Breitburn Energy Partners LP
Breitburn Energy Partners LP (Form: 8-K, Received: 05/25/2017 13:18:57)


UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 8-K
 
CURRENT REPORT
Pursuant to Section 13 or 15(d)
of the Securities Exchange Act of 1934

Date of Report (Date of Earliest Event Reported)
May 25, 2017
 

BREITBURN ENERGY PARTNERS LP
(Exact name of Registrant as specified in its charter)
 

Delaware
001-33055
74-3169953
(State or other jurisdiction
of incorporation or jurisdiction)
(Commission
File Number)
(IRS Employer
Identification No.)

707 Wilshire Boulevard, Suite 4600
Los Angeles, CA 90017
(Address of Principal Executive Offices)
(213) 225-5900
(Registrant’s telephone number)
 
Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

o
Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)
 
 
o
Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)
 
 
o
Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))
 
 
o
Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 (§230.405 of this chapter) of the Securities Act of 1933 or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging growth company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act o





Item 7.01 Regulation FD Disclosure.

As previously reported, on May 15, 2016, Breitburn Energy Partners LP (the “ Partnership ”) and certain of its affiliates (such affiliates, together with the Partnership, the “ Debtors ”) filed voluntary petitions for relief (and the cases commenced thereby, the “ Chapter 11 Cases ”) under chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. The Chapter 11 Cases are being administered jointly under the caption “In re Breitburn Energy Partners LP, et al.”, Case No. 16-11390.

In November 2016 and January 2017, the Partnership entered into confidentiality agreements (collectively, the “ Confidentiality Agreements ”) with certain holders of the 7.875% Senior Unsecured Notes due 2022 and 8.625% Senior Notes due 2020 issued by the Partnership (the “ Unsecured Notes ” and, the holders thereof that are party to the Confidentiality Agreements, the “ Confidential Agreement Parties ”) regarding potential transactions to restructure, among other things, the Unsecured Notes. The Confidentiality Agreements expired pursuant to their terms on May 19, 2017. The Debtors are in ongoing discussions with the advisors to certain holders of the Unsecured Notes and the Official Committee of Unsecured Creditors regarding the terms of a chapter 11 plan of reorganization (the “ Plan ”). The Debtors intend to enter into new confidentiality agreements with such holders. The Debtors are currently negotiating a definitive plan support agreement, pursuant to which such holders would agree to support the Plan. The Debtors are also currently negotiating an investment and backstop agreement with such holders that provides for the holders to make a $1 billion equity investment. The proposed terms of the investment and backstop agreement are reflected in the illustrative term sheet referred to below. No assurances can be given that such definitive documents will be executed.

Pursuant to the Confidentiality Agreements, the Debtors have agreed to publicly disclose material non-public information (as determined by the Debtors in good faith) regarding the Partnership and its subsidiaries provided to the Confidential Agreement Parties. Over the course of several months, meetings occurred between certain representatives of the Debtors and the Confidential Agreement Parties (the “ Meetings ”), during which the Debtors made diligence presentations regarding the Partnership to the Confidential Agreement Parties. In connection with the Meetings and subsequent to the Meetings, the Debtors provided certain confidential information to the Confidential Agreement Parties pursuant to the Confidentiality Agreements, including certain illustrative terms included in the above-referenced illustrative term sheet (the “ Diligence Materials ”), which are attached hereto as Exhibit 99.1, Exhibit 99.2 and Exhibit 99.3 to this report.

Any financial projections or forecasts included in the Diligence Materials were not prepared with a view toward public disclosure or compliance with the published guidelines of the Securities and Exchange Commission or the guidelines established by the American Institute of Certified Public Accountants regarding projections or forecasts. The projections do not purport to present the Partnership’s financial condition in accordance with GAAP. The Partnership’s independent accountants have not examined, compiled or otherwise applied procedures to the projections and, accordingly, do not express an opinion or any other form of assurance with respect to the projections. The projections were prepared for internal use, capital budgeting and other management decisions and are subjective in many respects. The projections reflect numerous assumptions made by management of the Partnership with respect to financial condition, business and industry performance, general economic, market and financial conditions, and other matters, all of which are difficult to predict, and many of which are beyond the Partnership’s control. Accordingly, there can be no assurance that the assumptions made in preparing the projections will prove accurate. It is expected that there will be differences between actual and projected results, and the differences may be material, including due to the occurrence of unforeseen events occurring subsequent to the preparation of the projections. The inclusion of the projections herein should not be regarded as an indication that the Partnership or its affiliates or representatives consider the projections to be a reliable prediction of future events, and the projections should not be relied upon as such. Neither the Partnership nor any of its affiliates or representatives has made or makes any representation to any person regarding the ultimate outcome of the Partnership’s restructuring compared to the projections, and none of them undertakes any obligation to publicly update the projections to reflect circumstances existing after the date when the projections were made or to reflect the occurrence of future events, even in the event that any or all of the assumptions underlying the projections are shown to be in error.

Certain of the information provided herein was prepared as early as December 2016, and is subject to all of the cautionary statements and limitations described herein and under the caption “Cautionary Note Regarding Forward-Looking Statements.” Certain conditions have changed since most of these materials were prepared as the Partnership continues to operate, technical advancements continue to occur, commodity prices change, land acquisitions and dispositions continue to occur in the ordinary course, costs change and other similar changes take place. As a result, the forward looking information contained in the materials should be viewed in the context of the time it was prepared and with the understanding that some of the forward looking estimates or expectations have proven to be incorrect and thus the forward looking information is no longer accurate. Projections and estimates for the Partnership’s future production volumes are based on, among other things,





assumptions of capital expenditure levels and the assumption that market demand and prices for oil and gas will continue at levels that allow for economic production of these products, and projected future volumes may be lower due to the impact of wells being shut-in or not being repaired due to their being uneconomic at current commodity prices. The production, transportation and marketing of oil and gas are extremely complex and are subject to disruption due to transportation and processing availability, mechanical failure, human error, weather, and numerous other factors, including the inability to obtain expected supply of CO2. The Partnership’s projections are based on certain other assumptions, such as well performance, which may actually vary significantly from those assumed. Lease operating costs, including major maintenance costs, vary in response to changes in prices of services and materials used in the operation of our properties and the amount of maintenance activity required. Lease operating costs, including taxes, utilities and service company costs, move directionally with increases and decreases in commodity prices, and we cannot fully predict such future commodity or operating costs. Similarly, interest rates and price differentials are set by the market and are not within our control, and they can vary dramatically from time to time. Capital expenditures were based on our expectations as of the date of such guidance as to the level of capital expenditures that will be justified based upon our then expectations about certain operating and economic factors not discussed herein. Accordingly, the guidance provided herein does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved; rather it simply sets forth our best estimate as of the date of such guidance for these matters based upon our then expectations about the future based upon both stated and unstated assumptions. Actual conditions and those assumptions may, and probably will, change.

The information in this report under Item 7.01 shall not be deemed to be “filed” for purposes of Section 18 of the Securities and Exchange Act of 1934, as amended (the “ Exchange Act ”), or otherwise subject to the liabilities of that Section, and shall not be incorporated by reference into any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such a filing.

Cautionary Note Regarding Forward-Looking Statements

The information in this report contains forward-looking statements relating to the Partnership’s operations that are based on management’s expectations, estimates and projections about its operations as of the date of such statements. Words and phrases such as “believes,” “expect,” “future,” “impact,” “will be,” “forecast” 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 our control and are difficult to predict. These include risks relating to the Partnership’s financial performance and results; the restructuring process, including our inability to develop, confirm and consummate a plan under chapter 11 of the U.S. Bankruptcy Code or an alternative restructuring transaction; changes in our business strategy; our future levels of indebtedness and liquidity; prices and demand for natural gas and oil; increases in operating costs; uncertainties inherent in estimating our reserves and production; our ability to replace reserves and efficiently develop our current reserves; political and regulatory developments relating to taxes, derivatives and our oil and gas operations; and the factors set forth under the heading “Risk Factors” incorporated by reference from our Annual Report on Form 10-K filed with the Securities and Exchange Commission, our Quarterly Reports on Form 10-Q and our 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 such statements. Unless legally required, the Partnership 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.






Item 9.01 Financial Statements and Exhibits.

(d) Exhibits

99.1
Breitburn Energy Partners LP - Discussion Materials.
99.2
Breitburn Energy Partners LP - Discussion Materials.
99.3
Breitburn Energy Partners LP - Proposed Equity Investment Term Sheet.






SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.




 
BREITBURN ENERGY PARTNERS LP
 
 
 
 
By:
BREITBURN GP LLC,
 
 
its general partner
 
 
 
Date: May 25, 2017
By:
/s/ James G. Jackson
 
 
James G. Jackson
 
 
Chief Financial Officer



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


 
CONFIDENTIAL PRELIMINARY DISCUSSION MATERIALS Highly Confidential Subject to FRE 408 Subject to Express Confidentiality Agreement BREITBURN ENERGY PARTNERS LP INCLUDES APRIL 19, 2017 PRESENTATION AND SUBSEQUENT SUPPLEMENTAL MATERIALS


 
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 OVERVIEW Agenda  Introductions  Overview • Corporate Overview and Operations Organization • Portfolio Modeling – Strategic to Tactical • BBEP Asset Base  Regional Reviews • West Texas Permian Basin – Division 6 • ArkLaTex Upper Gulf Coast Basin – Division 4 • Enhanced Oil Recovery – Division 5 • California San Joaquin and L.A. Basins – Division 2 • Eastern (MI/IN/KY/FL-S) Michigan and Gulf Coast Basins – Division 1 • Rockies Big Horn and Green River Basins – Division 1 pg. 3


 
CONFIDENTIAL ATTRACTIVE ASSETS IN 7 PRODUCING AREAS ARK-LA-TEX 2016 Avg. Daily Production 10,587 Boe/d Est. Proved Reserves 34.4 MMboe SOUTHEAST 2016 Avg. Daily Production 4,782 Boe/d Est. Proved Reserves 13.5 MMboe MI/IN/KY 2016 Avg. Daily Production 7,956 Boe/d Total Proved Reserves 41.1 MMboe MID-CONTINENT 2016 Avg. Daily Production 5,648 Boe/d Est. Proved Reserves 30.4 MMboe CALIFORNIA 2016 Avg. Daily Production 4,161 Boe/d Est. Proved Reserves 15.5 MMboe ROCKIES 2016 Avg. Daily Production 5,871 Boe/d Est. Proved Reserves 24.2 MMboe PERMIAN BASIN 2016 Avg. Daily Production 10,706 Boe/d Est. Proved Reserves 46.2 MMboe TOTAL TOTAL EST. PROVED RESERVES: 205.3 Mmboe(1) PROVED RESERVE LIFE: ~11 years PERMIAN BASIN 22% ROCKIES 12% ARK-LA-TEX 17% MI/IN/KY 20% SOUTHEAST 7% CALIFORNIA 8% MID-CONTINENT 15% Estimated Proved Reserves By Area CALIFORNIA ROCKIES MI/IN/KY MID-CONTINENT PERMIAN BASIN ARK-LA-TEX SOUTHEAST (1) Based on SEC 2016 average pricing of $42.75/bbl WTI and $2.48/MMBTU gas pg. 4


 
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 3 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 - HISTORICAL REDUCTIONS Prudent Deployment of Investment Capital Reflective of Market Conditions (1) 2014 combines full-year QRE & BBEP operating results pg. 5 2016 OIL & GAS CAPITAL BY DIVISION $ in millions $3.4 $14.1 $23.1 $21.7 $6.0 Div 1 Div 2 Div 4 Div 5 Div 6 CAPITAL INVESTMENT - OIL & GAS DEV CAPITAL INVESTMENT - OIL & GAS DEV $ in millions $582.1 $210.6 $68.3 ( $371.5 ) ( $513.8 ) $- $100 $200 $300 $400 $500 $600 2014 (1) 2015 2016 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 LEASE OPERATIONS - HISTORICAL 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) pg. 6 LOE ANNUAL RUN-RATE COSTS $ in millions $425.7 $350.4 $261.7 ( $75.3 ) ( $163.9 ) $- $50 $100 $150 $200 $250 $300 $350 $400 $450 2014 (1) 2015 2016 Run-Rate LOE Costs Reduction 39% Decrease in Run-Rate LOE Costs (vs. YE '14) LOE ANNUAL PER BBL COSTS $/BOE 20.64 17.42 14.32 3.23 6.33 $- $5.00 $10.00 $15.00 $20.00 $25.00 2014 (1) 2015 2016 Run-Rate Lifting Cost Reduction 31% Decrease in Run-Rate LOE/BOE Costs (vs. YE '14)


 
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 pg. 7


 
CONFIDENTIAL POSSIBLE OPPORTUNITIES • BBEP has a sizeable inventory of potential projects • Projects have been matured to varying states of readiness pg. 8 OPERATED PROJECT TYPE PERMIAN ARKLATEX EOR CALIFORNIA EASTERN ROCKIES Total CONVERT TO INJECTION - - 4 1 35 9 48 DC&E - HORIZONTAL 415 72 - - 170 - 656 DC&E - VERTICAL 134 585 169 63 51 120 1,123 EOR EXPANSION - - 63 - - - 63 FACILITY PROJECTS 1 7 13 7 1 0 29 RECOMPLETION 22 182 1 63 24 2 294 RETURN TO PRODUCTION 1 583 17 - - - 601 WATERFLOOD EXPANSION 2 3 - - - 1 6 WORKOVER 8 169 13 86 4 8 287 # of NET PROJECTS 582 1,601 280 220 285 140 3,107 NET RESERVES (MMBOE) 216 130 54 11 80 27 519 NET CAPITAL (MM$) 2,410 1,232 587 87 890 195 5,402 NON-OPERATED # of NET PROJECTS 291 2 - - 1 - 293 NET RESERVES (MMBOE) 111 1 - - 1 - 113 NET CAPITAL (MM$) 1,346 5 - - 6 - 1,357 TOTAL COMPANY # of NET PROJECTS 873 1,602 280 220 285 140 3,400 NET RESERVES (MMBOE) 327 131 54 11 81 27 631 NET CAPITAL (MM$) 3,756 1,237 587 87 897 195 6,759


 
CONFIDENTIAL CORPORATE PORTFOLIO MODELING Key model characteristics • Self-funding after 2018 • Investment of $3.4B over 10 yr period (60% of inventory) • Grows operating cash flow by 2.8x over 10-yr horizon Extended date of emergence restricts capital spending in front years • 2017 budget set based on July emergence • Major projects postponed until 4Q 2017 Oil inventory development favorable in early years • Acceleration of Permian, Postle and Belridge inventory • Liquids Rich gas plays still compete • Dry gas plays deferred – Oak Hill (Hynvl), Colgwd-Utica Improvements in Permian- EMB well performance, capital and operating efficiency • Generates increased cashflow • Provides funding for expanded capital spending The optimization criteria utilized for constructing the capital plan structure was maximization of PV10 Key Constraints: • March 2017 Plan • Pricing Model – Strip 01/25/2017 • Illustrative Credit Facility and Capital Structure Assumptions pg. 9


 
CONFIDENTIAL 2017 OPERATING PLAN PROJECTION (1) (1) Based on company operating projections and Jan 25, 2017 market strip pricing. Totals exclude East TX SWD and Postle condensate purchases NET BOE (BBEP) CAPITAL (BBEP) LEASE OPERATING EXPENSE (BBEP) NET FREE CASHFLOW (BBEP) pg. 10


 
CONFIDENTIAL 2017 POST-EMERGENCE CAPITAL PLAN ASSUMES JULY 1 EMERGENCE Area 2017E ($MM) Commentary Permian – Eastern Midland Basin $48 • Begin horizontal Wolfcamp / Spraberry development; first rig in July and second in January 2018 • Complete successful overhaul of artificial lift systems on vertical producers • Acreage consolidation and exploitation of economies of scale ArkLaTex $35 • Testing/Expansion of gas and liquids-rich horizontal drilling inventory • Low-cost and rapid payback deepenings, recompletions and workovers at ETOF • Technology driven performance improvement. Hz Haynesville Jay N2 EOR $25 • Drilling and recompletion program targeting lower recovery, immature flood patterns • Completion of major trunk-line replacement program • Focus on conformance and surveillance to boost recoveries in immature patterns Postle Area CO2 EOR $23 • Expansion of Morrow A sand flood and exploitation of largely undeveloped A1 and A2 sands • Ongoing CO2 to service existing patterns • Expansion around Postle complex and along pipeline infrastructure Permian – CBP & New Mexico $7 • Delineation and continued development of deep horizons at M State Field • Non-Operated drilling obligations Other Oil & Gas $25 • Primarily in Wyoming, California and Michigan • Continued expansion of Santa Fe Springs Field facilities infrastructure • Expansion of successful waterfloods in Wyoming and CO2 floods in Michigan Total Oil & Gas $163(1) (1) Excludes non oil & gas capex. pg. 11


 
CONFIDENTIAL WEST TEXAS PERMIAN DIVISIONS II & VI


 
CONFIDENTIAL PERMIAN BASIN OVERVIEW(1) ASSUMES JULY 1 EMERGENCE Net Production by Phase Net Reserves by Category Operating Plan Annual Projection Operating Plan Production Profile Year Production (MMBoe) CAPEX ($MM) LOE ($MM) 2017 3.4 55.0 59.1 2018 4.8 163.8 63.9 2019 6.9 264.2 70.8 2020 10.1 255.2 82.2 2021 11.9 282.6 90.8 Annual PDP Decline Jan. '17 - Jan. '18 (9.9%) Jan. '18 - Jan. '19 (11.5%) Jan. '19 - Jan. '20 (10.7%) Production Profile (Net Volumes) (1) Based on company operating projections and Jan 25, 2017 market strip pricing. Totals exclude East TX SWD and Postle condensate purchases pg. 13


 
CONFIDENTIAL PERMIAN BASIN DEVELOPMENT ACREAGE • As of 12/31/2016, Breitburn held ~130,000 gross (~90,000 net) acres in the Permian Basin. Key leaseholds include: Howard & Martin Counties • ~10,100 net acres in highly contiguous, horizontal operated positions in Howard and Martin County • ~7,400 net acres with horizontal non-operated opportunities in Howard and Martin County • ~5,000 net acres with vertical/wellbore rights only in Howard & Martin County • Entire position has deep rights HBP from the top of the Spraberry to the base of the Wolfcamp formations East Quito • ~1,600 net acres with horizontal potential in Western Ward County • Position includes HBP deep rights in the Bone Springs and/or Wolfcamp formations • Primary offset operators are Callon, Energen, and Anadarko M State Lease • 3,080 gross acre JV with XOM/XTO in Lea County; earned 680 net acres to date • 77 potential locations; 17 drilled & producing wells • Historically Blinebry, Drinkard, Tubb, Abo; recently discovered additional formations (Glorieta, Devonian, Fusselman) East Fuhrman Area • ~3,100 net acres (3,080 acres with deep rights) in Andrews County (100% operated) producing from the San Andres and Glorieta • Potential additional developable zones include Wichita- Albany/Abo and Spraberry Other • ~22,900 net acres with additional Permian upside development formations/rights • ~39,600 net acres with limited additional upside potential Commentary Acreage Map East Quito Update sub maps Update sub maps East Fuhrman Area Howard & MartinM Lease pg. 14 Gross Net Midland Basin (Howard & Martin County) Horizontal Rights 20,703 17,502 Midland Basin (Howard & Martin County) Vertical/Wellbore Rights Only 5,344 5,039 Delaware Acres w/ Horizontal Bone Spring and/or Wolfcamp Rights 2,592 1,591 Additional Permian Upside Development Formations / Rights 25,186 22,894 Central Basin Platform Acres w/ Horizontal Rights 6,120 3,760 Acres with Limited Additional Upside Potential 70,389 39,639 Total 130,334 90,425


 
CONFIDENTIAL Howard Co., TX EASTERN MIDLAND BASIN OVERVIEW • Spraberry Trend Acreage – Total Acreage (including vertical/wellbore only & HZ rights): 26,047 gross / 22,541 net – Total HZ Acreage: 20,703 gross / 17,502 net – operated HZ Acreage: 10,310 gross / 10,080 net • 5.5 MBoe/d of Q4 2016 net production – 409 gross producing wells • 2017 Capex: $48MM (Assuming July 1 Emergence) Asset Highlights Curent Development Plan City of Midland Eastern Shelf Midland Basin Platform Margin TX NM Core Area 85 bopd, peak month daily rate per 1000 ft Breitburn Op Horizontal Breitburn Non-Op Horizontal • Secure off-lease surface locations • Ensure adequate frac water supplies • Utilize pad drilling • Generation 3 frac design w/ zipper fracs • Centralize production facilities pg. 15 P ojects Low Risk Bnch Med Risk Bnch Non-op (20%) 2017 8 0 8 2018 18 0 14 2019 36 0 14 2020 36 0 14 2021 36 0 14


 
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 Diamondback - Phillips-Hodnett Unit Lateral length - 7,430’ IP/IP30 (Boe/d): 1,505/1,374 Diamondback – Reed (LS) Lateral Length: 9,721’ IP/IP30 (Boe/d): 797/1,053 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 SM Energy – Ogre 47-2A 1WA Lateral Length: 7,435’ IP/IP30 (Boe/d): 1,033/1,615 SM Energy – Tackleberry WCA Lateral Length: 7,861’ IP/IP 30: 2,639/2,262 (Boe/d) Diamondback - Phillips-Hodnett Unit Lateral Length: 7,296’ IP/IP30 (Boe/d): 574/NA Surge – Allred Unit B 08-05 8AH Lateral Length: 10,022’ IP/IP30 (Boe/d): 1,501/NA Diamondback – Reed (WCA) Lateral Length: 9,727’ IP/IP30 (Boe/d): 2,150/1,827 April 10, 2017 Diamondback – Asro Lateral Length: ~9,700’ IP/IP30 (Boe/d): NA / NA Diamondback – Asro Lateral Length: ~9,700’ IP/IP30 (Boe/d): NA / NA Surge - Wolfe-McCann Unit 10-2SH Lateral Length 6,851’ IP/IP30 (Boe/d): 1,161/783 Surge - Hamlin-Middleton Unit #1H Lateral Length: 6492’ IP/IP30 (Boe/d): 1370/872 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: 7,295’ IP/IP30 (Boe/d): 1,112/861 Notes: Key horizontal wells; Lateral lengths are perf-to-perf stimulated lengths. Diamondback - Phillips-Hodnett Unit Lateral Length: 7,093‘ IP/IP30 (Boe/d): 1,490/1,211 Diamondback – Reed (WCB) Lateral Length: 9,727’ IP/IP30 (Boe/d): 1,799/1,485 Diamondback – Asro Lateral Length: ~9,700’ IP/IP30 (Boe/d): NA / NA SM Energy – Tackleberry LS Lateral Length: 7,873’ IP/IP 30: 1,426/1,286 (Boe/d) SM Energy – Tackleberry WCB Lateral Length: 7,885’ IP/IP 30: 1655,1412 (Boe/d) SM Energy Diamondback Surge Operating Energen Energen – Gaskins SN 6-43 03 #103H Lateral Length: ~7,200‘ AFE currently being routed for approval Energen – Adams NS 43-6 01 #601H Middle Spraberry Target Zone Lateral Length: ~9,100‘ AFE currently being routed for approval Lower Spraberry (34) Wolfcamp A (80) Wolfcamp B (20)Middle Spraberry (1) pg. 16


 
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 2) $50 Flat Pricing, 2-Stream wellhead EUR 3) 1.5 mile lateral drilled off-lease, 7,700’ perf-to-perf HORIZONTAL MIDLAND BASIN DEVELOPMENT Lower Spraberry Wolfcamp A Wolfcamp B Add. Potential Benches (1) Total Net Locations Operated 57 57 57 224 395 Non-Operated 40 42 40 185 307 Total Net Locations 97 99 97 409 702 Gross Operated Locations 60 60 60 Unrisked EUR (Mboe) (2) 805 876 609 IP (Boe/d) 978 1,341 957 30 Day IP (Boe/d) 823 1,121 802 Recovery Factor 8% 8% 7% D&C Capex ($MM) 5.9 5.9 5.9 Lateral Length (3) 7,700' 7,700' 7,700' IRR @ $50 Flat 38% 58% 26% Operated HZ’s Non-Operated HZ’s pg. 17 The type curve economics above are illustrative of a 7,700’ lateral, i.e., a 1 ½ mile off-lease well. The average lateral length currently expected over our acreage is 8,400’.


 
CONFIDENTIAL LAND POSITION – INITIAL TARGET AREA 2017 Plan Wells – Initial Target Area (1) 2014 October 2016 Budget 2017 Plan (2) With Acreage in Advanced Negotiations (3) Average WI 73% 85% 95% 92% Gross Well Count 44 189 180 216 Two Mile Well Count 0 15 63 126 Net Lateral Length (thousand feet) 222 1,152 1,437 1,745 In Advanced Negotiations 2016 BudgetOctober 2014 (1) Illustrative well count includes only one landing point in each of the Lower Spraberry, Wolfcamp A and Wolfcamp B zones, assuming 6 wells per section, except for Oct 2014 which was based on 2 benches. (2) Basis for 2017 Ops Plan (released in March); based on acreage actually held as of January 2017 plus the Conoco and SM acreage trades considered highly likely to close (excludes the Diamondback 2 trade which closed subsequently and excludes the court-approved Guidon/Endeavor and CrownQuest trades.) (3) Adds to the 2017 Plan the following acreage: the court-approved Guidon/Endeavor and CrownQuest trades considered likely to close, Diamondback 2 and 2 confidential trades currently in advanced negotiations (excludes additional trades currently in earlier stages of negotiation). pg. 18


 
CONFIDENTIAL MARTIN & HOWARD COUNTY DRILLING BLOCKS • 3 new BOLP horizontal drilling blocks created through trades completed / pending trades to date • 4 additional horizontal drilling blocks created through identified trades in progress by YE 2017 • 6 OBO horizontal drilling blocks currently committed to or currently participating in • 7 OBO planned horizontal drilling blocks that have been identified with other Operators • 720 net acres of trades closed/closing to date in 2017 • 2,142 net acres identified and in negotiations with additional Operators in Howard/Martin County, aiming to be completed in 2017 pg. 19


 
CONFIDENTIAL U. Spraberry Shale Clear Fork L. Spraberry Shale Dean Wolfcamp A Wolfcamp B Wolfcamp C Cline Jo Mill Sand 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 Horizontal Production in Howard Co. Additional Horizontal 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. 20


 
CONFIDENTIAL Key Points  Reservoirs are present across acreage ─ 300-350’ of proven Lower Spraberry ─ 200-275’ of proven Wolfcamp A ─ 225’-300’ of proven Wolfcamp B  Thickness and stratigraphic position of carbonate beds vary, present in other areas that are being developed STRATIGRAPHIC CROSS-SECTION B-B’ DATUM: TOP OF DEAN FM GR RT PHIE Cemetery #1 West (B) East (B’) Sw GR RT PHIE Sw GR RT PHIE Sw GR RT PHIE Sw GR RT PHIE Sw GR RT PHIE Sw Little #1 Cline Unit 32-A #2 McNew #2 Rogers 34 #1 Callie #1 Lower Spraberry Shale Dean Dean Wolfcamp AWolfcamp A Wolfcamp B Wolfcamp B Lower Spraberry Shale Lower Spraberry Sands L. Wolfcamp L. Wolfcamp B B’ Diamondback BBEP Element pg. 21


 
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 ─ Well Logs normalized to core ─ Reservoir parameters calculated (Porosity, Oil Saturation, Net Pay, HCPV) ─ Maps generated to quantify resource potential across leasehold ─ 115 linear miles of 2D seismic data  342 sq. mi. of 3D seismic data recently acquired by CGG, to be license shortly pg. 22


 
CONFIDENTIAL LOWER SPRABERRY TYPE CURVE LOCATOR MAP Martin Howard Wilbanks SN 16-15 #501H Gunslinger Unit L #4H Hamlin 19-30 #1H Smith SN 48-37 #502H Wright Unit 44-41 #3H Fryar Unit A 13-12 #3SH Clark Unit ‘B’ 24-13 #7SH Shroyer-Wilson Unit 23-14 #3H Wright Unit 41-32 #1SH Fryar Unit B 13-12 #5SH Clark Unit ‘B’ 24-13 #5SH Elrod-Antell Unit A 11-02 #4SH Garrett Unit 37-48 3SH Hamlin-Middleton Unit 16-21 3SH Hendrix 3H Shroyer-Wilson Unit A 23-14 1SH Whitaker 3905 1LS Wolfe-McCann Unit 10-15 2SH Ponderosa Unit L 1H Wells in Current Type Curve Wells Excluded from Type Curve Tackleberry 43-42 A-2 Phillips-Hodnett Unit 1 Reed 1 A-1 WR Soapberry Unit #10H2 Ward 17B H1705 Falkor 4-8 A5LS Lacking Sufficient Production Data Wright-Adams Unit 31-6SH SFH Unit 23 #3SH Operated Acreage Non-Operated Acreage pg. 23


 
CONFIDENTIAL LOWER SPRABERRY TYPE CURVE ESTIMATED Lower Spraberry – Normalized to 7,700’ EUR Oil (MBo) EUR Gas (MMcf) EUR NGL’s (MMcf) EUR 3-stream (MBoe) Type Curve(1) 705 389 93 862 (1) EUR’s based on $50 Flat Price Deck. Key Points  19 offset analog wells  Normalized to 7,700’ simulated length  Decline Parameters ─ IP = 978 Boe/d (2-Stream) ─ IP = 857 Bo/d ─ Di = 75% ─ b = 1.6 ─ Dmin = 6% ─ GOR = 850 scf/Bbl  Single Well ROR = 38% pg. 24


 
CONFIDENTIAL Operated Acreage Non-Operated Acreage WOLFCAMP A TYPE CURVE LOCATOR MAP Smith SN 48-37 #101H Wolfe McCann Unit 10-15 #2H Garrett Reed Unit 37-48 #4H Garrett Snell Unit B 36-25 #4H Wilbanks SN 16-15 #103H Hamlin-Middleton Unit 16-21 #1H Clark Unit B 24-13 #6H Clark Unit 24-13 #1H Adams H #4201WA Wright Unit 44-41 #3AH Wilkinson Ranch #351H Wright Unit 41-32 #2H Hamlin 20-29 #2H Hamlin Unit 1522 #5AH Fryar Unit B 13-12 6AH Elrod Antell Unit A 11-02 #4AH Wright Unit B 41-32 #8AH Hendrix #1H Gardner Unit 1510 #2H Adams H #4231WA Clark Unit B 24-13 #5AH Fryar Unit A 13-12 1AH Guitar Galusha 1H Ripley 10-2 A 15WA Shields 3107 WA Wells in Current Type Curve Tackleberry 43-42 A-2 Phillips-Hodnett Unit 1 Reed 1 A-1 WR Bur Oak Unit 3HB Wells Excluded from Type Curve Lacking Sufficient Production Data Elrod Antell Unit B 11-02 #6H SFH Unit 23 #1H Whitaker 3907 1WA Elrod Antell Unit B 11-02 #5AH Garrett-Snell Unit B 36-25 5H Shields 3102 WA Shields 3105 WA Martin Howard Older Wells pg. 25


 
CONFIDENTIAL WOLFCAMP A TYPE CURVE ESTIMATED Wolfcamp A – Normalized to 7,700’ Vintaged to only include wells completed after September 2015 EUR Oil (MBo) EUR Gas (MMcf) EUR NGL’s (MBNGL) EUR 3-stream (MBoe) Type Curve(1) 750 488 116 948 Key Points  15 analog offset wells ─ vintaged to include wells completed after September 2015 ─ average proppant is 1,405 ppf  Normalized to 7,700’ simulated length  Decline Parameters ─ IP = 1,341 Boe/d (2-stream) ─ IP = 1,150 Bo/d ─ Di = 78% ─ b = 1.4 ─ Dmin = 6% ─ GOR = 1,000 scf/Bbl  Single Well ROR = 58% (1) EUR’s based on $50 Flat Price Deck. pg. 26


 
CONFIDENTIAL Operated Acreage Non-Operated Acreage WOLFCAMP B TYPE CURVE LOCATOR MAP Wilbanks SN 16-15 #101H Hamlin 20-29 #1H Smith SN 48-37 #202H Middleton 47-38 #1H Hamlin 19-18 #1H Hamlin Unit 1522 #3H Mozetti 37-48 #1H Wright Unit 40-33 7BH Reed 1 A-1WB Phillips-Hodnett Unit 1WB Gratis 32-R 1HB WR Bur Oak Unit #9HB WR Soapberry Unit #2HE Tackleberry 43-42 A-2WB Wells in Current Type Curve Wells Excluded from Type Curve Lacking Sufficient Production Data Hamlin 19-18 #1AH Martin Howard WR Lacebark Elm Unit #6HB WR Cedar Elm Unit # 5HE pg. 27


 
CONFIDENTIAL WOLFCAMP B TYPE CURVE ESTIMATED Wolfcamp B – Normalized to 7,700’Key Points  Type curve derived by fitting to the average oil production of analog offset wells and accounting for recent improved performance.  Normalized to 7,700’ simulated length  Decline Parameters ─ IP = 957 Boe/d (2-stream) ─ IP = 820 Bo/d ─ Di = 78% ─ b = 1.4 ─ Dmin = 6% ─ GOR = 1,000 scf/Bbl  Single Well ROR = 26% EUR Oil (MBo) EUR Gas (MMcf) EUR NGL’s (MBNGL) EUR 3-stream (MBoe) Type Curve(1) 522 339 81 659 (1) EUR’s based on $50 Flat Price Deck. 0 5 10 15 20 25 30 35 40 45 50 10 100 1,000 10,000 0 12 24 36 We ll C ou nt BO PD /770 0 fe et Hamlin U 1522 3H Hamlin 20-29 1H Middleton 47-38 1H Williams 24-13 1H Lester 27-34 1H Smith SN 48-37 02 202H Mozetti 37-48 1H Wilbanks SN 16-15 101H Gratis 32 R 1HB Phillips-Hodnett U 1WB Type Curve Average # Wells Oil pg. 28


 
CONFIDENTIAL Locator Map Type Log: Fred Phillips 19 #2 OOIP AND RECOVERY FACTOR Key Points LS WC A WC B OOIP (MMBo/960 Acres) 53 57 45 TC EUR Oil (MBo) 705 751 522 Recovery Factor (%) 8% 8% 7% Recovery Factor Based on 6 Well / 960 Acres (880’ Spacing)LS WC A WC B Depth (TVD ft) 7,600 8,000 8,200 Gross Thickness (ft) 345 225 275 Net Thickness (ft) 216 177 165 Effective Porosity 6.2% 6.6% 7.0% Core TOC (%) 2.2% 2.5% 2.8% HCPV (ft) 8.9 9.5 7.6 L. Spraberry Dean Wolfcamp A Wolfcamp B L. Wolfcamp Fred Phillips 19 #2 pg. 29


 
CONFIDENTIAL HORIZONTAL INVENTORY SPACING 6 3 4 0 ’ 1 5 0 ’ 2 2 5 ’ 2 6 0 ’ De-Risked Bench Lower Spraberry Shale Wolfcamp A Wolfcamp B Base Upside 5 6 6 6 6 6 6 pg. 30


 
CONFIDENTIAL Surface Casing: 13 3/8", 54.5#, K-55, BT&C Hole Size: 17 1/2" set @ 450' 9 5/8" Stage tool @ 4,000' MD Intermediate Casing: 9 5/8", 40#, HCK-55, BT&C set @ 6,150' , 0 degs Hole Size: 12 1/4"" to 6,150' MD (base of Clearfork) Production Casing: Start of Build Section Start of Horizontal Section 5½", P-110,20#, GeoCon BT&C @ ~ 6,566' MD @ 7,900' MD set @ 15,600' MD Hole Size: 8 3/4" from 6,150' to TD Lower Spraberry Formation TD: 15,600' 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 ─ 7,700’ lateral 1  Frac Design ─ slick water ─ plug and perf method ─ 48 frac stages ─ 1,600 lbs/ft proppant in cost est. ─ 2,000 lbs/ft proppant planned Single Well Capex M$ Drill 1,874 Complete 3,667 Equip / Artificial Lift 332 Total 5,873 1) perf-to-perf length pg. 31


 
CONFIDENTIAL MIDLAND BASIN COMPLETIONS FRAC DESIGN EVOLUTION Generation Stg Length Clstr Spacing Avg # Clstrs lbs / ft Cluster / Stage Avg Tot Prop 1 200 – 250 50 – 60’ 150 1000 – 1400 4 – 5 9,000,000 2 200 – 240 50 – 60’ 150 1400 – 1600 4 – 5 11,250,000 3 150 – 180 15 – 40’ 325 1800 – 2200 5 – 8 15,000,000 Generation 1 Generation 2 Generation 3 pg. 32


 
CONFIDENTIAL DRILLING & PRODUCTION CORRIDOR Key Points  Maximize productive drain hole length  Production Corridors ─ capital efficiencies ─ LOE efficiencies pg. 33


 
CONFIDENTIAL CENTRALIZED PRODUCTION FACILITIES Key Points  Facilities Design ─ consolidates 36 wells ─ Significant per-well savings ─ reduces vessel count from 370 to 70 ─ lower electricity costs due to employing primary electrical systems ─ single point monitoring of processes and well operations ─ low cost system redundancies  Oil sold via LACT at location pg. 34


 
CONFIDENTIAL FRAC WATER MANAGEMENT PLAN Key Points  Frac Pit Water Storage ─ Jo Paul: 450 Mbbls ─ Central: 850 Mbbls ─ McNew: 650 Mbbls ─ Middle Pit: 1,200 Mbbls ─ Total storage: 3,150 Mbbls  Frac Water Pipeline Infrastructure ─ 7.4 miles buried 8” line ─ 30 MBWPD transfer capacity  Frac Water Sources ─ fresh water o BBEP: 10 - 20 MBWPD o non-op: 10 - 20 MBWPD ─ other water o brackish(XRI): 20 - 40 MBWPD o recycled: 10 - 20 MBWPD  Water Requirements ─ 460 Mbbls / frac ─ 52 MBWPD / dedicated frac crew Middle Pit XRI pg. 35


 
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 ─ total capacity of 38 MBWPD  2017 Plans ─ drill 2 additional SWD wells ─ increase capacity by 50 MBWPD Lloyd SWD pg. 36


 
CONFIDENTIAL Key Points  Lease operating expenses based on extensive experience operating across the basin  Cost model; - variable: $2.00/bbl - fixed: $13,000 to $8,000 /month  Produced water disposal is the primary early LOE cost driver  Plan to dispose of produced water in operated SWD wells  Artificial lift method will be 2 rental ESP’s followed by the installation of 640 pumping unit  Gas Lift Evaluation ongoing for future artificial lift option Year ($ / 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. 37


 
CONFIDENTIAL PERMIAN EASTERN MIDLAND BASIN ESTIMATED PROFILE OF DEV PROJECTS (ALL 8,400’ AVG DEV LATERAL LENGTH) $0.20 $0.07 $0.23 $0.51 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 882.4 MMBOE Net Rsv 683.5 MMBOE % Oil 81.7 % % Gas 7.5 % WI: 94.94 % BPO % APO NRI: 72.26 % BPO % APO OBO: 20/15% Identified Inventory (OP/OBO): 60/202 Pot. Unidentified Inventory: 0 Max Projects per Year: 16 Gross CAPEX/Well: 6,223 $M Gross CAPEX/Facility: 306 $M* Lower Spraberry Hz Wolfcamp ‘A’ Hz WI: 94.94 % BPO % APO NRI: 72.26 % BPO % APO OBO: 20/15% Identified Inventory (OP/OBO): 60/202 Pot. Unidentified Inventory: 0 Max Projects per Year: 16 Gross CAPEX/Well: 6,223 $M Gross CAPEX/Facility: 306 $M* Wolfcamp ‘B’Hz $0.19 $0.07 $0.21 $0.54 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE WI: 94.94 % BPO % APO NRI: 72.26 % BPO % APO OBO: 20/15% EUR: 960.1 MMBOE Net Rsv 751.3 MMBOE % Oil 79.2 % % Gas 8.6 % Identified Inventory (OP/OBO): 60/202 Pot. Unidentified Inventory: 0 M x Projects per Ye r: 16 Gross CAPEX/Well: 6,223 $M Gross CAPEX/Facility: 306 $M* $(2,000) $- $2,000 $4,000 $6,000 $8,000 $10,000 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 $2.30 $2.87 $3.45 $4.02$1.72 $0.22 $0.07 $0.30 $0.41 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 669.3 MMBOE Net Rsv 523.7 MMBOE % Oil 79.2 % % Gas 8.6 % $(2,000) $- $2,000 $4,000 $6,000 $8,000 $10,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profil ROR, % PV10, $M $1.72 $2.30 $2.87 $3.45 $4.02 $(2,000) $- $2,000 $4,000 $6,000 $8,000 $10,000 0% 10% 20% 30% 40% 50% 60% $30.00 40.0 50.0 $60.0 $70.0 Flat Price per Bbl/Mcf Return Profil ROR, % PV10, $M $1.72 $2.30 $2.87 $3.45 $4.02 pg. 38


 
CONFIDENTIAL EASTERN MIDLAND BASIN pg. 39 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 CBP/DELAWARE BASIN OVERVIEW • ~104,300 gross acres / ~67,900 net acres – ~8,700 gross acres / ~5,300 net acres with horizontal potential rights • 4.8 MBoe/d of Q1 2017 net production – 1042 active producing wells • 2017 Capex: $7.5 MM (Assumes July 1 emergence) • M State Drilling – Abo/Drinkard Drilling – M State Glorieta Recompletions – Abandonments and Compliance • Mature Waterfloods ‒ East Fuhrman  Development Opportunities ‒ Cowden, N. ‒ Multiple CBP mature waterfloods • Primary development ‒ M State (CBP Western Margin) ‒ Quito, E. (Delaware Basin) Asset Highlights M State Quito, E. E. Fuhrman Current Development Plan2017 Dev Wells M State Drlg M State Glor 2017 2 0 2018 2 0 2019 2 0 2020 2 5 2021 10 5 Multiple waterflood enhancement projects pg. 40


 
CONFIDENTIAL M STATE LEASE DEVELOPMENT • 3,000 acre JV with XTO in Lea Co. NM • BPO 100%/75% • APO 65%/56.875% • 180 day continuous development • Primarily Abo, Drinkard, Blinebry • Secondary: Devonian, Glorieta • 2016 Activity – Strong Results • M State 18 & M Fee 21-1 • Continuous improvement increases type curve • 2017 Proposed Activity • M State 20 - Target spud date April, 2017, • M State 11 – Target Spud October, 2017 Leasehold Map Acreage Position Production History PROD PUD PROB POSS 2017 Drill 2016 Drill M State 20 Deep rights only M State 18 M Fee 21-1 M State 11 pg. 41


 
CONFIDENTIAL M STATE LEASE – GEOLOGIC SETTING Asset Characterization Horizon – Offset Field Gross Oil [MBO] Gross Gas [MMCF] Equivalent [MBOE] Granite Wash - Wantz 78 430 150 Ellenburger – Brunson* 190 605 291 Simpson - Hare/Teague 129 260 172 Montoya - Cary 40 94 56 Fusselman – Brunson* 172 120 192 Silurian - McCormack 142 257 185 Devonian - Teague/Langley 169 1,000 336 Abo/Drink/Bline – BBEP* 148 740 271 Glorieta – BBEP PUD* 131 131 153 Offset Field EUR/Potential M State Upside • Multiple pay horizons from Glorietta to Ellenburger • Deeper reservoirs structurally controlled and stratigraphically sealed against regional unconformity • Historic Production from Abo/Drinkard/Blinebry • Seismic purchased to assist in assessment of deeper potential • Key potential in shallower Glorieta zones M State Structure Map pg. 42


 
CONFIDENTIAL M STATE – OPERATIONAL TRENDS Completions: Proppant Trends • Continued the improvements observed in the M State #18 Well • MSE technology applied to improve drilling efficiency, with similar great results • Cut 40% off previous drilling performance (days) • Resulted in better than 30% reduction in capital cost that leverages each additional location Drilling: Days vs Depth pg. 43


 
CONFIDENTIAL QUITO EAST AREA GEOLOGY pg. 44


 
CONFIDENTIAL QUITO EAST AREA ACREAGE, HZ TARGETS pg. 45


 
CONFIDENTIAL WOLFCAMP HORIZONTAL TYPE CURVE (119 WELLS) QUITO EAST AREA – WOLFCAMP HZ POTENTIAL ESTIMATED 10 0 10 00 10 00 0 10 00 00 Oil , bbl /m o Oil - Average curve 10 0 10 00 10 00 0 10 00 00 Oil , bbl /m o 5 10 15 No. of Months Oil Oil, bbl/mo Qual= Oil - 1 Ref= 4/2015 Cum= 0 Rem= 754805 EUR= 754805 Yrs= 100.000 Qi= 25880.5 b= 0.999980 De= 69.000000 Df= 0.985734 Qab= 115.7 IP=764 BOPD Di=69% B= 1.0 Dt=4% AVG EUR – 524 MBO (gross) Economic Summary 8000’ lateral $8.0 MM D&C (gross) Avg. WI: 35.3% NRI: 29.8% Net EUR: 258 MBOE ROR: 44.4% Payout 2.0 yrs PV10: $1.93 MM ($50/BO flat, $2.87/ MCF) Inventory: 8 Wolfcamp HZ pg. 46


 
CONFIDENTIAL EAST_FUHRMAN – GLORIETA 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. 47


 
CONFIDENTIAL PERMIAN CBP/DELAWARE BASIN ESTIMATED PROFILE OF DEVELOPMENT PROJECTS M State Abo/Drinkard Vt M State Glorieta Vt $(1,000) $- $1,000 $2,000 $3,000 $4,000 $5,000 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 $1.44 $2.30 $2.87 $3.45 $4.02 $0.11 $0.08 $0.28 $0.53 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 263.1 MBOE Net Rsv 231.2 MBOE % Oil 39.6 % % Gas 30.8 % WI: 100.00 % BPO 65.00 % APO NRI: 75.00 % BPO 56.88 % APO Identified Inventory: 23 Pot. Unidentified Inventory: 0 Max Projects per Year: 10 Gross CAPEX/Well: 1,775 $M Gross CAPEX/Land-Facility: 0 $M* $(1,000) $- $1,000 $2,000 $3,000 $4,000 $5,000 0% 10% 20% 30% 40% 50% 60% $30. 0 $40. 0 $50. 0 $60. 0 $70.00 Flat Price per Bbl/Mcf R turn Profile ROR, % PV10, $M $1.72 $2.30 $2.87 $3.45 $4.02 $0.12 $0.07 $0.35 $0.46 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 113.8 MBOE Net Rsv 82.3 MBOE % Oil 75.4 % % Gas 12.6 % WI: 100.00 % BPO 65.00 % APO NRI: 75.00 % BPO 56.88 % APO Identified Inventory (OP/OBO): 17 Pot. Unidentified Inventory: 23 Max Projects per Year: 10 Gross CAPEX/Well: 1,100 $M Gross CAPEX/Facility: 0 $M* pg. 48


 
CONFIDENTIAL CBP/DELAWARE BASIN pg. 49 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 ARKLATEX U. GULF COAST BASIN DIVISION IV


 
CONFIDENTIAL ARKLATEX OVERVIEW(1) ASSUMES JULY 1 EMERGENCE Net Production by Phase Net Reserves by Category Operating Plan Annual Projection Operating Plan Production Profile Year Production (MMBoe) CAPEX ($MM) LOE ($MM) 2017 3.3 33.8 45.9 2018 3.8 27.8 43.0 2019 3.6 23.4 43.5 2020 4.3 64.0 46.3 2021 6.2 93.8 51.0 Annual PDP Decline Jan. '17 - Jan. '18 (11.7%) Jan. '18 - Jan. '19 (9.0%) Jan. '19 - Jan. '20 (8.7%) Production Profile (Net Volumes) (1) Based on company operating projections and Jan 25, 2017 market strip pricing. Totals exclude East TX SWD and Postle condensate purchases pg. 51


 
CONFIDENTIAL ARKLATEX REGION OVERVIEW  125K gross, 82K net acres 1,524 Gross Producing wells  Q1 2017 Net Production: 9,462 BOED (49% Liquids)  120 wells available for immediate reactivation with higher commodity prices yielding additional 140 BOPD  Asset Mix: Low-decline oil and rich gas condensate fields  Primary Producing horizons: Cotton Valley, Woodbine, Travis Peak, Pettet, Haynesville sands & Smackover  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  2015 acquisition – drilling well #12 of 13  Hot Link Prospect  Potential for >30 locations  Currently leasing/acquiring farm outs  Evaluating/pursuing multiple CV AOIs  Potential for Acreage Swaps, farm-ins & new JV’s to unlock new value Asset Highlights Blocker/Oakhill/Carthage Major Field Areas Gladewater & ETOF Overton Dorcheat Shongaloo Homer Neches Current Development Plan pg. 52 2017 Dev Wells Overton Haynesville Other CV Hz Hot Link 2017 5 1 0 2 2018 0 0 0 2 2019 0 0 0 2 2020 0 0 14 2 2021 0 0 14 10


 
CONFIDENTIAL OVERTON OVERVIEW Overton Cotton Valley Taylor Activity Map Overview • Acreage: Approximately 10,000 gross acres, including ~3,000 acres acquired in 2015 • BBEP Q1 2017 Net Production: 3,427 BOED (30% Liquids) • Produces from Cotton Valley, Travis Peak and Pettet • 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 21 Horizontal wells through Q1 2017 • Drill & Complete 7 wells : $15.3MM – Includes 1 carryover well from 2016 • Facilities Maintenance: $70M • Total 2017 Capital Program: $15.4MM 2017 Plan (Assumes July 1 Emergence) AMI G R EE N BAY 1 6 H E C H A R D 9 H H A R M O N -C AME R O N 1 H C AME R O N -H A R M O N 1 H G R IMES 2 H D AV ID W IL S O N 1 1 H M C E L R O Y-S W A N N 2 H M C E L R O Y-S W A N N -M O O R E 2 H M C E L R O Y-S W A N N -M O O R E 1 H E C H A R D 7 H N E O 4 H S H CLICK 1 1 G R GISSOM 1 1 W E RUCKER 1 1 SAM CLICK 1 1 W E RUCKER 2 2 MILLER-RUCKER UNIT 1 1 E RUCKER A-1 A-1 JOHN RORK 1 1 G A TOMME 1 1 MRS R E BREEDLOVE 1 1 M C CHILES 1 1 AFTON THRASH 1 1 L L TAYLOR 1 1 L L TAYLOR 1 1 W HALE EST 1 1 MINIE O NEAL 1 1 MRS M H JONES 1 1 WILKINSON 1 1 A T ONEAL 1 1 ONEAL 1 1 A T ONEAL 1 1 R T WARD 1 1 J T TALLEY HEIRS 1 1 HAROLD WHITESIDE 1 1 KELLEY A D 8 8 KELLEY H D 9 9ANNIE KELLEY 4 4 ROZELLE RUDE 1 1 W E RUCKER 3 3 AFTON THRASH 1 1 AFTON THRASH 1 1 AFTON GLASPIE 1 1 F PRESTON HALL UNIT 2 2 DOUGLAS GRAY 1 1 L F THOMPSON 1 1 LOONEY 1 1 THRASH /CNVL/ GU 1 1 1 BARNES DAVID ALLEN 1 1 PINKERTON P C JR 1 1 CHILES 2 2 HALE EFFIE 1 1 NORTHCUTT EARL D 1 1 RUCKER WM LEON GU 1 1 1 MURPHY H J 1 1 CHILES ETAL GU 3 3 RUCKER W L GU 1 2 2 ARMSTRONG 1 1 MCGILL LARRY D 1 1 CHILES ETAL GU #B-1 1 1 BOMAR JOHN L P ETAL 1 1 BARRON GAS UN 1 1 SHUTTLESWORTH 1 1 WARD RUSSELL 1 1 WINNINGHAM GARLAND 1 1WINNINGHAM GARLAND 1-A 1-A TAYLOR LESTER 1 1 RUSSELL WARD 1 1 WARD RUSSELL 3 3 JAKUBIK 1 1 GRIMES 1 1 GRAY 1 1 AFTON THRASH UNIT 1 2 2 MCELROY A1 A1 MURRAY 1 1 MCELROY 1 1 REAGAN 1 1 BURTON 1 1 SIEBER 1 1 NORTHCUTT 2 2 MCELROY A2 A2 FLORENCE B A 1 1 WILKINSON 1 1 RUCKER 4 4 POND 1 1 CHILDRESS UNIT 1 1 CHILDRESS UNIT 1 1 NORTHCUTT 3 3JAKUBIK 2 2 JAKUBIK 3 3 RORK 1 1 TROUP 1D 1D HUFF 1 1 AFTON THRASH GAS UN 5 5 AFTON THRASH UNIT 1 3 3 JAKUBIK 4 4 MURPHY H J GAS UNIT 2 2 BARNES GAS UNIT 1 2 2 CHILES B 2 2 BARNES GAS UNIT 1 3 3 MCGILL 4 4 MCELROY A4 4 MCELROY A3 3 MCGILL 5 5 THOMPSON 1 1 AFTON THRASH UNIT 1 15 15 BARNES GAS UNIT 1 4 4 JAKUBIK 5 5 BARNES GAS UNIT 1 5 5 BARNES D A GAS UNIT 6 6 AFTON THRASH UNIT 1 4 4 AFTON THRASH UNIT 1 11 11 THRASH A CV GAS UNI 8 8 AFTON THRASH UNIT 1 10 10 JAKUBIK 6H 6H BARNES GAS UNIT 1 10 10 AFTON THRASH UNIT 1 6 6 THRASH A CV GAS UNI 7 7 BARNES GAS UNIT 1 15 15 BARNES D A GAS UNIT 18 18 THRASH AFTON UNIT 1 17 17 THRASH A `CV` GU 1 18 18 THRASH AFTON UNIT 1 12 12 CHILES GAS UNIT B-1 3 3 ARMSTRONG DEEP 1 1 RUCKER 5H 5H THRASH AFTON UNIT 1 14 14 THRASH AFTON UNIT 1 16 16 NORTHCUTT GAS UNIT 4 4 NORTHCUTT GAS UNIT 44 BARNES GAS UNIT 1 14 14 JAKUBIK 7H 7H BURNS 2 2 RUCKER WL GAS UNIT 6H 6H CORLEY RUTH 1 1 WALDROP MATTIE E W 1 1 MUD CREEK 1 1 RAY L C GAS UNIT 1 1 MORBY 1 1 MC MOYLE 1 1 THRASH AFTON 1 1 KIRKPATRICK W P 1 1 TUCKER /G/ 1 1 BRIGHT 1 1 DODD R M 1 1 ALLRED 1 1 COOK S S ESTATE 2 2 OVERTON GAS UNIT 3 2 2 GOOD OMEN PETTET UNI 52 52 BLACKWELL 1 1 POOLE 1 1 MOORE J W ETAL 1 1 ROBERSON UNIT 1 1 MAXIE WILSON 1 1 1 RUSHING J R 1 1 W P RUSHING 1 1 DR WILLINGHAM 1 1 W P RUSHING 3 3 WILLINGHAM 1 1 W P RUSHING 1 1 H C GRISSOM 1 1 J EARL TOWNS ETAL 1 1 TOWNS 40 AC UNIT #1 1 1 B D WARREN 1 1JOE T TOWNS 1 1 HAMMOND J A 1 1 WILLIE SMITH 1 1 CITY OF TYLER 1 1 J C MCRAE 1 1 R D FIELDS 1 1 LENNIS STOVALL 1 1 L T MARTIN 1 1 J JARVIS UNIT #1 1 1 HAMILTON R W 1-B 1-BHAMILTON-ROBERTS 1 1 D C MCRIMMON 3 3 D C MCRYMMON 4 4 R D FIELDS 1 1 S O BROOKS 2 2 S O BROOKS 3 3 S O BROOKS 1 1 J C SALMON 1 1 ROSS BONNIE ESTATE A-1 A-1 F L WARREN UNIT 1 1 D R SHAW 1 1 GRADY B WILSON 1 1 A BLEDSOE ETAL 1 1 BULLOCK 1 1 HITT M E 1 1 RONS-JARVIS UNIT 1 1 MOORE HUBERT ETAL 1 1 MCRIMMON D B 2 2 LYDIA ETAL 1 1 J CALDWELL ETAL 1 1 LANGHAM JACOB EST 2 2 HALMGTON B UNIT 1 1 LANGHAM 5 5LULA WILLIAMS UNT 3 3 D D PINKSTON 1 1 W MCCLENDON 1 1 ALBRED UNIT 1 1 NEAL DAVID 1 1 SMITH HRS 1 1 LANGHAM JACOB EST 4 4 WILLIAMS H G ETAL 1 1 WILKINSON FANNIE MAE B-1 B-1 MCRIMMON D B 1 1 SINCLAIR UNIT 1 1 J ALLRED 1 1 LANGHAM JACOB EST 1 1 JASPER J UNIT 1 1 WILSON JASPER 2 2 WILSON JASPER L 1 1 WILSON UNIT /B/ 1 1 WILSON UNIT 1 1 FANNIEMAE WILKERSON 1-B 1-B WILKINSON D-1 D-1 WILKINSON FANNIE MAE 2 2 WILKINSON F M ETAL 1 1 LANGHAM JACOB 3 3 WILLIAMS H G 2 2 WILKINSON 3 3 WARE J F 1 1 ECHARD 1 1 EDDIE HAMILTON 1 1 LOYS ARNOLD 1 1 B J WILSON 1 1 ARNOLD-DUNCAN UNIT 1 1 ALLRED 1 1 MCNEW BEN J 2 2 MCNEW BEN J 1 1 HAROLD HACKET ETAL 1 1 FANNIE M WILKINSON 1 1 JARVIS ESTATE 1 1 FRANKLIN H 1 1 BROWN MAYBELL ETAL 1 1 BROWN WRATHER B-1 B-1 ARNOLD DUNCAN UNT 2 1-P 1-P MAYFIELD-MCCLENDON 1-P 1-P LOYS ARNOLD 2 2 JACKSON UNIT 1 1 HAMILTON R W 1 1 FRANKLIN-SMITH UNIT 1 1 LOUELLA FORK 1 1 ELLIS UNIT 1 1 ELLIS C C 1 1 DUNCAN /B/ UNIT 1 1 D C MCRIMMON UNIT 1 1 COLLIER UNIT 1 1 DUNCAN UNIT 1 1 DANIELS JOSIE 1 1 DANIELS J 2 2 CRUTCHER UNIT 1 1 WARE ETAL UNIT 1 1 MCNEW 1 1 SANDERS JIM 1 1 ROBERTS 1 1 R W HAMILTON 1 1 D C MCRIMM 2 2 R W HAMILTON 2 2 LULU WILLIAMS UNIT 4 4 TRP INDEP SCHL DIST 1 1 H L MOORE 1 1 KARL M LARSEN 1 1 HENRY PEYTON 1 1 MARY E DOUGLAS 1 1 ANNIE WHITE 1 1 GRADY WILSON 1 1 LUTHER WILLIS 1 1 COLLIER J R 1 1 E F THOMPSON 1 1 MRS E JARVIS 1 1 LOYS ARNOLD 1 1 LYDIA MELVIN ETAL UN 1 1 WOOLF 1 1 MOLLIE WOOLF 2 2 ARTEXBURY UNIT 1 1 ARNOLD 1-A 1-A ARNOLD UNIT 2 1 1 J O DICKERSON 1 1ANDREWS-LYDIA UNIT P-1 P-1 TILLMAN-ANDREWS 1 1 LYDIA HEIRS 1-F 1-F JARVIS-WHITE UNIT 1 1 CHAPMAN-ANDERSON 1 1 JAMES FRANKLIN 1 1 LYNN RAY 1 1 D WRIGHT 1 1 THELMA WRIGHT 1 1 FEE 1 1 MRS EMMA FRAZER 1 1 J G COOK 1 1 B E WILSON EST ETAL 1 1 TLIFR-MSSLWHTE UN 1 1 1 BEULAH MEANS 1 1 FROMMER J J 3 3 GREEN J E 1 1 P M WILSON 1 1 C R WILSON 1 1 C GLENN HODGES 1 1 H A PACE/B/ 39 39 MRS M WILSON 1 1 R A TROUSDALE ESTAT 1 1 TRIMBLE FEE 1 1 LEON STEINBACK 1 1 ERVIN RUCKER 1 1 TRIMBLE T W 2 2 DAN FIELDS 1 1 MARGARET WALDROP 1 1 KARL W LARSON UNIT 1 1 DOUGLAS MARY HEIRS 1 1 OVERTON GAS UNIT 1 1 1 TARBUTTON J H EST 1 1 OVERTON GAS UNIT 3 1 1 W F JOHNSON GAS UN 1 1 FRED N GENTRY ETAL 1 1 S S COOK ESTATE 1 1 OVERTON GAS UNIT 12 1 1 MOLLIE WOOLF GU 1 1 MELTON 1 1 OVERTON GAS UNIT 14 1 1 OVERTON GAS UNIT 15 1 1 OVERTON GAS UNIT 16 1 1 ARNOLD GAS UNIT 1 1 OVERTON GAS UNIT 20 1 1 OVERTON GAS UNIT 21 1 1 ARNOLD GAS UNIT #2 1 1 ODOM JESSE RANDOLPH 1 1 PERRY GAS UNIT 1 1 1 WILSON VERNON GU 1 1 KICKAPOO CREEK GU 1 1 1 CHADWICK GAS UN 1 1 1 NEWSOME /A/ 1 1 POINTS 11 WARE J F #1 1 1 COLE WILLIAM A 1 1 ALLRED 1 1 WARREN SALLIE M HRS 1 BURKE FRANK 1 1 MCDONALD JOHN 1 1 MATLOCK 1 1 CORLEY 1 1 WILSON GRADY B 1 1 WALDROP GAS UNIT 1 10 10 ANDERSON MILTON GAS 16 16 WILSON DAVID G 2 1 1 HARMON 8 8 SWANN M C 13 13 ODOM JESSE RANDOLPH 4 4 KICKAPOO CREEK GAS U 12 12 WILSON VERNON GAS UN 12 12 WRIGHT GAS UNIT 1 9 9 MORBY UNIT 1 11 11 OVERTON GAS UNIT 20 4 4 OVERTON GAS UNIT 20 5 5 WILSON DAVID G 14 14 WILSON DAVID G 10 10 ECHARD HEIRS UNIT 5 5 PERRY GAS UNIT 1 6 6 KICKAPOO CREEK GAS U 15 15 ALLRED GAS UNIT 1 15 15 NEWSOME GAS UNIT 1 8 8 KIRKPATRICK GAS UNIT 4 4 NEWSOME GAS UNIT 7 7 WILSON DAVID G 15 15 NEWSOME A 9 9 CROSS JERRY GAS UNIT 10 10NEWSOME GAS UNIT 1 10 10 MCMOYLE UNIT 1 8 8 WOOLF GAS UNIT 1 17 17 ARNOLD GAS UNIT 2 15 15 NEWSOME UNIT 1 11 11 DOUGLAS 1 1 BARTON GAS UNIT 1 3 3 ARNOLD GAS UNIT 2 14 14 MORBY GAS UNIT 1 12 12 WILSON VERNON B GAS 16 16 WALDROP GAS UNIT 1 12 12 MCMOYLE GAS UNIT 1 11 11 PERRY GAS UNIT 1 8 8 CHALLENGER 1 1 ODOM JESSE RANDOLPH 5 5 MCMOYLE 14 14 WILSON GRADY GU 1 15 15 PERRY GAS UNIT 1 7 7 CROSS JERRY GAS UNIT 13 13 CROSS JERRY GAS UNIT 3 3 MCMOYLE UNIT 1 13 13 WILSON VERNON B GAS 17 17 KIRKPATRICK GAS UNIT 3 3 MCMOYLE UNIT 1 10 10 MORBY UNIT 1 14 14 MCMOYLE GAS UNIT 1 12 12 WILSON GRADY GAS UNI 14 14 KIRKPATRICK WILLARD 5 5 KICKAPOO CREEK GAS U 16 16 MORBY UNIT 1 15 15 KIRKPATRICK WILLARD 7 7 WARREN SALLIE M HEIR 9 9 WALDROP GAS UNIT 1 17 17 MORBY OU 18 18 MCELROY 12 12 NEWSOME UNIT 1 17 17 MCMOYLE UNIT 1 17 17 WARREN SALLIE M HEIR 12 12 ODOM JESSE RANDOLPH 6 6 KIRKPATRICK WILLARD 8 8 KIRKPATRICK GAS UNIT 6 6 MORBY OIL UNIT 1 1 WARREN SALLIE M HEIR 13 13 WALDROP MEW GAS UNIT 11 11 ODOM JESSE RANDOLPH 12 12 KIRKPATRICK GAS UNIT 10 10 WARE J F GAS UNIT 1 12 12 MCMOYLE UNIT 1 9 9 SHAW GAS UNIT 1 13 13 WYLIE HEIRS 1 1 WALDROP GAS UNIT 1 15 15 ARNOLD GAS UNIT 1 14 14 OVERTON N E UNIT 4 4 SWANN M C 14 14 CROSS JERRY GAS UNIT 5 5 NEWSOME A 12 12 OVERTON N E UNIT 5 5 MCGILL 6 6 WILSON DAVID G 17 17 STEPHENS GU 1 1 MCMOYLE UNIT 1 15 15 NEWSOME UNIT 1 13 13 WARE J F GAS UNIT 1 13 13 KIRKPATRICK GAS UNIT 9 9 WALDROP MEW GAS UNIT 13 13 OVERTON GAS UNIT 20 2 2 WARREN SALLIE M HEIR 11 11 ARNOLD GAS UNIT 2 13 13 CROSS JERRY GAS UNIT 15 15 ARNOLD GAS UNIT 2 16 16 SHAW GAS UNIT 1 10 10 CROSS JERRY GAS UNIT 12 12 ARNOLD GAS UNIT 2 12 12 ARNOLD GAS UNIT 2 11 11 ODOM JESSE RANDOLPH 15 15 ODOM JESSE RANDOLPH 7 7 DENSON ET AL 1 1 MCDONALD GAS UNIT 2H 2H ARNOLD GAS UNIT 1 17 17 MCMOYLE UNIT 1 16 16 WOOLF GAS UNIT 1 15 15 WALDROP GAS UNIT 1 14 14 WRIGHT GAS UNIT 1 13 13 CROSS JERRY GAS UNIT 16 16 OVERTON GAS UNIT 3 10 10 WOOLF MOLLIE GAS UNI 7 7 WRIGHT GAS UNIT 1 10 10 PERRY GAS UNIT 1 11H 11H WARE OIL UNIT 1 1 WILSON P M HEIRS UNI 7 7 WARREN SALLIE M HEIR 10 10 OVERTON NE UNIT 6 6 WARREN SALLIE M HRS 8 8 ECHARD HEIRS UNIT 6 6 ANDERSON MILTON GAS 17 17 ODOM J R GAS UNIT 1 13 13 GREEN BAY 11 11 ODOM J R GAS UNIT 1 17 17 DYER GAS UNIT 3H 3H WARREN SALLIE M HIER 14 14 WARREN SALLIE M HRS 15 15 STEPHENS GU 2H 2H STEPHENS GAS UNIT 2H 2H KIRKPATRICK GAS UNIT 15 15 KIRKPATRICK GAS UNIT 14 14 KIRKPATRICK GAS UNIT 12 12 CALICUTT 1 1 WRIGHT 2 2 ARNOLD GAS UNIT NO 2 2 2 CHADWICK GU NO 1 2 2 MORBY GAS UNIT 1 2 2 TUCKER "G" GAS UNIT 2 2 NEWSOME "A" GAS UNIT 2 2 OVERTON GAS UNIT 1 1 1 OVERTON GAS UNIT 15 2 2 PERRY GU 1 2 2 ARNOLD GAS UNIT 1-2 1-2 KICKAPOO CREEK GU 1 2 2 ALLRED GAS UNIT 1 2 2 WILSON P M HEIRS 1 1 ARP OIL UNIT 1 1 KLEUPPEL 1 1 ARP OIL UNIT 2 1 1 WOOLF MOLLIE GAS UNI 2 2 WARE GAS UNIT 1 2 2 MATLOCK CARRIE GAS U 2 2 BURKE FRANK M JR GU 2 2 WILSON VERNON B GU 1 2 2 WARREN SALLIE M HEIR 2 2 KICKAPOO CREEK GAS U 3 3 ARNOLD GAS UNIT 1 3 3 BRIGHT GAS UNIT 1 2 2 WARE J F GAS UNIT 1 3 3 WILSON P M HEIRS UNI 2 2 MATLOCK CARRIE GAS U 3 3 ALLRED GAS UNIT 1 3 3 WILSON GRADY GAS UNI 2 2 WILSON JASPER GAS UN 1 1 WILSON VERNON B GAS 3 3 BURKE FRANK GAS UNIT 3 3 ECHARD HEIRS 1 1 ANDERSON MILTON GAS 1 1 WOOLF GAS UNIT 1 3 3 CROSS JERRY GAS UNIT 1 1 KICKAPOO CREEK GAS U 4 4 WALDROP GAS UNIT 1 2 2 MATLOCK CARRIE GAS U 4 4 WILSON VERNON B GAS 4 4 WILSON DAVID G 1 1 BURNS 1 1 PERRY VIRGINIA GAS U 3 3 WILSON JASPER GAS UN 2 2 ANDERSON MILTON GAS 2 2 ARNOLD GAS UNIT 1 4 4 CAMERON 1 1 WARREN SALLIE HEIRS 3 3 WILSON JASPER GAS UN 3 3 WOOLF MOLLIE GAS UNI 4 4 LINTNER 1 1 ANDERSON MILTON GAS 3 3 WILSON P M HEIRS UNI 3 3 ALLRED GAS UNIT 1 4 4 CROSS JERRY GAS UNIT 2 2 WILSON GRADY GU 1 3 3 WILSON JASPER GAS UN 4 4 WARE J F GAS UNIT 1 4 4 WARE J F GAS UNIT 1 5 5 MCRIMMON GAS UNIT 1 1 1 ARNOLD GAS UNIT 2 3 3 WILSON DAVID G 2 2 WOOLF MOLLIE GAS UNI 5 5 JACKSON GAS UNIT 1 1 1 ANDERSON MILTON GAS 4 4 BRIGHT GAS UNIT 1 3 3 GREEN BAY 1 1 WILSON P M HEIRS GAS 4 4 WALDROP GAS UNIT 1 3 3 CORLEY 2 2 ALLRED GAS UNIT 1 5 5 BRIGHT GAS UNIT 1 4 4 PERRY GAS UNIT 1 4 4 ARNOLD GAS UNIT 2 4 4 BRASWELL 1 1 WILSON DAVID G 3 3 MCRIMM GAS UNIT 1 2 2 LYLES 1 1 WILSON JASPER GAS UN 5 5 ARN LD GAS UNIT 1 5 5 ANDERSON MILTON GAS 5 5 SWANN M C 1 1 WRIGHT GAS UNIT 1 2 2 MCRIMMON GAS UNIT 1 3 3 MCRIMMON GAS UNIT 1 4 4 WILSON JASPER GAS UN 6 6 KLEUPPEL 1 1 ARNOLD GAS UNIT 1 6 6 ANDERSON MILTON GAS 6 6 KICKAPOO CREEK GAS U 6 6 WILSON JASPER GAS UN 7 7 ALLRED GAS UNIT 1 6 6 CORLEY 3 3 WOOLF GAS UNIT 1 6 6 WILSON DAVID G 1 TP 1 TP WRIGHT GAS UNIT 1 4 4 WRIGHT GAS UNIT 1 3 3 GREEN BAY 2 2 LYLES 2 2 LYLES 4 4 LYLES 3 3 WOOLF GAS UNIT 1 9 9 WILSON DAVID G 2TP 2TP MCRIMMON GAS UNIT 1 5 5 MCRIMMON GAS UNIT 1 6 6 WRIGHT GAS UNIT 1 5 5 ANDERSON MILTON GAS 7 7 WILSON VERNON B GAS 5 5 GUTHRIE 1TP 1TP SWANN M C 2 2 CORLEY 4 4 GREEN BAY 3 3 ARNOLD GAS UNIT 1 7 7 MATLOCK CARRIE GAS U 6 6 DUNCAN HEIRS UNIT 1H 1H WILSON VERNON B GAS 6 6 GREEN BAY 4 4 SWANN M C 3 3 SHAW GAS UNIT 1 1 1 WILSON G B GAS UNIT 4 4 ALLRED GAS UNIT 1 8 8ALLRED GAS UNIT 1 7 7 KIRKPATRICK GAS UNIT 2 2 WILSON DAVID G 4 4 ARNOLD GAS UNIT 2 5 5 WARE J F GAS UNIT 1 6 6 CROSS JERRY GAS UNIT 4 4 CHADWICK GAS UNIT 1 3 3MCRIMMON GAS UNIT 1 7 7 KICKAPOO CREEK GAS U 7 7 BARTON GAS UNIT 1 1 1 JACKSON GAS UNIT 1 2 2 WILSON VERNON B GAS 7 7 WILSON 1 1 NEWSOME UNIT 1 3 3 WARE J F GAS UNIT 1 7 7 MOORE 1 1 GREEN BAY 5 5 GREEN BAY 6 6 MATLOCK CARRIE GAS U 5 5 JACKSON GAS UNIT 1 4 4 KICKAPOO CREEK GAS U 5 5 LYLES 5 5 ARNOLD GAS UNIT 2 6 6 SHAW GAS UNIT 1 2 2 JACKSON GAS UNIT 1 7 7 ANDERSON MILTON GAS 8 8 WILSON GRADY GAS UNI 5 5 DYER 1 1 GUTHRIE 1 1 MOORE 2 2 LYLES 6 6 CAMERON 2 2 OVERTON GAS UNIT 3 3 3 KLEUPPEL A 2 2 WILSON JASPER GAS UN 8 8 WARE J F GAS UNIT 1 8 8 MCRIMMON GAS UNIT 1 10 10 WOOLF MOLLIE GAS UNI 8 8 OVERTON GAS UNIT 3 4 4 WOOLF MOLLIE GAS UNI 10 10 ALLRED GAS UNIT 1 9 9 MCELROY 1 1 GREEN BAY 7 7 BURKE FRANK M JR GAS 5 5 KICKAPOO CREEK GAS U 8 8 MATLOCK CARRIE GAS U 7 7 WILSON VERNON B GAS 9 9 SHAW GAS UNIT 1 3 3 WRIGHT GAS UNIT 1 6 6 BURKE FRANK M JR GAS 7 7 WILSON JASPER GAS UN 11 11 WILSON JASPER GAS UN 9 9 MCRIMMON GAS UNIT 1 8 8MCRIMMON GAS UNIT 1 9 9 WILSON VERNON B GAS 8 8 CALICUTT 1 1 MCRIMMON GAS UNIT 1 11 11SHAW GAS UNIT 1 6 6 ARNOLD GAS UNIT 1 8 8 WILSON P M HEIRS GAS 5 5 OVERTON GAS UNIT 3 6 6 OVERTON GAS UNIT 3 5 5 SHAW GAS UNIT 1 5 5 MCMOYLE UNIT 1 2 2 BRIGHT GAS UNIT 1 5 5 ALLRED GAS UNIT 1 10 10 CITY OF TYLER 1 1 ANDERSON MILTON GAS 10 10 KICKAPOO CREEK GAS U 9 9 OVERTON GAS UNIT 15 3 3 BARTON GAS UNIT 1 2 2 ARNOLD GAS UNIT 2 8 8 MATLOCK GAS UNIT 1 9 9 TUCKER G GAS UNIT 3 3 ODOM JESSE RANDOLPH 2 2 BURKETT 1 1 ANDERSON MILTON GAS 13 13 WILSON JASPER GAS UN 13 13 PERRY GAS UNIT 1 5 5 WILSON JASPER GAS UN 12 12 MCRIMMON GAS UNIT 1 13 13 HARMON 1 1 MCMOYLE 3 3 JACKSON GAS UNIT 1 5 5 SHORES GAS UNIT 1 1 ANDERSON MILTON GAS 11 11 CROSS JERRY GAS UNIT 6 6 BRIGHT GAS UNIT 1 6 6 KICKAPOO CREEK GAS U 10 10 MCRIMMON GAS UNIT 1 12 12 CAMERON 3 3 SWANN M C 4 4 MCELROY 3 3 MCELROY 2 2 BURKE FRANK M JR GAS 10 10 ANDERSON MILTON GAS 9 9 ALLRED GAS UNIT 1 14 14 MORBY UNIT 1 3 3 BURKE FRA K M JR GAS 8 8 WILSON JASPER GAS UN 14 14 BURKE FRANK M JR GAS 9 9 WILSON JASPER GAS UN 10 10 BRIGHT GAS UNIT 1 8 8 CROSS JERRY GAS UNIT 7 7 MOORE 3 3 MATLOCK 11 11 WILSON G B GAS UNIT 6 6 CROSS JERRY GAS UNIT 9 9 MATLOCK 8 8 GREEN BAY 12 12 WRIGHT GAS UNIT 1 7 7 BRIGHT GAS UNIT 1 7 7 LINTNER 2 2 MCGILL G GAS UNIT 2 2 LINTNER 3 3 BURKE FRANK M JR GAS 16 16 MATLOCK CARRIE GAS U 15 15 GUTHRIE 2 2 TUCKER G GAS UNIT 4 4 GREEN BAY UNIT 9 9 KLEUPPEL GAS UNIT 3 3 WILSON VERNON B GAS 14 14 BURKE FRANK M JR GAS 4 4 WARREN SALLIE M GAS 4 4 CROSS JERRY GAS UNIT 11 11 BURKE FRANK M JR GAS 12 12 WILSON GRADY GAS UNI 7 7 WRIGHT GAS UNIT 1 8 8 MORBY UNIT 1 4 4 CROSS JERRY GAS UNIT 8 8 GREEN BAY 14 14 BURKE FRANK M JR GAS 11 11 WILSON P M HEIRS GAS 6 6 MCELROY 4 4 CAMERON 4 4 RAY L C GAS UNIT 1 2 2 BURKE FRANK M JR GAS 15 15 WARE GAS UNIT 1 10 10 BRIGHT GAS UNIT 1 9 9 ALLRED GAS UNIT 1 12 12 WALDROP GAS UNIT 1 4 4 MORBY GAS UNIT 1 5 5 JACKSON GAS UNIT 1 9 9 MCMOYLE 5 5 GREEN BAY 15 15 ECHARD HEIRS 13 13 MORBY GAS I 1 6 6 JACKSON GAS UNIT 1 8 8 MCMOYLE 4 4 WILSON DAVID G 5 5 MORBY 7 7 MCRIMMON UNIT 1 15 15 MCELROY 5 5 DAVIS SHARON 1 1 OVERTON GAS UNIT 3 7 7 ANDERSON UNIT 1 1 STEWART 1 1 MCELROY 8 8 MCELROY 13 13 MCELROY 10 10 LINTNER 17 17 MORBY 8 8 ANDERSON MILTON GAS 15 15 BURKETT 3 3 WOOLF MOLLIE GAS UNI 11 11 BURKE FRANK M JR GAS 13 13 WILSON VERNON B GAS 11 11 ALLRED GAS UNIT 1 13 13 OVERTON GAS UNIT 3 8 8 OVERTON NORTHEAST UN 9 9 MCRIMMON UNIT 1 16 16 WILSON DAVID G 7 7 WILSON GRADY GAS UNI 9 9 SWANN M C 5 5 WILSON GRADY GAS UNI 8 8 SWANN M C 7 7 KICKAPOO CREEK GAS U 11 11 WOOLF MOLLIE GAS UNI 14 14 WILSON JASPER GAS UN 15 15 BURKE FRANK M JR GAS 14 14 MCELROY 7 7 BRIGHT GAS UNIT 1 10 10 WILSON JASPER GAS UN 16 16 BRIGHT GAS UNIT 1 11 11 WARE J F GAS UNIT 1 9 9 WALDROP GAS UNIT 1 6 6 SHAW GAS UNIT 1 7 7 OVERTON NE UNIT 8 8 SHAW GAS UNIT 1 8 8 MCELROY 9 9 WILSON DAVID G 6 6 CAMERON 9 9 ARNOLD GAS UNIT 1 9 9 MCMOYLE UNIT 1 6 6 GREEN BAY 13 13 BRIGHT GAS UNIT 1 15 15 MCDONALD 1 1 MCGILL 3 3 BRIGHT GAS UNIT 1 13 13 CROSS JERRY GAS UNIT 14 14 ANDERSON MILTON GAS 14 14 WALDROP GAS UNIT 1 5 5 BRIGHT GAS UNIT 1 12 12 WARREN SALLY GAS UNI 5 5 LINTNER 5 5 WILSON G B GAS UNIT 11 11 SWANN M C 10 10 WARREN SALLIE M HRS 7 7 SWANN M C 12 12 SWANN M C 11 11 LINTNER 6 6 WILSON B J 1 1 ECHARD HEIRS 1616 SWANN M C 6 6 WILSON VERNON B GAS 13 13 MORBY GAS UNIT 1 10 10 BRIGHT GAS UNIT 1 16 16 MATLOCK CARRIE GAS U 16 16 MATLOCK CARRIE GAS U 14 14 POOLE 2 2 ANDERSON MILTON GAS 12 12 SWANN M C 9 9 MORBY UNIT 1 9 9 BRIGHT GAS UNIT 1 14 14 SHAW GAS UNIT 1 9 9 WARE J F GAS UNIT 1 11 11 NEWSOME GAS UNIT 1 4 4 WILSON VERNON B GAS 15 15 KICKAPOO CREEK GAS U 14 14 WARREN SALLIE M HEIR 6 6 NEWSOME UNIT 1 5 5 ECHARD HEIRS UNIT 4R 4R ODOM J R GAS UNIT 1 3 3 WOOLF MOLLIE GAS UNI 13 13 ARNOLD GAS UNIT 1 11 11 MOORE 4 4 KICKAPOO CREEK GAS U 17 17 MUD CREEK GAS UNIT 2H 2H MOORE 5 5 SWANN M C 8 8 WALDROP GAS UNIT 1 8 8 MCRIMMON GAS UNIT 1 14 14 WALDROP GAS UNIT 1 7 7 OVERTON GAS UNIT 3 9 9 COLE 2 2 NEWSOME GAS UNIT 1 6 6 MCMOYLE GAS UNIT 1 7 7 ARNOLD GAS UNIT 1 16 16 LYLES 7 7 WILSON GRADY GAS UNI 10 10 WILSON G B GAS UNIT 12 12 ARNOLD GAS UNIT 2 10 10 WILSON DAVID G 8R 8R WILSON DAVID G 13 13 WILSON DAVID G 9 9 MCELROY 11 11 MOORE 6 6 WILSON DAVID G 12 12 MCELROY 6 06 JACKSON GAS UNIT 1 11 11 WILSON GRADY GAS UNI 13 13 WALDROP GAS UNIT 1 9 9 WARE J F GAS UNIT 1 16 16 ARNOLD GAS UNIT 2 9 9 MORBY UNIT 1 13 13 OVERTON GAS UNIT 16 3 3 OVERTON GAS UNIT 16 4 4 ARNOLD GAS UNIT 1 15 15 WILSON GRADY GAS UNI 16 16 RUCKER 3 3 CHILES 3CHILES ETAL GAS UNI 3 BARRON 1 JAKUBIK 9H 9H ARMSTRONG 1 1 RUCKER WL GAS UNIT 7H 7H ROBERSON 1 CROS JERRY OIL UNIT 4RC RC WO LF 1-R -R WRIGHT 3 3 WRI HT 1WRIGHT 1-C -C JOHNSON W F GAS UNIT 1 OVERTON GAS UNIT 11 1 G B WILSON G S UNIT 1 RAY L C 1 OVERTON GAS UNIT 11 2 CROSS JERRY GAS UNIT 8 8 6 6 3 3 4 4 RUCKER WL GAS UNIT 8H 8H GRAY 2 2 GRAY 2 OIL UNIT 2 Guthrie Wilson Lintner 1H 1H CHILES GAS UNIT B-1 5H 5H CHILES 4H 4H CHILES 5H 5H WYLIE HEIRS 1H 1H CHILES GAS UNIT B-1 4H 4H GUTHRIE 5H 5H ECHARD HEIRS 8H 8H CHILES GAS UNIT B-1 6H 6H CHILES 6H 6H CHILES GAS UNIT B-1 7H 7H 1 1 1 LINTNER-WILSON GAS 1H 1H Lintner Guthrie 1H 1H junk GUTHRIE-WILSON GU AL 1H 1H 2H Overton N E 3H 3H CHILES GAS UNIT B-1 5H 5H 4 1 3 3 3 2 2 2 2 MURRAY-MCELROY A 1H 1H CAMERON GAS UNIT 5H 5H MURRAY-POND-GRAY 1H 1H LINTNER-WILSON GAS 2H 2H LINTNER-GUTHRIE-PETR 1H 1H GREEN BAY - ECHARD 1H 1H 1H 1H REAGAN-BLACK STONE- 1H 1H WILKINSON - MCELROY 1H 1H MCELROY-GUTHRIE-WIL 1H 1H MURRAY-MCELROY A 2H 2H BURNS 3H 3H POOLE 5H 5H WOOLF MOL IE 1 1 WILSON P M HEIRS 3 ARNOLD JAMES 1 W OLF MOLLIE 1 9 WOOLF MOLLIE 1 8 3 OIL WELLOVERTON 3 OIL 6 POOLE 2 2 WILSON DAVID G 8 OVERTON GAS UNIT #3 9 #2 OVERTON GAS UNIT #3 10 MCALVAIN 1 1 MCALVAIN 2 2 MCELROY-SWANN ALLOC 1H 1H CAMERON GAS UNIT 5H MURRAY-POND-GRAY A 2H 2H THOMPSON 2H2H McELROY `A` - WILKINSON 1H 1H MCELROY 'A' - MURRAY 1H 1H REAGAN-BLACK STONE- 2H 2H 1H 1H MALDONADO-MURRAY 1H 1H POND-GRAY 1H 1H 2H 2H 2 POND 2H 2H OH W G U 2 -C -L 1 H M U R R AY-P O N D -G R AY 2 H M C E L R O Y "A "-W IL K IN S O N 1 H M C E L R O Y "A "-M U R R AY 1 H MA L D O N A D O -M U R R AY 1 H P O N D -G R AY 1 H R EA G A N -B L A C KS T O N E- W IL K IN S O N 2 H P O N D 2 H FEET 0 2,000 PETRA 4/11/2017 8:29:00 AM Drilled 2017 WO Comp. 2017 Future East Texas Gas Region BBEP Windsor Newly Acq. pg. 53


 
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. 54


 
CONFIDENTIAL Type Curve Parameters • EUR/FT = 1.05 MMCF/FT (Mean) • Oil Yield= 15 BBL/MMCF (remaining locations) • Di: 79% Dmin: 5% b value: 1.1 • Lateral length = 4,865’ • IP: 9.5 MMCFPD • EUR: 5.1 BCF & 77 MBO (Gross) • D&C Cost $4.8MM • Continually seeing cost reductions OVERTON HORIZONTAL COTTON VALLEY TYPE CURVE PROFILE Overton Type Curve Gross Capital ($MM) Net EUR (MBOE) ROR (%) NPV10 ($M) Development Cost ($/BOE) Overton Type Curve $4.8 387.6 30% $ 1,098 $6.19 * Economics run on at $50/Bbl and $2.87/Mcf flat strip pg. 55


 
CONFIDENTIAL - 500 1,000 1,500 2,000 2,500 3,000 3,500 - 10,000 20,000 30,000 40,000 50,000 60,000 70,000 01/2014 01/2015 01/2016 01/2017 01/2018 01/2019 D ai ly O il (B O P D ) D ai ly G as ( M C FP D ) 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: 5 MMCFPD & 37 BCPD  June 2016 Gross Production: 65 MMCFPD & 1,500 BCPD Overton - Gross Production and Forecast Condensate Yield Map (BBL/MMCF) Overton Field 2015: 2-Rigs 2016: 1-Rig 2017: 1-Rig 2014: Begin Hz program (1-Rig) 2016: Drop Rig pg. 56


 
CONFIDENTIAL COTTON VALLEY TAYLOR EXPANSION Overview  Leveraging off of success and experience in Overton Development area  Identified prospective areas with  Thick Cotton Valley Taylor sands  High condensate yield  Success acquiring acreage through:  Bolt-on acquisitions  Farm outs  Primary term leasing  Gladewater area  Prospect area 20,750 gross acres (9,368 net acres controlled leasehold)  Current horizontal inventory: 39 locations  Bolt-on opportunities Additional Opportunities Gladewater Area Overton Development Area  Evaluating additional growth opportunities: Haynesville Shale, Travis Peak, Pettet, James Lime, and Goodland Lime pg. 57


 
CONFIDENTIAL 30 Locations - Type Curve Parameters • EUR/FT = 0.99 MMCF/FT (Risked Mean) • Oil Yield= 30 BBL/MMCF (Mean) • Di: 75.4% Dmin: 6% b value: 1.2 • Lateral length = 6,000’ • Risked Gross IP: 7.8 MMCFPD • Risked EUR: 5.9 BCF & 178 MBO Gross • D&C Cost $5.4 MM Development Capacity • 2017: Prove Concept • D&C 2 Wells and monitor production • 2018-2021: Continuous Rigline • 8 Wells/Rig/Year HOT LINK - HORIZONTAL COTTON VALLEY ESTIMATED # of Locations Gross Capex ($M) Net EUR (MBOE) ROR (%) NPV10 ($M) Development Cost ($/BOE) 2017 D&C Plan 2 $10,878 1,902 48.3% $9,548 $5.72 2017 Land and Facilities - $4,000 - - - - Total Project Development 30 $175,010 29,933 37.4% $97,089 $5.85 Normalized to 6000’ * Economics run on at $50/Bbl and $2.87/Mcf flat strip Hot Link (Risked: 0.99 MMcf/ft) Overton Analog (1.33 MMcf/ft) Overton Analog Chapel Hill (Risked) 3 -Day IP (MMcf) 10.5 7.8 EUR/ft (MMcf/ft) 1.33 0.99 EUR (Bcf) 8.0 6.0 Di 75.4% 75.4% b-factor 1.2 1.2 Dmin 6% 6% Hot Link pg. 58


 
CONFIDENTIAL HOT LINK TAYLOR STRATIGRAPHIC CROSS- SECTION Hot Link OVERTON (WINDSOR) Limestone Cap Bossier Shale Source W-M 1HLOCATION 2 5 0 ’ 5 0 ’ *Wilkinson-McElroy 1H (South Overton) 30d IP 11.5 MMcf/d & 567 BCPD pg. 59


 
CONFIDENTIAL EAST TEXAS OIL FIELD OVERVIEW  Discovered in 1930  Production zone: Woodbine Sands at 3,500’  Original oil in place: > 7 billion STB  Cumulative production: > 5.5 billion STB  Shallow base production decline  Low-cost field SWD gathering and reinjection system (ETSWD)  Hundreds of low cost and low risk uplift opportunities  Deepening's, RTP’s, and ESP upgrades  February 2017 net production: 1,769 BOEPD (100% liquids)  Uneconomic wells were shut-in during 2015 and early 2016  Beginning in early 2017, wells returned to production as economics justified  Current 2017 plan: $4,031M  20 ESP upgrades: $1,000M  P&As: $1,110M  Facilities: $1,921M 2017 Plan (Assuming July 1 Emergence) Overview pg. 60


 
CONFIDENTIAL EAST TEXAS OIL FIELD OPPORTUNITIES  Deepenings: 95  ESP upgrades: 100 Future Opportunities (2017 and Beyond)  RTP: 71  New drill: 1  Clean Outs: 3 0 1,000 2,000 3,000 4,000 5,000 6,000 G ro ss O il P rod u ction , S TB P D Historical PDP Forecast Wedge Forecast Wells Shut-in Due to Low Oil Prices pg. 61


 
CONFIDENTIAL SHONGALOO LOWER HAYNESVILLE INFILL POTENTIAL Haynesville Sands Type Log • Acreage, Gross/Net: 8,525 / 6,575 acres • WI/NRI: 88/68% • February 2017 net production: 787 BOED (40% liquids) • Produces primarily from the Haynesville Sand • Current spacing >70 ac (no recent drilling activity) • Lower permeability sands – required massive hydraulic fracturing in the 1990’s • Potential for 50 infill locations using current completion practices Estimated economics: • Gross D&C Cost: $2.4 MM • Unrisked gross EUR/well: 3.0 BCF and 48 MSTB • ROR: 39% • Total potential reserves: 28 MMBOE Overview Shongaloo pg. 62


 
CONFIDENTIAL SHONGALOO UPPER HAYNESVILLE HZ POSS A B C D UHNVL LHNVL pg. 63


 
CONFIDENTIAL OAK HILL HAYNESVILLE SHALE POTENTIAL ANADARKO LETOURNEAU #12 Haynesville Shale Bossier Shale CV Taylor Sands Target Interval Haynesville Lime Haynesville Type Log Non-Op Int. OAK HILL AREA Contingent Ac. 2015 Budget Overview - Gross acreage: 4,615 ac - Net acreage: 4,594 ac (HBP) - Average WI/NRI: 100% / 74% - Ownership: All depths - 60 BBEP operated vertical wells - Current production zones: Cotton Valley - Feb 2017 net production: 413 BOED (15% Liq.) Haynesville Shale Horizontal Potential - Expected landing depth: 11,700’ - Average CLL: 6,000’ - Spacing: 660’ between wells - Gross interval: >300’ - Offset drilling by Anadarko and Sabine - Recent larger fracs have resulted in better EUR’s - 33 PROB locations - 9 PROB contingent joint venture wells - Potential to purchase bolt-on acreage and drill venture wells with partners Oak Hill pg. 64


 
CONFIDENTIAL HARRISON AND PANOLA COUNTIES NORMALIZED GAS EUR VS PROPPANT LOADING High proppant load wells (15 wells) Filter Settings - County: (HARRISON, PANOLA) - CLL, ft: (2062 <= CLL, ft <= 9555) - Proppant Loading, lbs/CLL: (1008.79 <= Proppant Loading, lbs/CLL <= 10562.67) without empty values pg. 65


 
CONFIDENTIAL HAYNESVILLE SHALE EST. UPSIZED FRAC - TYPE CURVE ECONOMICS Upsized Frac Type Curve/ft CLL Cash flow assumptions • Lateral length: 6,000’ • Operating costs • Capital cost: $6.5 MM • Fixed cost: $2,000/month • WI / NRI: 100% / 74% • Water disposal: $0.25/bbl • Shrink: 0.97 (residual) • GTC: $0.20/MCF • Yield: 0 STB/MMSCF 6,000’ Type Curve Economics (Upsized Fracs) Gross D&C Cost: $6.5 MM Gross Qi: 12.5 MMcf/d Gross EUR/ft CLL: 1,274 MMcf Gross EUR: 7,644 MMcf ROR: 27% NPV10: $2,237 M Locations: 33 Upsized Fracs Mean = 1,274 MMcf/ft Oak Hill Direct Offsets Mean = 768 MMcf/ft pg. 66


 
CONFIDENTIAL ARKLATEX ESTIMATED PROFILE OF DEVELOPMENT PROJECTS ETX Cotton Valley Hz ETX Haynesville Hz Shongaloo Haynesville Vt WI*: 100.00 % BPO % APO NRI*: 78.00 % BPO % APO * Varies by area EUR: 1,175.3 MBOE Net Rsv 995.9 MBOE % Oil 14.0 % % Gas 68.6 % $0.06 $0.05 $0.27 $0.62 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE Identified Inventory (OP/OBO): 86 Pot. Unidentified Inventory: 32 Max Projects per Year: 16 Gross CAPEX/Well: 5,440 $M Gross CAPEX/Facility: 333 $M** $- $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 $1.72 $2.30 $2.87 $3.45 $4.02 $- $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 0% 10% 20% 30% 40% 50% 60% $30.00 4 5 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $1.72 $2.30 $2.87 $3.45 $4.02 $0.15 $0.05 $0.42 $0.37 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 1273.8 MBOE Net Rsv 914.3 MBOE % Oil 0.0 % % Gas 100.0 % WI: 100.00 % BPO % APO NRI: 74.00 % BPO % APO Identified Inventory (OP/OBO): 40 Pot. Unidentified Inventory: 0 M x Projects per Year: 14 Gross CAPEX/Well: 6,500 $M Gross CAPEX/Facility: 44 $M* $- $2,000 $4,000 $6,000 $8,000 $10,000 $12,000 0% 10% 20% 30% 40% 50% 60% $30. 0 $40. 0 $50. 0 $60. 0 $70.00 Flat Price per Bbl/Mcf R turn Profile ROR, % PV10, $M $1.72 $2.30 $2.87 $3.45 $4.02 $0.21 $0.06 $0.27 $0.47 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 544.8 MBOE Net Rsv 446.0 MBOE % Oil 8.0 % % Gas 67.1 % WI: 100.00 % BPO % APO NRI: 74.37 % BPO % APO Identified Inventory (OP/OBO): 57 Pot. Unidentified Inventory: 0 M x Projects per Year: 12 Gross CAPEX/Well: 2,369 $M Gross CAPEX/Facility: 0 $M* pg. 67


 
CONFIDENTIAL ARKLATEX pg. 68 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 ENHANCED OIL RECOVERY DIVISION V


 
CONFIDENTIAL EOR OVERVIEW(1) ASSUMES JULY 1 EMERGENCE Net Production by Phase Net Reserves by Category Operating Plan Annual Projection Operating Plan Production Profile Year Production (MMBoe) CAPEX ($MM) LOE ($MM) 2017 3.2 48.3 69.9 2018 3.3 34.9 76.4 2019 3.2 36.5 78.0 2020 3.0 34.1 78.0 2021 3.1 54.2 78.6 Annual PDP Decline Jan. '17 - Jan. '18 (8.5%) Jan. '18 - Jan. '19 (11.6%) Jan. '19 - Jan. '20 (10.3%) Production Profile (Net Volumes) (1) Based on company operating projections and Jan 25, 2017 market strip pricing. Totals exclude East TX SWD and Postle condensate purchases pg. 70


 
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 PUD, PROB & POS drilling opportunities  Postle & NEHU –10+ years of development tertiary locations  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  Capacity expansion for accelerated development pace  Libby Ranch – CO2 Source field  Supplies necessary CO2 for all PUD development  Big Escambia Creek (Non-op): Pressure Depletion Gas-Cond.  2016 daily avg. net production 9.3 MBoe/d from 500 wells  Reduced Opex by 23% in 2016  Focus on horsepower usage and efficiency  Reduced well failure rates from root cause failure analysis (RCFA)  Focus on consumable spend rate; chemicals, parts, etc. Asset Highlights Fields With Potential Future Projects Postle & NEHULibby Ranch Jay/LEC BEC Current Development Plan2017 Dev Wells Postle Pat NEHU Pat Jay Drill Jay RC 2017 0 2 2 5 2018 0 2 0 5 2019 6 2 0 5 2020 12 2 0 0 2021 8 2 7 0 pg. 71


 
CONFIDENTIAL GREATER POSTLE PROJECT INVENTORY Project Project Count Capex per Pattern ($M) IP (Bopd) EUR per Pattern (MBoe) ROR $50/bbl Flat Deck PV-10 ($M) NEHU PUD Pattern 6 +20 Probable $1,934 (CO2) 102 190 86% $1,178 Postle Tier 1 PUD Pattern 8 $1,500 DC&C $4,836 (CO2) 82 601 23% $2,800 Postle Tier 2 PUD Pattern 72 $1,500 DC&C $3,366 (CO2) 62 415 19% $1,591 Postle PUD Pattern – A1 & A2 Targets 121 0 200 GAMMA_RAY -300 -5 SP (CTR) 5 15 CALIPER 30 0 CORE_PHI_DS 0.3 0 PHIE_1 0.02 2000 CORE_KMAX_DS 0.1 1000 FOCUSED 0.1 1000 DEEP_IND 0.1 1000 SHALL_IND MAR_ATOP [DAM] MAR_A_BASE [DAM] MAR_A2TOP [DAM] MAR_A2_BASE [DAM] MAR_A1TOP [DAM] MAR_A1_BASE [DAM] 61 0 0 61 5 0 62 0 0 62 5 0 63 0 0 Subsea Depth(ft) Subsea Depth(ft) -2750 -2750 -2760 -2760 -2770 -2770 -2780 -2780 -2790 -2790 -2800 -2800 -2810 -2810 -2820 -2820 -2830 -2830 -2840 -2840 -2850 -2850 -2860 -2860 -2870 -2870 -2880 -2880 -2890 -2890 -2900 -2900 -2910 -2910 -2920 -2920 -2930 -2930 -2940 -2940 -2950 -2950 -2960 -2960 -2970 -2970 POSTLE HS=0 PETRA 4/11/2017 9:01:58 AM ‘A’ Sand 85% Developed Porosity Avg 15% Perm Avg 26 md ‘A1’ Sand 15% Developed Porosity Avg 14% Perm Avg 11 md ‘A2’ Sand 3% Developed Porosity Avg 14% Perm Avg 13 md NEHU PUD Pattern Water Patterns 2017 CO2 Patterns CO2 Patterns  Postle Complex OOIP 460 MMBO  Postle Field processing rate 2-10 times faster than typical Permian San Andres floods  PUD pattern consists of new injector to target A1 & A2 and associated CO2  Existing production wells are open in lower A1 & A2 sands  NEHU only requires CO2 capex pg. 72


 
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 • 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 ‘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 pg. 73


 
CONFIDENTIAL 100 1,000 10,000 100,000 G ro ss Dai ly Pr o d u ctio n ( B OP D ) Postle/NEHU Field Oil Production 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 pg. 74


 
CONFIDENTIAL POSTLE FUTURE EXPANSION OPPORTUNITIES • Sufficient CO2 already available to complete the projects at Postle and N.E. Hardesty • Increased CO2 capacity from Libby Ranch expansion or other contracts means: • Ability to expand CO2 injection to other fields in the area with similar CO2 needs • EUR potential of incremental 30 MMBO from other projects. Field Reservoir Cum Prod MMBO Postle Windows Morrow 0.0 Postle SE Expansion Morrow 0.0 Interstate Morrow 19.0 Carthage Topeka 13.4 Carthage NE Morrow 6.2 Camrick, Gas Morrow 11.8 Rice/Burton SE Morrow 4.0 pg. 75


 
CONFIDENTIAL GREATER POSTLE FIELD pg. 76 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 JAY PROJECT INVENTORY ESTIMATED ECONOMICS Project Project Count Capex per Pattern ($M) IP (Bopd) EUR per Project (MBoe) ROR $50/bbl Flat Deck PV-10 ($M) Jay PDNP 22 +10 Probable $750 75 230 56% $1,117 Jay PUD (no facilities) 12 $4,135 160 637 23% $2,040 Jay PUD (with facilities) 23 +15 Probable $5,685 160 637 14% $596 St Regis TF – 70 acres & 90,000+ BHP(1) Air Separation Facility – N2 Generation Ja y - St R egis T re at in g Facili ty Ja y - Fl o m at o n AS U (1) Estimate includes 22,000 BHP located at ASU facility  Current RF of 45% (OOIP 1,029 MMBO)  Over 200 MMB of mobile unswept oil  Analogous fields have high RFs  Wildfork Creek 63%  South Burnt Corn Creek 68%  West Appleton 65%  Appleton 68% pg. 77


 
CONFIDENTIAL Future Drill Wells (35) JAY FIELD – 2017 CAPITAL PLAN ASSUMING JULY 1 EMERGENCE Fraction of Pay - High Reservoir Quality 2014-2015 Drill Wells (5) 2017 Plan Total Reserve IRR @ Capex ($MM) (MBoe) Flat $50 PNP Projects 6.2 2,081 73% PUD Wells 5.8 910 16% Plant & Facility 12.6 2,633 35% TOTAL 24.6 5,624 39% 2018+ Inventory PNP PUD PRB POS Wells Wells Wells Wells 13 34 15 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% pg. 78


 
CONFIDENTIAL 100 1,000 10,000 100,000 1,000,000 1/ 1 97 0 1/ 1 97 2 1/ 1 97 4 1/ 1 97 6 1/ 1 97 8 1/ 1 98 0 1/ 1 98 2 1/ 1 98 4 1/ 1 98 6 1/ 1 98 8 1/ 1 99 0 1/ 1 99 2 1/ 1 99 4 1 /1 9 9 6 1/ 1 99 8 1/ 2 00 0 1/ 2 00 2 1/ 2 00 4 1/ 2 00 6 1/ 2 00 8 1/ 2 01 0 1/ 2 01 2 1/ 2 01 4 1/ 2 01 6 1 /2 0 1 8 1/ 2 02 0 1/ 2 02 2 1/ 2 02 4 1/ 2 02 6 1/ 2 02 8 1/ 2 03 0 1/ 2 03 2 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 ESTIMATE AS OF YE2016 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. 79


 
CONFIDENTIAL JAY PATTERN MATURITY 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 Jay/LEC Unit Dimensionless Oil Vs. Total Inj % OOIP Pattern 1A Pattern 1B Pattern 2A Pattern 2B Pattern 3A Pattern 3B Pattern 4A Pattern 4B Pattern 5AB Jay Field Average Inactive Active – Cum. 2A1AB 4B Cum. N2 Injection Pattern Under-Performance  Loss of Well Count  Limited N2 Injection  Limited Perforation Conformance  Pattern Development Targets: 1A, 1B, 2A & 4B Western & Southern Flanks pg. 80


 
CONFIDENTIAL GREATER JAY FIELD pg. 81 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 CALIFORNIA SAN JOAQUIN & LA BASINS DIVISION II


 
CONFIDENTIAL CALIFORNIA OVERVIEW(1) ASSUMES JULY 1 EMERGENCE Net Production by Phase Net Reserves by Category Operating Plan Annual Projection Operating Plan Production Profile Year Production (MMBoe) CAPEX ($MM) LOE ($MM) 2017 1.5 11.4 37.7 2018 1.5 3.5 37.4 2019 1.7 14.0 39.7 2020 1.6 11.1 39.4 2021 1.6 10.7 38.9 Annual PDP Decline Jan. '17 - Jan. '18 (7.3%) Jan. '18 - Jan. '19 (7.7%) Jan. '19 - Jan. '20 (7.5%) Production Profile (Net Volumes) (1) Based on company operating projections and Jan 25, 2017 market strip pricing. Totals exclude East TX SWD and Postle condensate purchases pg. 83


 
CONFIDENTIAL CALIFORNIA Asset Highlights Current Development Plan • 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 • Recompletions, artificial lift upgrades, waterflood optimization, deeper horizon exploitation, facility expansion – 2.5 billion Bbl OOIP, 1.5 billion Bbl remaining • 3,985 BOEPD Q1 2017 net production – 705 active wells: 517 Producers, 188 Injectors • 2017 capex: $ 10 MM (Assuming July 1 emergence) – $ 5 MM obligatory, mandatory & abandonment projects – $ 5 MM discretionary rate generating projects – 2017 projects include: • Belridge Subsidence Mitigation and Producer Re-Fracs • Recompletions, injector profile modifications, and artificial lift optimization projects in SFS, E. Coyote, and Sawtelle Fields 2017 Dev Wells Belridge SFS RC 2017 0 12 2018 0 7 2019 10 7 2020 10 7 2021 10 7 Multiple waterflood enhancement projects per year pg. 84


 
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) 2,200 Boe/d Plan Reserves (100% oil)(1) 12.8 MMBoe % PDP 63% Key Operating Statistics (1) Based on company operating projections and Jan 25, 2017 market strip pricing. pg. 85


 
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. 86


 
CONFIDENTIAL SANTA FE SPRINGS PRODUCTIVE INTERVAL(S) • Productive interval consists of 6000’ of massive channelized fan deposits and interbedded sand/shale sequences • Active program exploiting by-passed oil in recompleted wellbores • Drilling potential targeting favorable structure and secondary oil accumulation in largely abandoned West flank of field 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. 87


 
CONFIDENTIAL SFS DRILLING POTENTIAL ESTIMATED Hathaway 200 Isochore Green Outline shows Volumetric Area Red Circles are other potential drill locations Fee Acreage (Exp 4/18) WEST SIDE DRILL POTENTIAL Proposed BH TVD 8500’ (LSF 200) 100% GWI / 81.25% NRI Nordstrom – Secondary Targets (4930’) HW 200 – Primary Target (7540’) Project: Santa Fe Springs Vert Target: Pliocene (Hathaway/Nordstrom) Division: 2 Type: Drilling - Directional COO/S: 100% Vital Statistics Identified Inventory (OP/OBO): 5 WI: 100.00 % BPO Pot. Unidentified Inventory: 25 % APO Max Projects per Year: 10 NRI: 81.25 % BPO Gross CAPEX/Well: 2,080 $M % APO Gross CAPEX/Facility: 0 $M* * Allocated per well Type Curve Parameters Primary Phase: Oi EUR: 179.1 MBOE Initial Rate: 79 BOPD or MCFD Net Rsv 142.0 MBOE Dei: 56.0 %/yr % Oil 100.0 % Hyp Exponent: 1.40 % Gas 0.0 % Method: Tangent Determinal: 5.0 %/yr Margin Projection Basis GOR/Yield: 0.0 MCF/B or B/MMCF pg. 88


 
CONFIDENTIAL Belridge Diatomite Oil Isopach Current Spacing Remaining Locations 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 56 wells - 5/8 Acre Development Single Well Economics 650,000 $ Gross Cost Estimate Base Case Modeled on 2013 Program Results 46.2 MBOE net Reserve Potential 85 BOPD Initial Rate Add $50/Bbl Flat Pricing 40% IRR, $ 553 M PV10 BELRIDGE DRILLING POTENTIAL pg. 89


 
CONFIDENTIAL BELRIDGE RE-FRAC POTENTIAL A B C D E F G H G1 Original Comp Frac Original Comp Frac Original Comp Frac Original Comp Frac Original Comp Frac Original Comp Frac Proposed Add Frac Interval Proposed Add Frac Interval Proposed Add Frac Interval Belridge Re-Frac Program Adding Frac Intervals to the Original Completions of select 2013 and 2014 Production Well D&Cs 2017 Capital Program Includes DD-5, DDD-11, GGG-9, KKK-8, AA-8A, BBB-14 Three Stage Addition to Each Completion 175 M$/Well (100% BBEP WI) $1,050 M Total Allocated within the 2017 Capital Budget 15 BOPD Gross Build Up Anticipated (83% Net Interest) Timing of Work Dependent Upon Permitting 2013 and 2014 Production Well Results versus Logged Expectations pg. 90


 
CONFIDENTIAL CALIFORNIA EST. PROFILE OF DEVELOPMENT PROJECTS Santa Fe Springs Recomplete Santa Fe Springs Vt Belridge Opal ‘A’ Diatomite Vt $(1,000) $- $1,000 $2,000 $3,000 $4,000 $5,000 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 $1.72 $2.30 $2.87 $3.45 $4.02 $0.27 $0.05 $0.37 $0.32 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 179.1 MBOE Net Rsv 142.0 MBOE % Oil 100.0 % % Gas 0.0 % WI: 100.00 % BPO % APO NRI: 81.25 % BPO % APO Identified Inventory (OP/OBO): 5 Pot. Unidentified Inventory: 25 Max Projects per Year: 10 Gross CAPEX/Well: 2,080 $M Gross CAPEX/Facility: 0 $M* $(1,000) $- $1,000 $2,000 $3,000 $4,000 $5,000 0% 10% 20% 30% 40% 50% 60% $30.00 $40.0 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf Return Profile ROR, % PV10, $M $1.72 $2.30 $2.87 $3.45 $4.02 Greater than 100% ROR $0.40 $0.05 $0.08 $0.47 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 42.9 MBOE Net Rsv 38.9 MBOE % Oil 100.0 % % Gas 0.0 % WI: 100.00 % BPO % APO NRI: 93.25 % BPO % APO Identified Inventory: 65 Pot. Unidentified Inventory: 10 Max Projects per Year: 10 Gross CAPEX/Well: 150 $M Gross CAPEX/Land-Facility: 0 $M* $(1,000) $- $1,000 $2,000 $3,000 $4,000 $5,000 0% 10% 20% 30% 40% 50% 60% $30. 0 $40.00 $50.00 $60.00 $70.00 Flat Price per Bbl/Mcf R turn Profile ROR, % PV10, $M Poly. (ROR, %) $1.72 $2.30 $2.87 $3.45 $4.02 $0.14 $0.32 $0.53 $0.00 $0.20 $0.40 $0.60 $0.80 $1.00 $/$ REVENUE EUR: 55.4 MBOE Net Rsv 46.2 MBOE % Oil 86.2 % % Gas 13.8 % WI: 100.00 % BPO % APO NRI: 83.00 % BPO % APO Identified Inventory: 56 Pot. Unidentified Inventory: 0 M x Projects per Year: 10 Gross CAPEX/Well: 650 $M Gross CAPEX/Land-Facility: 0 $M* pg. 91


 
CONFIDENTIAL CALIFORNIA pg. 92 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 EASTERN – MI/IN/KY/FL-S MICHIGAN & GC BASINS DIVISION I


 
CONFIDENTIAL EASTERN OVERVIEW(1) ASSUMES JULY 1 EMERGENCE Net Production by Phase Net Reserves by Category Operating Plan Annual Projection Operating Plan Production Profile Year Production (MMBoe) CAPEX ($MM) LOE ($MM) 2017 3.1 8.7 49.9 2018 3.1 5.7 49.1 2019 3.1 12.2 38.4 2020 2.9 5.8 36.9 2021 2.8 1.7 36.2 Annual PDP Decline Jan. '17 - Jan. '18 (2.0%) Jan. '18 - Jan. '19 (10.2%) Jan. '19 - Jan. '20 (5.7%) Production Profile (Net Volumes) (1) Based on company operating projections and Jan 25, 2017 market strip pricing. pg. 94


 
CONFIDENTIAL MICHIGAN OVERVIEW • Breitburn is the largest gas producer in Michigan and one of the top producers in the Antrim Shale – 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) • 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 Current Development Plan (1) Estimated reserves based on December 31, 2015 SEC Reserve Report 2017 D v Wells Antrim RC MI Deep Drlg Antrim Up Drlg 2017 0 2 0 2018 0 1 0 2019 0 0 0 2020 0 0 0 2021 1 0 0 pg. 95


 
CONFIDENTIAL MI/IN/KY pg. 96 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 – WY/CO BIG HORN & GREEN RIVER BASINS DIVISION I


 
CONFIDENTIAL ROCKIES OVERVIEW(1) ASSUMES JULY 1 EMERGENCE Net Production by Phase Net Reserves by Category Operating Plan Annual Projection Operating Plan Production Profile Year Production (MMBoe) CAPEX ($MM) LOE ($MM) 2017 1.9 4.2 20.0 2018 1.9 4.2 18.3 2019 1.8 1.5 18.1 2020 1.7 0.6 17.9 2021 1.6 4.3 17.8 Annual PDP Decline Jan. '17 - Jan. '18 (6.3%) Jan. '18 - Jan. '19 (6.7%) Jan. '19 - Jan. '20 (6.9%) Production Profile (Net Volumes) (1) Based on company operating projections and Jan 25, 2017 market strip pricing. pg. 98


 
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) • 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 Current Development Plan (1) Estimated reserves based on December 31, 2015 SEC Reserve Report 2017 Dev Wells WY WF Proj 2017 2 2018 2 2019 2 2020 0 2021 2 pg. 99


 
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. 100


 
CONFIDENTIAL ROCKIES pg. 101 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 DIVISION I


 
CONFIDENTIAL SW FLORIDA pg. 103 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 SUPPLEMENT A


 
CONFIDENTIAL PERMIAN ACREAGE POSITION EVOLUTION OPERATED HORIZONTAL VS. TOTAL ACREAGE pg. 105 Total Acreage Horizontal Acreage 35% 45% 55% 65% 75% 6,000 8,000 10,000 12,000 YE 2014 YE 2015 YE 2016 April 2017 Pending Operated as % of Total Hz Acrea geAc res Operated Hz Acreage Non-Operated Hz Acreage Operated as % of Total Hz Acreage 18,000 20 22,000 24,000 YE 2014 YE 2015 YE 2016 April 2017 Pending Acres


 
CONFIDENTIAL PERMIAN ACREAGE POSITION EVOLUTION (CONT’D) OPERATED NET LATERAL FEET pg. 106 4Q 2015 2Q 2017 Total Operated (1) Total Operated Net Horizontal Locations (3 Primary Benches) 351 146 293 171 Average Net Lateral Well Length (ft.) 7,000 7,000 8,400 8,400 Net Lateral Feet 2,457,000 1,022,000 2,461,200 1,436,400 Operated % of Total 42% 58% (1) Approximation of operated locations, assuming ~90% operational control of 162 PDA (prior classification) locations.


 
CONFIDENTIAL PERMIAN ACREAGE POSITION DETAIL INITIAL ACQUISITION TO PRESENT Total Acreage Horizontal & Vertical/Wellbore Horizontal Development Acreage Retained Vertical/Wellbore Only Acreage Operated Horizontal Development Acreage Percentage Operated Horizontal Development Acreage Non-Operated Horizontal Development Acreage Percentage Non- Operated Horizontal Development Acreage Element & CrownQuest 1, et al Acquisition (July, 2012) 1 4,600 4,600 - N/A N/A CrownQuest 2, et al Acquisition (December, 2012) 1 9,800 5,200 - N/A N/A CrownQuest 3, et al Acquisition (December, 2013) 1 15,400 5,600 - N/A N/A Antares Acquisition (October, 2014) 1 19,100 3,700 - N/A N/A 2012- 2014 Leasing/Title Adjustments 3 18,951 (149) - - - Initial Acquisition Totals 18,951 18,951 - 6,883 36% 12,068 64% Pioneer Trade (June, 2015) 19,603 (157) 810 652 (810) Energen 1 Trade (August, 2015) 20,168 5 560 565 (560) Big Star Trade (September, 2015) 20,328 (7) 167 160 (167) Double Eagle 1 Sale for CO Production/Cash (September, 2015) 20,328 (1,266) 1,266 - (1,266) 2015 Leasing/Title Adjustments 3 20,914 176 410 40 136 Rock Oil 1 Trade (March, 2016) 21,474 7 553 560 (553) Diamondback 1 Trade (March, 2016) 21,580 2 104 106 (104) Rock Oil 2 Trade (October, 2016) 21,900 (9) 329 320 (329) XTO Trade (November, 2016) 21,980 (46) 126 80 (126) Double Eagle 2 Trade (November, 2016) 22,375 - 395 395 (395) 2016 Leasing/Title Adjustments 3 22,412 (15) 52 53 (69) Energen 2 Trade (January, 2017) 22,381 (138) 107 107 (244) Diamondback 2 Trade (April, 2017) 22,541 - 160 160 (160) April 2017 Presentation (P. 15) Totals 2 22,541 17,502 5,039 10,080 58% 7,422 42% 2017 Leasing/Title Adjustments 3 22,230 151 (462) (69) 220 Current Acreage Totals (as of 4/24/2017) 22,230 17,653 4,577 10,011 57% 7,642 5 43% Conoco Trade (court approved- pending closing) 4 22,390 - 160 160 (160) SM Energy Trade (court approved - pending closing) 4 22,790 - 400 400 (400) Guidon/Endeavor Trade (court approved- pending closing) 4 23,190 - 400 400 (400) CrownQuest Trade (court approved- pending closing) 4 23,865 - 675 675 (675) Post Court Approved Trade (pending closing) Totals 4 23,865 17,653 6,212 11,646 66% 6,007 5 34% Confidential Trades in Advanced Negotiations 4 24,327 - 462 462 (462) Non-Op to Operated Acreage Conversion due to Trades 6 24,327 - - 426 (426) Post Confidential Trades in Advanced Negotiations Totals 4 24,327 17,653 6,674 12,534 71% 5,119 5 29% Confidential Trades in Early Negotiations 4 26,007 - 1,680 1,680 (1,680) Post Confidential Trades in Early Negotiations Totals 4 26,007 17,653 8,354 14,214 81% 3,439 5 19% Total Non-Op Acreage Committed to, or in Negotiations to Commit to, Non-Op Joint Operating Agreements 387 Remaining Non-Op Acreage to Trade, Convert to Operated via Trade, or Participate in Non-Op Joint Development 3,052 1 - Acquisition totals for Horizontal Development Acreage are at closing estimates further adjusted by curative and due diligence efforts which are reflected in the Leasing/Title Adjustments 2 - April Presentation (P. 15) reflects the March 2017 Acreage Totals 3 - Leasing/Title Adjustments include the net of total additional leasing, lease expirations, and adjustments for any realized title defects or title benefits related to new surveys, curative, or due diligence 4 - Actual acreage traded at closing is subject to change to reflect actual acreage determined in title due diligence and/or other adjustments negotiated prior to closing 5 - Non-Op totals for Horizontal Development Acreage includes acreage committed to or under negotiation for commitment to Non-Op Joint Operating Agreements for initial/additional development within the next 12 months 6 - Actual acreage Converted due to Trades is subject to change to reflect actual strategically positioned acreage acquired in pending Trades pg. 107


 
CONFIDENTIAL SUPPLEMENT B


 
CONFIDENTIAL Reserve Summary Assumptions Pricing: • Reserve summary as of 1/1/17 • 05/19/2017 Strip Pricing (2017 – 2025+): • Oil: $51.05 / $51.02 / $50.27 / $50.53 / $51.37 / $52.57 / $53.88 / $54.72 / $55.26 • Gas: $3.40 / $3.11 / $2.88 / $2.86 / $2.90 / $2.95 / $3.03 / $3.10 / $3.18 / $3.25 / $3.34 / $3.42 / $3.51 Land: • The above reserves are estimates based on the following assumptions (refer to Permian Acreage Position Detail, Slide 3 of Supplement A [Page 107 of this document]) : • Includes acreage in “Current Acreage Totals (as of 4/24/2017)” • Includes acreage in “Post Court Approved Trade (pending closing) Totals” • Includes acreage in “Post Confidential Trades in Advanced Negotiations Totals” • Excludes acreage in “Post Confidential Trades in Early Negotiations Totals” • Uses the parameters in the column “With Acreage in Advanced Negotiations”, Slide 18 of April 19 Presentation [Page 18 of this document] PERMIAN EASTERN MIDLAND BASIN Total Net Reserves & Economics (MMBOE 6:1 conversion) Undisc Total 1P Total 3P LOE Capex Net Rev PV10 PDP PDNP PUD Proved % Liquids PROB POSS 3P % Liquids $MM $MM $MM $MM 05/19/2017 Strip Pricing 11.9 0.2 28.4 40.4 87.3% 252.0 32.0 324.4 91.3% 2,844.9 3,400.4 7,297.4 1,404.2 05/19/2017 Strip Pricing +10% 12.4 0.2 28.4 41.0 87.1% 252.6 32.1 325.7 91.3% 2,895.6 3,400.4 8,651.6 1,753.8 05/19/2017 Strip Pricing -10% 11.4 0.2 28.2 39.7 87.4% 245.9 20.6 306.3 91.3% 2,594.3 3,094.7 5,800.9 1,058.1


 
CONFIDENTIAL SUPPLEMENT C


 
Subject to Express Confidentiality Agreements LOCATION Gross Net Gross Net Gross Net NEW MEXICO – PERMIAN (DIV 2) M State (1) 680.0 680.0 2,360.0 - 3,040.0 680.0 WEST TEXAS – PERMIAN (DIV 2) Coahoma North 320.0 320.0 640.0 640.0 960.0 960.0 East Quito - Vertical (2a) 2,271.1 1,074.3 961.1 578.6 3,232.1 1,652.9 East Quito - Horizontal Bone Springs (2b) 320.4 260.2 2,271.0 1,330.6 2,591.4 1,590.8 East Quito - Horizontal Wolfcamp (2c) 120.0 90.0 2,471.4 980.2 2,591.4 1,070.2 East Fuhrman Area 4,842.0 4,842.0 - - 4,842.0 4,842.0 Garden City South - Vertical 440.0 440.0 200.0 200.0 640.0 640.0 Garden City South - Horizontal Lower Spraberry - - 640.0 640.0 640.0 640.0 Garden City South - Horizontal Middle Spraberry - - 640.0 640.0 640.0 640.0 Garden City South - Horizontal Wolfcamp A - - 640.0 640.0 640.0 640.0 East Cowden Grayburg Unit (includes NCU Non-Op) 2,689.2 955.5 - - 2,689.2 955.5 Sand Hills (includes University 31 Non-Op) 5,960.0 5,960.0 2,080.0 1,040.0 8,040.0 7,000.0 Turner Gregory Unit 1,371.0 1,341.6 2,020.0 1,976.6 3,391.0 3,318.2 Irion 3,257.4 3,181.0 - - 3,257.4 3,181.0 Total Effective Area Acreage (3) 21,591.1 18,464.6 12,563.5 8,666.0 34,154.5 27,130.6 Total Actual Area Acreage Position (4) 27,051.7 22,549.6 (1) Acreage figures reflect the XOM/Encore Farmout Agreement dated 12/11/2007. Breitburn has rights under this agreement to develop the remaining gross undeveloped acreage subject to continuous development obligations. (2a-2c) Net Acreage reflects the net record title acreage; outstanding historical contract areas may effectively change Breitburn's net acreage position. (3) Effective Acreage includes multiple drilling zones and is calculated by management, using geologic and industry judgment. (4) Actual Acreage is limited to surface acreage and does not reflect multiple drilling zones. DEVELOPED ACREAGE UNDEVELOPED ACREAGE TOTAL ACREAGE 1 of 1


 
CONFIDENTIAL SUPPLEMENT D


 
HIGHLY CONFIDENTIAL SUBJECT TO FRE 408 SUBJECT TO EXPRESS CONFIDENTIALITY AGREEMENTS Breitburn Energy Partners LP March Business Plan @ Strip 1/25/17 ($ in 000s, except as indicated) FY 2017 FY 2018 FY 2019 FY 2020 FY 2021 FY 2022 2017 2018 2019 2020 2021 2022 Average Price Assumptions: Oil Average Assumed Price ($/Bbl) 54.47$ 55.45$ 55.56$ 55.83$ 56.10$ 56.47$ Gas Average Assumed Price ($/Mcf) 3.43 3.10 2.88 2.87 2.89 2.90 Production: Oil Production (MBbl) 9,081 10,567 12,414 14,835 16,449 17,764 Gas Production (MMcf) 35,980 38,645 37,131 40,296 48,484 57,131 NGL Production (MBbl) 1,520 1,715 1,893 2,340 2,925 3,489 Total Production (MBOE) 16,598 18,722 20,495 23,892 27,455 30,775 Revenue: Oil, Gas, and NGL Revenue 608,348$ 693,238$ 783,398$ 933,954$ 1,059,888$ 1,167,052$ Realized Hedge Gains - - - - - - Other Revenue 17,557 17,732 17,784 17,642 17,567 17,562 Total Revenue 625,905$ 710,970$ 801,183$ 951,596$ 1,077,455$ 1,184,613$ Expenses: Lease Operating Expense 294,304$ 296,665$ 296,155$ 308,673$ 321,699$ 333,720$ District Expenses 26,420 31,417 33,104 34,097 35,638 36,707 Production Taxes 42,073 41,528 46,893 55,538 62,080 67,926 G&A Expense 54,069 60,951 63,829 66,647 69,482 72,315 Other Expenses 29,203 13,852 17,386 16,827 17,508 14,691 Unrealized Hedge Settlement Adjustment - - - - - - Adjusted EBITDA (Excl. Non-Cash Comp.) 179,836$ 266,557$ 343,815$ 469,814$ 571,048$ 659,253$ (-) Restructuring Payments (64,212)$ -$ -$ -$ -$ -$ (-) Oil and Gas Capital Expenditures (168,712) (245,711) (357,913) (377,082) (453,787) (541,341) (-) Acquisitions - - - - - - (-) Non-Oil and Gas Capital Expenditures (978) - - - - - (+/-) Change in Net Working Capital/Other 412,936 (13,884) (4,011) (16,008) 996 12,242 (+/-) Other Cash Expenses 0 (0) (0) (0) (0) (0) (+) Net Proceeds from Asset Sales - - - - - - Unlevered Free Cash Flow 358,871$ 6,962$ (18,110)$ 76,724$ 118,257$ 130,155$ DRAFT - Subject to Change Page 1 of 1


 
CONFIDENTIAL SUPPLEMENT E


 
CONFIDENTIAL G&A AND DISTRICT EXPENSE REDUCTION EFFORTS & OVERVIEW BREITBURN ENERGY PARTNERS LP NOVEMBER 2016 CONFIDENTIAL DRAFT SUBJECT TO FRE 408 DO NOT DISTRIBUTE


 
CONFIDENTIAL G&A EXPENSE


 
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. 1 G&A - HISTORICAL 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 $/BOE % Change (vs. YE '14) --- (19%) (26%) (26%) [1] 2014 G&A run rates primarily derived from Q1 '15. STIP amounts represented at 100% of target [2] Net cost reductions are calculated based on annualized run rate amounts and may materially vary from published f inancials [3] 2015 G&A run rates primarily derived from Q4 '15 . STIP amounts represented at 100% of target [4] 2016 G&A run rates derived from the second half '16 budget. STIP amounts represented at 100% of target [5] Payroll total excludes non-cash employee incentive compensation [6] PCEC Management Agreement fee applied against G&A only; agreement terminated as of June 30, 2016 [7] 2014 production run-rate is estimated utilizing Q1'15 in order to reflect the QRE merger, 2015 production f igure is a full-year actual, and 2016 is a full-year forecast pg. 2 G&A - HISTORICAL EXPENSE REDUCTIONS ($ millions, unless otherwise stated)


 
CONFIDENTIAL DISTRICT EXPENSE


 
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. 3 DISTRICT - HISTORICAL 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 $/BOE % Change (vs. YE '14) --- (18%) (21%) (21%) [1] 2014 District run rates primarily derived from Q1 '15. STIP amounts represented at 100% of target [2] Net cost reductions are calculated based on annualized run rate amounts and may materially vary from published f inancials [3] 2015 District run rates primarily derived from Q4 '15. STIP amounts represented at 100% of target [4] 2016 District run rates derived from the second half '16 budget. STIP amounts represented at 100% of target [5] Payroll total excludes non-cash employee incentive compensation [6] 2014 production run-rate is estimated utilizing Q1'15 in order to reflect the QRE merger, 2015 production f igure is a full-year actual, and 2016 is a full-year forecast pg. 4 DISTRICT - HISTORICAL EXPENSE REDUCTIONS ($ millions, unless otherwise stated)


 
DRAFT - CONFIDENTIAL Breitburn Energy Partners LP G&A and District Forecast Summary - March Business Plan DRAFT ($ 000s) Fcst. Fcst. Fcst. Fcst. Fcst. Fcst. Year Notes 2017 2018 2019 2020 2021 2022 Production (MBOE) (1) 16,371 18,542 20,315 23,712 27,275 30,595 Total Forecast G&A Expense (2) 57,738$ 60,951$ 63,829$ 66,647$ 69,482$ 72,315$ Total Forecast District Expense (2) 28,744 31,417 33,104 34,097 35,638 36,707 Total Forecast G&A and District Expense 86,483$ 92,368$ 96,933$ 100,744$ 105,120$ 109,022$ Total Forecast G&A Expense ($/BOE) 3.53$ 3.29$ 3.14$ 2.81$ 2.55$ 2.36$ Total Forecast District Expense ($/BOE) 1.76 1.69 1.63 1.44 1.31 1.20 Total Forecast G&A and District Expense ($/BOE) 5.28$ 4.98$ 4.77$ 4.25$ 3.85$ 3.56$ Capitalized Engineering ($/BOE) (0.35)$ (0.31)$ (0.30)$ (0.26)$ (0.23)$ (0.21)$ Gross District Expense ($/BOE) 2.10 2.01 1.93 1.70 1.54 1.41 Memo - Illustrative Allocation to Divisions (4) : Total Forecast District Expense (pre-Capitalized Engineering) (3) 34,411$ 37,253$ 39,115$ 40,289$ 42,015$ 43,276$ Capitalized Engineering (3) (5,666) (5,836) (6,011) (6,192) (6,378) (6,569) Division I - G&A Allocation 16,524$ 15,925$ 14,654$ 11,980$ 10,020$ 10,031$ Division II - G&A Allocation 12,672 10,626 10,291 8,989 8,383 7,959 Division IV - G&A Allocation 11,431 11,873 10,565 11,233 15,140 19,400 Division V - G&A Allocation 11,835 11,362 10,619 8,856 8,134 7,667 Division VI - G&A Allocation 5,277 11,166 17,700 25,588 27,805 27,259 Division I - District Allocation 9,316 6,340 6,209 5,875 5,669 5,091 Division II - District Allocation 7,874 6,872 6,946 6,881 6,935 4,040 Division IV - District Allocation 3,459 5,812 5,937 6,144 6,856 9,847 Division V - District Allocation 4,450 6,498 6,623 6,474 6,499 3,892 Division VI - District Allocation 3,646 5,894 7,389 8,722 9,678 13,836 Total Forecast G&A and District Expense (4) 86,483$ 92,368$ 96,933$ 100,744$ 105,120$ 109,022$ Division I - District Allocation (464)$ (1,279)$ (1,255)$ (1,240)$ (1,220)$ (1,231)$ Division II - District Allocation (1,232) (1,230) (1,225) (1,234) (1,237) (1,263) Division IV - District Allocation (1,678) (1,233) (1,257) (1,297) (1,369) (1,456) Division V - District Allocation (1,507) (1,119) (1,130) (1,129) (1,129) (1,154) Division VI - District Allocation (784) (975) (1,145) (1,292) (1,423) (1,466) Total Capitalized District Expense (4) (5,666)$ (5,836)$ (6,011)$ (6,192)$ (6,378)$ (6,569)$ (1) Assumed production is from the Company's draft March Business Plan (2) Forecast District and G&A Expenses exclude non-cash comp, advisory fees, and reorganization items, but include STIP at 100%, recoveries, and capitalized engineering, where applicable (3) Capitalized engineering is capitalized labor that is netted out of District Expense and added to Capital Expenditures (4) Divisional allocations are based on identifiable expenses (+) a pro-rata share of unidentifiable expenses based on production For Discussion Purposes Only Printed 5/24/2017 Page 1 of 1


 
CONFIDENTIAL SUPPLEMENT F


 
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


 
CONFIDENTIAL DRAFT MAY NOT BE DISTRIBUTED BEYOND DIRECT RECIPIENTS Rights Offering • A rights offering to raise a total of $1.0 billion of common equity (“New Common Stock”) in the Reorganized Debtors (the “Rights Offering”), on terms as set forth on Exhibit [•], and committed to pursuant to a backstop purchase agreement (the “Backstop Agreement”) − Purchase price based on a total enterprise value of the Debtors of $2,100 million − Rights to be exercised at a [16%] discount to post-money plan equity value, implying a buy-in equity value of approximately [$1,190 million] (the “Buy-In Equity Value”) • The Rights Offering will be backstopped by the existing Unsecured Noteholders set forth on Exhibit [•] (the “Initial Backstop Parties”) − Each holder of Unsecured Note claims which is an accredited investor as defined in Regulation D under the Securities Act (an “Eligible Noteholder”) shall have the right, exercisable for [20 business days] following the filing of a motion by the Debtors seeking approval for the Backstop Agreement, to elect to backstop its pro rata share (based upon the ratio of such holder’s Unsecured Note Claims to all Unsecured Note Claims) of the Rights Offering (each such holder, an “Additional Backstop Party”) − 35% of the New Common Stock to be sold pursuant to the Rights Offering shall be reserved for and purchased by the Initial Backstop Parties and any Additional Backstop Party − 65% of the New Common Stock to be sold pursuant to the Rights Offering shall be offered pro rata to all Eligible Noteholders (including the Initial Backstop Parties and any Additional Backstop Party) − Initial Backstop Parties to receive a fee equal to [8.0%] of Buy-In Equity Value, payable in New Common Stock • Equates to a fee of [9.5%] of the Rights Offering amount Illustrative Rights Offering Term Sheet I L L U S T R A T I V E R I G H T S O F F E R I N G T E R M S H E E T B R E I T B U R N E N E R G Y P A R T N E R S 1