INVESTOR PRESENTATION. February 2019

INVESTOR PRESENTATION February 2019

Disclaimer: Forward Looking Statements and Non-GAAP Information This presentation contains various statements, including those that express belief, expectation or intention, as well as those that are not statements of historical fact, that are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. These forward-looking statements may include projections and estimates concerning Bonanza Creek Energy, Inc. s (the Company ) capital expenditures, liquidity and capital resources, estimated revenues and losses, timing and success of specific projects, outcomes and effects of litigation, claims and disputes, business strategy and other statements concerning the Company s operations, economic performance and financial condition. When used in this presentation, the words could, believe, anticipate, intend, estimate, expect, forecast, may, continue, predict, potential, project and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. The Company has based these forward-looking statements on certain assumptions and analyses it has made in light of its experiences and perceptions of historical trends, current conditions and expected future developments as well as other factors it believes are appropriate under the circumstances. The actual results or developments anticipated by these forward-looking statements are subject to a number of risks and uncertainties, many of which are beyond the Company s control, and may not be realized or, even if substantially realized, may not have the expected consequences. Factors that could cause actual results to differ materially include, but are not limited to, the following: the Company s ability to replace oil and natural gas reserves; declines or volatility in prices it receives for its oil and natural gas, including any impact on the Company s asset carrying values or reserves arising from the price declines; its financial position; its cash flow and liquidity; general economic conditions, whether internationally, nationally or in the regional and local market areas in which the Company does business; development and completion expectations and strategy; impact of the Company s reorganization; initial 2019 guidance, the Company s ability to generate sufficient cash flow from operations, borrowings or other sources to enable it to fully develop its undeveloped acreage positions; the presence or recoverability of estimated oil and natural gas reserves and the actual future production rates and associated costs; uncertainties associated with estimates of proved oil and gas reserves and, in particular, probable and possible resources; the possibility that the industry may be subject to future regulatory or legislative actions (including additional taxes and changes in environmental regulation); environmental risks; drilling and operating risks, including risks related to horizontal drilling; exploration and development risks; competition in the oil and natural gas industry; management s ability to execute the Company s plans to meet its goals, uncertainties of negotiations to result in an agreement or a completed transaction; the Company s ability to retain key members of its senior management and key technical employees; infrastructure challenges; access to adequate gathering systems and pipeline take-away capacity to execute the Company s drilling program; the Company s ability to secure firm transportation for oil and natural gas it produces and to sell the oil and natural gas at market prices; costs associated with perfecting title for mineral rights in some of the Company s properties; the Company s ability to realize estimated well cost reductions; continued hostilities in the Middle East; other sustained military campaigns or acts of terrorism or sabotage; and other economic, competitive, governmental, legislative, regulatory, geopolitical and technological factors that may negatively impact the Company s businesses, operations or pricing; and other important factors that could cause actual results to differ materially from those projected in this presentation and in the Company s filings with the U.S. Securities and Exchange Commission (the SEC ). For further detail on these and other risks and uncertainties, the Company refers you to the information under the headings Risk Factors in the Company s Annual Report on Form 10-K for the year ended December 31, 2018 and in comparable sections of our Quarterly Reports on Form 10-Q, as filed with the SEC. All of the forward-looking statements made in this presentation are qualified by these cautionary statements and are made only as of the date hereof. The Company does not undertake, and specifically declines, any obligation to update any such statements or to publicly announce the results of any revisions to any such statements to reflect future events or developments. Although the Company believes that its plans, intentions and expectations reflected in or suggested by the forward-looking statements it makes in this presentation are reasonable, the Company can give no assurance that these plans, intentions or expectations will be achieved. This presentation also includes historical and forward-looking financial measures that are not in accordance with generally accepted accounting principles ( GAAP ), included Adjusted EBITDAX and PV-10. While management believes such measures are useful for investors because they allow for greater transparency with respect to key financial metrics, they should not be used as a replacement for financial measures that are in accordance with GAAP. Please see appendix for a reconciliation of non-gaap financial measures. PV-10 represents the present value, discounted at 10% per year, of estimated future net cash flows. The Company s calculation of PV-10 using SEC prices herein differs from the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC in that it is calculated before income taxes rather than after income taxes using the average price during the 12- month period, determined as an unweighted average of the first-day-of-the-month price for each month. With respect to PV-10 calculated as of an interim date, it is not practical to calculate the taxes for the related interim period because GAAP does not provide disclosure of standardized measure on an interim basis. The Company s calculation of PV-10 using SEC benchmark pricing as of December 31, 2018 should not be considered as an alternative to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC. Please see appendix for a reconciliation of year-end 2018 PV-10 to standardized measure. This presentation also includes information regarding our PDP PV-10 at strip pricing as of February 19, 2019 for year end 12/31/18 reserves. Strip pricing as of February 19, 2019 for WTI crude oil and Henry Hub natural gas were as follows: $57.81/$2.81, $58.01/$2.75, $56.42/$2.65, $55.28/$2.66, $54.72/$2.72, $54.51/$2.81, $54.52/$2.90, $54.62/$3.00, $54.62/$3.10 for years 2019, 2020, 2021, 2022, 2023, 2024, 2025, 2026, and 2027 thereafter. By attending or receiving this presentation you acknowledge that you will be solely responsible for your own assessment of the market and the market position of the Company and that you will conduct your own analysis and be solely responsible for forming your own view of the potential future performance of the Company s business. This presentation does not constitute the solicitation of the purchase or sale of any securities. This presentation has been prepared for informational purposes only from information supplied by the Company and from third-party sources. Such third-party information has not been independently verified. The Company makes no representation or warranty, expressed or implied, as to the accuracy or completeness of such information. Trademarks that appear in this presentation belong to their respective owners. 2 2

Bonanza Creek Pure Play Wattenberg Operator Highly contiguous, oily leasehold in rural Wattenberg Over 1,000 future economic drilling locations (1) Wattenberg Target Proved Reserves 12/31/18 Niobrara/Codell ~116.8 MMBoe (42% PDP) Acres Production 4Q18 ~65,000 net 17.75 MBoe/d (62% oil) Strong financial position 2018 exit leverage of 0.3x Debt/EBITDAX > $300 million of liquidity at 12/31/18 Year-end 2018 SEC PV-10 of $955 million (2) PDP PV-10 at strip of $480 million (3) Expected 2019 Wattenberg production growth in excess of 30% (4) Capex of $230MM - $255MM in 2019 vs $275MM in 2018 (4) Expected 2019 exit leverage of ~0.5x Debt/EBITDAX (4) Rocky Mountain Infrastructure ( RMI ) provides low well head gathering pressures and access to four gas processors through eleven interconnects Company s leasehold is 100% located in unincorporated Weld County (1) Gross, SRL equivalent (2) SEC pricing based off of $65.56 WTI, and $3.10 Henry Hub. (3) PV-10 based on reserves as of 12/31/18 using 2/19/19 strip pricing. See Forward Looking Statements for strip pricing as of 2/19/19. (4) Based on guidance provided on January 30, 2019 which was predicated on $50 WTI and $3 Henry Hub. 3 3

Growth & Value Opportunity Building a Track Record of Solid Growth in Wattenberg ~48% production growth Q417 to Q418 >30% annualized growth 2018 to 2019 (1) ~20% production growth 2019 to 2020 (1) Strong Balance Sheet >$300 million of liquidity at 12/31/18 Expected 2019 exit leverage of ~0.5x Debt/EBITDAX (1) Wattenberg Production (Mboe/d) 28.0 24.0 20.0 16.0 12.0 8.0 4.0 0.0 14.1 12.6 12.5 12.0 ~48% Production Growth 4Q17 to 4Q18 13.7 15.1 > 30% Production Growth 2018 to 2019 16.8 17.7 24.0-20.0 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 2019 Expected 2020 exit leverage of < 1.0x Debt/EBITDAX (1) 5.0x 4.5x 4.0x Compelling Valuation (2) ~2.3x 2019 EV/EBITDAX vs DJ Peer Group of ~3.3x and SMID Cap Peer Group Average of 4.4x EV/EBITDA 3.5x 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x (1) Based on guidance provided on January 30, 2019 which was predicated on $50 WTI and $3 Henry Hub. (2) Peer Group includes HPR, PDCE, SRCI, and XOG and SMID Cap Peer Group includes AXAS, CPE, CRZO, ECR, HK, and MTDR and is based on Bloomberg consensus estimates as of 2/26/19 0.0x BCEI DJ Basin Peer Group SMID Cap Peer Group 4 4

Building a Track Record of Execution Wattenberg Production Adjusted EBITDAX & EBITDAX Margin (1) Mboe/d 20.0 ~48% Growth 16.0 12.0 8.0 14.1 16.8 17.7 12.6 12.5 13.7 15.1 12.0 4.0 0.0 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Wattenberg LOE Wattenberg Revenues & Realized Prices (2) ($MM) $50.0 52.0% 63.9% $40.0 48.7% 50.1% 43.3% 47.4% 43.4% 46.6% $30.0 $38.4 $41.9 $29.7 $34.8 $20.0 $26.3 $18.9 $21.3 $21.6 $10.0 $0.0 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 EBITDAX EBITDAX Margin 70.0% 60.0% 50.0% 40.0% 30.0% 20.0% 10.0% 0.0% EBITDAX Margin ($/Boe) LOE/BOE $7.00 $6.00 $5.00 $4.00 $3.00 $2.00 $1.00 $0.00 ~45% Decline $5.47 $5.94 $5.76 $6.11 $6.00 $6.01 $4.26 $3.27 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 ($MM) $80.0 $70.0 $60.0 $50.0 $40.0 $30.0 $20.0 $10.0 $0.0 $41.79 $43.02 $45.28 $40.14 $35.79 $32.07 $28.98 $29.58 $69.9 $66.2 $59.0 $51.7 $40.6 $33.6 $34.1 $39.4 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 $50.00 $40.00 $30.00 $20.00 $10.00 $0.00 ($/Boe) (1) As reported. Adjusted EBITDAX is a non-gaap number. See appendix for reconciliation of Adjusted EBITDAX to Net Income. (2) Before impacts of derivatives 5 5

Wattenberg Assets ~65,000 net / ~92,000 gross acres in high-value multi-stack pay ~60% oil & ~20% NGLs Upstream + RMI gathering efficiencies Contiguous acreage in rural Weld County No municipalities overlapping our acreage Over 1,000 future gross drilling locations (1) Colorado (1) Gross, SRL equivalent 6

Rocky Mountain Infrastructure Rocky Mountain Infrastructure Assets ~140 miles of pipelines 100 MMcf/d of gas gathering capacity 11 interconnects to 4 midstream gas processors 6 compressor sites, ~30k total horsepower capacity 4 CPFs with total 36 Mbo/d capacity ~22 miles of water gathering connecting to 2 third party disposal wells ~15 miles of current oil gathering Additional ~16 miles of oil pipeline to Riverside in late 2Q19 lowers diff by $1.25 - $1.50 (1) RMI Benefits to Upstream Business Provides consistent and low wellhead pressure Operating and surface use cost efficiencies Delivery point flexibility with greater access to 3 rd party processing Cureton contract helps unlock Northern acreage and additional firm gas processing Company growth not impacted by basin-wide gas processing constraints 7 (1) The Company s 2019 oil differential guidance includes this expected benefit. For Company s oil moving through pipeline to Riverside only. 7

RMI Provides Consistent and Low Wellhead Pressure and Flow Assurance 500 BCEI/RMI vs Prevailing Field Pressures Line Pressure (psi) 400 300 200 100 Prevailing Field Pressure BCEI/RMI Field Pressure 0 Jun-16 Sep-16 Dec-16 Mar-17 Jun-17 Line Pressure (psi) Sep-17 Dec-17 Mar-18 Jun-18 Sep-18 Dec-18 500 400 300 200 100 Pre-Gathering System Inconsistent Line Pressure, Low Production and Erratic Flowrates Production vs Line Pressure (1) Connected to Gathering Post-Gathering System Consistent Line Pressure, Higher Production and Predictable Flowrates 375 300 225 150 75 Gross Production (boed) 0 Month 1 Month 6 Month 12 0 Line Pressure (psi) Gross Production (boed) (1) Represents actual line pressure and well performance from group of wells that were completed, produced, and later connected into Rocky Mountain Infrastructure. 8 8

2019 Capital Program Capex: $230MM - $255MM with primary focus in Legacy West & Central 2019 D&C Capex: $210MM - $220MM ~55% SRL / ~45% XRL gross development D&C: $3.5 - $4.0MM SRL / $5.6 - $6.1MM XRL Proppant: 2,000-2,250 lbs/ft vs avg. ~1,800 lbs/ft in 18 Fluid: 2,000-2,250 gal/ftvs avg. ~1,300 gal/ftin 18 Drill: 59 gross / 38.6 net wells Turn to sales: 45 gross / 32.8 net wells Exit 2019 with approximately 10 net wells in progress (1) Operational Focus High-intensity completion designs driving well performance Enhanced recovery flow back generating higher oil yields Own and operate midstream gathering to enhance flow assurance & lower costs Centralized facilities deliver lower lifting costs Maintain operational flexibility to prudently respond to market conditions (1) Wells that have been drilled, completed or completing but not turned to sales 9

Higher-Intensity Completion Design Driving Value Creation 2018 Completion Design 100,000 Cumulative Oil 2017 Completion Design Tighter stage and perforation architecture Increased proppant intensity Increased slickwater volumes and rates Optimized reservoir pressure management Enhanced fracture complexity Cumulative Production (BO) 80,000 60,000 40,000 20,000 2018 38% + 2017 135% + Pre-2017 0 0 100 200 300 400 500 600 700 800 Time (days) Legacy Completion 2017 Completion 2018 Completion 10 10

Enhanced Completions & Spacing Driving Resource Recovery Uplift (1) Downspacing test at K-22 pad continues to perform inline with offset results on a per 45,000 K-22 Pad (2Q 2018) Well Density: 16 wells /section I-21 Pad (1Q 2019) Well Density: 16 wells / section well basis in Legacy West Early results from I-21 pad (~16 wells/section) pad exceeding type curve 3-Stream Cumulative Production (Mboe/1,000') 4,000 I-21 Pad 3,500 ~16 wells/section 3,000 2,500 2,000 1,500 1,000 500 0 0 15 30 Time (Days) 3-Stream Cumulative Production (Mboe/1,000') 40,000 35,000 30,000 25,000 20,000 15,000 10,000 5,000 2019 West SRL TC 2018 Legacy West Wells (2018) ~11 wells/section Includes F-26, O-26, and I-26 pads 0 0 30 60 90 120 150 180 210 240 270 300 330 360 Time (Days) Higher density spacing providing ~50% increase in per section resource recovery (1) Well performance represent Niobrara B and C results only. 11 11

Encouraging Results from French Lake Contiguous leasehold in rural Weld County 25 Accommodates XRL (9,500 ) development Initial XRL delineation wells are encouraging 6 of 8 outperforming their respective type curve State Longhorn has coil tubing BHA stuck in lateral Recently added artificial lift Mustang had failed casing Recently executed joint development plan Currently working on midstream plan 3-Stream Cumulative Production (Mboe/1,000') 20 15 10 5 State Longhorn D14-11-12 Mustang V41-34-33 0 0 30 60 90 120 150 180 210 240 270 300 330 360 French Lake DELINEATION XRL TC (1) Proppant Intensity: ~2,250 ppf Fluid Intensity: ~2,100 gpf Time (Days) (1) Delineation type curve represents French Lake actuals constrained by incomplete infrastructure buildout. 12 12

High Intensity Stimulation Designs Driving Enhanced Well Performance (1) Legacy West Type Curves Legacy Central Type Curves Cumulative Boe 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000-1,030 Mboe EUR 580 Mboe EUR 0 30 60 90 120 150 180 210 240 270 Days on Production Cumulative Boe 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000-930 Mboe EUR 520 Mboe EUR 0 30 60 90 120 150 180 210 240 270 Days on Production XRL Type Curve SRL Type Curve XRL Type Curve SRL Type Curve Legacy East Type Curves French Lake Type Curves (2) Cumulative Boe 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000-0 30 60 90 120 150 180 210 240 270 Days on Production 830 Mboe EUR 470 Mboe EUR XRL Type Curve SRL Type Curve XRL Delineation Type Curve XRL Development Type Curve (1) Type curves predicated on 2017 and 2018 actuals. 75%-80% liquids depending on drawdown and thermal maturation. (2) Delineation type curve represents French Lake actuals constrained by incomplete infrastructure buildout. Development type curve represents the Company s best estimate with infrastructure buildout expected late 2019. Cumulative Boe 180,000 160,000 140,000 120,000 100,000 80,000 60,000 40,000 20,000-0 30 60 90 120 150 180 210 240 270 Days on Production 940 Mboe EUR 13 13

2019 Guidance Focused on Profitable Growth & Operational Flexibility (1) Guidance (2) FY18 Actuals FY19 Guidance Production (Mboe/d) 15.8 20.0 24.0 LOE ($/Boe) $4.76 $3.00 - $3.50 RMI Opex ($/Boe) $1.35 $1.10 - $1.40 Severance Ad/Valorem Tax (as a % of revenue) 8.9% 8% - 9% Oil Differential ($/bbl) $6.02 $4.25 - $5.25 Total Capex ($MM) D&C Capex ($MM) $275 $230 - $255 $250 $210 - $220 Current program provides for production growth in excess of 30% while maintaining ample liquidity and a strong balance sheet Maintain operational flexibility Prudently respond to market conditions to maximize shareholder returns Expected 2019 exit leverage of ~0.5x Debt/EBITDAX Anticipating production growth of ~20% and exit leverage of < 1.0x Debt/EBITDAX in 2020 (1) Based on guidance provided on January 30, 2019 which was predicated on $50 WTI and $3 Henry Hub. (2) Represents actuals and guidance for Wattenberg assets only. 14 14

Strong Financial Position COMMITTED TO MAINTAINING FINANCIAL STRENGTH AND FLEXIBILITY TO PARTICIPATE IN FULL-CYCLE VALUE CREATION Patient capital structure with low leverage > $300 million of liquidity as of 12/31/18 Pro-active hedging philosophy to protect revenues Disciplined capital allocation and returns-focused production growth 15

Appendix 16 16

Hedged Volumes* Oil Hedges Natural Gas Hedges 12,000 10,000 8,828 9,830 9,000 9,000 25,000 20,000 20,739 21,709 22,500 22,500 8,000 6,000 4,000 2,000 0 $57.84 $59.16 $59.92 $59.92 $51.46/ $65.40 $55.00 $54.51/ $68.74 $58.13/ $75.54 $58.13/ $75.54 5,000 $63.48 $55.00/ $62.00 1Q19 2Q19 3Q19 4Q19 1Q20 15,000 10,000 5,000 0 $2.20 $3.13 $2.75/ $3.22 $2.15 $2.75/ $3.22 $2.13 $2.13 2,500 $2.40 1Q19 2Q19 3Q19 4Q19 1Q20 Oil Puts (bopd) Oil Collars (bopd) Oil Swaps (bopd) NYMEX Collars (mcfpd) NYMEX Swaps (mcfpd) CIG Fixed Swaps (mcfpd) Protect cash flow and reduce price volatility Combination of swaps and collars above prices that provide line-of-sight to free cash flow positive Employ CIG fixed and basis hedges to help ensure realized natural gas prices Floating Index MMBtu/Day Weighted Average Basis Differential to NYMEX Henry Hub (per MMBtu) 1Q19 CIG 7,600 $0.665 *Hedges as of 2/26/2019. 17 17

Adjusted EBITDAX Reconciliation Adjusted EBITDAX is a supplemental non-gaap financial measure that is used by management to provide a metric of the Company's ability to internally generate funds for exploration and development of oil and gas properties. The metric excludes items which are non-recurring in nature and/or items which are not reasonably estimable. Management believes Adjusted EBITDAX provides external users of the Company s consolidated financial statements such as industry analysts, investors, lenders, and rating agencies with additional information to assist in their analysis of the Company. The Company defines Adjusted EBITDAX as earnings before interest expense, income taxes, depreciation, depletion, amortization, impairment, exploration expenses and other similar non-cash and non-recurring charges. Adjusted EBITDAX is not a measure of net income (loss) or cash flows as determined by GAAP. The following table presents a reconciliation of the GAAP financial measure of net income (loss) to the non-gaap financial measure of Adjusted EBITDAX. 1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18 Net income $ (94,276) $ 93,356 $ 4,328 $ (5,768) $ 13,870 $ 4,859 $ 43,363 $ 106,094 Exploration 3,407 651-3,386 29 221 (6) 47 Depreciation, depletion and amortization 21,212 11,689 7,350 9,126 7,508 9,564 10,987 13,824 Abandonment and impairment of unproved properties - - - - 2,502 2,477 430 (138) Unused commitments - - - - 21 - - - Stock-based compensation (1) 1,725 8,340 2,646 1,035 1,008 2,184 1,741 2,223 Severance costs (1) - - 1,605 - - - 279 - Ad valorem reimbursement - - - - - - - (5,134) Advisor fees related to CEO search and strategic alternatives (1) - - - 2,774 - - - - Interest expense 4,568 1,283 265 313 357 805 608 833 Derivative gain (loss) - - 2,762 12,603 8,742 22,012 16,078 (77,103) Derivative cash settlements - - - (1,464) (4,312) (7,310) (8,322) 1,784 Gain on sale of oil and gas properties - - - - - - (26,720) (604) Pre-petition advisory fees (1) 683 - - - - - - - Post-petition restructuring fees (1) - 1,422 2,317 - - - - - Reorganization items, net 89,003 (97,811) - - - - - - Income tax effect - - - (376) - - - - Deferred financing costs amortization - - - - - - - 30 Adjusted EBITDAX $ 26,322 $ 18,930 $ 21,273 $ 21,629 $ 29,725 $ 34,812 $ 38,438 $ 41,856 (1) Included as a portion of general and administrative expense in the consolidated statements of operations. 18 18