Exhibit 99.6

September 23, 2016 CONFIDENTIAL DRAFT Subject to Material Revision Subject to F.R.E. 408

2 Header 2 Management Meeting Objectives  Illustrate enhanced value creation with increased activity and capital spend  Confirm increased E&P and RMI value creation with greater activity  Outline the associated capital requirements  Describe the rigor of our planning methodology  Describe the upside to the Business Plans  Recent operational tests and results  Development opportunities on northwest and southwest acreage  Discuss firm transport alternatives

3 Header 3 Management Meeting Outline  Value creation of our RM Region Assets  Discuss Type Curve & Planning Methodology  Use of historic, well specific data  Rigorous risking method  Thorough internal review  Comparison of historical forecasting to results (production and reserves )  Discuss Business Plan models  Value and operational benefits from increased activity  Capital needs (size and commitment)  Sensitivity to commodity price  Performance Upside  B enefits from operational changes  Strategic Considerations  Development of northwest and southwest acreage  Issues associated with firm transport contracts

4 Header 4 Corporate Objectives  Maintain best - in - class EH&S record  Integrated Field Development – full - field engineering & planning for a large geological resource – a low cost stacked pay petroleum system  Deliver large, high return, continually improving, wellbore reinvestment portfolio for investors enabled by surface infrastructure efficiencies  Ongoing RMI development - enhance productivity and field efficiencies  Optimize capital program to the external environment  Develop Northwest and Southwest acreage blocks  Optimize firm transportation conduits

5 Header 5 A Bench B Bench C Bench Codell 36’ 35’ 32’ 30’ 21’ 41’ 38’ 35’ 37’ Thickness (feet) of Niobrara B Bench Resistivity > 20 Ohms NBL: Wells Ranch BCEI: Southwest Acreage BCEI: West Acreage BCEI: Northwest Acreage BCEI: East Acreage 1 2 3 4 5 6 7 8 9 1 2 3 4 5 7 8 6 9 Niobrara A Bench Potential target in Northwest acreage Niobrara B Bench Consistent thickness and resistivity across BCEI leasehold Niobrara C Bench Good uniformity across BCEI leasehold with thickest net pays in the Northwest Codell Present across BCEI leasehold with thickest net pays in the West & Southwest 2 Consistent Geology in Stacked Pay System Greenhorn Evaluating

6 Header 6 15+ Years of Wattenberg Unrisked Resources YE 2015 Gross Locations YE 2015 Net Locations Proved Undeveloped 204 164 Development Niobrara A TBD TBD Niobrara B 1,310 794 Niobrara C 1,464 960 Codell 264 166 Greenhorn TBD TBD Development 3,038 1,920 Total HZ Locations 3,242 2,084 PUDs as % of Total Resource 6.3% 7.9%  PUD locations assume 80 - acre spacing of Niobrara B and C and 160 - acre spacing of Codell locations  Development locations assume 40 - acre spacing of Niobrara B and C and 160 - acre spacing of Codell locations Deep Inventory with Multi - Bench Resource Potential

7 Header 7  The Company expects to have 3,242 remaining SRL locations in the Wattenberg; assuming 70 SRL wells per rig year, the Company has a significant inventory runway  By increasing the development pace to a 3 - rig program, the Company develops 65% of its current inventory within a 10 year period, maximizing value Maximizing Value T hrough I ncreased D evelopment P ace 0 500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 3-Rig Program 1-Rig Program Resource Locations Gross SRL Locations Current Collateral Value PDP 11% PUD 6% Unbooked Inventory 83% Wattenberg Inventory 401 PDP 10 - Year Drilling Inventory Remaining Inventory After Year 10 10 - Year Drilling Inventory Remaining Inventory After Year 10 PDP PDP 3,200+ Locations Value is heavily discounted for 78% of inventory

8 Header 8 Engineering Overview

9 Header 9 Internal Type Curve Generation Process Public Data Type Curve Process  Well Statistics (location, lateral length, formation, etc.)  Categorize well by type  SRL, MRL, XRL (lateral length)  Area – west, central, east, north  Spacing – 80 - acre offsets, 80/40 acre Nio B/C, 40 acre offset, 40/20 Nio B/C, 60 acre offset, 5 - spot pattern with Codell, B/Codell alignment, etc.  Analyze productivity details (KEY)  Refine data set to include wells exhibiting “reservoir” performance  Was completion 100% successful? (i.e. any missed frac stages, etc.)  Short - term production problem ? (i.e. fraced into by offsetting well, shut in for offset drilling, etc.) – included in f inancial m odel risking  Sufficient data for type curve analysis? (i.e. prefer > 6 months of data)  Reflect recent completion type? (typically remove 2011 and 2012 completions due to later changes in design)  Other Generating Type Curves – The Process  Well Statistics (location, lateral length, formation, etc.)  Categorize well by type  SRL, MRL, XRL (lateral length)  Area – west, central, east, north (location on BCEI acreage) Public data type curve process typically stops at this point  Generation of multiple type curves  Use multiple type curves in our Business Plan  PUD type curves are 80 - acre spaced Niobrara, primarily SRL

10 Header 10  Select the appropriate group of wells for type curve analysis from the sample set  Normalize the production history of the wells  Fit a curve through the normalized production  Review “fit” curve parameters with knowledge of field/basin  Calculate an EUR and perform “reality check” with knowledge of field/basin, well type, etc. Generating Type Curves – The Process ( Cont ) Example: Central Area 80 - acre Niobrara Oil Type Curve Individual wells are light grey with the majority of production within the red dashed lines, The green line is the curve fit to the normalized production of all selected wells TOTAL CENTRAL - 80-ACRE OLDER COMPLETIONS SHORT-TERM PROD. ISSUES PATTERN TYPE CURVE WELLS Well Locations Public Data Access Ends

11 Header 11 Engineering Volumes Forecasting Methodology  Strong collaboration between Planning and Operations teams to develop a highly achievable plan  Well specific drill schedule (many factors considered)  Economics (which part of the field, existing/new infrastructure, lateral length)  Production impact  Proximity to existing wells ( frac - into impact)  Pad size  Pad location (surface)  Permits  PUD capture  Working Interest  Well type curves are based on historical production from a representative set of wells that share characteristics (i.e . acreage location, lateral length, etc .)  Projections do not include enhancement potential from new completion techniques  “In - field” (RMI) infrastructure planned for and built to complement the drill schedule

12 Header 12 Engineering Volumes Forecasting Methodology  Risking applied based on previous experience  Weather  3 rd Party infrastructure  Frac - into (effect on base production)  Rig/well delays  Cycle times  Facility readiness  Multiple levels of review  Engineers, Geologists  Regional VP’s, Land, EHS&RC  Full management team

13 Header 13 Engineering Volumes Forecasting Results  Actual – monthly financials  Adjusted Plan – original engineering plan revised due to significant changes in scope (i.e. rig count, well timing, etc.) Variance (Actual less Forecast) FY 2014 -3.1% FY 2015 -0.5% YTD 2Q 2016 1.7%  30 month volume weighted variance: - 1.1%  Strong track record of matching forecast  +2.2% variance since RMI commissioning in May/June 2015 RMI Commissioning

14 Header 14 Continuous Reserves Growth 21.4 32.4 49.0 68.1 80.2 4 35 73 106 95 0 10000 20000 30000 40000 50000 60000 70000 80000 90000 0 30 60 90 2011 2012 2013 2014 2015 NET MMBOE HZ PDP Reserves HZ PUD + Vert. Reserves # Wells Drilled  History of continuous proved reserves growth in the RM Region  Significant 5 - year growth in HZ PDP reserves  CAGR = 107 %  Increasing % of RM HZ PDP to RM total proved reserves over 5 - years  “Measured” PUD booking RM Region Total Proved & Horizontal PDP Reserves

15 Header 15 2012 2013 2014 2015 Production Reserve Adds Volume RM Region Production and Reserve Adds  RM Region reserve replacement - reserve adds exceed production year after year  Reserve adds are defined as the sum of the capital reserve adds and the revisions (excludes acquisitions)  Over or under booking of reserves one year is caught in revisions in subsequent years  Provides an indication of true reserve adds Reserve Replacement

16 Header 16 Value Creation

17 Header 17 Base Case Capital Program – Creating Long Term Value Base Case (1 - 3 Rig ) Alternate Plan (1 Rig) E&P Value Created at YE18 (1) $1.8 billion $658 million RMI Valuation at YE18 (2) $650 million $338 million RMI Value Created at YE18 (2) $395 million $83 million March 2018 RBL Borrowing Base Proved Reserves & BB BB Unchanged 4Q16 to 4Q18 Production CAGR 44% 11% Develop Northwest Acreage 4Q 2017 Beyond Forecast Horizon Develop French Lake Acreage 4Q 2017 HBP Drilling Only Integrated French Lake Development Re - engage as operator Liquidity / operatorship risk Strategic Firm Transport Partnership 2 Rig Minimum Insufficient Activity  Base Case Business Plan creates $2.2 billion in value  Base Case results in higher production and proved reserves at YE17 than Alternate Plan  Maximizes RBL borrowing base and de - risks 2018 capital funding  Base Case Business Plan more than doubles production in 2 years from 17.9 mboe /d in 4Q16 to 37.1 mboe /d in 4Q18  Alternate Plan provides production growth in 2017 but only maintains YE17 production in 2018  Higher committed equity capital will accelerate ability to unlock high value French Lake acreage (1) Assumes starting enterprise value based on per flowing bbl metric of $55,000 per Bbl . See appendix for discussion on per flowing barrel metrics. (2) Utilizes multiple from 4Q15/1Q16 RMI divestiture process.

18 Header 18 Summary of Capital Needs – Base Case (1) Assumes fully consented, pre - packaged restructuring. (2) Strip pricing as of 7/15/2016 as per cleansing materials. Cumulative Oct-Dec '16 '17 '18 Oct-Dec '16 '17 '18 Base Case Business Plan (1-3 Rig) Rockies Daily Total Net Production (boe/d) 14,258 18,125 30,762 Rockies Daily Net Crude Production (bbl/d) 7,392 10,349 18,257 Uses Restructuring fees and expenses (1) $50 $0 $0 $50 $50 $50 RBL paydown 229 0 0 229 229 229 E&P capex 2 219 335 2 221 556 RMI capex 0 108 55 0 108 163 Change in working capital 5 10 2 5 15 17 Total $286 $337 $392 $286 $623 $1,015 Sources Estimated beginning cash (9/30/16) $135 $0 $0 $135 $135 $135 Operating cash flow (2) 27 177 310 27 204 514 Total $162 $177 $310 $162 $339 $649 Capital Need Before Transporation Costs $124 $160 $81 $124 $284 $365

19 Header 19 Sensitivity to Commodity & Transport – Base Case (1) Strip pricing as of 7/15/2016 as per cleansing materials. Capital Need After Transport Costs Cumulative Variance to Strip 2017 - 2018 Pricing Trans. ($/bbl) Oct-Dec '16 '17 '18 Oct-Dec '16 '17 '18 $3.00 $143 $248 $223 $143 $391 $614 6.00 145 260 243 145 404 647 9.00 147 271 263 147 418 681 $3.00 $135 $210 $162 $135 $344 $506 6.00 137 221 182 137 358 540 9.00 139 232 202 139 371 573 $3.00 $126 $171 $101 $126 $297 $399 6.00 128 182 121 128 311 432 9.00 130 194 141 130 324 466 $3.00 $118 $132 $41 $118 $251 $291 6.00 120 144 61 120 264 325 9.00 122 155 81 122 277 358 $3.00 $110 $94 ($20) $110 $204 $184 6.00 112 105 (0) 112 217 217 9.00 114 116 20 114 231 250 +$10.0/bbl -$10.0/bbl -$5.0/bbl Strip at 7/15 (1) $50.54 (2017) $52.52 (2018) +$5.0/bbl  Current strip is $49.96 (2017) and $52.08 (2018). Total Net Production ( boe /d) 17,855 21,173 33,279

20 Header 20 Base Case Business Plan – Value Creation  Base Case Business Plan adds 8,600 boe /d per year in 2017 and 10,700 in 2018  Implied E&P value creation of $1.0 billion by YE17 and $ 1.8 billion by YE18 (value created from YE16)  2017 capital efficiency of $24,907 – $30,001 per boe /d (IP - 360) E&P Value Creation RMI Value Creation  3 Rigs by YE 2017 requires additional RMI investment  Past RMI processes have validated RMI capital in excess of 2.0x capital employed  Implied market value of ~$650MM by YE18  Ability to market assets with commitment to higher throughput could significantly improve the return on this capital  $650MM valuation relates to mid - to - high teens multiple on 2018 RMI EBITDAX  Multiple is consistent with early RMI marketing processes  EBITDAX does not include water and oil gathering 4Q 2018 RMI Market Valuation 4Q15 Book Value of RMI Assets $105.0 4Q15/1Q16 RMI Divestiture Bid $255.0 Divestiture Multiple 2.4x RMI Market Valuation 2017-2018 RMI Capital Expenditures $162.7 Implied 4Q 2018 Book Value $267.7 Implied 4Q 2018 Market Valuation $650.1 2-Year RMI Value Creation $395.1 2-Year Multiple on RMI Capital 2.4x (1) Financial projections do not include transportation costs/penalties under current FT contracts . Strip pricing as of 7/15/2016 as per cleansing materials . (2) E&P capital expenditures less annual operating cash flow. (3) See appendix for discussion on per flowing barrel metrics. 3Q 2016 4Q 2016 4Q 2017 4Q 2018 ($ in millions) Financial Forecst Summary (1) Net Production (boe/d) Rockies 17,651 14,262 23,673 34,781 Mid-Con 4,029 3,593 2,800 2,371 Total BCEI 20,356 17,855 26,473 37,152 Total Revenues $61.9 $54.7 $88.4 $129.7 Operating Expenses (28.9) (26.7) (31.3) (38.2) EBITDAX $33.1 $28.0 $57.1 $91.5 LTM EBITDAX -- -- $156.6 $313.0 LTM Operating Cash Flow -- -- $177.3 $310.3 LTM Gross E&P Capex -- -- $219.2 $334.8 LTM RMI Capital Expenditures -- -- $108.1 $54.6 LTM Total Capital Expenditures -- -- $327.2 $389.4 Net E&P Funding Required/(Provided) (2) -- -- $41.9 $24.5 3Q 2016 YE 2016 YE 2017 YE 2018 Valuation Net Production (boe/d) 20,356 17,855 26,473 37,152 EV/MRQ Production ($/boe/d) (3) 35,000 55,000 75,000 75,000 Implied BCEI E&P Enterprise Value $712.5 $982.0 $1,985.5 $2,786.4 Annual E&P Value Creation -- -- $1,003.5 $801.0 Gross E&P Capex $219.2 $334.8 Annual Multiple on Gross E&P Capex 4.6x 2.4x YE 2018 Enterprise Value Sensitivity Net Production (boe/d) Flowing Barrel Metric (3) 55,000 65,000 75,000 85,000 95,000 Implied BCEI E&P Enterprise Value $2,043.4 $2,414.9 $2,786.4 $3,157.9 $3,529.5 YE16 to YE18 E&P Value Creation $1,061.4 $1,432.9 $1,804.4 $2,175.9 $2,547.5 2017-2018 Gross E&P Capex $554.0 $554.0 $554.0 $554.0 $554.0 2-Year Multiple on E&P Capital 1.9x 2.6x 3.3x 3.9x 4.6x 37,152

21 Header 21 Summary of Capital Needs – Alternate Plan Cumulative Oct-Dec '16 '17 '18 Oct-Dec '16 '17 '18 Alternate Case Business Plan (1 Rig Program) Rockies Daily Total Net Production (boe/d) 14,258 17,138 19,343 Rockies Daily Net Crude Production (bbl/d) 7,392 9,583 10,884 Uses Restructuring fees and expenses (1) $50 $0 $0 $50 $50 $50 RBL paydown 229 0 0 229 229 229 E&P capex 2 134 98 2 135 234 RMI capex 0 20 14 0 20 34 Change in working capital 6 9 1 6 15 16 Total $286 $163 $113 $286 $450 $563 Sources Estimated beginning cash (9/30/16) $135 $0 $0 $135 $135 $135 Operating cash flow (2) 27 147 162 27 174 336 Total $162 $147 $162 $162 $309 $471 Capital Need Before Transporation Costs $125 $16 ($49) $125 $141 $92 (1) Assumes fully consented, pre - packaged restructuring. (2) Strip pricing as of 7/15/2016 as per cleansing materials.

22 Header 22 Sensitivity to Commodity & Transport – Alternate Plan  Current strip is $49.96 (2017) and $52.08 (2018). (1) Assumes fully consented, pre - packaged restructuring. (2) Strip pricing as of 7/15/2016 as per cleansing materials. Capital Need After Transport Costs Cumulative 2017 - 2018 Pricing Trans. ($/bbl) Oct-Dec '16 '17 '18 Oct-Dec '16 '17 '18 $3.00 $143 $100 $43 $143 $243 $286 6.00 145 111 55 145 256 311 9.00 147 121 67 147 268 335 $3.00 $135 $64 $3 $135 $198 $201 6.00 137 74 15 137 211 226 9.00 139 85 27 139 223 250 $3.00 $127 $27 ($37) $127 $153 $116 6.00 129 37 (25) 129 166 141 9.00 131 48 (13) 131 178 165 $3.00 $118 ($10) ($77) $118 $108 $32 6.00 121 0 (65) 121 121 56 9.00 123 11 (53) 123 133 80 $3.00 $110 ($47) ($117) $110 $63 ($53) 6.00 112 (36) (105) 112 76 (29) 9.00 114 (26) (93) 114 88 (4) -$10.0/bbl -$5.0/bbl Strip at 7/15 (1) $50.54 (2017) $52.52 (2018) +$5.0/bbl +$10.0/bbl Total Net Production ( boe /d) 17,855 20,186 21,859

23 Header 23 Alternate Business Plan – Value Creation  Alternate Business Plan adds approximately 4,000 boe /d in 2017 and no growth in 2018  Implied E&P value creation of $658 million by YE17 with no growth in 2018 versus the $ 1.8 billion created in the preferred Base Case Business Plan E&P Value Creation RMI Value Creation  Does not grow RMI value for future development of northern/southern acreage and/or potential divestiture  Future marketing process for RMI would likely require commitment to at least 2 rig throughput  $338MM valuation relates to mid - to - high teens multiple on 2018 RMI EBITDAX  Multiple is consistent with early RMI marketing processes  EBITDAX does not include water and oil gathering 4Q 2018 RMI Market Valuation 4Q15 Book Value of RMI Assets $105.0 4Q15/1Q16 RMI Divestiture Bid $255.0 Divestiture Multiple 2.4x RMI Market Valuation 2017-2018 RMI Capital Expenditures $34.1 Implied 4Q 2018 Book Value $139.1 Implied 4Q 2018 Market Valuation $337.8 2-Year RMI Value Creation $82.8 2-Year Multiple on RMI Capital 2.4x 3Q 2016 4Q 2016 4Q 2017 4Q 2018 ($ in millions) Financial Forecst Summary (1) Net Production (boe/d) Rockies 17,651 14,262 19,167 19,492 Mid-Con 4,029 3,593 2,800 2,371 Total BCEI 20,356 17,855 21,967 21,863 Total Revenues $61.9 $54.7 $71.5 $73.6 Operating Expenses (28.9) (26.7) (29.2) (30.1) EBITDAX $33.1 $28.0 $42.3 $43.6 LTM EBITDAX -- -- $143.4 $169.8 LTM Operating Cash Flow -- -- $146.9 $161.8 LTM Gross E&P Capex -- -- $133.5 $98.3 LTM RMI Capital Expenditures -- -- $20.4 $13.6 LTM Total Capital Expenditures -- -- $154.0 $111.9 Net E&P Funding Required/(Provided) (2) -- -- ($13.4) ($63.5) 3Q 2016 YE 2016 YE 2017 YE 2018 Valuation Net Production (boe/d) 20,356 17,855 21,967 21,863 EV/MRQ Production ($/boe/d) (3) 35,000 55,000 75,000 75,000 Implied BCEI E&P Enterprise Value $712.5 $982.0 $1,647.6 $1,639.7 Annual E&P Value Creation -- -- $665.6 -$7.8 Gross E&P Capex $133.5 $98.3 Annual Multiple on Gross E&P Capex 5.0x -0.1x YE 2018 Enterprise Value Sensitivity Net Production (boe/d) Flowing Barrel Metric (3) 55,000 65,000 75,000 85,000 95,000 Implied BCEI E&P Enterprise Value $1,202.5 $1,421.1 $1,639.7 $1,858.3 $2,077.0 YE16 to YE18 E&P Value Creation $220.5 $439.1 $657.7 $876.4 $1,095.0 2017-2018 Gross E&P Capex $231.8 $231.8 $231.8 $231.8 $231.8 2-Year Multiple on E&P Capital 1.0x 1.9x 2.8x 3.8x 4.7x 21,863 (1) Financial projections do not include transportation costs/penalties under current FT contracts . Strip pricing as of 7/15/2016 as per cleansing materials . (2) E&P capital expenditures less annual operating cash flow. (3) See appendix for discussion on per flowing barrel metrics.

24 Header 24 Scenario Comparison – Creating Long Term Value Base Case (1 - 3 Rig ) Alternate Plan (1 Rig) E&P Value Creation at YE18 (1) $1.8 billion $658 million RMI Valuation at YE18 (2) $650 million $338 million RMI Value Created at YE18 (2) $395 million $83 million 4Q16 to 4Q17 Production Added ( boe /d) 8,618 4,112 4Q17 to 4Q18 Production Added ( boe /d) 10,679 (104) 4Q16 to 4Q18 CAGR 44% 11% 2017 - 2018 Gross E&P Capital $554 million $232 million 2017 - 2018 RMI Capital $163 million $34 million Capital Requirement @ $3/ Bbl Differential (3) $399 million $116 million 2 - Year Multiple on E&P Capex (1) 3.3x 2.8x (1) Assumes starting enterprise value based on per flowing bbl metric of $55,000 per Bbl. See appendix for discussion on per flowing barrel metrics. (2) Utilizes multiple from 4Q15/1Q16 RMI divestiture process . (3) Strip pricing as of 7/15/2016 as per cleansing materials.  Base Case Business Plan creates $2.2 billion in value and provides financial flexibility for 2018 capital program by growing RBL borrowing base collateral value  Base Case provides 50 additional PDP wells for valuation in March 2018 borrowing base redetermination  Running >1 rig in 2018 after a 1 rig program in 2017 could require high RBL utilization  Additional strategic value created through RMI and FT partnerships through Base Case Plan

25 Header 25 Performance Upside

26 Header 26  Sliding sleeves - 40 e ntry points  Plug & Perf - 1920 entry points  Increased sand concentration  Advanced perforation technology  Enhanced completion fluids  Flatter decline 2016+ Plan – Plug & Perf Completions Going Forward – Lookback Type Curves use Legacy Completions Methods Potential 10% Uplift Reserves uplift has leverage positive impact on PUD PV - 9 value

27 Header 27 Standard Spaced SRL Niobrara Wells Standard vs. Upsized Job Size Cumulative Production (BOE) 2016+ Plan – Increased Proppant Loading – Lookback Type Curves Have Lower Proppant Loadings Actual Actual Reserves uplift has leverage positive impact on PUD PV - 9 value

28 Header 28 Pronghorn P - T - 17HNB Monthly Production (Net BOEM 3 - Stream) 2016+ Plan – Impact of RMI Infrastructure – Lookback Type Curves Impacted by 3 rd Party Midstream

29 Header 29 Increased Reserve Performance with RMI REMAINING PDP RESERVES REMAINING PDP RESERVES PUD RESERVES PUD RESERVES 0 25 01/15 FORECAST* 01/16 FORECAST* NET MMBOE  RMI online in East Area by mid - 2015  Reserves enhanced by reduction in line pressure and stabilized operating conditions  Realized a significant increase in performance in the East Area proved reserves from Jan . 2015 to Jan. 2016  13% increase in remaining PDP reserves (same 50 wells)  41% increase in PUD reserves (same 67 wells) East Area Proved Reserves – January 2015 to January 2016 * Volumes from January 2016 forward.

30 Header 30 Strategic Considerations

31 Header 31 BCEI Wattenberg Acreage Delineate and Develop Northwest and Southwest Acreage Weld Northwest Acreage (BCEI) Legacy Acreage (BCEI) French Lake Acreage (BCEI) Wells Ranch Acreage ( NBL) PDP (Horizontal) PDP (Vertical)  Bonanza Creek holds approximately 70,000 net acres in its Wattenberg play  Of its 70,000 net acres, ~35,000 net acres were purchased from DJ Resources in 2014  The purchased acres represent the Northwest and Southwest (French Lake) acreage positions  These acquisition acres are largely undeveloped and have the potential to unlock significant value and inventory when delineated and derisked  Preferred development of French Lake is to aggregate checkerboard acreage into a 1280 acre development plan

32 Header 32 Regional Integrated Development Plans East Pony IDP • 44,900 net ac • Stacked formations • Operated infrastructure strategically sized for life of HZ development • 15 miles oil gathering lines • Tied to Briggsdale and Platteville crude oil treating facilities Whiting Redtail IDP • 129,000 net ac • Average WI 84% • Stacked formations • Operated infrastructure strategically sized for life of HZ development • 140MMcfd Gas Plant • 141 miles gas gathering lines (connected to Trailblazer) • 111 miles oil gathering lines (connected to Pony Express) • 111 miles saltwater disposal lines • 24 miles freshwater lines • $315MM in infrastructure investment • $640MM in upstream savings through use of Central Production Facilities • $250k savings per well Noble Wells Ranch IDP • 78,100 net ac • Stacked formations • Operated infrastructure strategically sized for life of HZ development • 25 miles oil and saltwater gathering lines • 20 miles freshwater lines • 30 miles gas pipelines • 96k bbls crude oil storage • 32k bbls saltwater storage • 500k bbls freshwater storage • ~$660MM infrastructure value (w/East Pony) Bonanza Creek French Lake Unit • Uniquely positioned for IDP development • Planned operations by BCEOC • ~23,000 contiguous net acre Unit • 1280 - acre drilling blocks • 20 wells per drilling block • 350+ XRL wells stacked formations • Opportunity to plan and execute optimal midstream infrastructure • Opportunity to partner with a large Wattenberg operator of both upstream and midstream resources • Operatorship is capital dependent

33 Header 33 Development Plan with Interest O wners Coordinated under FLSU Development Plan for BCEI without Adjacent Leasehold Coordination French Lake Integrated Development

34  Phase 1 – 3Q17 – Build CPFs & Gas Infrastructure  Phase 2 – 4 Q17 – Mustang Section 22/21  Phase 3 – 1Q18 – Mustang Section 23/24  Phase 4 – 2Q18 – Mustang Section 27/28  Phase 5 – 3Q18 – Mustang Section 26/25  Phase 6 – 4Q18 – Mustang Section 34/33  Phase 7 – 1Q19 – Mustang Section 35/36  Phase 8 – 2Q19 – Mustang Section 15/14 French Lake CPF French Lake Development – Cascading Production Illustrative Integrated Development

35 Field Planning in Basin with Excess Takeaway Capacity  The overbuild of DJ Basin crude takeaway provides BCEI with a multitude of options  3 major interstate pipelines  Refineries in CO, WY & UT  Multiple rail terminals in CO and WY  RMI expansion into crude gathering is an important part of our integrated strategy for full field development  Maintaining optionality to build a crude gathering system to a nearby terminal is advantageous  Significantly de - risks crude takeaway problems related to trucking and weather  Would likely further increase the current value of RMI  Higher netback realizations are available via multiple nearby market outlets Grand Mesa Riverside Terminal Suncor Refinery 103,000 Bbls/d Utah Refineries 178,000 Bbls/d WY Refineries 177,000 Bbls/d PXP Pawnee Terminal 9 0,000 Bbls/d Grand Mesa Lucerne Terminal White Cliffs Pipeline 215,000 Bbls/d Southern WY Rail Terminals 160,000 Bbls/d Multiple Rail Terminals 120,000+ Bbls/d Grand Mesa / Saddlehorn Pipeline 340,000 Bbls/d WY Pipeline Terminals 550,000 Bbls/d

36 Header 36 Appendix

37 Header 37 Base Case Business Plan – 1 - Rig 1Q17, 2 - Rig 2Q17, 3 - Rig 4Q17 Drilling Program and Strip Pricing (1) Depicts BCEI’s base case business plan, which includes a 1 - rig drilling program starting in 2017 increasing to 3 rigs by year end. Projections do not include transportation costs / penalties under current pipeline contracts ($ in millions) Notes: ( 1) Strip pricing as of 07/15/2016 (2) Realized prices do not include any transportation fees (3) Timing adjustments primarily relate to cash impact from payment of production taxes 2016 2017 2018 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018 3Q 2018 4Q 2018 Rockies Gross Operated Production Crude Oil (b/d) 13,466 11,778 11,172 10,656 10,208 9,335 8,999 8,980 10,935 16,267 19,620 13,986 23,278 27,321 29,880 31,005 27,897 Rockies Net Production Crude Oil (b/d) 10,268 9,107 8,672 8,272 7,925 7,254 6,995 6,929 8,120 12,417 13,831 10,349 15,201 18,125 18,856 20,779 18,257 NGLs (b/d) 3,828 3,647 3,485 3,346 3,223 2,877 2,784 2,775 2,845 3,586 4,310 3,384 4,713 5,333 5,771 6,171 5,502 Natural Gas (Mcf/d) 27,301 28,887 27,670 26,527 25,529 22,753 22,005 21,918 22,344 27,827 33,191 26,355 36,164 40,769 44,021 46,988 42,021 Rockies Equivalent (boe/d) 18,646 17,569 16,769 16,039 15,404 13,924 13,447 13,357 14,689 20,641 23,673 18,125 25,941 30,252 31,965 34,781 30,762 Mid-Con Net Production Crude Oil (b/d) 2,412 2,056 2,018 1,972 1,925 1,895 1,854 1,760 1,650 1,561 1,485 1,613 1,420 1,362 1,310 1,262 1,338 NGLs (b/d) 685 651 642 628 612 604 589 554 518 489 464 506 443 424 407 392 416 Natural Gas (Mcf/d) 7,622 7,149 7,043 6,889 6,717 6,622 6,467 6,105 5,705 5,380 5,104 5,570 4,868 4,661 4,473 4,303 4,574 Mid-Con Equivalent (boe/d) 4,367 3,898 3,834 3,749 3,656 3,602 3,520 3,331 3,119 2,947 2,800 3,048 2,674 2,563 2,462 2,371 2,516 Total Net Production (mboe/d) 23,013 21,467 20,603 19,788 19,060 17,526 16,967 16,688 17,808 23,588 26,473 21,173 28,615 32,815 34,427 37,152 33,279 Realized Oil ($/bbl) (2) $43.37 $49.67 $49.55 $49.98 $50.13 $50.49 $50.77 $49.49 $50.36 $50.89 $51.43 $50.71 $51.89 $52.32 $52.71 $53.17 $52.57 NGL ($/bbl) (2) $10.59 $13.23 $13.27 $13.51 $13.69 $14.05 $14.25 $14.43 $14.53 $14.25 $14.11 $14.30 $14.09 $14.04 $14.05 $14.08 $14.06 Gas ($/Mcf) (2) $1.50 $2.20 $2.21 $2.19 $2.22 $2.38 $2.59 $2.67 $2.44 $2.44 $2.49 $2.51 $2.60 $2.22 $2.24 $2.32 $2.34 Realized Prices ($/boe) (2) $28.25 $32.18 $32.09 $32.28 $32.43 $33.14 $33.67 $33.14 $34.22 $36.06 $35.90 $35.06 $36.41 $36.61 $36.56 $37.23 $36.73 Total Revenues $19.7 $21.6 $20.6 $19.3 $19.3 $17.6 $17.8 $50.1 $56.0 $78.8 $88.4 $273.3 $95.6 $111.2 $118.6 $129.7 $455.1 Less: Rockies Lease Operating Expense ($2.6) ($3.2) ($3.1) ($3.0) ($3.0) ($2.8) ($2.8) ($8.4) ($8.8) ($9.2) ($9.7) ($36.1) ($10.4) ($11.4) ($12.3) ($13.3) ($47.4) Less: Mid-Con Lease Operating Expense (1.7) (1.4) (1.4) (1.3) (1.3) (1.3) (1.3) (3.8) (3.7) (3.6) (3.6) (14.7) (3.5) (3.4) (3.4) (3.3) (13.6) Less: Production Tax (1.5) (1.3) (1.3) (1.2) (1.2) (1.1) (1.1) (3.2) (3.6) (5.2) (5.9) (18.0) (6.4) (7.5) (7.9) (8.7) (30.4) Less: G&A - Cash (3.8) (3.1) (3.1) (3.1) (3.1) (3.1) (3.1) (10.5) (10.5) (10.5) (10.5) (42.0) (10.5) (10.5) (10.5) (10.5) (42.0) Less: RMI Operating Expense (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (1.4) (1.4) (1.5) (1.7) (5.9) (1.9) (2.1) (2.3) (2.4) (8.7) Less: Total Operating Expenses ($10.2) ($9.4) ($9.3) ($9.1) ($9.1) ($8.8) ($8.8) ($27.3) ($28.0) ($30.1) ($31.3) ($116.7) ($32.6) ($34.8) ($36.4) ($38.2) ($142.1) EBITDAX $9.5 $12.2 $11.4 $10.2 $10.2 $8.8 $9.1 $22.9 $28.0 $48.7 $57.1 $156.6 $62.9 $76.4 $82.1 $91.5 $313.0 Less: Total Adjustments (3) - 1.6 1.3 (0.9) (0.6) 0.1 (0.8) 4.2 (0.3) 2.8 13.9 20.6 3.8 (2.0) 4.2 (8.0) (2.7) Operating Cash Flow $9.5 $13.7 $12.7 $9.4 $9.6 $8.9 $8.3 $27.1 $27.7 $51.5 $71.0 $177.3 $66.7 $74.5 $86.3 $83.6 $310.3 E&P Capex (0.3) (2.0) (2.7) (1.1) (0.6) (1.0) (0.2) (25.4) (58.6) (63.7) (71.5) (219.2) (75.4) (79.9) (92.8) (86.7) (334.8) RMI Capex - (0.2) (0.2) - - - - (29.8) (44.6) (19.2) (14.4) (108.1) (14.2) (14.4) (10.0) (16.0) (54.6) Less: Total Capex (0.3) (2.2) (2.9) (1.1) (0.6) (1.0) (0.2) (55.3) (103.2) (82.9) (85.9) (327.2) (89.6) (94.3) (102.8) (102.7) (389.4) Less: (Increase) / Decrease in Working Capital 22.0 3.8 (4.9) 3.8 (13.1) 3.9 3.8 (3.9) (18.0) 10.3 2.1 (9.6) 2.6 (14.9) 9.1 0.9 (2.3) Unlevered FCF $31.2 $15.2 $4.9 $12.1 ($4.1) $11.7 $11.8 ($32.1) ($93.5) ($21.1) ($12.9) ($159.5) ($20.4) ($34.7) ($7.4) ($18.2) ($81.4) EBITDAX Under Current Pipeline Transport Agreeements $9.5 $9.7 $8.9 $7.9 $7.8 $3.9 $4.0 $7.6 $12.7 $32.7 $41.9 $94.9 $49.2 $62.3 $67.6 $75.6 $254.7 2017 2018

38 Header 38 Alternate Model – 1 - Rig Drilling Program and Strip Pricing (1) Depicts financial projections assuming 1 - rig drilling program starting in 2017 through 2018. Projections do not include transportation costs / penalties under current pipeline contracts ($ in millions) Notes: ( 1) Strip pricing as of 07/15/2016 (2) Realized prices do not include any transportation fees (3) Timing adjustments primarily relate to cash impact from payment of production taxes 2016 2017 2018 Jun-16 Jul-16 Aug-16 Sep-16 Oct-16 Nov-16 Dec-16 1Q 2017 2Q 2017 3Q 2017 4Q 2017 1Q 2018 2Q 2018 3Q 2018 4Q 2018 Rockies Gross Operated Production Crude Oil (b/d) 13,466 11,778 11,172 10,656 10,208 9,335 8,999 9,281 12,493 14,432 14,384 12,666 15,220 15,497 16,559 15,964 15,814 Rockies Net Production Crude Oil (b/d) 10,268 9,107 8,672 8,272 7,925 7,254 6,995 7,170 9,366 11,007 10,735 9,583 11,129 10,435 10,974 11,000 10,884 NGLs (b/d) 3,828 3,647 3,485 3,346 3,223 2,877 2,784 2,834 3,135 3,478 3,684 3,285 3,721 3,621 3,749 3,722 3,703 Natural Gas (Mcf/d) 27,301 28,887 27,670 26,527 25,529 22,753 22,005 22,358 24,517 27,013 28,496 25,617 28,724 27,930 28,851 28,620 28,532 Rockies Equivalent (boe/d) 18,646 17,569 16,769 16,039 15,404 13,924 13,447 13,730 16,587 18,987 19,167 17,138 19,637 18,711 19,531 19,492 19,343 Mid-Con Net Production Crude Oil (b/d) 2,412 2,056 2,018 1,972 1,925 1,895 1,854 1,760 1,650 1,561 1,485 1,613 1,420 1,362 1,310 1,262 1,338 NGLs (b/d) 685 651 642 628 612 604 589 554 518 489 464 506 443 424 407 392 416 Natural Gas (Mcf/d) 7,622 7,149 7,043 6,889 6,717 6,622 6,467 6,105 5,705 5,380 5,104 5,570 4,868 4,661 4,473 4,303 4,574 Mid-Con Equivalent (boe/d) 4,367 3,898 3,834 3,749 3,656 3,602 3,520 3,331 3,119 2,947 2,800 3,048 2,674 2,563 2,462 2,371 2,516 Total Net Production (mboe/d) 23,013 21,467 20,603 19,788 19,060 17,526 16,967 17,061 19,706 21,934 21,967 20,186 22,311 21,274 21,993 21,863 21,859 Realized Oil ($/bbl) (2) $43.37 $49.67 $49.55 $49.98 $50.13 $50.49 $50.77 $49.50 $50.35 $50.89 $51.42 $50.63 $51.89 $52.31 $52.71 $53.15 $52.52 NGL ($/bbl) (2) $10.59 $13.23 $13.27 $13.51 $13.69 $14.05 $14.25 $14.40 $14.38 $14.29 $14.29 $14.33 $14.35 $14.45 $14.47 $14.55 $14.46 Gas ($/Mcf) (2) $1.50 $2.20 $2.21 $2.19 $2.22 $2.38 $2.59 $2.67 $2.43 $2.45 $2.51 $2.51 $2.62 $2.25 $2.27 $2.35 $2.37 Realized Prices ($/boe) (2) $28.25 $32.18 $32.09 $32.28 $32.43 $33.14 $33.67 $33.22 $34.54 $35.35 $35.14 $34.65 $35.81 $35.20 $35.62 $36.09 $35.68 Total Revenues $19.7 $21.6 $20.6 $19.3 $19.3 $17.6 $17.8 $51.4 $62.5 $71.9 $71.5 $257.2 $72.5 $69.0 $73.3 $73.6 $288.5 Less: Rockies Lease Operating Expense ($2.6) ($3.2) ($3.1) ($3.0) ($3.0) ($2.8) ($2.8) ($8.4) ($8.5) ($8.8) ($9.0) ($34.7) ($9.2) ($9.4) ($9.6) ($9.8) ($37.9) Less: Mid-Con Lease Operating Expense (1.7) (1.4) (1.4) (1.3) (1.3) (1.3) (1.3) (3.8) (3.7) (3.6) (3.6) (14.7) (3.5) (3.4) (3.4) (3.3) (13.6) Less: Production Tax (1.5) (1.3) (1.3) (1.2) (1.2) (1.1) (1.1) (3.3) (4.1) (4.8) (4.7) (16.9) (4.8) (4.6) (4.8) (4.9) (19.1) Less: G&A - Cash (3.8) (3.1) (3.1) (3.1) (3.1) (3.1) (3.1) (10.5) (10.5) (10.5) (10.5) (42.0) (10.5) (10.5) (10.5) (10.5) (42.0) Less: RMI Operating Expense (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (0.5) (1.4) (1.4) (1.4) (1.4) (5.6) (1.5) (1.4) (1.6) (1.6) (6.0) Less: Total Operating Expenses ($10.2) ($9.4) ($9.3) ($9.1) ($9.1) ($8.8) ($8.8) ($27.3) ($28.2) ($29.1) ($29.2) ($113.8) ($29.4) ($29.3) ($29.9) ($30.1) ($118.7) EBITDAX $9.5 $12.2 $11.4 $10.2 $10.2 $8.8 $9.1 $24.1 $34.3 $42.7 $42.3 $143.4 $43.1 $39.7 $43.4 $43.6 $169.8 Less: Total Adjustments (3) - 1.6 1.3 (0.9) (0.6) 0.1 (0.8) 8.5 (14.9) 2.0 8.0 3.6 (6.4) 3.5 0.7 (5.9) (8.0) Operating Cash Flow $9.5 $13.7 $12.7 $9.4 $9.6 $8.9 $8.3 $32.5 $19.4 $44.7 $50.3 $146.9 $36.7 $43.2 $44.1 $37.7 $161.8 E&P Capex (0.3) (2.0) (2.7) (1.1) (0.6) (1.0) (0.2) (32.5) (33.6) (34.5) (33.0) (133.5) (19.9) (27.0) (31.9) (19.5) (98.3) RMI Capex - (0.2) (0.2) - - - - (7.4) (6.5) (2.9) (3.6) (20.4) (1.3) (4.3) (7.3) (0.7) (13.6) Less: Total Capex (0.3) (2.2) (2.9) (1.1) (0.6) (1.0) (0.2) (39.9) (40.1) (37.4) (36.6) (154.0) (21.2) (31.3) (39.2) (20.2) (111.9) Less: (Increase) / Decrease in Working Capital 22.0 3.8 (4.9) 3.8 (13.1) 3.9 3.8 (3.9) (17.9) 10.4 2.2 (9.2) 2.9 (14.6) 9.4 1.2 (1.0) Unlevered FCF $31.2 $15.2 $4.9 $12.1 ($4.1) $11.7 $11.8 ($11.3) ($38.6) $17.8 $15.9 ($16.2) $18.4 ($2.7) $14.3 $18.7 $48.9 EBITDAX Under Current Pipeline Transport Agreeements $9.5 $9.7 $8.9 $7.9 $7.8 $3.9 $4.0 $8.8 $18.8 $26.8 $26.5 $80.9 $27.8 $25.0 $28.7 $28.5 $110.0 2017 2018

39 Header 39 ($ in millions) 2017 2018 Total New Spuds 99 155 Total New IPs 74 139 Avg. WI% 81.3% 77.9% New SRLs 55 106 Gross D&C per SRL $2.3 $2.3 Gross D&C SRL $126.5 $243.8 Avg. WI% 87.9% 76.1% Net D&C SRL $111.2 $185.5 New MRLs 0 3 Gross D&C per MRL $3.2 $3.2 Gross D&C MRL $0.0 $9.6 Avg. WI% 0.0% 65.5% Net D&C MRL $0.0 $6.3 New XRLs 44 46 Gross D&C per XRL $4.1 $4.1 Gross D&C XRL $180.4 $188.6 Avg. WI% 73.0% 82.7% Net D&C XRL $131.7 $156.0 Total Net D&C before Adjustments $242.9 $347.8 Activity Based Timing Adjustement (1) (25.2) (14.5) Total Net D&C $217.7 $333.3 Well Pad Connect Costs $9.2 $8.8 CPF Costs 30.2 11.3 Compression Costs 26.9 7.5 Gathering Costs 31.7 25.6 Electrical/Automation Costs 10.1 1.4 RMI Capital $108.1 $54.6 FF&E Capex $1.5 $1.5 Total $327.2 $389.4 Notes: (1) Timing adjustment for wells in progress D&C RMI FF&E Total Base Case Business Plan – Capital Expenditure Detail

40 Header 40 ($ in millions) 2017 2018 Total New Spuds 49 52 Total New IPs 48 41 Avg. WI% 84.6% 64.5% New SRLs 27 31 Gross D&C per SRL $2.3 $2.3 Gross D&C SRL $62.1 $71.3 Avg. WI% 86.2% 61.2% Net D&C SRL $53.5 $43.6 New MRLs 0 3 Gross D&C per MRL $3.2 $3.2 Gross D&C MRL $0.0 $9.6 Avg. WI% 0.0% 65.5% Net D&C MRL $0.0 $6.3 New XRLs 22 18 Gross D&C per XRL $4.1 $4.1 Gross D&C XRL $90.2 $73.8 Avg. WI% 82.7% 69.9% Net D&C XRL $74.6 $51.6 Total Net D&C before Adjustments $128.1 $101.5 Activity Based Timing Adjustement (1) 3.9 (4.7) Total Net D&C $132.0 $96.8 Well Pad Connect Costs $4.6 $3.3 CPF Costs 1.0 4.3 Compression Costs 6.2 1.0 Gathering Costs 8.7 5.1 Electrical/Automation Costs 0.0 0.0 RMI Capital $20.4 $13.6 FF&E Capex $1.5 $1.5 Total $154.0 $111.9 Notes: (1) Timing adjustment for wells in progress. D&C RMI FF&E Total Alternate Model – Capital Expenditure Detail

41 Header 41 Per Flowing Bbl Valuation Metrics  DJ Basin peers current $/flowing boe (EV/MRQ Production) as of 9/16/16.  As of 9/21/16 BCEI traded at $34,243 per flowing boe. In valuation work - ups, assumed the Company would trade up to a peer average given the presumed reduction in leverage and increase in production growth.  SocGen research dated 8/31/16 noted average $ / flowing bbl metric for US small cap companies of $87,826 .  Compared DJ Basin peers above to larger set of E&P companies comparing flowing metrics to product mix and debt leverage Company $/Flowing Boe @ 9/21/16 BBG $52,228 PDCE $95,634 SYRG $139,007 * $/ F lowing Boe data pulled from Bloomberg; calculations made by Company.

42 Header 42 Per Flowing Bbl Valuation Metrics (Cont.) BBG BCEI COG CRK CRZO CXO DNR ECR GPOR HK LPI MTDR NFX NOG OAS PDCE PQ QEP REN REXX RICE RRC SM SN SYRG WLL WPX XCO XEC 0% 20% 40% 60% 80% 100% $- $20,000.00 $40,000.00 $60,000.00 $80,000.00 $100,000.00 $120,000.00 $140,000.00 $160,000.00 MRQ Production Mix (% oil) $/Flowing Boe BBG BCEI COG CRZO CXO DNR ECR GPOR LPI MTDR NFX NOG OAS PDCE PQ QEP REN REXX RICE RRC SM SN SYRG WLL WPX XEC 0.0 4.0 8.0 12.0 16.0 $- $20,000.00 $40,000.00 $60,000.00 $80,000.00 $100,000.00 $120,000.00 $140,000.00 $160,000.00 2016 Estimated Net Debt/EBITDAX $/ Flowing Boe * $/ F lowing Boe data pulled from Bloomberg; calculations made by Company. BCEI COG CRZO CXO DNR ECR GPOR LPI MTDR NFX NOG OAS PDCE PQ QEP REN REXX RICE RRC SM SN SYRG WLL WPX XEC -30% -10% 10% 30% 50% 70% $- $20,000.00 $40,000.00 $60,000.00 $80,000.00 $100,000.00 $120,000.00 $140,000.00 $160,000.00 2017 Estimated Production Growth $/ Flowing Boe

43 Header 43 Geologic Description of the Niobrara and Codell Late Cretaceous Turonian Coniacian & Santonian Greenhorn Carlile Codell SS Niobrara Sharon Springs Fort Hays LS Smokey Hill A Chalk A Marl B Chalk B Marl C Chalk C Marl D Chalk Niobrara Formation  Two Structural Units: Smokey Hill Chalk and Fort Hays Limestone  Smokey Hill member made up of interbedded Chalks and Marls  Niobrara B Bench and C Bench are primary targets for horizontal wells  Niobrara A Bench potential being evaluated Codell Sandstone  Thinner compared to Niobrara  Tight , clay rich sand  Primary target for horizontal wells Resistivity Porosity Gamma Ray Latham 14 - 2 Formations with existing horizontal wells Niobrara Formation Codell Sandstone

44 Header 44  Legacy Acreage  Utilize existing infrastructure  72% of 2017 base case wells utilize existing RMI gas gathering infrastructure  45% of 2017 base case wells will utilize existing RMI CPFs  Build out development using 2 mile radius around CPFs  2014  State North Platte CPF 42 - 26  2015  Pronghorn CPF 41 - 32  State Antelope CPF O - 1  Antelope CPF 13 - 21  2017+  Whitetail CPF A - 4  Seventy Holes CPF B - 5  Pronghorn CPF A - 15  French Lake CPF #1 FRENCH LAKE Infrastructure Utilization Strategy