in District Positions (vs. YE '14) Note: District annual run-rate costs include STIP and exclude LTIP awards. DISTRICT ANNUAL RUN-RATE COSTS $ in millions $41.6 $34.2 $29.7 ( $7.4 ) ( $11.9 ) $- $15 $30 $45 4Q 2014 4Q 2015 2Q 2016 Run-Rate District Costs Reduction 29% Decrease in Run-Rate District Costs (vs. YE '14)
CONFIDENTIAL District Position Reductions Division 4Q 2014 Positions Net Reductions 4Q 2015 Positions Net Reductions 2Q 2016 Positions Total Net Reductions CEO - - - - - - CAO - - - - - - CFO - - - - - - COO 182 (20) 162 (29) 133 (49) Subtotal 182 (20) 162 (29) 133 (49) District Headcount % Change (vs. YE '14) --- (11%) (27%) (27%) Open Positions 19 (15) 4 - 4 (15) Total District Positions 201 (35) 166 (29) 137 (64) Total District Positions % Change (vs. YE '14) --- (17%) (32%) (32%) District Cost Reductions Notes 2014 Run-Rate [1] Net Cost Reductions [2] 2015 Run-Rate [3] Net Cost Reductions [2] 2016 Budget Run-Rate [4] Total Cost Reductions [2] District Payroll Total [5] 38.2$ (6.5)$ 31.7$ (4.3)$ 27.4$ (10.8)$ District Non-Payroll Total 8.3 (1.2) 7.0 (0.2) 6.8 (1.4) District OH Recoveries 0.3 0.4 0.7 (0.9) (0.2) (0.5) Capitalized Expense (5.2) (0.1) (5.2) 0.9 (4.3) 0.8 Total District Expenses 41.6$ (7.4)$ 34.2$ (4.5)$ 29.7$ (11.9)$ Total District Expenses % Change (vs. YE '14) --- (18%) (29%) (29%) MBOE Production [6] 20,206 (26) 20,180 (1,930) 18,250 (1,956) District $/BOE 2.06$ (0.36)$ 1.70$ (0.07)$ 1.63$ (0.43)$ Total District $/BOE % Change (vs. YE '14) --- (18%) (21%) (21%) [1] 2014 District run rates primarily derived from Q1 '15. STIP amounts represented at 100% of target [2] Net cost reductions are calculated based on annualized run rate amounts and may materially vary from published f inancials [3] 2015 District run rates primarily derived from Q4 '15. STIP amounts represented at 100% of target [4] 2016 District run rates derived from the second half '16 budget. STIP amounts represented at 100% of target [5] Payroll total excludes non-cash employee incentive compensation [6] 2014 production run-rate is estimated utilizing Q1'15 in order to reflect the QRE merger, 2015 production f igure is a full-year actual, and 2016 is a full-year forecast pg. 72 DISTRICT EXPENSE REDUCTIONS ($ millions, unless otherwise stated)
CONFIDENTIAL Current expense reduction initiatives offset the bulk of forecasted increases in 2017 District Expense budget Initiatives underway have resulted in run-rate savings, driving down District Non-Payroll costs • Reject unfavorable leases - Relocate Houston office from 5HC to Rosetta - Reject Chase Tower lease 2017 – 2021 District budgets include planned hires needed for development of the Permian Basin & other assets under the current business plan pg. 73 DISTRICT EXPENSE INITIATIVES FOR 2017 2017 District Budget Initiatives2017 Budget District Bridge 2016 Fcst Inflationary Business Plan Run-Rate 2017 ($MM) Run-Rate Growth Hires Savings Budget Payroll 27.4$ 0.7$ 1.6$ -$ 29.8$ Non-Payroll 6.8 0.2 - (1.2) 5.8 OH & CapEng (4.5) - - - (4.5) Ttl District Exp 29.7$ 0.9$ 1.6$ (1.2)$ 31.0$ $29.7 $31.0 $0.9 $1.6 $(1.2) 26.0 29.0 32.0 35.0 ($MM)
CONFIDENTIAL PRELIMINARY DISCUSSION MATERIALS BREITBURN ENERGY PARTNERS LP DECEMBER 21, 2016 Highly Confidential Subject to FRE 408 Subject to Express Confidentiality Agreement
CONFIDENTIAL None of Breitburn, Lazard Frères & Co. LLC (“Lazard”) and Alvarez & Marsal North America, LLC (“A&M”), and each of their subsidiaries, affiliates, officers, directors, shareholders, employees, consultants, advisors, agents and representatives of the foregoing (collectively, “Representatives”), makes any representation or warranty, express or implied at law or in equity, in connection with any of the information made available either herein or subsequent to this presentation, including, but not limited to, the past, present or future value of the anticipated cash flows, income, costs, expenses, liabilities and profits, if any, of Breitburn. Accordingly, any person, company or interested party shall rely solely upon its own independent examination and assessment of the information in making any investment decision with respect to Breitburn (the “Transaction”), including, but not limited to, a restructuring of Breitburn’s balance sheet, and in no event shall any recipient party make any claim against Breitburn, Lazard, A&M or any of their respective Representatives in respect of, or based upon, the information contained either herein or subsequent to this document. None of Breitburn, Lazard or A&M, or any of their respective Representatives, shall have any liability to any recipient party or its respective Representatives as a result of receiving and/or evaluating any information concerning the Transaction (including, but not limited to, this presentation). This presentation contains forward-looking statements relating to Breitburn’s operations that are based on management’s current expectations, estimates and projections about its operations. Words and phrases such as “expected,” “guidance,” “expansion,” “opportunities,” “target,” “estimated,” “future,” “believe,” “potential,” “will be” and variations of such words and similar expressions are intended to identify such forward-looking statements. These statements are not guarantees of future performance and are subject to certain risks, uncertainties and other factors, some of which are beyond Breitburn’s control and are difficult to predict. These include risks relating to Breitburn’s financial performance and results, availability of sufficient cash flow and other sources of liquidity to execute Breitburn’s business plan, prices and demand for natural gas and oil, increases in operating costs, uncertainties inherent in estimating Breitburn’s reserves and production, Breitburn’s ability to replace reserves and efficiently develop Breitburn’s current reserves, Breitburn’s ability to obtain sufficient quantities of CO2 necessary to carry out Breitburn’s enhanced oil recovery projects, political and regulatory developments relating to taxes, derivatives and Breitburn’s oil and gas operations, and the risk factors set forth under the heading “Risk Factors” incorporated by reference from Breitburn’s Annual Report on Form 10-K filed with the Securities and Exchange Commission, and if applicable, Breitburn’s Quarterly Reports on Form 10-Q and Breitburn’s Current Reports on Form 8-K. Therefore, actual outcomes and results may differ materially from what is expressed or forecasted in such forward- looking statements. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Breitburn undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise. Unpredictable or unknown factors not discussed herein also could have material adverse effects on forward-looking statements. Information in this presentation is dependent upon assumptions with respect to commodity prices, production, development capital, exploration capital, operating expenses, availability and cost of adequate capital and performance as set forth in this presentation. The production, transportation and marketing of oil and gas are subject to disruption due to transportation and processing availability, mechanical failure, human error, inclement weather and numerous other factors. Breitburn’s estimates are based on certain other assumptions, such as well performance, which may vary significantly from those assumed. The recipient hereby acknowledges that none of Breitburn, Lazard, A&M or any of their respective Representatives has any obligation to update any such projections or forecasts. References to “Breitburn,” “BBEP,” or like terms refer to Breitburn Energy Partners LP and its subsidiaries. These materials are confidential and intended solely for informational purposes. These materials are not intended for distribution to, or use by any person or entity in any jurisdiction or country where such distribution or use would be contrary to local law or regulation. This presentation is being made to the recipient on a confidential basis in accordance with the terms of the non-disclosure agreement (“NDA”) entered into between the recipient and Breitburn. This presentation and the information contained herein may only be used by the recipient as provided in the NDA. If you are not the intended recipient of this presentation, please delete and destroy all copies immediately. LEGAL DISCLOSURE pg. 75
CONFIDENTIAL OVERVIEW Agenda Introductions Overview • BBEP Asset Base • Operational Management Organization • Portfolio Modeling – Strategic to Tactical • Cost Control Performance • Capital Investment Plan Divisional Reviews • Division VI – Permian Eastern Midland Basin • Division V – Enhanced Oil Recovery • Division IV –Ark-La-Tex • Division II – Permian Central and Western / California • Division I – Michigan / Wyoming / S. Florida pg. 76
CONFIDENTIAL ATTRACTIVE ASSETS IN 7 PRODUCING AREAS ARK-LA-TEX 2015 Avg. Daily Production 10,022 Boe/d Est. Proved Reserves 46.9 MMboe SOUTHEAST 2015 Avg. Daily Production 5,585 Boe/d Est. Proved Reserves 20.4 MMboe MI/IN/KY 2015 Avg. Daily Production 8,468 Boe/d Total Proved Reserves 51.5 MMboe MID-CONTINENT 2015 Avg. Daily Production 7,710 Boe/d Est. Proved Reserves 32.3 MMboe CALIFORNIA 2015 Avg. Daily Production 4,849 Boe/d Est. Proved Reserves 17.9 MMboe ROCKIES 2015 Avg. Daily Production 6,332 Boe/d Est. Proved Reserves 25.7 MMboe PERMIAN BASIN 2015 Avg. Daily Production 12,322 Boe/d Est. Proved Reserves 44.6 MMboe TOTAL TOTAL EST. PROVED RESERVES: 239.3 Mmboe PROVED RESERVE LIFE: ~12 years PERMIAN BASIN 19% ROCKIES 11% ARK-LA-TEX 20% MI/IN/KY 21% SOUTHEAST 9% CALIFORNIA 7% MID-CONTINENT 13% Estimated Proved Reserves By Area CALIFORNIA ROCKIES MI/IN/KY MID-CONTINENT PERMIAN BASIN ARK-LA-TEX SOUTHEAST Estimated reserves based on December 31, 2015 SEC Reserve Report pg. 77
CONFIDENTIAL EXTENSIVE CAPABILITIES; BROAD AND DEEP ECONOMIC OPPORTUNITY SET Conventional and Unconventional Reservoirs • Shallow gas, natural water drive • Permian shale, tight gas Value via Drill-Bit • Horizontal drilling and completion • Infills, step-outs Secondary and Enhanced Oil Recovery Proficiency • Waterflood design/surveillance/optimization • CO2 flood, nitrogen flood, steam Regional Operational Knowhow • Complex environments (urban L.A., Florida Everglades) • Diverse landowners (Native American, BLM) Extensive IP & Data Access/Application • Seismic, completion/recovery technology • Regulatory, community relationships Proven Operational Efficiency • Cost-focused throughout organization • Supply chain, marketing Ability to Employ Range of Investment Strategies • Acquire and exploit producing properties • Lease and drill Proved Reserves by Region ArkLaTex California Florida MI/IN/KY Mid-Con Permian Rockies 3P Reserves by Category PDP PDNP PUD PROB POS Reserves by Commodity Oil Gas NGL Reserves by Recovery Mechanism Primary-Oil Primary-Gas Waterflood Miscible Flood Estimated reserves based on December 31, 2015 SEC Reserve Report pg. 78
CONFIDENTIAL PORTFOLIO MANAGEMENT • What is Portfolio Management? – A strategic planning process that efficiently models the impact of resource allocation on corporate performance – A methodology to compare the relative attractiveness and trade-offs of alternative investment scenarios • How do we use Portfolio Management? – Quickly look at multiple investment scenarios to hone in on the ultimate project selection – A precursor to the annual budget process (not a substitute) – Utilize a commercial software program by 3esi 2016 2017 2018 2019 2020 2021 Capital ($MM) Capex 1 Capex 2 Capex 3 5 Yr Cum Prod PV10% Max Exposure 5 Yr CF from Ops 2020 Exit Rate Capex 1 Capex 2 Capex 3 5 Yr Cum Prod PV10% Max Exposure 5 Yr CF from Ops 2020 Exit Rate Price A Price B Price Sensitivity to Base Case 2016 2017 2018 2019 2020 2021 Production (MBoepd) Capex 1 Capex 2 Capex 3 pg. 79
CONFIDENTIAL POSSIBLE OPPORTUNITIES • BBEP has a sizeable inventory of identified opportunities • Projects have been matured to varying states of readiness • Portfolio exhibits balance between oil and gas investments pg. 80 PROJECT TYPE DIVISION 1 DIVISION 2 DIVISION 4 DIVISION 5 DIVISION 6 Total CONVERT TO INJECTION 49 21 4 74 DC&E - HORIZONTAL 37 20 96 416 569 DC&E - VERTICAL 267 293 689 57 1,306 EOR EXPANSION 1 67 68 FACILITY PROJECTS 60 26 5 7 98 RECOMPLETION 71 147 289 507 RET RN TO PRODUCTION 23 219 8 250 WATERFLOOD EXPANSION 3 7 3 13 WORKOVER 7 88 258 4 357 OPERATED PROJECTS 494 626 1,559 147 416 3,242 OUTSIDE OPERATED 2 86 48 1,530 1,666 TOTAL # of PROJECTS 496 712 1,607 147 1,946 4,908 Gross Inventory
CONFIDENTIAL As market conditions continually deteriorated over the last two years, the company has maintained disciplined capital spending programs. Budgeting decisions have been influenced by critical factors such as: liquidity conservation, dynamic project economics and preservation of vested corporate interests Oil and gas development capital spending has been reduced ~88% or $516.0 million (vs. YE’14 levels). 2016 spending focused on 4 core principals: • Effectively maintain safe work conditions and environmental compliance • Properly maintain equipment, operational capability • Meet contractual obligations to participate in non-operated projects where non-consent would forfeit valuable ownership interests • Limit discretionary spending to only projects that clearly enhance liquidity, deliver high returns and rapid payouts Limited, but highly effective acquisition activity ~$10 million in 2016 • Market conditions present once-per-decade acquisition opportunities • Targeted bolt-on type assets with “no-cost” attractively economic upside projects (added ~50 locations in 2016) • Completed acreage trades and small asset purchases that leverage economics of keystone Permian Eastern Midland Basin horizontal play CAPITAL INVESTMENT REDUCTIONS Prudent Deployment of Investment Capital Reflective of Market Conditions (1) 2014 combines full-year QRE & BBEP operating results (2) 2016P includes 10 mos. actuals plus 2 mos. projected CAPITAL INVESTMENT - OIL & GAS DEV $ in millions $582.1 $210.6 $66.1 ( $371.5 ) ( $516.0 ) $- $100 $200 $300 $400 $500 $600 2014 (1) 2015 2016P (2) Investment Reduction 88% Decrease in Dev. Capital Costs (vs. YE '14) pg. 81
CONFIDENTIAL Organizational structural changes placed the company’s best managers in a position to have maximum impact. The assets were broken into smaller divisions grouping together those with complimentary technical characteristics. Employees met the challenge of changing emphasis from intense capital project work to efficiency driven cost control. Achieved ~38% or $160.6 million reduction in total LOE (vs. YE’14 levels) while maintaining cost-effective production level • Each of 5 divisions contributed double-digit cost structure improvement • Reductions realized and sustained across all categories of spend Value driven approach to procurement of resources and key services integrated operating teams with specific Supply Chain professionals Evaluated and took action on all levels of spend • Eliminated overtime by adjusting scheduling • Bid all materials and services – often multiple times • Leveraged automation to make more efficient use of time by adopting control room/dispatch concept • Re-routed production to eliminate high cost facilities • Reduced workover frequency by improving system designs and deffering marginally economic repairs LEASE OPERATING EXPENSE REDUCTIONS Tactical Re-alignment of Personnel and Focus Delivered Substantial Improvement in Operational Efficiency (1) QRE 2014 LOE adjusted for capitalization of workover expenses. (+$14.8MM) (2) 2016P includes 10 mos. actuals plus 2 mos. projected LOE ANNUAL RUN-RATE COSTS $ in millions ( $75.3 ) ( $160.6 ) $425.7 $350.4 $265.0 $- $50 $100 $150 $200 $250 $300 $350 $400 $450 2014 (1) 2015 2016P (2) Run-Rate LOE Costs Reduction 38% Decrease in Run-Rate LOE Costs (vs. YE '14) LOE ANNUAL PER BBL COSTS $/BOE 20.64 17.42 14.51 3.23 6.14 $- $5.00 $10.00 $15.00 $20.00 $25.00 2014 (1) 2015 2016P (2) Run-Rate Lifting Cost Reduction 30% Decrease in Run-Rate LOE/BOE Costs (vs. YE '14) pg. 82
CONFIDENTIAL DIVISION VI PERMIAN-EASTERN MIDLAND BASIN
CONFIDENTIAL DIVISION VI OVERVIEW • Spraberry Trend Acreage as of 9/30/16 – Total Acreage (including vertical/wellbore only & HZ rights): 24,670 gross / 21,580 net – Total HZ Acreage: 20,703 gross / 17,502 net • 6.3 MBoe/d of Q1 2016 net production – 401 gross producing wells • 2016 Capex: $3.3 MM – focusing on base production and LOE reduction – building-out horizontal infrastructure projects Asset Highlights Howard Co., TX City of Midland Eastern Shelf Midland Basin Platform Margin TX NM Core Area 85 bopd, peak month daily rate per 1000 ft Primary Area Breitburn leasehold position pg. 84
CONFIDENTIAL U. Spraberry Shale M. Spraberry Shale Clear Fork L. Spraberry Shale Dean Wolfcamp A Wolfcamp B Wolfcamp C Cline Jo Mill Sand U. Spraberry Sands PRIMARY DEVELOPMENT AREA STRATIGRAPHY System Series Formation San Andres, GlorietaGuad. Cisco Canyon Strawn Bend (Atoka) Woodford Kinderhook Mississippian Lime Barnett Shale Leo n ar d ia n W o lf campi an Sp ra b err y Tr en d Ar ea Per m ia n P enn sylvan ia n Mi ss D ev Type Log: Fred Phillips 19 #2 Productive in Howard Co. Lo w er Spra b err y Wol fca m p A GR Res Eff. Poro. Wol fca m p B Primary objectives Additional potential Key Points Stacked low porosity and low permeability pays from Permian age Clear Fork through the Mississippian Limestones Midland Basin operators are exploiting multiple organic rich benches in the Leonardian and Wolfcampian series of the Permian The Leonardian and Wolfcampian section is greater than 2,500’ thick Consists of thick organic rich shales, interbedded with thin sand and carbonate beds Horizontal exploitation targets in the core area include: ─ 300-350’ of proven Lower Spraberry ─ 400-550’ of proven Wolfcamp Other possible targets include: benches in the Spraberry, Cline, Pennsylvanian, and Mississippian pg. 85
CONFIDENTIAL 1) Includes Jo Mill Sand, Middle Spraberry, Wolfcamp D/Cline, and a second row of infill wells in the Wolfcamp A and the Lower Spraberry HORIZONTAL MIDLAND BASIN DEVELOPMENT Lower Spraberry Wolfcamp A Wolfcamp B Add. Potential Benches (1) Total Net Locations Operated 53 53 53 207 365 Non-Operated 55 55 55 251 416 Total Net Locations 108 108 108 458 781 Horizontal Acreage Vertical rights only acreage Operated HZ’s Non-Operated HZ’s pg. 86
CONFIDENTIAL DEVELOPMENT PLAN SUPPORTED BY SUBSURFACE MODEL Key Points Technical data includes: logs, cores and 2D seismic data ─ 590 wells with digital triple- combo data ─ Member of Core Lab’s Midland Basin consortium ─ Cored 800’ of section from Lower Spraberry into the Wolfcamp B in the Beall Unit 18 #1 well ─ In-house petrophysical model tied to core and used to analyze 474 wells ─ 115 linear miles of 2D seismic data 342 sq. mi. of 3D seismic data recently acquired by CGG ─ License in 1Q17 pg. 87
CONFIDENTIAL Key Points Reservoirs are present across acreage ─ Lower Spraberry ─ Wolfcamp A ─ Wolfcamp B Thickness and stratigraphic position of carbonate beds vary, present in other areas that are being developed W-E STRATIGRAPHIC CROSS-SECTION DATUM: TOP OF DEAN FM GR RT PHIE West East Sw GR RT PHIE Sw GR RT PHIE Sw GR RT PHIE Sw GR RT PHIE Sw GR RT PHIE Sw Lower Spraberry Shale Dean Dean Wolfcamp AWolfcamp A Wolfcamp B Wolfcamp B Lower Spraberry Shale Lower Spraberry Sands L. Wolfcamp L. Wolfcamp W E BBEP pg. 88
CONFIDENTIAL INDUSTRY ACTIVITY AROUND BREITBURN ACREAGE Martin Howard Crownquest - Gratis 32-R 1HB Lateral Length: 9,953’ IP/IP30 (Boe/d): 1,343/1,063 Callon– Garrett Unit 37-48 3SH Lateral Length: 6,901’ IP/IP30 (Boe/d): 882/682 Surge - Elrod-Antell Unit A 11-02 4SH Lateral Length: 6,676‘ IP/IP30 (Boe/d): 1,272/780 Oxy - Shields 31051WA Lateral Length: 9,152’ IP/IP 30 (Boe/d): 1,606/1,323 Lower Spraberry (34) Wolfcamp A (80) Wolfcamp B (20) Diamondback - Phillips-Hodnett Unit Lateral Length: 7,430’ IP/IP30 (Boe/d): 1,505/1,375 Diamondback – Reed (LS) Lateral Length: 9,721’ IP/IP30 (Boe/d): 797/NA CrownQuest - Guitar Galusha 1H Lateral Length: 7,147’ Peak 24hr/30 day IP (Boe/d): 1,972/1,402 SM Energy– Falkor 4-8A 5LS Lateral Length: 7,781’ IP/IP30 (Boe/d): 1,111/1,007 Surge - Hamlin-Middleton Unit #3SH Lateral Length: 7,000’ IP/IP30 (Boe/d): 754/789 SM Energy – Ogre 47-2A 1WA Lateral Length: 7,435’ IP/IP30 (Boe/d): 1,033/1,615 SM Energy – Tackleberry (LS, WCA, WCB) Lateral Length: ~7,800’ 3 well pad total: IP/IP30 (Boe/d): 4,860/NA Diamondback - Phillips-Hodnett Unit Lateral Length: 7,093‘ IP/IP30 (Boe/d): 1,490/1,227 Diamondback - Phillips-Hodnett Unit Lateral Length: 7,296’ IP/IP30 (Boe/d): 574/NA EUR: +875 Mboe Surge – Allred Unit B 08-05 8AH Lateral Length: 10,022’ IP/IP30 (Boe/d): 1,501/NA Diamondback – Reed (WCB) Lateral Length: 9,727’ IP/IP30 (Boe/d): 1,799/NA Diamondback – Reed (WCA) Lateral Length: 9,727’ IP/IP30 (Boe/d): 2,150/NA December 19 , 2016 Diamondback – Asro Lateral Length: ~9,700’ Currently fracing Diamondback – Asro Lateral Length: ~9,700’ Currently fracing Diamondback – Asro Lateral Length: ~9,700’ Currently fracing Surge - Wolfe-McCann Unit 10-2SH Lateral Length 6,851’ IP/IP30 (Boe/d): 1,161/783 Callon – Garrett – Snell Unit B 36-25 8AH Lateral Length: NA IP/IP30 (Boe/d): NA/1,228 SM Energy– Ripley 10-2 A-15WA Lateral Length: 6,886’ IP/IP30 (Boe/d): 1,249/983 Callon – Garrett Unit 37-48 4AH Lateral Length: 6,901’ IP/IP30 (Boe/d): 1,005/NA Notes: Key horizontal wells; Lateral lengths are perf-to-perf stimulated lengths. SM Energy Diamondback Surge Operating pg. 89
CONFIDENTIAL SM ENERGY INVESTOR PRESENTATION DECEMBER 7, 2016 pg. 90
CONFIDENTIAL DIAMONDBACK INVESTOR PRESENTATION NOVEMBER 2016 pg. 91
CONFIDENTIAL CALLON PETROLEUM INVESTOR PRESENTATION NOVEMBER 2, 2016 pg. 92
CONFIDENTIAL Surface Casing: 13 3/8", 54.5#, K-55, BT&C Hole Size: 17 1/2" set @ 450' ( cement to surface ) 9 5/8" Stage tool @ 3000' Intermediate Casing: 9 5/8", 40#, HCK-55, BT&C set @ 6,150' , 0 degs (special drift to 8.75") Hole Size: 12 1/4"" to 6,150' MD (6,150' TVD) (base of Clearfork) Production Casing: Start of Build Section Start of Horizontal Section 5½", P-110, 17#, GeoCon BT&C @ ~ 6,566' MD @ 7,901' MD set @ 14,850' MD (cement top to 5,800') Hole Size: 8 3/4" from 6,150' to TD Lower Spraberry Formation TD: 14850' MD 7,487' TVD Build Section: 10° per 100 ft WELLBORE DIAGRAM Key Points Drilling Plan ─ 3-string casing design ─ Closed-loop fresh water mud system ─ 7,250’ lateral 1 Frac Design ─ Water frac ─ Plug and perf method ─ 36 frac stages ─ 1,600 lbs/ft of proppant Single Well Capex M$ Drill 1,914 Complete 3,301 Total D&C 5,215 Pre-drill 200 Facilities 455 Equip / Artificial Lift 384 Total all-in cost 6,254 1) perf-to-perf length Updated cost for longer lateral length pg. 93
CONFIDENTIAL CENTRAL PRODUCTION FACILITY Key Points Design ─ 36 wells per CPF ─ individual well test separators ─ two 18 well systems w/separate - oil processing - electrical transmission ─ shared SWD facilities ─ 450’ by 400’ location size Benefits ─ ~50% reduction in capital costs ─ lower operating costs ─ improved operational efficiency Oil sold via LACT at location Central Production Facility Preliminary Design pg. 94
CONFIDENTIAL FRAC WATER MANAGEMENT PLAN Key Points Frac Pit Water Storage ─ 2,200 Mbbls FW Pipeline Infrastructure ─ 7.4 miles buried 8” line ─ 30 MBWPD transfer capacity Frac Water Sources ─ Fresh water o BBEP:15-20 MBWPD o Non-op: 10-15 MBWPD ─ Other water o ~10 MBWPD Water Requirements ─ 400 Mbbls / frac ─ 20 MBWPD per rig pg. 95
CONFIDENTIAL SALT WATER DISPOSAL SYSTEM Key Points Current Salt Water Disposal System ─ SWD pipeline in place ─ 1 operated SWD well ─ 3 tie-ins to 3rd party systems ─ Capacity of 38 MBWPD 2017 Plans ─ Drill 2 additional SWD wells ─ Capacity increase ~35 MBWPD Lloyd SWD pg. 96
CONFIDENTIAL Key Points Lease operating expenses based on extensive experience operating across the basin Fixed & Variable LOE cost model Produced water disposal is the primary early LOE cost driver Plan to dispose of produced water in operated SWD wells Artificial lift method will be 2 rental ESP’s followed by the installation of 640 pumping unit Gas Lift Evaluation ongoing for future artificial lift option Year ($ / well / month) Artificial Lift 1 42,000 Primary rental ESP, SWD via Pipeline 2 24,000 Secondary ESP (24 months), SWD via Pipeline 3 17,000 C-640 Pumping Unit 4 15,000 C-640 Pumping Unit 5 14,000 C-640 Pumping Unit LEASE OPERATING EXPENSE Example Horizontal Well LOE pg. 97
CONFIDENTIAL HORIZONTAL WELL PROGRAM PRIMARY DEVELOPMENT AREA Key Points Development ─ 3 well pad drilling ─ Six wells across section (880’ spacing) ─ 180 base operated locations (LS, WCA,WCB) ─ 236 upside operated locations (WCA,LS, Jo Mill, MS, Cline) Land ─ Acreage 100% HBP’d ─ 18 drill ready locations ─ Obtaining PSA’s on all wells ─ 93% ave. WI in operated wells Infrastructure ─ SWD pipeline system in-place ─ Building frac fresh water infrastructure ─ Securing frac water sources pg. 98
CONFIDENTIAL DIVISION V ENHANCED OIL RECOVERY
CONFIDENTIAL DIVISION V - EOR OVERVIEW Jay/LEC Unit – 0.30 HCPV Injected N2 flood began in 1981; 101 MMBBL tertiary recover to date Flexible OPEX program Robust PDNP Capital Program (RTP, RTI & CTI) Substantial drilling opportunities Postle Units – Range from 0.69-1.09 HCPV Injected CO2 flood began in 1995; 44 MMBBL tertiary recover to date NEHU – Range from 0.3-0.47 HCPV Injected CO2 flood began in 2014 Libby Ranch – CO2 Source field Supplies necessary CO2 for all PUD development Big Escambia Creek: Pressure Depletion Gas-Cond. 3Q 2016 net production 9.0 MBoe/d from 475 wells 2016 Capex: $22.1 MM Asset Highlights Fields With Potential Future Projects Postle & NEHULibby Ranch Jay/LEC BEC pg. 100
CONFIDENTIAL CO2 DELIVERY INFRASTRUCTURE pg. 101 CO2 Sources ►Libby Ranch (Reliant) ►Bravo Dome (Exxon) ►Team CO2 (Whiting) Midstream Facilities ►Libby Ranch Compression ►Libby Ranch PL Lateral ►Transpetco Pipeline ►NE Hardesty PL Lateral Oil Field ►Postle Complex (5 Units) ►NE Hardesty Unit ►Dry Trails Gas Processing
CONFIDENTIAL * Morrow Sands - Net Isopach Maps – ‘A’, ‘A1’, ‘A2’ ** - New ‘A’ Patterns Include Lease Line and Interior Patterns Flooded ‘A’ / Floodable ‘A’ / Developed (MM STB) (MM STB) (%) HMAU – 59.3 / 59.3 / 100 HMU – 70.9 / 85.3 / 83 PUMU – 44.2 / 44.2 / 100 WHMU – 112.7 / 125.7 / 90 Total – 287.1 / 314.5 / 91 20-Ac ‘A1’ PilotExisting Patterns Future Patterns POSTLE DEVELOPMENT INVENTORY ‘A’ Sand ‘A1’ Sand ‘A2’ Sand Flooded ‘A2’ / Floodable ‘A2’ / Developed (MM STB) (MM STB) (%) WHMU – 2.1 / 53.2 / 4 Flooded ‘A1’ / Floodable ‘A1’ / Developed (MM STB) (MM STB) (%) WHMU – 19.2 / 115.7 / 17 • 16% recovery factor on tertiary (from typecurve), with unswept secondary recovery in A1/A2 as potential upside • 173 active Postle/NEHU patterns and 105 potential 3P patterns, one-half of which are economically viable at current commodity price • Sufficient CO2 available via Libby Ranch source field to complete current project queue at Postle/NEHU pg. 102
CONFIDENTIAL 100 1,000 10,000 100,000 G ro ss Dail y P ro d u cti o n ( B OPD ) Postle/NEHU Field Oil Production POSS PROB PUD PNP PDP Historic POSTLE HISTORICAL & PROJECTED PRODUCTION Start Waterflood Start CO2 flood – PUMU, HMAU, WHMU Start CO2 flood - HMU Unit OOIP, MMSTB Primary + Secondary Actuals and Forecast, MMBO Incremental Tertiary Actuals and Forecast, MMBO HMAU 59.3 20 10.7 HMU 70.9 13 12 PUMU 44.2 24 11.7 WHMU 112.7 35 19 Total 287.1 92 53.4 Start CO2 flood - NEHU pg. 103
CONFIDENTIAL 1) Dimensionless Typecurve closely fits with Unit where majority of PUDs are located CO2 EOR PUD DEVELOPMENT METHODOLOGY 2) Determine by statistics the likely processing rate of PUDs, again by analog 3) Use geologic parameters to determine OOIPs of PUD pattern areas, allowing us to scale the dimensionless curve by the volume of each PUD 4) Schedule out PUD development schedule based on • Profitability – execute most lucrative PUDs first • Field Constraints – Limit development pace based on facility, pipeline, organizational capability, and CO2 availability constraints Other Input Considerations • Similar dimensionless typecurve process performed to model CO2 recycle • NGL processing included in projects yielding 141 bbl/MMcf wet HCGas • Libby Ranch CO2 source field development scheduled to meet supply needs of Postle PDP and PUD development • Base CO2 production shared among units to subsidize CO2 needs of future development, leading to less purchases and more profitability pg. 104
CONFIDENTIAL • In the west end of WHMU, the primary ‘A’ sand doesn’t exist, and the A1/A2 has been developed instead • Variability in tertiary RF% stems from pattern configuration and centrally located injection well PROOF OF CONCEPT – A1/A2 DEVELOPMENT Pattern Tertiary RF% CO2 Start WHMU 216 0.25 02/2001 WHMU 25 0.18 02/2001 WHMU 26 0.06 10/2006 WHMU 299 0.08 01/2007 WHMU 307 0.17 12/2006 WHMU 308 0.06 12/2006 WHMU 403 0.17 08/2006 WHMU 51 0.14 02/2001 WHMU 60 0.09 06/2001 WHMU 82 0.11 06/2001 - 2.0 4.0 6.0 8.0 10.0 12.0 - 100 200 300 400 500 600 700 0 1 -J an -0 0 0 1 -D e c- 0 0 0 1 -N o v- 0 1 0 1 -Oct -0 2 0 1 -S e p -0 3 0 1 -A u g- 0 4 0 1 -J u l- 0 5 0 1 -J u n -0 6 0 1 -M ay -0 7 0 1 -A p r- 0 8 0 1 -M ar -0 9 0 1 -F e b -1 0 0 1 -J an -1 1 0 1 -D e c- 1 1 0 1 -N o v- 1 2 0 1 -Oct -1 3 0 1 -S e p -1 4 0 1 -A u g- 1 5 0 1 -J u l- 1 6 Gas In je ctio n R at e , M M CF D O il R at e , B O P D Oil Rate IGAS pg. 105
CONFIDENTIAL Future Drill Wells (35) JAY FIELD – LOCATION AND INVENTORY Fraction of Pay - High Reservoir Quality 2014-2015 Drill Wells (5) Future Opportunities PNP PUD PRB POS Wells Wells Wells Wells 10 35 16 0 Well Spacing (Prod. + Inj.) Peak Development 100 acres/well Current Active 200 acres/well Future Plan 140 acres/well 3-P View 110 acres/well Immature Miscible Flood N2 Injection only 0.3 Pore Volume Limited N2 Inj. on West & South Flank Oil Volumes OOIP 1,029 MMBO Cum Prod. 466 MMBO Current RF 45% Locator Map pg. 106
CONFIDENTIAL RECOVERY PROFILE BY PATTERN Inactive Active – Cum. D&C 2A1AB 4B • Four of the 9 patterns performed below average • Three Patterns have a rounded-curve suggesting gradual decline in production rate • Pattern 1A • Pattern 1B • Pattern 2A • One of these 4 Patterns has a sharp bend in curve resulting from loss of high rate wells • Pattern 4B 0.00 0.10 0.20 0.30 0.40 0.50 0.60 0.00 0.50 1.00 1.50 2.00 2.50 Oil R eco ve ry Fact o r Cumulative Total Injection % of OOIP Dimensionless Oil Vs. Total Inj % OOIP Pattern 1A Pattern 1B Pattern 2A Pattern 2B Pattern 3A Pattern 3B Pattern 4A Pattern 4B Pattern 5AB Sharp bend in RF curve Rounded RF curve pg. 107
CONFIDENTIAL 25 36 2627282930 31 32 33 34 35 1 10 11 2 21 22 3 25 34 35 36 30 31 12 13 24 39 40 10 11 12 17 18 19 2 20 21 22 23 24 2930 3132 4 40 41 42 43 56 7 8 9 2829 32 33 34 35 36 5N 29W 6N 29W 36-2 36-1 31-5 25-16 26-7 36-5 36-6 36-9 25-13 26-15 35-1 36-3 35-4 31-5ST 36-14 32-2 33-4B 30-4B 1 31-5 29-3 25-3 28-4 31-3 31-8 31-6 29-10 33-5 30-5 32-5 32-3 100,427 32-1 30-3 31-1B 19,078 33-3 32-4 87,898 30-2B 1 1 1 30-13 36-1 37-4 37-1 60,712 37-2 1-1 30-1B 2-3 3-1 2-1 35-4 47,681 35-2B 35-2 34-4B 5,572 35-3 31-3B 1-2 31-2A 31-2 10-1B 10,794 3-2 11,237 2-2 52,451 31-1C 37-5 ST 30-3B 1A 34-4A 5-2 10-4 9-3 5-3 132,486 10-2 8-1 137,056 21-1 6-1 7-4 19-2 3-2 34-2 44,677 7-3 121,219 33-3A 11-1 40-1 40-4B 18-1 39-1 71,106 22-4 19-1 20-2 7-8 22,241 19-9 40-2B 5-10 5-9 6-5 16,293 6-6 5-7 17-3 5-6 41-7 19-8 40-12 41-6 19-7 40-10 9-5A 19-6 7-7 10-6 41-5 36,181 18-4 38-2 5-577,457 18-3 31,216 33-4 108,303 23-5 41-4A 6-2 43-1 10-5 7-6 19-5 41-1 36,098 40-2 16,761 1 24-4 70,727 30-4 26,135 24-1 34-1 21,759 22-3 8,068 40-4A 21-2 28,258 38-1 39-3 17-2 29-2 70,568 41-3 31-1 24,253 24-223-1 12-1 20-3 61,237 22-2 30,473 23-3 13-1 23-2 18-2 62,306 22-1 26,461 5-4 30-2A 24-3 30-1A 41-2 2,47019-4 23-4 10-3 97,597 10-1A 153,448 20-4 9,374 1 40-6 33-2 17-1 34,011 7-1 20-1 84,051 40-11 7-2 59,003 33-1 139,675 9-4 6-4 33-4A 41-7 ST 5-7 ST 1B 1,103 7-9 409 10-7 1 1 1 1 1 36-1B1 1 1 1 1 1 19-3 41-1 10-4H 31-4 1 37-5 41-1H 41-4 5-5A 10-8 19-10 7-10 32-6 31-7 33-3B 32-1 7-10 ST BBEP Jay Field Cum Inj Water MSTB Map FEET 0 3,186 6,372 POSTED WELL DATA Well Number SMACKOVER_RESV_ENG - CUM_WATER_MSTB[NV] (MSTB) CONTOURS SMACKOVER_RESV_ENG - CUM_WATER_MSTB [NV] - Cum water Mstb injected SMACKOVER_RESV_ENGCUM_WATER_MSTBNV.GRD Contour Interval = 5000 mg/l 5 0 0 0 1 0 0 0 0 2 0 0 0 0 3 0 0 0 0 4 0 0 0 0 5 0 0 0 0 6 0 0 0 0 7 0 0 0 0 8 0 0 0 0 9 0 0 0 0 1 0 0 0 0 0 1 1 0 0 0 0 1 2 0 0 0 0 1 3 0 0 0 0 1 4 0 0 0 0 1 5 0 0 0 0 WELL SYMBOLS Abandoned Well Abandoned Injector Dry Hole, With Show of Oil Dry Hole Junked Oil Well Junked Location Only Oil Well Plugged and Abandoned Plugged & Abandoned Oil Well Plugged Injection Plugged Oil Well Producing Shut-in or suspended With Oil Shut-in Oil and Gas Temporarily Abandoned Injector - Active POSS_PRODUCER December 8, 2016 PETRA 12/8/2016 1:22:56 PM 25 36 2627282930 31 32 33 34 35 1 10 11 2 21 22 3 25 34 35 36 30 31 12 13 24 39 40 10 11 12 17 18 19 2 20 21 22 23 24 2930 3132 4 40 41 42 43 56 7 8 9 2829 32 33 34 35 36 5N 29W 6N 29W 36-2 36-1 31-5 25-16 26-7 36-5 36-6 36-9 25-13 26-15 35-1 36-3 35-4 31-5ST 36-14 32-2 33-4B 30-4B 1 31-5 29-3 25-3 28-4 31-3 31-8 31-6 29-10 33-5 30-5 32-5 32-3 29,651 32-1 30-3 31-1B 30,001 33-3 32-4 26,747 30-2B 1 1 1 30-13 36-1 37-4 37-1 16,325 37-2 1-1 30-1B 2-3 3-1 2-1 35-4 12,132 35-2B 35-2 34-4B 311 35-3 31-3B 1-2 31-2A 31-2 10-1B 913 3-2 797 2-2 18,736 31-1C 37-5 ST 30-3B 1A 34-4A 5-2 10-4 9-3 5-3 37,591 10-2 8-1 34,273 21-1 6-1 7-4 19-2 3-2 34-2 7,865 7-3 46,377 33-3A 11-1 40-1 40-4B 18-1 39-1 24,174 22-4 19-1 20-2 7-8 21,472 19-9 40-2B 5-10 5-9 6-5 7,833 6-6 5-7 17-3 5-6 41-7 19-8 40-12 41-6 19-7 40-10 9-5A 19-6 7-7 10-6 41-5 36,945 18-4 38-2 5-527,176 18-3 13,592 33-4 38,272 23-5 41-4A 6-2 43-1 10-5 7-6 19-5 41-1 11,984 40-2 9,825 1 24-4 23,000 30-4 198 24-1 34-1 1,426 22-3 4 40-4A 21-2 527 38-1 39-3 17-2 29-2 23,303 41-3 31-1 135 24-223-1 12-1 20-3 7,487 22-2 540 23-3 13-1 23-2 18-2 11,899 22-1 6,943 5-4 0 30-2A 24-3 30-1A 41-2 019-4 23-4 10-3 34,637 10-1A 47,007 20-4 0 1 40-6 33-2 17-1 2,771 7-1 20-1 30,022 40-11 7-2 1,429 33-1 47,579 9-4 6-4 33-4A 41-7 ST 5-7 ST 1B 0 7-9 17 10-7 1 1 1 1 1 36-1B1 1 1 1 1 1 19-3 41-1 10-4H 31-4 1 37-5 41-1H 41-4 5-5A 10-8 19-10 7-10 32-6 31-7 33-3B 32-1 7-10 ST BBEP Jay Field Cum Inj N2 MMSCF Map FEET 0 3,186 6,372 POSTED WELL DATA Well Number SMACKOVER_RESV_ENG - CUM_N2_MMSCF[NV] (MMSCF) CONTOURS SMACKOVER_RESV_ENG - CUM_N2_MMSCF [NV] - cum N2 injected SMACKOVER_RESV_ENGCUM_N2_MMSCFNV1.GRD Contour Interval = 1000 mg/l 5 0 0 0 6 0 0 0 8 0 0 0 1 0 0 0 0 1 2 0 0 0 1 4 0 0 0 1 6 0 0 0 1 8 0 0 0 2 0 0 0 0 2 2 0 0 0 2 4 0 0 0 2 6 0 0 0 2 8 0 0 0 3 0 0 0 0 3 2 0 0 0 3 4 0 0 0 3 6 0 0 0 3 8 0 0 0 4 0 0 0 0 4 2 0 0 0 4 4 0 0 0 4 6 0 0 0 4 8 0 0 0 WELL SYMBOLS Abandoned Well Abandoned Injector Dry Hole, With Show of Oil Dry Hole Junked Oil Well Junked Location Only Oil Well Plugged and Abandoned Plugged & Abandoned Oil Well Plugged Injection Plugged Oil Well Producing Shut-in or suspended With Oil Shut-in Oil and Gas Temporarily Abandoned Injector - Active POSS_PRODUCER December 8, 2016 PETRA 12/8/2016 1:15:46 PM CUM N2 INJECTION (MMSCF) SCALE: 5 BCF – 48 BCF CUM WATER INJECTION (MSTB) SCALE: 5 MMSTB – 150 MMSTB CUMULATIVE INJECTION pg. 108
CONFIDENTIAL 20% 25% 30% 35% 40% 45% 50% 55% 60% 50 100 150 200 250 300 350 400 Pre-Dev RF Total Well Spacing (Acres/Well.) Jay/LEC Unit 2016 (Pre-Development) RESERVOIR QUALITY & RECOVERY FACTOR 1AB 2A 2B 3A 3B 4A 4B 5AB 21,627 10,141 17,502 35,584 58,358 Recovered Remaining Recovered Remaining Recovered Remaining Recovered Remaining Recovered Remaining Pattern Recovery Efficiency Characterization 3A/4A High well spacing & high cum. injection vol. 2B Thin pay & better vertical sweep efficiency 5AB Probable OOIP through delineation 2A/3B Moderate well spacing & moderate cum. Inj. vol. 1AB/4B Poor well spacing & marginal cum. Inj. vol. 2B 2B 1AB/4B 1AB/4B 3A/4A 3A/4A 5AB 5AB 2A/3B 2A/3B *Vol. in MBO *Assumed 60% RF pg. 109
CONFIDENTIAL 100 1,000 10,000 100,000 1,000,000 G ro ss D ai ly P ro d u ctio n ( B o p d ) Jay Field Oil Production POSS PROB PUD PNP PDP JAY HISTORICAL & PROJECTED PRODUCTION Unit OOIP, MMSTB Primary + Secondary Actuals and Forecast, MMBO Incremental Tertiary Actuals and Forecast, MMBO Jay/LEC 1029 417 116 Start Waterflood Start N2 WAG Reduced Staff & Maintenance Initiate Facility Redesign pg. 110
CONFIDENTIAL DIVISION IV ARK-LA-TEX
CONFIDENTIAL DIVISION IV OVERVIEW 116K gross, 73K net acres 2,024 Gross Prod wells (Year-end NSAI) 2016 Forecasted Net Production: 10,814 BOED or 9% above Budget 2016 Forecasted LOE: 39.7 MM$ or 39% below Budget 120 wells available for immediate reactivation with higher commodity prices yielding additional 200 BOPD Asset Mix: Low-decline oil and rich gas condensate fields Primary Producing horizons: Cotton Valley, Woodbine, Travis Peak, Pettit, Haynesville sands & Smackover 2016 Unit LOE: $10.42/BOE vs 2015 Unit LOE: $20.67/BOE Successful Overton Cotton Valley horizontal drilling JV Numerous Infill drilling, deepening and high ROR workover/RC opportunities Expanding acreage position in High Liquid Hz Cotton Valley Capital Plan 2016: $20 MM Asset Highlights Blocker/Oakhill/Carthage Major Field Areas Gladewater & ETOF Overton Dorcheat Shongaloo Homer Neches pg. 112 * 2016 Estimates from 10 + 2 Forecast
CONFIDENTIAL ARK-LA-TEX LOE Reduced total LOE by 52% Q1 2016 vs Q1 2015 Reduced Workover Activity Vendor Price Reductions Shut in Uneconomic Wells Cost Saving projects (Overton SWD) Grew Production by 12% Q1 2016 vs Q1 2015 Overton Program Reduced Unit LOE by $13.18/BOE (58%) Source: LOS Accounting Month Actuals, Excludes ETSWD Variance % Variance Time Period Q1 2015 Q2 2015 Q3 2015 Q4 2015 Q1 2016 Q1'16 vs. Q1'15 Q1'16 vs. Q1'16 LOE (MM$) 20.4 17.3 15.6 12.2 9.7 -10.7 -52% Production (MBOE) 891 847 897 965 1000 109 12% Unit LOE ($/BOE) 22.91 20.41 17.43 12.64 9.74 -13.17 -58% pg. 113
CONFIDENTIAL AMI G R E E N B A Y 1 6 H E CH A RD 9 H H A R M O N -C A M E R O N 1 H C A M E R O N -H A R M O N 1 H G R IM E S 2 H D A V ID W IL S O N 1 1 H M C E LR O Y -S W A NN 2 H M C E LR O Y -S W A NN -M O O R E 2 H M C E LR O Y -S W A NN -M O O R E 1 H E CH A RD 7 H N E O 4 H W G U2 -C -L 1 H M UR R A Y -P O ND -G R A Y 2 H M C E LR O Y "A "-W IL K IN S O N 1 H M C E LR O Y "A "-M UR R A Y 1 H M A L D O N A D O -M UR R A Y 1 H P O ND -G R A Y 1 H R E A G A N -B L A C K S T O N E -W IL K IN S O N 2 H P O ND 1 H FEET 0 2,747 PETRA 12/1/2016 10:15:43 AM OVERTON OVERVIEW Overton Cotton Valley Taylor Activity Map Drilled Inventory Overview • Acreage: Approximately 10,000 gross acres, including ~3,000 acres acquired from Windsor in 2015 • BBEP 2016 Net Production: 4,486 BOED (28% Liquids) • Produces from Cotton Valley, Travis Peak and Pettit • Horizontal Target: Lower Cotton Valley Taylor Sands • Depth: 11,000 – 12,000’ • BBEP owns 100% WI & 75%+ NRI on Vertical wells. • Executed 50/50 JV with Tanos Exploration in 2014 to Horizontally develop the Lower Cotton Valley Taylor Sands – Tanos is a Low Cost Driller with Cotton Valley Expertise – Tanos D&C’s the wells – BBEP Takes over operations after wells are completed • JV has D&C’d 16 Horizontal wells through Q1 2016 • Drill 9 & Complete 6 wells : $22 MM • SWD System Upgrade: $840K • Tubing Installations: $500K • Facilities Maintenance: $412K • Total 2016 Capital Program: $23.75MM 2016 Plan East Texas Gas Region BBEP Windsor Newly Acq. pg. 114
CONFIDENTIAL Previous Overton Operators Targeted Taylor 4 BBEP’s Southern Acreage has limited Taylor 4 but thicker Taylor 3 BBEP Southern Overton wells Typically land in Taylor 3 Micro-seismic surveys and well performance indicate fracs are contacting all intervals in Southern Overton Potential for additional Taylor 3 Target Bolt-On Acquisitions Taylor 3 Taylor 4 OVERTON COTTON VALLEY TARGET INTERVAL pg. 115
CONFIDENTIAL OVERTON COTTON VALLEY PERFORMANCE Improved Condensate Yields on Southern acreage Initial Yields Exceeding 50 BBL/MMCF on some wells Significantly enhances economics May 2014 Gross Production was 4.7 MMcf/d & 37 BCPD Jan 2016 Gross Production exceeded 58 MMcf/d and 1500 BCPD Gross Production/PDP Forecast 2015: 2-Rig Program 2016: 1-Rig Program End of 2016 Program 2017: 1-Rig Program 2015: 1-Rig Program pg. 116
CONFIDENTIAL Development Pace o 2017: Prove Concept • D&C 2 Wells and monitor production o 2018-2021: Continuous Rigline • 8 Wells/Rig/Year HOT LINK - HORIZONTAL COTTON VALLEY Project Development Profile # of Locations Capex ($M) Net EUR (MBOE) Development Cost ($/BOE) 2017 D&C Plan 2 $10,878 1,902 5.72 2017 Land and Facilities - $4,000 - - Total Project Development 30 $175,804 28,400 6.19 Chasing “Look Alike” Development Opportunities o Captured 18+ locations to-date o Potential for 40+ locations o Land intensive o Low entry cost o Lateral length = 6,000’ o Similar well performance potential to Overton pg. 117
CONFIDENTIAL EAST TEXAS OIL FIELD OVERVIEW Discovered in 1930 Woodbine Sands at ~ 3500’ Original Oil in Place > 7 billion bbls Cumulative Production > 5.5 billion barrels Shallow base decline Low-cost field SWD gathering and reinjection system (ETSWD) Hundreds of low cost/low risk uplift opportunities (Deepening's, RTPs, ESP’s) • Current 2016 Plan: $2,120M 20 ESP Uplift Projects : $977M P&As: $293M Facilities: $850M Uneconomic wells were shut-in during 2015 and early 2016 Recently began returning these wells to production as economics allow 2016 Plan Overview pg. 118
CONFIDENTIAL EAST TEXAS OIL FIELD OPPORTUNITIES Modest development capital program maintains stable production rate 997 ESP Installations and RTP Uplift Projects 50 Deepenings and Recompletions Future Opportunities (2017 and Beyond) pg. 119
CONFIDENTIAL SHONGALOO LOWER HAYNESVILLE INFILL POTENTIAL Haynesville Sands Type Log • Gross/Net Acreage: 8525/6575 acres – Located on Louisiana/Arkansas State Line • WI/NRI: 88/68% • Q1 2016 Net Production: 746 BOED (33% Liquids) • Produces Primarily from the Haynesville Sand • Current spacing >70 ac, no recent D&C activity • Lower Perm Sands – Required Massive Hydraulic Fractures in the 1990’s • Potential for 50 Infill Locations using current completion practices • Gross D&C Cost: $2.5 MM • Unrisked EUR/Well: 3.3 BCF & 57 MBO Overview Shongaloo Upside – 30 Ac Infill 28 MMBOE+ Reserve Potential pg. 120
CONFIDENTIAL DIVISION II CALIFORNIA, W. PERMIAN
CONFIDENTIAL CALIFORNIA • Concentrated in large oil fields in the Los Angeles Basin and San Joaquin Valley – Company has long history in region with unique operational capabilities – Mature fields (some producing over 100 years) with low risk development opportunities – 2.5 billion Bbl OOIP, 1.5 billion Bbl remaining • 4,300 BOEPD Q1 2016 net production – 705 active wells: 517 Producers, 188 Injectors • 2016 capex: $ 8.4 MM – Facilities Upgrades & Capacity Optimization - Santa Fe Springs – Recompletions, artificial lift upgrades and injector profile modification projects in SFS, E. Coyote, and Sawtelle Fields Asset Highlights pg. 122
CONFIDENTIAL Highlights SANTA FE SPRINGS OVERVIEW • Field discovered in 1919; 2.0 BBbl OOIP • Peak production in 1920’s was 345,000 Bo/d • Cum oil production 640 MMBo (32%) • BBEP purchased from Texaco in 1999 for <$10mm; 1,400 Bo/d and 5.8 mmbo Reserves • 100% operated with 100% WI (~94% NRI) in the unit • 141 producers and 79 injectors; 3,500’- 9,100’ • BBEP acreage of 617 ac. current well spacing of 3-10 acres depending on zone • Waterflooding was implemented in the 1970’s, and is now conducted in the Bell, Meyer, Buckbee, Nordstrom, Clark- Hathaway and USF formations Metric Statistic Current net Production (100% oil) 2,300 Boe/d Proved Reserves (100% oil)(1) 8.3 MMBoe % PDP 71% Key Operating Statistics (1) 1P Reserves based on YE 2015 Reserve Report at SEC prices pg. 123
CONFIDENTIAL SANTA FE SPRINGS FIELD PRODUCTION HISTORY Foix,Bell, Meyer Nordstrom,Buckbee,Clark-Hathaway,O’Connell Santa Fe, Bell100 Unitization Waterflood Meyer, Clark-Hathaway (1972) BBEP Purchased Field (1999) pg. 124
CONFIDENTIAL SANTA FE SPRINGS PRODUCTIVE INTERVAL(S) • Productive interval consists of 6000’ of massive channelized fan deposits and interbedded sand/shale sequences Upper M io ce n e P li o ce n e A B MEYER NORDSTROM O’CONNELL BELL HATHAWAY SANTA FE BUCKBEE - 10,000 - 2,000 - 8,000 - 6,000 - 4,000 Reservoir Characteristics Depths 3,500 – 9,100 ft Initial Pressure 1,500 – 4,000 psi Porosity 15 – 25 % Permeability 16 – 820 md Viscosity 0.3 – 3.8 cp Gravity 35 API 6 ,000 Fee t Rese rvoir Colu m n pg. 125
CONFIDENTIAL FIELD DEVELOPMENT PLAN • Upgrade current Production Handling facilities to maximize throughput and reliability • Optimize well performance through surveillance, pumping diagnostics and lift optimization • Recomplete idle/underperforming wells targeting stratigraphically isolated incremental reserves • Prepare groundwork to enable construction of additional 100,000 Bbl capacity facility in 400 Block (AQMD Permits received) 2016 Capital $2.7 MM Rate Generating Projects including 8 high-graded recompletions, 3 artificial lift optimization projects and Block 000 RTP $1.3 MM Fluid Throughput capacity increase including injector repairs, CTIs, facilities modifications $2.2 MM Mandatory capital including compliance upgrades, leak risk mitigation, LOE reduction Capex pg. 126
CONFIDENTIAL SFS ADDITIONAL DRILLING OPPORTUNITIES HATHAWAY 200 & NORDSTROM EXAMPLE Hathaway 200 (Green structural high) (Red Circles are other potential drill locations) Hathaway 200 Nordstrom Drilling and Completion ($M) 2,100 150 Risked 30 Day IP (BOPD) 81 63 Volumetric Reserve Potential 860 MBO Proposed BH TVD 8500’ (LSF 200) Fee Tracts • Secondary migration of mobile oil into structurally advantaged reservoir position • Exploitation of more sparsely developed west flank • Numerous stacked pay horizons through 6,000’ of productive stratigraphy pg. 127
CONFIDENTIAL Belridge BELRIDGE Key UpsideDaily Production (Mboe/d) Asset Highlights • Current Diatomite Gross Production: 800 BOPD, 800 Mcf/d, 16500 BWPD • 114 Active Diatomite Production Wells, 79 Active Water Injection Completions • 320 Acre Lease (100% BBEP WI, 83% Net) Operated by BBEP • 26 Re-Fracs of Existing Wells • Additional Diatomite Drilling Potential with 56 Locations Identified (5/8 acre spacing) • Optimization of Diatomite Water Support via Injection Profile Modification • Tulare behind pipe potential (farm-in opportunity) pg. 128
CONFIDENTIAL BELRIDGE PRODUCER RE-FRAC POTENTIAL D-E D-A D-B D-C D-D D-F D-G D-G1 D-H C-8C Spud 5/15/2013 By-passed Pay Re-Frac Reserves and Economics Cost: $175,000 per well 20 MBO Gross Reserves per well pg. 129
CONFIDENTIAL Belridge Diatomite Oil Isopach Current Spacing Remaining Locations BELRIDGE DRILLING POTENTIAL 0 20 40 60 80 100 120 140 160 180 200 1 6 3 1 2 5 1 8 7 2 4 9 3 1 1 3 7 3 4 3 5 4 9 7 5 5 9 6 2 1 6 8 3 7 4 5 8 0 7 8 6 9 9 3 1 9 9 3 1 0 5 5 1 1 1 7 Type Curve Rate Profile G ro ss B OP D Days Post Initial Production Gross Reserves 45 MBO Average 51 MBO Mean P90/P10 = 4.4 Per well Reserves and Economics $650,000 Drill and Complete 85 BOPD Initial Rate 45 MBO Gross Reserves Inventory: 56 Locations pg. 130
CONFIDENTIAL 0 20000 40000 60000 80000 100000 120000 140000 160000 180000 200000 1 3 5 7 9 11 13 15 17 19 21 Anaheim 2 and 3 Upside EAST COYOTE Sawtelle Three BBEP Wells Remain to Complete Downhole Pump Conversions Eliminating Kobe Hydraulic Pumps with Significant LOE Savings Resulting 2015 2016 $/Month, BBEP Historic Well Service Expense LA BASIN FIELDS CAPITAL OPPORTUNITIES A2/A3 injection optimization A2/A3 Recompletions Artificial Lift Upgrades LOE Reduction Projects pg. 131
CONFIDENTIAL W PERMIAN • 98,951 Gross, 63,872 net acres across Permian Basin as of 9/30/16 • Mature waterflood properties including E. Fuhrman, N. Cowden, Howard Glasscock, and Turner Gregory Fields and OBO interests in Wasson, Westbrook, and Vacuum • Prolific gas properties in the Pegasus, Waha, Coyanosa, and Block 16 Fields held within a high WI JV with XTO • Vertical Spraberry Trend Area production at Garden City and Coahoma Fields with infill potential and HZ upside • ABO/Drinkard/Blinebry production at M State lease in NM with additional locations and further delineation • 4,900 BOEPD Q1 2016 net production • 30% net production outside operated • 1,042 active Operated wells • 747 producers and 295 injectors • 2016 Capex $5.2 MM • Development drilling at M State lease Asset Highlights pg. 132
CONFIDENTIAL M STATE LEASE – LEA COUNTY, NEW MEXICO Key Points: • 3,000 acre JV with XTO in Lea Co. NM • 180 continuous development • Next spud date 11/1/2016 • Historically Blinebry, Drinkard, Tubb • Additional pay opportunities to exploit Leasehold Map Acreage Position Field Production pg. 133
CONFIDENTIAL M STATE 18 DRILLING RESULTS • MSE technology applied to improve drilling efficiency, with great results • Cut 8 days or 40% off previous drilling performance • Results in better than 30% reduction in capital cost that leverages each additional location • Process and technology transfers readily to companies varied operating areas. M State 18 Days vs. Depth Drilling Summary 0 1000 2000 3000 4000 5000 6000 7000 8000 9000 10000 11000 0 5 10 15 20 25 M eas u re d D e p th , F ee t Days BREITBURN DRILLING PERFORMANCE Depth vs. Days Curve M State #18 Actual M State #19 Actual M Fee 21-1 Actual M State #1 M State #15 M State #16 pg. 134
CONFIDENTIAL EAST_FUHRMAN – GLORIETTA WATERFLOOD EXPANSION Phase 1A Phase 1B • Phase 1A – $3.3 MM – (2017) • 2 years to peak rate • 2 Injectors • 4 Recompletions/Workovers • Phase 1B – $11.6 MM • Assumes completion of Phase 1A • 2 years to peak rate • 5 Producers, • 4 Injectors • 4 Recompletions/Workovers • Reserves • Phase 1 – 1.2 MMBOE • Phase 2 Upside pg. 135
CONFIDENTIAL DIVISION I
CONFIDENTIAL MICHIGAN OVERVIEW • Breitburn is the largest gas producer in Michigan and one of the top producers in the Antrim Shale as of 9/30/16 – Other Michigan reservoirs include: Praire du Chien, Richfield, Detroit River Zone III, and Niagaran pinnacle reefs – New Albany shale (IN/KY) • Acreage: 554,205 (gross) / 305,665 (net) as of 9/30/16 • Interests in 3,752 productive wells (60% operated) • 22% of total estimated proved reserves (1) – 91% gas / 8% oil / 1% NGLs • MichCon city-gate pricing; generally trades at a premium to Henry Hub Asset Highlights (1) Estimated reserves based on December 31, 2015 SEC Reserve Report pg. 137
CONFIDENTIAL ROCKIES OVERVIEW • Key basins include – Evanston and Green River Basins in southwestern Wyoming (primarily natural gas) – Big Horn and Wind River basins in central Wyoming (primarily oil) • Acreage: 207,778 (gross) / 112,865 (net) as of 9/30/16 • Interests in 970 productive wells (67% operated) • 11% of total estimated proved reserves (1) – 55% oil / 45% gas • Medium / heavy gravity crude and high BTU gas; generally trade at a discount to WTI and Henry Hub Asset Highlights (1) Estimated reserves based on December 31, 2015 SEC Reserve Report pg. 138
CONFIDENTIAL WYOMING WATERFLOODS SW BIGHORN BASIN OIL FIELDS WATERFLOOD PILOT WF CANDIDATE WF CANDIDATE Ferguson Ranch Field • Two active injectors • Waterflood unit in place • Opportunity to expand to full field flood Hunt Field • Not unitized • Offset operator must be addressed Sheep Point Field • Not unitized • Phosphoria only Breitburn Properties pg. 139
CONFIDENTIAL SUPPLEMENTAL MATERIALS PROVIDED SEPARATELY
Project: Belridge Diatomite Target: Opal 'A' Diatomite Division: 1 Type: Drilling ‐ Vertical COO/S: 100% Vital Statistics Identified Inventory: 56 WI: 100.00 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 10 NRI: 83.00 % BPO Gross CAPEX/Well: 650 $M % APO Gross CAPEX/Land‐Facility: 0 $M* * For project economic cases Type Curve Parameters Primary Phase: Oil EUR: 55.4 MBOE Initial Rate: 85 BOPD or MCFD Net Rsv 46.2 MBOE Dei: 80 %/yr % Oil 86.2 % Hyp Exponent: 3.00 % Gas 13.8 % Method: Secant Determinal: 5 %/yr Margin Projection Basis: GOR/Yield: 0.96 MCF/B or B/MCF Payout: 2.49 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 50 100 150 200 0 10 20 30 40 50 60 0 12 24 36 48 60 72 84 96 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(400) $(200) $‐ $200 $400 $600 $800 $1,000 $1,200 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M Poly. (ROR, %) $1.15 $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 1
Project: ETOF Deepening Target: Woodbine Division: 4 Type: Drill ‐ Deepen COO/S: Vital Statistics Identified Inventory (OP/OBO): 60 WI: 100.00 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 10 NRI: 87.50 % BPO Gross CAPEX/Well: 125 $M % APO Gross CAPEX/Facility: 0 $M* * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 10.8 MBOE Initial Rate: 19 BOPD or MCFD Net Rsv 8.9 MBOE Dei: 70.0 %/yr % Oil 96.3 % Hyp Exponent: 1.47 % Gas 0.5 % Method: Secant Determinal: 8.0 %/yr Margin Projection Basis GOR/Yield: 600 MCF/B or B/MMCF Payout: 1.25 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 20 40 60 80 100 120 140 160 180 200 0 2 4 6 8 10 12 14 16 18 20 0 12 24 36 48 60 72 84 96 108 120 W tr, G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $(50) $‐ $50 $100 $150 $200 $250 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 2
Project: ETOF RTP Target: Woodbine Division: 4 Type: Recomplete ‐ Return to Production COO/S: Vital Statistics Identified Inventory (OP/OBO): 150 WI: 100.00 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 30 NRI: 87.50 % BPO Gross CAPEX/Well: 70 $M % APO Gross CAPEX/Facility: 0 $M* * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 14.8 MBOE Initial Rate: 4 BOPD or MCFD Net Rsv 12.2 MBOE Dei: 5.0 %/yr % Oil 96.3 % Hyp Exponent: 0.00 % Gas 0.5 % Method: Exp Determinal: 5.0 %/yr Margin Projection Basis GOR/Yield: 600 MCF/B or B/MMCF Payout: 2.81 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 0 1 1 2 2 3 3 4 4 0 12 24 36 48 60 72 84 96 108 120 G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(50) $‐ $50 $100 $150 $200 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 3
Project: Jay Vertical (No Facility Req.) Target: Smackover Division: 5 Type: Drilling ‐ Vertical COO/S: Vital Statistics Identified Inventory (OP/OBO): 12 WI: 93.16 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 7 NRI: 76.31 % BPO Gross CAPEX/Well: 4,135 $M % APO Gross CAPEX/Facility/CO2: 0 $M* * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 636.6 MBOE Initial (Peak) Rate: 160 BOPD or MCFD Net Rsv 535.5 MBOE Dei: 9.0 %/yr % Oil 90.7 % Hyp Exponent: 0.70 % Gas 0.0 % Method: Sec Determinal: 4.0 %/yr Margin Projection Basis GOR/Yield: 0 MCF/B or B/MMCF Payout: 3.79 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 500 1,000 1,500 2,000 2,500 3,000 3,500 0 20 40 60 80 100 120 140 160 180 0 12 24 36 48 60 72 84 96 108 120 W tr, G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $‐ $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 4
Project: Jay Vertical (Facility Req.) Target: Smackover Division: 5 Type: Drilling ‐ Vertical COO/S: Vital Statistics Identified Inventory (OP/OBO): 23 WI: 93.16 % BPO Pot. Unidentified Inventory: 15 % APO Max Projects per Year: 7 NRI: 76.31 % BPO Gross CAPEX/Well: 4,135 $M % APO Gross CAPEX/Facility/CO2: 1,550 $M* * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 636.6 MBOE Initial (Peak) Rate: 160 BOPD or MCFD Net Rsv 535.5 MBOE Dei: 9.0 %/yr % Oil 90.7 % Hyp Exponent: 0.70 % Gas 0.0 % Method: Sec Determinal: 4.0 %/yr Margin Projection Basis GOR/Yield: 0 MCF/B or B/MMCF Payout: 3.79 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 500 1,000 1,500 2,000 2,500 3,000 3,500 0 20 40 60 80 100 120 140 160 180 0 12 24 36 48 60 72 84 96 108 120 W tr, G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $‐ $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 5
Project: MI Antrim (Type Curve is 10 Well Package) Target: Antrim (Lachine / Norwood) Division: 1 Type: Drilling ‐ Vertical COO/S: Vital Statistics Identified Inventory (OP/OBO): 36 WI: 100.00 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 6 NRI: 87.50 % BPO Gross CAPEX/Well: 2,100 $M % APO Gross CAPEX/Facility: 0 $M* * Allocated per well Type Curve Parameters Primary Phase: Gas EUR: 493.1 MBOE Initial Rate: 408 BOPD or MCFD Net Rsv 431.4 MBOE Dei: 5.0 %/yr % Oil 0.0 % Hyp Exponent: 0.00 % Gas 100.0 % Method: Exp Determinal: 5.0 %/yr Margin Projection Basis GOR/Yield: 0.0 MCF/B or B/MMCF Payout: 9.16 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 100 200 300 400 500 600 0 0 0 0 0 1 1 1 1 1 1 0 12 24 36 48 60 72 84 96 108 120 W tr, G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $(1,000) $(800) $(600) $(400) $(200) $‐ $200 $400 $600 $800 $1,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 6
Project: MI Collingwood‐Utica Target: Collingwood / Utica Division: 1 Type: Drilling ‐ Horizontal COO/S: Vital Statistics Identified Inventory (OP/OBO): 141 WI: 94.73 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 25 NRI: 82.12 % BPO Gross CAPEX/Well: 5,610 $M % APO Gross CAPEX/Facility: 0 $M* * Allocated per well Type Curve Parameters Primary Phase: Gas EUR: 454.0 MBOE Initial Rate: 5,393 BOPD or MCFD Net Rsv 414.1 MBOE Dei: 81.0 %/yr % Oil 0.0 % Hyp Exponent: 1.40 % Gas 90.0 % Method: Secant Determinal: 8.0 %/yr Margin Projection Basis GOR/Yield: 6.0 MCF/B or B/MMCF Payout: 11.29 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 4,500 5,000 0 0 0 0 0 1 1 1 1 1 1 0 12 24 36 48 60 72 84 96 108 120 W tr, G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $(2,000) $(1,500) $(1,000) $(500) $‐ $500 $1,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 7
Project: M State Abo/Drinkard Target: Abo/Drinkard/Blinebry Division: 2 Type: Drilling ‐ Vertical Vital Statistics Identified Inventory: 23 WI: 100.00 % BPO Pot. Unidentified Inventory: 0 65.00 % APO Max Projects per Year: 10 NRI: 75.00 % BPO Gross CAPEX/Well: 1,900 $M 56.88 % APO Gross CAPEX/Land‐Facility: 0 $M* * For project economic cases Type Curve Parameters Primary Phase: Oil EUR: 263.1 MBOE Initial Rate: 131 BOPD or MCFD Net Rsv 232.6 MBOE Dei: 62 %/yr % Oil 39.6 % Hyp Exponent: 1.80 % Gas 30.8 % Method: Secant Determinal: 7 %/yr Margin Projection Basis: GOR/Yield: 4.67 MCF/B or B/MCF Payout: 2.27 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 60 120 180 240 300 360 420 480 540 600 0 20 40 60 80 100 120 140 160 180 200 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(200) $200 $600 $1,000 $1,400 $1,800 $2,200 $2,600 $3,000 0% 10% 20% 30% 40% 50% 60% 70% 80% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 ProjectDataSheet_MStateVert_AboDrinkard_BP30 Subject to Express Confidentiality Agreements 8
Project: Permian‐EMB Jo Mill Hz (8,400') Target: Jo Mill (Spby) Division: 6 Type: Drilling ‐ Horizontal COO/S: 38% Vital Statistics Identified Inventory (OP/OBO): 50/183 WI: 94.94 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 16 NRI: 72.26 % BPO Gross CAPEX/Well: 6,223 $M % APO Gross CAPEX/Facility: 0 $M* OBO: 20/15% * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 864.4 MMBOE Initial Rate: 622 BOPD or MCFD Net Rsv 669.6 MMBOE Dei: 64.0 %/yr % Oil 81.7 % Hyp Exponent: 1.60 % Gas 7.5 % Method: Secant Determinal: 6 %/yr Margin Projection Basis GOR/Yield: 0.85 / 155 MCF/B or B/MCF Payout: 2.65 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 100 200 300 400 500 600 0 100 200 300 400 500 600 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(1,000) $‐ $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 0% 10% 20% 30% 40% 50% 60% $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $70 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02$1.15 Subject to Express Confidentiality Agreements 9
Project: Permian‐EMB Lwr Spraberry Hz (8,400')‐ NSAI Target: Lwr Spraberry Division: 6 Type: Drilling ‐ Horizontal COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 60/202 WI: 94.94 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 16 NRI: 72.26 % BPO Gross CAPEX/Well: 6,604 $M % APO Gross CAPEX/Facility: 0 $M* OBO: 20/15% * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 546.3 MMBOE Initial Rate: 921 BO/D Net Rsv 428.9 MMBOE Dei: 79.1 %/yr % Oil 78.3 % Hyp Exponent: 1.30 % Gas 8.9 % Method: Secant Determinal: 6.0 %/yr Margin Projection Basis GOR/Yield: 1.05 / 155 MCF/B or B/MCF Payout: 3.47 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 100 200 300 400 500 600 700 800 900 0 100 200 300 400 500 600 700 800 900 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(2,000) $(1,000) $‐ $1,000 $2,000 $3,000 $4,000 0% 5% 10% 15% 20% 25% 30% 35% 40% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $70 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 10
Project: Permian‐EMB Lwr Spraberry Hz (8,400') Target: Lwr Spraberry Division: 6 Type: Drilling ‐ Horizontal COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 60/202 WI: 94.94 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 16 NRI: 72.26 % BPO Gross CAPEX/Well: 6,223 $M % APO Gross CAPEX/Facility: 306 $M* OBO: 20/15% * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 882.4 MMBOE Initial Rate: 935 BOPD or MCFD Net Rsv 683.5 MMBOE Dei: 75.0 %/yr % Oil 81.7 % Hyp Exponent: 1.60 % Gas 7.5 % Method: Secant Determinal: 6.0 %/yr Margin Projection Basis GOR/Yield: 0.85 / 155 MCF/B or B/MCF Payout: 2.38 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 100 200 300 400 500 600 700 0 100 200 300 400 500 600 700 800 900 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD $(2,000) $‐ $2,000 $4,000 $6,000 $8,000 $10,000 0% 10% 20% 30% 40% 50% 60% $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $70 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02$1.44 Subject to Express Confidentiality Agreements 11
Project: Permian‐EMB Mid Spraberry Hz (8,400') Target: Mid Spraberry Division: 6 Type: Drilling ‐ Horizontal COO/S: 48% Vital Statistics Identified Inventory (OP/OBO): 60/124 WI: 94.94 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 16 NRI: 72.26 % BPO Gross CAPEX/Well: 6,223 $M % APO Gross CAPEX/Facility: 0 $M* OBO: 25/19% * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 416.4 MMBOE Initial Rate: 460 BOPD or MCFD Net Rsv 322.5 MMBOE Dei: 74.5 %/yr % Oil 81.7 % Hyp Exponent: 1.60 % Gas 7.5 % Method: Secant Determinal: 6 %/yr Margin Projection Basis GOR/Yield: 0.85 / 155 MCF/B or B/MCF Payout: 8.73 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 100 200 300 400 500 600 0 50 100 150 200 250 300 350 400 450 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(2,500) $(2,000) $(1,500) $(1,000) $(500) $‐ $500 $1,000 $1,500 $2,000 $2,500 0% 5% 10% 15% 20% 25% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $70 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $2.30 $2.87 $3.45 $4.02$1.72 Subject to Express Confidentiality Agreements 12
Project: Permian‐EMB Wolfcamp 'A' Hz (8400') NSAI Target: Wolfcamp 'A' Division: 6 Type: Drilling ‐ Horizontal COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 60/202 WI: 94.94 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 16 NRI: 72.26 % BPO Gross CAPEX/Well: 6,604 $M % APO Gross CAPEX/Facility: 0 $M* OBO: 20/15% * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 771.2 MMBOE Initial Rate: 1,307 BOPD Net Rsv 605.4 MMBOE Dei: 80.3 %/yr % Oil 78.3 % Hyp Exponent: 1.20 % Gas 8.9 % Method: Secant Determinal: 6.0 %/yr Margin Projection Basis GOR/Yield: 1.05/ 155 MCF/B or B/MCF Payout: 2.05 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 100 200 300 400 500 600 700 800 900 1,000 0 100 200 300 400 500 600 700 800 900 1000 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(1,000) $‐ $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 $8,000 0% 10% 20% 30% 40% 50% 60% 70% $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $70 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02$1.44 Subject to Express Confidentiality Agreements 13
Project: Permian‐EMB Wolfcamp 'A' Hz (8400') Target: Wolfcamp 'A' Division: 6 Type: Drilling ‐ Horizontal COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 60/202 WI: 94.94 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 16 NRI: 72.26 % BPO Gross CAPEX/Well: 6,223 $M % APO Gross CAPEX/Facility: 306 $M* OBO: 20/15% * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 960.1 MMBOE Initial Rate: 1,255 BOPD or MCFD Net Rsv 751.3 MMBOE Dei: 78.0 %/yr % Oil 79.2 % Hyp Exponent: 1.40 % Gas 8.6 % Method: Secant Determinal: 6.0 %/yr Margin Projection Basis GOR/Yield: 1.00 / 155 MCF/B or B/MCF Payout: 1.70 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 200 400 600 800 1,000 1,200 0 200 400 600 800 1000 1200 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(2,000) $‐ $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $70 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02$1.44 Subject to Express Confidentiality Agreements 14
Project: Permian‐EMB Wolfcamp 'B' Hz (8,400')‐ NSAI Target: Wolfcamp 'B' Division: 6 Type: Drilling ‐ Horizontal COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 60/202 WI: 94.94 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 16 NRI: 72.26 % BPO Gross CAPEX/Well: 6,223 $M % APO Gross CAPEX/Facility: 306 $M* OBO: 20/15% * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 463.9 MMBOE Initial Rate: 855 BOPD Net Rsv 367.6 MMBOE Dei: 76.7 %/yr % Oil 76.0 % Hyp Exponent: 1.30 % Gas 9.9 % Method: Secant Determinal: 6.0 %/yr Margin Projection Basis GOR/Yield: 1.2 / 155 MCF/B or B/MCF Payout: 4.81 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 100 200 300 400 500 600 700 800 0 100 200 300 400 500 600 700 800 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(2,500) $(2,000) $(1,500) $(1,000) $(500) $‐ $500 $1,000 $1,500 $2,000 $2,500 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 15
Project: Permian‐EMB Wolfcamp 'B' Hz (8,400') Target: Wolfcamp 'B' Division: 6 Type: Drilling ‐ Horizontal COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 60/202 WI: 94.94 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 18 NRI: 72.26 % BPO Gross CAPEX/Well: 6,223 $M % APO Gross CAPEX/Facility: 306 $M* OBO: 20/15% * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 669.3 MMBOE Initial Rate: 895 BOPD or MCFD Net Rsv 523.7 MMBOE Dei: 78.0 %/yr % Oil 79.2 % Hyp Exponent: 1.40 % Gas 8.6 % Method: Secant Determinal: 6.0 %/yr Margin Projection Basis GOR/Yield: 1.0 / 155 MCF/B or B/MCF Payout: 2.96 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 100 200 300 400 500 600 700 800 0 100 200 300 400 500 600 700 800 0 12 24 36 48 60 72 84 96 108 120 G as, M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(2,000) $(1,000) $‐ $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 0% 10% 20% 30% 40% 50% 60% $20.00 $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $2.30 $2.87 $3.45 $4.02$1.72 Subject to Express Confidentiality Agreements 16
Project: Postle CO2 Pattern ‐ Tier 1 Target: Morrow A1/A2 Division: 5 Type: EOR Pattern COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 8 WI: 98.66 % BPO Pot. Unidentified Inventory: 0 98.66 % APO Max Projects per Year: 6 NRI: 85.86 % BPO Gross CAPEX/Well: 1,500 $M 85.86 % APO Gross CAPEX/Facility/CO2: 4,836 $M* * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 600.6 MMBOE Initial (Peak) Rate: 82 BOPD or MCFD Net Rsv 518.5 MMBOE Dei: 33.0 %/yr % Oil 77.0 % Hyp Exponent: 0.00 % Gas 2.4 % Method: Exp Determinal: 33.0 %/yr Margin Projection Basis GOR/Yield: 142.0 MCF/B or B/MMCF Payout: 5.51 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 200 400 600 800 1,000 1,200 0 10 20 30 40 50 60 70 80 90 0 12 24 36 48 60 72 84 96 108 120 W tr, G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $‐ $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 17
Project: Postle CO2 Pattern ‐ Tier 2 Target: Morrow A1/A2 Division: 5 Type: EOR Pattern COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 72 WI: 98.66 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 6 NRI: 85.86 % BPO Gross CAPEX/Well: 1,500 $M % APO Gross CAPEX/Facility/CO2: 3,366 $M* * Allocated per well Type Curve Parameters Primary Phase: Oil EUR: 414.9 MMBOE Initial (Peak) Rate: 62 BOPD or MCFD Net Rsv 353.9 MMBOE Dei: 0.0 %/yr % Oil 76.9 % Hyp Exponent: 0.00 % Gas 2.4 % Method: Exp Determinal: 33.0 %/yr Margin Projection Basis GOR/Yield: 142.0 MCF/B or B/MMCF Payout: 5.74 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 200 400 600 800 1,000 1,200 0 10 20 30 40 50 60 70 0 12 24 36 48 60 72 84 96 108 120 W tr, G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $‐ $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 $4,000 $4,500 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 18
Project: Santa Fe Springs RCP ‐ BP3.0 No Risk Target: Bell/Meyer/Nordstrom/Buckbee/Clark/HW Division: 2 Type: Recompletion Vital Statistics Identified Inventory: 65 WI: 100.00 % BPO Pot. Unidentified Inventory: 10 % APO Max Projects per Year: 10 NRI: 93.25 % BPO Gross CAPEX/Well: 150 $M % APO Gross CAPEX/Land‐Facility: 0 $M* * For project economic cases Type Curve Parameters Primary Phase: Oil EUR: 42.9 MBOE Initial Rate: 22 BOPD or MCFD Net Rsv 38.9 MBOE Dei: 15 %/yr % Oil 100.0 % Hyp Exponent: 0.00 % Gas 0.0 % Method: Exp Determinal: 15 %/yr Margin Projection Basis: GOR/Yield: 0 MCF/B or B/MCF Payout: 0.72 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 200 400 600 800 1,000 0 5 10 15 20 25 0 12 24 36 48 60 72 84 96 108 120 W ater, B W PD and G as, M D FD O i l , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $200 $300 $400 $500 $600 $700 $800 $900 $1,000 $1,100 $1,200 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 19
Project: SW Wyoming Vert Target: Frontier/Dakota Division: 1 Type: Drilling ‐ Vertical (Avg. of 3 well groups) COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 60 WI: 45.00 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 5 NRI: 35.14 % BPO Gross CAPEX/Well: 2,420 $M % APO Gross CAPEX/Facility: 0 $M* * Allocated per well Type Curve Parameters Primary Phase: Gas EUR: 1002.6 MBOE Initial Rate: 3,017 BOPD or MCFD Net Rsv 356.3 MBOE Dei: 56‐95 %/yr % Oil 3.1 % Hyp Exponent: 1.40‐1.90 % Gas 96.9 % Method: Tangent Determinal: 5.0‐6.0 %/yr Margin Projection Basis GOR/Yield: 11.0 MCF/B or B/MMCF Payout: 10.19 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 500 1,000 1,500 2,000 2,500 3,000 0 5 10 15 20 25 0 12 24 36 48 60 72 84 96 108 120 W tr, G as, B bls or M D FD L i q u i d , B P D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $(1,200) $(1,000) $(800) $(600) $(400) $(200) $‐ $200 $400 $600 $800 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 20
Project: East Texas Hz Target: Cotton Valley Taylor Division: 4 Type: Drilling Horizontal *Actual WI will Vary COO/S: 80% Vital Statistics Identified Inventory (OP/OBO): 86 WI*: 100.00 % BPO Pot. Unidentified Inventory: 32 % APO Max Projects per Year: 16 NRI*: 78.00 % BPO Gross CAPEX/Well: 5,440 $M % APO Gross CAPEX/Facility: 333 $M** ** Allocated per well Type Curve Parameters Primary Phase: Gas EUR: 1,175.3 MBOE Initial Rate: 9,000 BOPD or MCFD Net Rsv 995.9 MBOE Dei: 75.4 %/yr % Oil 14.0 % Hyp Exponent: 1.20 % Gas 68.6 % Method: Secant Determinal: 5.0 %/yr Margin Projection Basis GOR/Yield: 30.0 MMCF/B or B/MMCF Payout: 1.84 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 1,000 2,000 3,000 4,000 5,000 6,000 7,000 8,000 9,000 10,000 0 50 100 150 200 250 0 12 24 36 48 60 72 84 96 108 120 G as, M DF D Li q u id , BP D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $ $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 21
Project: East Texas Haynesville Hz Target: Haynesville Division: 4 Type: Drilling Horizontal COO/S: 72% Vital Statistics Identified Inventory (OP/OBO): 40 WI: 100.00 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 14 NRI: 74.00 % BPO Gross CAPEX/Well: 6,500 $M % APO Gross CAPEX/Facility: 44 $M* * Allocated per well Type Curve Parameters Primary Phase: Gas EUR: 1273.8 MBOE Initial Rate: 12,500 BOPD or MCFD Net Rsv 914.3 MBOE Dei: 67.0 %/yr % Oil 0.0 % Hyp Exponent: 0.75 % Gas 100.0 % Method: Secant Determinal: 5.0 %/yr Margin Projection Basis GOR/Yield: 0.0 MCF/B or B/MMCF Payout: 2.43 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 2,000 4,000 6,000 8,000 10,000 12,000 14,000 0 100 200 300 400 500 600 700 0 12 24 36 48 60 72 84 96 108 120 Gas, Bb ls or MDFDL iqu id, BP D MONTHS OF PRODUCTION Production Profile BOPD BWPD MCFPD $(1,000) $ $1,000 $2,000 $3,000 $4,000 $5,000 $6,000 $7,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 22
Project: East Texas Haynesville Vt Target: Haynesville Division: 4 Type: Drilling Vertical COO/S: 70% Vital Statistics Identified Inventory (OP/OBO): 57 WI: 100.00 % BPO Pot. Unidentified Inventory: 0 % APO Max Projects per Year: 12 NRI: 74.37 % BPO Gross CAPEX/Well: 2,369 $M % APO Gross CAPEX/Facility: 0 $M* * Allocated per well Type Curve Parameters Primary Phase: Gas EUR: 544.8 MBOE Initial Rate: 2,400 BOPD or MCFD Net Rsv 446.0 MBOE Dei: 55.0 %/yr % Oil 8.0 % Hyp Exponent: 1.06 % Gas 67.1 % Method: Secant Determinal: 5.0 %/yr Margin Projection Basis GOR/Yield: 16.0 MCF/B or B/MMCF Payout: 2.61 Yrs (1) BOE basis (Gas 6:1 / NGL 1:1); PEB basis (Gas 17.4:1 / NGL 2.4:1) 0 500 1,000 1,500 2,000 2,500 0 10 20 30 40 50 60 70 80 90 100 0 12 24 36 48 60 72 84 96 108 120 Wtr, Gas, Bbls or MDFD Liq uid , BP D MONTHS OF PRODUCTION Production Profile BOPD MCFPD BWPD $(500) $ $500 $1,000 $1,500 $2,000 $2,500 $3,000 $3,500 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $0 $10 $20 $30 $40 $50 $60 $/BOE $/PEB Full Cycle Margin Projection(1) PROFIT (Undisc.) F&D TAX LOE $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE $1.72 $2.30 $2.87 $3.45 $4.02 Subject to Express Confidentiality Agreements 23