BreitBurn Energy Partners L.P. NASDAQ: BBEP. Investor Presentation

Transcription

1 BreitBurn Energy Partners L.P. NASDAQ: BBEP Investor Presentation Halbert S. Washburn Chief Executive Officer November 2013

2 Forward Looking Statements Cautionary Statement Regarding Forward-Looking Information This presentation contains forward-looking statements relating to the Partnership s operations that are based on management's current expectations, estimates and projections about its operations. Words and phrases such as expected, anticipated, guidance, plans, 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 our control and are difficult to predict. These include risks relating to the Partnership s ability to complete the acquisition of the Whiting and related assets on the agreed terms and expected schedule; the Partnership s financial performance and results, availability of sufficient cash flow and other sources of liquidity to execute our business plan, 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, our ability to obtain sufficient quantities of CO 2 necessary to carry out our enhanced oil recovery projects, political and regulatory developments relating to taxes, derivatives and our oil and gas operations, risks relating to our acquisitions, 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, and if applicable, 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 this press release. 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. 2

3 BBEP: Key Investment Considerations E&P MLP 25 years of Successful Operatorship Predecessor founded in 1988, 2006 IPO Focus on acquisition, exploitation and development of oil and gas properties Enterprise value: ~$3.8 billion (1) High Quality MLP Assets Balanced portfolio of oil / gas reserves and production Long-lived oil and gas properties with ~15 year reserve life (2) ~190.8 MMBoe est. proved reserves 71% PDP 57% oil / 5% NGLs / 38% gas (2) Disciplined Acquisition & Exploitation-Oriented Growth Successfully closed 12 acquisitions since July 2011 totaling ~$1.8 billion 2012 acquisitions totaled > $600 million; 2013 YTD acquisitions totaled ~$864 million Recently completed oil-weighted acquisition in Oklahoma Panhandle and New Mexico from Whiting Oil and Gas for ~$834 million (3) Committed to Distribution Growth Distributions have increased for 14 consecutive quarters Distributions have increased 30% since Q Best in class distribution growth among E&P MLPs Conservative Capital Structure and Financial Flexibility Maintain solid liquidity profile and low leverage ratios over time Fund acquisitions with carefully conceived financing strategies designed to ensure liquidity while optimizing long-term cost of capital (1) Based on unit price as of November 8, 2013, cash of $2.8 million as of September 30, 2013 and total debt outstanding of $1.88 billion as of November 6, (2) Based on FY 2012 and Oklahoma Panhandle acquisition ( Whiting Acquisition ) which closed on July 15, (3) Subject to customary post closing adjustments. Excludes ~$30.2 million for the purchase of additional interests in the acquired assets from other sellers. 3

4 Geographically Diversified Asset Base Geographic Presence In Nine States BreitBurn Totals (1) Est. Proved Reserves: MMBoe Reserve Mix: 57% Oil / 5% NGLs / 38% Gas Production Mix: 56% Oil / 5% NGLs / 39% Gas (2) % Proved Developed: 78% R/P: ~15 years California 2012 Avg. Daily Prod.: 4,068 Boepd Est. Proved Reserves: 25.6 MMBoe % Proved Developed: 85% R/P: ~18 years Wyoming 2012 Avg. Daily Prod: 7,189 Boepd Est. Proved Reserves: 39.4 MMBoe % Proved Developed: 78% R/P: ~17 years Michigan 2012 Avg. Daily Prod.: 9,206 Boepd Est. Proved Reserves: 51.7 MMBoe % Proved Developed: 92% R/P: ~17 years Indiana and Kentucky 2012 Avg. Daily Prod.: 557 Boepd Est. Proved Reserves: 0.6 MMBoe % Proved Developed: 100% R/P: ~3 years Oklahoma and New Mexico BBEP Closed ~$864 million acquisition of Oklahoma Panhandle assets and associated midstream assets on July 15, Texas 2012 Avg. Daily Prod: 3,482 Boepd Est. Proved Reserves: 21.7 MMBoe % Proved Developed: 41% R/P:~22 years Florida 2012 Avg. Daily Prod.: 1,924 Boepd Est. Proved Reserves: 10.4 MMBoe % Proved Developed: 100% R/P: ~14 years (1) Reserves data based on BBEP s estimated proved reserves as of December 31, 2012, prepared by its independent reserve engineers, and management s internal estimate of proved reserves for the Whiting Acquisition as of June 30, (2) Production mix based on second half 2013 guidance issued on June 24,

5 Proven Business Strategy Since 1988 Operational Expertise Excellent industry experience and responsible management Strong track record of integrating acquisitions Significant history with BreitBurn assets Utilize fit-for-purpose technologies Acquisition Criteria Mature properties with large amounts of OOIP Consistent with current asset base Inventory of low-risk development opportunities Commodity diversity Balanced reserve base Shallow decline, long life reserves with low maintenance capital requirements Balanced reserve and production profile between oil and gas Visible growth through low-risk exploitation and development opportunities Reduced cash flow volatility due to consistent, high level of hedging 5

6 Successful Operating Plan that Pays Sequential Distribution Growth 14 consecutive quarters of distribution growth FY 2012 distribution growth of ~7% (1) Accretive Acquisitions Acquire assets that complement existing portfolio and are accretive to DCF/unit Strong Hedging Strategy Mitigate commodity price volatility, stabilize cash flow Add hedges added systematically and in conjunction with new acquisitions Organic Growth Opportunities Continuously review base business to identify growth opportunities Strong MLP Base Assets Exploit base business of long-life, low-decline, mature assets with predictable production profiles (1) Based on total FY 2012 distributions of $1.850 over total FY 2011 distributions of $

7 An Expanding Portfolio of Great MLP Assets Portfolio Highlights (1) Geographically diverse across 9 states, concentrated in mature basins with operations dating to 1800s Long-life (~15 years reserve life), low decline assets with predictable production profiles and organic growth opportunities Over 5,600 gross producing wells Brent based pricing for CA crude oil production Total acreage: ~925,000 gross; ~562,000 net acres Includes over 130,000 net acres in the Utica Collingwood (~85% held by production) Includes over 75,000 net acres in the developing A-1 Carbonate play in Michigan (~80% held by production) Extensive inventory of proved low-risk infill drilling, recompletion and development opportunities in core operational areas Growing Inventory of Proved Drilling Projects Increase Production Organically (1) Based on FY 2012 and Whiting Acquisition. 7

8 High Margin, High Growth Reserve Base Increased Focus on Oil Focus on expanding oil / liquids opportunities Acquisitions were key drivers of increased oil exposure 62% of estimated proved reserves are Oil / NGLs based on FY 2012 and Whiting Acquisition Long-term option on natural gas Liquids % of Estimated Proved Reserves 35% 62% 2010 FY Whiting Acquisition PUD % of Estimated Proved Reserves Expanded PUD Component Provides organic growth opportunity Large portfolio of proved and low risk potential drilling locations 9% 22% 2010 FY Whiting Acquisition 8

9 Operational Overview

10 Wyoming Operating Area Asset Overview Key Basins: Wind River, Big Horn, Green River, Powder River Wells first drilled in 1884; long, active production history Total acreage: 218,109 gross, 114,896 net Gross producing wells: 964 Medium gravity crude; Gas is high BTU (~1,150) High net revenue interest Low risk infill drilling opportunities Low lifting costs: ~$12.50/Boe Significant bolt on acquisition opportunities Discount to WTI for oil Discount to Henry Hub for gas Asset Map Park Big Horn Washakie Teton Hot Springs Fremont Sublette Lincoln Sweetwater Uinta Sheridan Crook Johnson Campbell Weston Natrona Converse Niobrara Platte Goshen Carbon Albany Laramie Estimated Proved Reserves by Resource Mix (1) 2012 Operational Highlights PDNP 5% PUD 22% PDP 73% Gas 47% Oil 53% Estimated proved reserves: 39.4 MMboe Production: 2,542 Mboe (44% oil) 2012 Capital Program $32 million (90% spent on oil wells) Drilled 20 productive development wells, 20 workovers, 6 recompletions Incremental net production added: ~950 Boe/d Completed bolt on acquisition of oil properties in the Big Horn Basin in central Wyoming from NiMin Energy Corp (June 2012) (1) Estimated proved reserves and production based on YE 2012 Reserve Report at SEC Prices. 10

11 Texas Operating Area Asset Overview Key Basin: Permian Operating Partner: CrownQuest (66% operatorship currently; 22% operatorship starting May 2013) Total acreage: 11,880 gross, 8,791 net Gross producing wells: 90; Avg. Working Interest: 70% 40 API oil Large inventory of proved undeveloped drilling locations and 20 acre downspacing opportunities Low lifting costs: ~$6.20/Boe Slight discount to WTI for oil Premium to Henry Hub for high BTU gas (~1,100) Asset Map Cochran Hockley Lubbock Crosby Dickens Yoakum Terry Lynn Garza Kent Ector Loving Winkler Ward Gaines Dawson Borden Scurry Fisher Andrews Crane Martin Midland Sterling Glasscock Upton Howard Mitchell Reagan Crockett Irion Coke Nolan Tom Green Schleicher Sutton BreitBurn Knott Area BreitBurn Zebulon Area Estimated Proved Reserves by Resource Mix (1) 2012 Operational Highlights PUD 59% PDNP 7% PDP 34% NGL 20% Gas 21% Oil 59% (1) Estimated proved reserves and production based on YE 2012 Reserve Report at SEC Prices. Estimated proved reserves: 21.7 MMboe Production: 315 Mboe (57% oil) Gas production is associated gas only 2012 Capital Program $16 million (100% spent on oil wells) Drilled 18 productive wells Incremental net production added: ~1,200 Boe/d Completed five separate acquisitions from CrownRock and Element Petroleum (July) and CrownRock, Lynden Energy, and Piedra Energy (December) 11

12 California Operating Area Asset Overview Key Fields: Santa Fe Springs, Belridge, East Coyote, Sawtelle Concentrated in large, complex oil fields within the Los Angeles and San Joaquin Basins Certain fields producing over 100 years Total acreage: 3,958 gross, 3,128 net Gross producing wells: 424 Medium gravity crude High net revenue interests Mature fields with low risk development opportunities and significant original oil in place Low decline rate and maintenance capex Brent based pricing, traded at a premium to WTI Belridge Asset Map San Luis Obispo Santa Barbara Ventura Sawtelle Rosecrans Kern Los Angeles Santa Fe Springs Orange East Coyote San Bernardino Brea Olinda Riverside San Diego Imperial Estimated Proved Reserves by Resource Mix (1) 2012 Operational Highlights PDNP 7% PUD 15% PDP 78% Oil 97% (1) Estimated proved reserves and production based on YE 2012 Reserve Report at SEC Prices. Gas 3% Estimated proved reserves: 25.6 MMboe Production: 1,183 Mboe (99% oil) Gas production is associated gas only 2012 Capital Program $47 million (100% spent on oil wells) Drilled 20 productive wells, completed 14 workovers, 1 recompletion Incremental net production added: ~1,400 Boe/d Acquisition of 320 acre Dow-Chanslor lease in Belridge oilfield from American Energy Operations (November) 12

13 Santa Fe Springs Field, CA Reservoir Characteristics Fine to coarse sands deposited in a deep-water turbidite environment Porosity ranges from 15-25%, permeability ranges from md, oil viscosities range from 0.3 to 3.8 cp Depths range from 3,500-9,100 with multiple stacked pay horizons Total field original oil in place ( OOIP ) 2,200 MMBO Cum oil production 630 MMBO (28.6%) New Well Log Deep Targets Operational Highlights 20 wells drilled in 2012; 20 wells scheduled in 2013 Over 100 potential drilling locations identified Drill well type curve IP 45 BOPD with >50% IRR 40% increase in field production since start of 2012 drilling program Recent deep completion IP 650 BOPD; 470 BOPD 3 week average New 3-D seismic expected to produce additional drilling opportunities Santa Fe Springs Field Classic MLP Asset with Significant Original Oil in Place and Organic Growth Opportunities 13

14 2013 Capital Program Summary 2013 expected capital program totals approximately $270 million Drill / re-drill 145 wells in 6 states Increase liquids production by over 100% from Q to Q Q Completed 54 gross (51.1 net) drill wells, 19 workovers and added ~2,730 boe/day in incremental net initial production Bulk of capital program will be spent from Q2 through Q4 Production ramp up in 2H 2013; December exit rate expected between 34,700 and 36,100 boe/day (including Whiting Acquisition) Capital Allocation by State ($ in Millions) YE 2013 Wells Drilled / Re-Drilled by State MI, $13 OK, $14 WY, 18 OK, 10 MI, 7 WY, $27 FL, 4 FL, $40 TX, $96 CA, 46 TX, 60 CA, $84 14

15 Acquisition Overview

16 Disciplined Acquisition Strategy BreitBurn acquisition strategy unchanged for 25 years 15 person business development and acquisition evaluation team Acquire mature oil and gas properties with stable, long-life production and low-risk drilling opportunities Selective screening adds only high quality assets that complement existing portfolio Acquisitions exceeded acquisition target of $300-$500 million 2012 acquisitions totaled > $600 million, expanded BBEP presence to 7 states, enhanced exposure to oil, established more balanced portfolio Recently closed oil-weighted acquisition in Oklahoma Panhandle and New Mexico for ~$834 million (1) Exceeded 2013 acquisition target of $500 million 2012 Transaction Activity Screened ~ 500 opportunities Evaluated 34 assets Bid 20 for ~$1.9 billion Closed 7 Texas - $420 Million California - $94 Million Wyoming - $95 Million Piedra Energy (1) Subject to customary post closing adjustments. Excludes ~$30.2 million for the purchase of additional interests in the acquired assets from other sellers. 16

17 Oklahoma Panhandle Acquisition Summary Assets: Interests in oil properties in Postle and North East Hardesty Fields in Oklahoma Panhandle Plus associated midstream assets in Oklahoma, New Mexico and Texas Seller: Whiting Oil and Gas Corporation Purchase Price: $834 Million Cash (1) Closed: July 15, 2013 Key Terms April 1, 2013 Effective Date Funding Source: Amended Credit Facility Borrowing base increased to $1.5 billion with elected commitment amount of $1.4 billion Asset Highlights ~41.4 MMBoe Estimated Proved Reserves (2) Est. proved reserve life index of ~15 years ~95% oil and NGLs ~68% Proved Developed Producing ~7,650 Boe/Day Net Production (3) Oil differentials of ~$8.00 / barrel below WTI ~$18.00 per Boe Lifting costs ~29,200 Net Acres (4) 100% HBP ~96% Average WI 100% Operated 251 Producing Wells 191 Injectors (water and CO 2 ) (1) Excludes $30.2 million for the purchase of additional interests in the acquired assets from other sellers. Subject to customary post closing adjustments. (2) Excludes the purchase of additional interests in the acquired assets from other sellers. Based on internal BBEP management estimates based on SEC pricing as of June 30, 2013 (3) Estimated average daily production for July (4) Excludes acres acquired through the purchase of additional interests in the acquired assets from other sellers. 17

18 Oklahoma Panhandle Acquisition Strategic Rationale High Quality MLP Assets Meaningful Increase in Scale High margin oil properties with ~15 year est. proved reserve life as of July 2013 (1) Current expectations for 10+ years of little to no decline in production Low risk development plan consisting of EOR expansion to new areas and wider exploitation of sand channels with banked oil Increases BBEP daily total production by ~29% and daily oil production by ~55% (1) Increases BBEP estimated proved reserves by ~28% and estimated oil proved reserves by ~48% (1) Expected to exit 2013 with liquids comprising ~64% of total net production Strong Accretion Complementary Diversification Strong accretion to distributable cash flow per unit expected in 2013, 2014 and subsequent years Expected to be significantly accretive to EBITDA, earnings, reserves, production, and NAV Attractive entry into Oklahoma and New Mexico expands geographic presence to nine states and establishes strong mid-continent presence State of the art field pattern analysis and exploitation techniques enhance BBEP s technical expertise Enhanced Growth Platform Provides expansion opportunities in Mid-Continent and Permian Tertiary flood expertise can potentially be applied to other BBEP properties (1) Reserves data based on BBEP s estimated proved reserves as of December 31, 2012, prepared by its independent reserve engineers, and management s internal estimate of proved reserves for the Whiting Acquisition as of June 30, Production data based on BBEP s FY 2012 average daily production including production from oil and gas properties from their respective acquisition dates to December 31, 2012 and estimated average daily production for July 2013 for the assets purchased in the Whiting Acquisition. 18

19 Oklahoma Panhandle Acquisition Asset Overview Colorado New Mexico Additional CO 2 Sources (Not Owned) Contracted supply in Bravo Dome, with step-in rights, for 129 BCF over yrs Expected to provide sufficient volume, when coupled with recycled CO 2, to develop 3P reserves Transpetco CO 2 Pipeline (100% Owned) 120 Miles 175 MMcfd capacity 35 MMcfd current throughput Oklahoma Texas Postle Field (~97% WI) 5 Units ~26,000 Net acres Kansas Hardesty Lateral CO 2 Pipeline (100% Owned) 32 Miles NE Hardesty Field (~95% WI) 1 Unit ~4,400 Net acres Hough Oil Pipeline (100% Owned) 51 Miles 20 Mboepd capacity Connections to Hooker and Beaver Stations Libby Lateral CO 2 Pipeline (100% Owned) 24 Miles (under construction) CO 2 Compression facility at origin (100% Owned) Dry Trails Gas Plant (100% Owned) CO 2 separation and recompression NGL and residue gas production Additional Asset Crude oil swaps novated to BBEP at closing: 4/1/13 12/31/13: 6,100 $ /1/14 12/31/14: 5,500 $ /1/15 12/31/15: 5,000 $ /1/16 3/31/16: 4,400 $

20 Oklahoma Panhandle Acquisition Field Operational Highlights Postle Field NE Hardesty Field Postle discovered 1958, waterflood 1967, CO 2 injection Postle Units (~97% WI) and 1 NE Hardesty Unit (~95% WI) ~7,650 Boe/d average daily production for July producing wells and 164 injectors Morrow and Cherokee Sands at ~6,100 with production revenue stream of approximately 93% oil, 5% NGLs and 2% gas OOIP of ~400 mmboe in Morrow A Sands Wells are completed with small acid stimulations Oil produced into Hough pipeline and sold to Shell, NGLs sold to OneOK, gas sold to Exxon CO 2 currently purchased from Exxon. Contracts in place with other sources for additional supply in near future, in amounts expected to be sufficient to develop 3P reserves Gas plant processes produced CO 2 for re-injection and natural gas for sales BBEP hired ~40 existing field personnel Transition services agreement through October 31,

21 Financial Overview

22 Operating and Financial Performance Strong Operating and Financial Performance Since 2006 IPO Production (Mboe) 31% CAGR Adjusted EBITDA (1) ($MM) 29% CAGR 9,000 8, $276 8,000 7,000 6,000 6,809 6,517 6,699 7, $233 $195 $227 $222 5,000 4,000 3,000 2,000 1,000 1,640 3, $61 $ Strong Operating and Financial Performance Supported by Successful Growth Through Acquisitions Strategy (1) Adjusted EBITDA conformed to exclude net operating cash flow from acquisitions from the effective date through the closing date. 22

23 Disciplined Financial Strategy Liquidity: Maintain solid liquidity profile Leverage: Seek to maintain low leverage ratios Maintain debt to LTM Adjusted EBITDA ratio ~3.0x Acquisitions typically financed with ~50% - 60% equity and ~40% - 50% debt Hedging: Goal of consistently hedging a high percentage of future production with swaps and costless collars Goal to hedge ~80% of annual production in year 1, ~75% in year 2, ~70% in year 3, ~60% in year 4, and ~50% in year 5 Hedge portfolio consists of 96% swaps and costless collars, 4% put options Aggressively hedge expected production from acquisitions Stable hedging profile is core element of our business strategy not a trading tool Distribution Coverage: Disciplined distribution growth policy considers present and future performance 23

24 Consistent Distribution Growth for Fourteen Straight Quarters Distributions Tax advantaged income (estimated 75% shield) 1 Partnership has made cumulative distributions of $10.77 per unit since IPO No Incentive Distribution Rights Future distribution growth supported by: Ongoing acquisitions Organic growth Strong hedge portfolio $.50 $.48 $.46 $.44 $.42 $.40 $.38 $.36 $.34 $.32 Sequential Quarterly Distribution Growth $1.850 $.488 $1.725 $.470 $.475$.480 $.450 $.455$.460$.465 $1.560 $.435 $.413 $.418$.423 $.375 $.383$.390 $.30 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q BreitBurn Continues to Deliver Best in Class Distribution Growth Among E&P MLP Peers (1) Estimate for common units purchased in February 2013 offering and held through December

25 % of Production Hedged Commodity Price Protection Portfolio: 4Q Q 2018 The chart assumes 4Q Q 2018 pro forma expected production remains constant at the annualized sum of (i) the midpoint of the Partnership's 2H 2013 production guidance and (ii) production from the early close of the Postle acquisition on July 15, 2013 (assumed at 7,650 boe/d & 98% liquids) Average Oil and Gas Hedge Prices 100% 80% 60% $95.01/bbl $5.73/mmbtu 86% 88% 83% $94.78/bbl $4.99/mmbtu 83% 77% $94.75/bbl $5.00/mmbtu 71% 73% 67% 67% $90.15/bbl $4.34/mmbtu 59% 55% 49% $84.11/bbl $4.49/mmbtu $82.20/bbl NA 40% 20% 0% 25% 27% 20% 6% 9% 0% 4Q 2013 FY 2014 FY 2015 FY 2016 FY Q 2018 Series3 Series1 Series2 Total Liquids Natural Gas Note: Includes all current hedges other than 2013 and 2014 call options entered into in October

26 Hedging Volumes (bbls/d) Commodity Price Protection Crude Oil Average Crude Oil Hedge Prices (per bbl) $95.01 $94.78 $94.75 $90.15 $84.11 $ ,000 15,000 18,716 17,614 15,489 12,511 10,000 5,000 17,216 16,114 13,489 11,011 5,769 2, ,000 1,000 1, ,000 4Q 2013 FY 2014 FY 2015 FY 2016 FY Q 2018 WTI W.A. $94.26 / 78% $93.24 / 73% $94.10 / 75% $87.36 / 62% $83.38 / 95% $88.20 / 100% Brent W.A. $97.57 / 22% $98.88 / 27% $96.72 / 25% $94.64 / 38% $97.50 / 5% NA / NA Swaps Collars Puts 26

27 Hedging Volumes (mmbtu/d) Commodity Price Protection Natural Gas Average Natural Gas Hedge Prices (per mmbtu) $5.73 $4.99 $5.00 $4.34 $ ,000 60,000 50,000 40,000 64,100 52,100 52,200 37,700 30,000 20,000 64,100 46,100 50,700 37,700 15,571 10,000-15,571 6,000 1,500 4Q 2013 FY 2014 FY 2015 FY 2016 FY 2017 Swaps Puts Note: Includes all current hedges other than 2013 and 2014 call options entered into in October

28 NYMEX Crude Oil / bbl Mitigating Commodity Price Volatility Our hedge portfolio has significantly mitigated crude oil and natural gas price fluctuations as evidenced by our quarterly Adjusted EBITDA (1) $160 $112 $ $58 $62 $62 $51 $47 $51 $48 $49 $51 $57 $60 $59 $56 $52 $52 $63 $61 $65 $77 $73 $64 $ NYMEX Natural Gas / Mcf Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q3 Q4 Q1 Q2 Q Quarterly Adjusted EBITDA ($MM) NYMEX Crude Oil NYMEX Natural Gas 0 (1) Adjusted EBITDA conformed to exclude net operating cash flow from acquisitions from the effective date through the closing date. 28

29 BBEP Value Proposition BBEP has attractive yield compared to peer group With current consensus target price of ~$22, BBEP has an implied yield of ~8.9% BBEP offers attractive opportunity for price appreciation 12.0% 10.0% 11.6% 11.5% 11.2% 10.4% 10.1% 9.7% 9.2% 8.9% 8.7% 8.7% 8.6% BBEP Target Price Implied Yield: 8.9% Distribution Yield (1) 8.0% 6.0% 4.0% 2.0% 0.0% LRE QRE ARP MEMP BBEP LINE LNCO VNR LGCY EVEP MCEP (1) Based on unit prices as of November 8, 2013 and most recently announced quarterly distribution. 29

30 Investment Highlights Responsible Management: Experienced management team has an average of over 25 years of industry experience Quality Assets: High quality asset base with predictable, long-lived production offering Critical mass in large mature basins with geographic, geologic and commodity diversity Recently closed oil-weighted acquisition in Oklahoma Panhandle and New Mexico from Whiting Oil and Gas for ~$834 million (1) Consistent Distribution Growth: Distributions have grown 30% since Q Strong Acquisition Track Record: Exceeded 2012 and 2013 acquisition targets with the completion of 10 acquisitions totaling ~$1.5 billion Completed 12 acquisitions since July 2011 totaling ~$1.8 billion Active Hedging: Substantial hedging through Q for oil at $92.57 and through 2017 for gas at $4.88 for gas (2) Attractive Yield: ~10% yield with an opportunity for price appreciation (1) Subject to customary post-closing adjustments. Excludes ~$30.2 million for the purchase of additional interests in the acquired assets from other sellers. (2) Weighted average prices per Commodity Price Protection Portfolio as detailed earlier in this presentation. 30

31 Appendix 1 (1) Financial statements included in the Appendix are from the Q Q.

32 2H 2013 Public Guidance ($ in 000s) 2H 2013 Guidance Total Production (Mboe): 5,950-6,350 Oil Production (Mbbls) 3,350-3,550 NGL Production (Mbbls) Gas Production (MMcfe) 13,800-14,760 December 2013 Exit Rate (boe/d) 34,700-36,100 Average Price Differential %: WTI Oil Price Differential % 91% - 92% Brent Oil Price Differential % (1) 95% - 96% NGL Price Differential % (of WTI) 34% - 35% Gas Price Differential % 102% - 103% Operating Costs / BOE (2)(3) $ $20.00 Production / Property Taxes (% of oil/ngl/gas revenue) 7.25% % G&A (Excl. Unit Based Compensation) $19,000 - $21,000 Cash Interest Expense (4) $43,000 - $45,000 Adjusted EBITDA (5) $235,000 - $245,000 Capital Expenditures (6) : Maintenance Capital $55,000 Growth Capital $95,000 - $105,000 ** Second half 2013 guidance assumes the inclusion of the Whiting Acquisition assets as of August 1, Footnotes on next slide. 32

33 2H 2013 Public Guidance Notes (1) Approximately 25% of oil production is expected to be sold based on Brent pricing. (2) Operating Costs include lease operating costs, processing fees, district expense, and transportation expense. Expected transportation expense totals approximately $3.5 million in 2H 2013, largely attributable to our Florida production. Excluding transportation expense, our estimated operating costs range per boe is approximately $ $ (3) Operating Costs are based on flat $95 per barrel WTI crude oil, $100 per barrel Brent crude oil, and $4.00 per mcfe natural gas price levels for 2H Operating costs generally move with commodity prices but do not typically increase or decrease as rapidly as commodity prices. (4) The Partnership typically borrows on a 1-month LIBOR basis, plus an applicable spread. Estimated cash interest expense assumes a 1-month LIBOR rate of 0.3%. (5) (Assuming the high and low range of our guidance, Adjusted EBITDA is expected to range between $245 million and $235 million, and is comprised of estimated net income (before non-cash unit based compensation) between $64 million and $52 million, plus unrealized loss on commodity derivative instruments of $18 million, plus DD&A of $120 million, plus interest expense between $43 million (high end of Adjusted EBITDA) and $45 million (low end of Adjusted EBITDA). Estimated 2H 2013 net income is based on oil prices of $95 per barrel for WTI crude oil, $100 per barrel Brent crude oil, and $4.00 per mcfe for natural gas. Consequently, differences between actual and forecast prices could result in changes to unrealized gains or losses on commodity derivative instruments, DD&A, including potential impairments of long-lived assets, and ultimately, net income. (6) Total capital expenditures for 2H 2013 exclude capital expenditures for additional acquisitions as well as technology capital spending of approximately $1.5 million. Maintenance capital is defined as the estimated amount of investment in capital projects and obligatory spending on existing facilities and operations needed to hold production approximately constant for the period. 33

34 2H 2013 Public Guidance 2H 2013 guidance is subject to all of the cautionary statements and limitations described below and under the caption "Cautionary Statement Regarding Forward-Looking Information." In addition, 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. 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 CO 2. The Partnership's estimates are based on certain other assumptions, such as well performance, which may actually prove to vary significantly from those assumed. Operating costs, which include 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. 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. They can vary dramatically from time to time. Capital expenditures are based on our current expectations as to the level of capital expenditures that will be justified based upon the other assumptions set forth below as well as expectations about other operating and economic factors not set forth below. The guidance below does not constitute any form of guarantee, assurance or promise that the matters indicated will actually be achieved. Rather, the table simply sets forth our best estimate today for these matters based upon our current expectations about the future based upon both stated and unstated assumptions. Actual conditions and those assumptions may, and probably will, change over the course of the year. 34

35 Non-GAAP Financial Measures Financial tables and other supplemental information provided herein, including the reconciliations of certain non-generally accepted accounting principles ( non-gaap ) measures to their nearest comparable generally accepted accounting principles ( GAAP ) measures, may be used periodically by management when discussing the Partnership's financial results with investors and analysts, and they are also available on the Partnership's website under the Investor Relations tab. Among the non-gaap financial measures used are Adjusted EBITDA and distributable cash flow. These non-gaap financial measures should not be considered as alternatives to GAAP measures, such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance. Management believes that these non-gaap financial measures enhance comparability to prior periods. Adjusted EBITDA is presented as management believes it provides additional information relative to the performance of the Partnership's business, such as our ability to meet our debt covenant compliance tests. Distributable cash flow is used by management as a tool to measure the cash distributions we could pay to our unitholders. This financial measure indicates to investors whether or not we are generating cash flow at a level that can support our distribution rate to our unitholders. These non-gaap financial measures may not be comparable to similarly titled measures of other publicly traded partnerships or limited liability companies because all companies may not calculate Adjusted EBITDA or distributable cash flow in the same manner. 35

36 Historical Financial Statements Adjusted EBITDA Three Months Ended September 30, June 30, September 30, Thousands of dollars (a) Reconciliation of net income (loss) to Adjusted EBITDA: Net income (loss) attributable to the Partnership $ (25,011) $ 76,432 $ (73,003) Loss (gain) on commodity derivative instruments 54,765 (66,993) 69,418 Commodity derivative instrument settlements (b) (c) (6,323) 4,798 22,496 Depletion, depreciation and amortization expense 60,125 46,541 37,270 Interest expense and other financing costs 23,548 18,420 15,362 Loss on interest rate swaps (d) Loss on sale of assets Income tax expense (benefit) (647) Unit-based compensation expense (e) 4,889 4,989 5,652 Adjusted EBITDA $ 112,094 $ 84,832 $ 76,858 Less: Maintenance capital (f) $ 25,782 $ 19,511 $ 17,677 Cash interest expense 21,748 17,072 15,173 Distributable cash flow available to common unitholders $ 64,564 $ 48,249 $ 44,008 Distributable cash flow per common unit $ 0.64 $ 0.48 $ 0.53 Common unit distribution coverage 1.3x 1.0x 1.1x Note: Footnotes on following slide. 36

37 Historical Financial Statements Adjusted EBITDA (continued) Reconciliation of net cash flows from operating activities to Adjusted EBITDA: Net cash provided by operating activities $ 69,520 $ 38,570 $ 65,725 Increase (decrease) in assets net of liabilities relating to operating activities 20,663 29,074 (3,935) Interest expense (d) (g) 21,721 17,062 15,133 Income from equity affiliates, net 121 (130) (47) Income taxes (18) Non-controlling interest Adjusted EBITDA $ 112,094 $ 84,832 $ 76,858 (a) Adjusted EBITDA for the three months ended September 30, 2012 was conformed to exclude $13.2 million related to "Net operating cash flow from acquisitions, effective date through closing date." (b) Excludes pre-paid premiums, paid in 2012, related to crude oil derivatives that settled during the three months ended September 30, 2013, June 30, 2013, and September 30, 2012 of $1.2 million, $1.2 million and $0.3 million, respectively. (c) For the three months ended September 30, 2013, June 30, 2013 and September 30, 2012, includes settlements received (paid) on crude oil derivatives of $(17.9) million, $(3.6) million and $2.0 million, respectively, and settlements received on natural gas derivatives of $11.6 million, $8.4 million and $20.5 million, respectively. (d) The three months ended September 30, 2012 include settlements paid on interest rate derivatives of $0.8 million. (e) Represents non-cash long-term unit-based incentive compensation expense. (f) Maintenance Capital is management's estimate of the investment in capital projects and obligatory spending on existing facilities and operations needed to hold production flat year over year. (g) Excludes amortization of debt issuance costs and amortization of senior note discount/premium. 37

38 Historical Financial Statements Consolidated Balance Sheets BreitBurn Energy Partners L.P. and Subsidiaries Unaudited Consolidated Balance Sheets September 30, December 31, Thousands ASSETS Current assets Cash $ 2,818 $ 4,507 Accounts and other receivables, net 115,931 67,862 Derivative instruments 16,558 34,018 Related party receivables 530 1,413 Inventory 11,118 3,086 Prepaid expenses 3,071 2,779 Intangibles, net 6,554 - Total current assets 156, ,665 Equity investments 7,126 7,004 Property, plant and equipment Oil and gas properties 4,409,806 3,363,946 Other assets 15,986 14,367 4,425,792 3,378,313 Accumulated depletion and depreciation (813,713) (666,420) Net property, plant and equipment 3,612,079 2,711,893 Other long-term assets Intangibles, net 6,693 - Derivative instruments 71,085 55,210 Other long-term assets 46,893 27,722 BreitBurn Energy Partners L.P. and Subsidiaries Unaudited Consolidated Balance Sheets September 30, December 31, Thousands LIABILITIES AND EQUITY Current liabilities Accounts payable $ 50,653 $ 42,497 Derivative instruments 12,388 5,625 Revenue and royalties payable 26,576 22,262 Wages and salaries payable 12,154 10,857 Accrued interest payable 29,467 13,002 Accrued liabilities 36,645 20,997 Total current liabilities 167, ,240 Credit facility 1,090, ,000 Senior notes, net 755, ,696 Deferred income taxes 2,739 2,487 Asset retirement obligation 111,642 98,480 Derivative instruments 1,775 4,393 Other long-term liabilities 4,431 4,662 Total liabilities 2,134,169 1,325,958 Partners' equity 1,766,287 1,589,536 Total liabilities and equity $ 3,900,456 $ 2,915,494 Total assets $ 3,900,456 $ 2,915,494 38

39 Historical Financial Statements Consolidated Statement of Operations BreitBurn Energy Partners L.P. and Subsidiaries Unaudited Consolidated Statements of Operations Three Months Ended September 30, Thousands of dollars, except per unit amounts Revenues and other income items Oil, natural gas and natural gas liquid sales $ 197,413 $ 111,700 (Loss) gain on commodity derivative instruments, net (54,765) (69,418) Other revenue, net Total revenues and other income items 143,385 43,078 Operating costs and expenses Operating costs 68,502 50,048 Depletion, depreciation and amortization 60,125 37,270 General and administrative expenses 16,116 13,721 Loss on sale of assets Operating (loss) income (1,435) (58,029) Interest expense, net of capitalized interest 23,548 15,362 Loss on interest rate swaps Other expense (income), net 4 17 Total other expense 23,552 15,621 (Loss) income before taxes (24,987) (73,650) Income tax expense (benefit) 24 (647) Net (loss) income (25,011) (73,003) Less: Net income attributable to noncontrolling interest - - Net (loss) income attributable to the partnership (25,011) (73,003) Basic net (loss) income per unit $ (0.25) $ (1.00) Diluted net (loss) income per unit $ (0.25) $ (1.00) 39

40 Historical Financial Statements Consolidated Statement of Cash Flows BreitBurn Energy Partners L.P. and Subsidiaries Unaudited Consolidated Statements of Cash Flows Nine Months Ended September 30, Thousands of dollars Cash flows from operating activities Net income (loss) $ 15,121 $ (30,405) Adjustments to reconcile net loss to cash flow from operating activities: Depletion, depreciation and amortization 154, ,068 Unit-based compensation expense 14,700 16,855 Loss (gain) on derivative instruments 11,948 (939) Derivative instrument settlements 3,633 62,877 Prepaid premiums on derivative instruments - (13,303) Income from equity affiliates, net (122) 356 Deferred income taxes 252 (503) Loss on sale of assets Other 3,989 3,366 Changes in assets and liabilities: Accounts receivable and other assets (62,882) 2,878 Inventory (8,032) 1,208 Net change in related party receivables and payables 883 2,329 Accounts payable and other liabilities 32,857 12,267 Net cash provided by operating activities 166, ,276 BreitBurn Energy Partners L.P. and Subsidiaries Unaudited Consolidated Statements of Cash Flows Nine Months Ended September 30, Thousands of dollars Cash flows from investing activities Property acquisitions (861,601) (313,404) Capital expenditures (191,472) (77,699) Proceeds from sale of assets Net cash used in investing activities (1,052,847) (390,240) Cash flows from financing activities Issuance of common units 285, ,504 Distributions (137,447) (93,734) Proceeds from issuance of long-term debt, net 1,381,000 1,066,885 Repayments of long-term debt (636,000) (1,109,000) Change in book overdraft (316) (2,299) Debt issuance costs (8,032) (9,346) Net cash provided by financing activities 884, ,010 Decrease in cash (1,689) (954) Cash beginning of period 4,507 5,328 Cash end of period $ 2,818 $ 4,374 40

41 Florida Operating Area Asset Overview Asset Map Key fields: Raccoon Point, Bear Island, West Felda, Lehigh Production is from the Cretaceous Sunniland Trend of South Florida Operate 5 fields (100% oil) Total acreage: 37,568 gross, 36,422 net Gross producing wells: API oil High net revenue interests Premium pricing to WTI Lehigh Acres Charlotte Lee West Felda Sunniland Bear Island Martin Glades Hendry Palm Beach Broward Collier Miami-Dade Monroe Sunoco Felda Raccoon Point Production transported via barge Estimated Proved Reserves by Resource Mix (1) PDNP 10% 2012 Operational Highlights Estimated proved reserves: 10.4 MMboe Production: 704 Mboe (100% oil) 2012 Capital Program $46 million (100% spent on oil wells) Drilled 4 productive wells Incremental net production added: ~600 Boe/d Incremental reserves added: 2,232 Mboe PDP 90% Oil 100% (1) Estimated proved reserves and production based on YE 2012 Reserve Report at SEC Prices. 41

42 Michigan Operating Area Asset Overview Key fields: Antrim Shale; Prairie du Chien, Richfield, Detroit River Zone III, and Niagaran Pinnacle Reefs BBEP is the largest gas producer in MI; one of the top producers in Antrim Shale Total acreage: 506,555 gross, 258,398 net Includes integrated midstream assets Interests in 3,677 gross productive wells Additional opportunities for bolt on acquisitions MichCon City-Gate prices which trade at a premium to Henry Hub Potential in the A-1 Carbonate and Utica/Collingwood Shales Asset Map Leelanau Benzie Charlevoix Grand Traverse Antrim Kalkaska Emmet Charlevoix Cheboygan Otsego Crawford Presque Isle Montmorency Oscoda Michigan Antrim Shale Alpena Alcona Estimated Proved Reserves by Resource Mix (1) 2012 Operational Highlights PDNP 10% PUD 8% Oil 9% NGL 2% Estimated proved reserves: 51.7 MMboe Production: 3,370 Mboe (86% gas) 2012 Capital Program $12 million (95% spent on oil wells) Drilled 11 productive wells, 26 recompletions and 5 workovers Incremental net production added: ~3,600 Mcfe/d PDP 82% Gas 89% (1) Estimated proved reserves and production based on YE 2012 Reserve Report at SEC Prices. 42

43 BreitBurn Energy Partners L.P. NASDAQ: BBEP Investor Presentation Halbert S. Washburn Chief Executive Officer November 2013