INVESTOR PRESENTATION

J a n u a r y 2 0 1 9

22

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; updated 2018 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, 2017 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 September 30, 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 2017 PV-10 to standardized measure.

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.

33

Bonanza Creek – Pure Play Wattenberg Operator

Target Proved Reserves 9/30/18

Niobrara/Codell ~107 MMBoe (40% PD)

Acres Production 3Q18

~67,000 net 16.8 MBoe/d (60% oil)

Wattenberg

• Highly contiguous, oily leasehold in rural Wattenberg

• Over 1,000 economic drilling locations(1)

• Strong financial position

• 2018 exit leverage of < 0.5x Debt/EBITDAX(3)

• > $300 million of liquidity

• Wattenberg Proved Reserves PV-10 of $749 million as of September 30, 2018(2)

• 56% growth vs year-end 2017

• Rocky Mountain Infrastructure (“RMI”) provides low well head gathering

pressures and access to four gas processors through eleven interconnects

• Company growth not impacted by basin-wide gas processing

constraints

(1) Gross, SRL equivalent

(2) PV-10 using SEC benchmark pricing as of 9/30/18. See appendix for reconciliation of 12/31/17 PV-10 to

Standardized Measure.

(3) Assumes 2018 guided program, 2-rig program in 2019, and strip pricing as of October 1, 2018

44

Growth & Value Opportunity

• ~25% annualized production growth 2017 to 2018(1)

• ~50% production growth Q417 to Q418(1)

• >50% annualized growth 2018 to 2019(1)

Building a Track Record of Solid Growth

• >$300 million of liquidity

• 2018 exit leverage of < 0.5x Debt/EBITDAX(2)

• Maintain < 1.0x Debt/EBITDAX throughout 2019(2)

• FCF positive in Q4 2019(2)

Strong Balance Sheet

Compelling Valuation

• ~2.4x 2019 EV/EBITDAX vs DJ Peer Group of ~2.9x(3) and SMID Cap Peer Group

Average of 4.1x(3)

14.112.6 12.5 12.0

13.715.1

16.8

18.2-

17.6

0.0

4.0

8.0

12.0

16.0

20.0

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

Mb

oe

/d

~50% Wattenberg

Growth

0.0x

0.5x

1.0x

1.5x

2.0x

2.5x

3.0x

3.5x

4.0x

4.5x

BCEI DJ Basin Peer Group SMID Cap Peer GroupEV

/EB

ITD

A

(1) Assumes 2018 guided program and 2-rig program in 2019

(2) Assumes 2018 guided program, 2-rig program in 2019, and strip pricing as of October 1, 2018

(3) Peer Group includes HPR, PDCE, SRCI, and XOG and SMID Cap Peer Group includes AXAS, CPE, CRZO, ECR, HK, MTDR,, and WRD and is based on

Bloomberg consensus as of 11/1/18

55

Wattenberg Assets

• ~67,000 net / ~92,000 gross acres in high-value

multi-stack pay

• ~60% oil & ~20% NGLs

• Upstream + RMI gathering efficiencies

• Existing right-of-way, pipelines, and facilities

does not require extra permitting or surface use

contracts

• Contiguous and rural Weld County with less surface

cultural risk

• No municipalities overlapping our acreage

• Over 1,000 gross drilling locations(1)

Colorado

(1) Gross, SRL equivalent

66

Rocky Mountain Infrastructure

• 120 miles of gas gathering pipe

• 100 MMcf/d of gas gathering capacity

• 11 interconnects to downstream gas processors

• 6 compressor sites with 32k total horsepower

• 4 CPFs with total 24 Mbo/d capacity

• 12 miles of pipe connecting 3 CPFs to 2 third party disposal wells

• Owned and operated by BCEI

• Provides consistent and low wellhead pressure

• Operating and surface use cost efficiencies

• Delivery point flexibility provides greater access to 3rd party

processing

• Opportunity to expand oil on pipe to Riverside terminal improving

oil netbacks

• New Cureton contract helps unlock Northern acreage and

provides additional firm gas processing

Rocky Mountain Infrastructure Assets

RMI Benefits to Upstream Business

Company growth not impacted by basin-wide gas processing constraints

77

RMI Provides Consistent and Low Wellhead Pressure and Flow Assurance

0

100

200

300

400

500

Jun-16 Sep-16 Dec-16 Mar-17 Jun-17 Sep-17 Dec-17 Mar-18 Jun-18 Sep-18

Lin

e P

ress

ure

(p

si)

BCEI/RMI vs Prevailing Field Pressures

BCEI/RMI Field Pressure

Prevailing Field Pressure

0

75

150

225

300

375

0

100

200

300

400

500

Gro

ss P

rod

uct

ion

(b

oe

d)

Lin

e P

ress

ure

(p

si)

Production vs Line Pressure

Line Pressure (psi) Gross Production (boed)

Connected to Gathering

Pre-Gathering System

Inconsistent Line Pressure, Low

Production and Erratic Flowrates

Post-Gathering System

Consistent Line Pressure, Higher

Production and Predictable Flowrates

Month 1 Month 6 Month 12

88

2018 Capital Program

• Spud 84 gross / 64 net wells

• Turn online 49 gross / 37 net wells

• Capex: $275MM - $295MM

Operational Focus…

• High-intensity completion designs driving value creation

• Enhanced recovery flow back generating higher oil yields

• Centralized gas lift delivering lower lifting costs

3Q18 Highlights…

• 11% sequential production growth in Wattenberg

• ~30% sequential decline in Wattenberg LOE to $4.26/Boe

• Encouraging performance in French Lake

• Executed French Lake joint development agreement

• Outstanding results in Legacy with F-26 and K-22 pads

99

Building a Track Record of Execution

$5.47 $5.94 $5.76 $6.10 $6.00 $6.01

$4.26$4.30

-$3.90

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

$7.00

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

LOE/

BO

E

14.1 12.6 12.5 12.013.7 15.1

16.8

18.2-

17.6

0.0

4.0

8.0

12.0

16.0

20.0

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18 4Q18

Mb

oe

/d

$26.3$18.9 $21.3 $21.6

$29.7$34.8

$38.4

$0.0

$5.0

$10.0

$15.0

$20.0

$25.0

$30.0

$35.0

$40.0

$45.0

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18

($M

M)

$40.6$33.6 $34.1 $39.4

$51.7$59.0

$69.9

$32.07$28.98 $29.58

$35.79

$41.79 $43.02$45.28

$0.00

$5.00

$10.00

$15.00

$20.00

$25.00

$30.00

$35.00

$40.00

$45.00

$50.00

$0.0

$10.0

$20.0

$30.0

$40.0

$50.0

$60.0

$70.0

$80.0

1Q17 2Q17 3Q17 4Q17 1Q18 2Q18 3Q18

($/B

oe

)

($M

M)

~50% Growth ~75% Growth

Wattenberg Production

Wattenberg LOE Wattenberg Revenues & Realized Prices(2)

Adjusted EBITDAX(1)

~75% Growth

~30% Decline

(3)

(3)

(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

(3) Based on guidance given on 11/8/18.

1010

Higher-Intensity Completion Design Driving Value Creation

2018 Completion Design

2017 Completion Design

• Tighter stage and perforation

architecture

• Increased proppant intensity

• Increased slickwater volumes and

rates

• Optimized reservoir pressure

management

• Enhanced fracture complexity

0

30,000

60,000

90,000

0 100 200 300 400 500 600 700 800

Cu

mu

lati

ve P

rod

uct

ion

(B

O)

Time (days)

Cumulative Oil

Legacy Completion 2017 Completion 2018 Completion

140% +

40% +

Pre-2017

2017

2018

1111

0

5

10

15

20

25

30

0 30 60 90 120 150 180 210 240 270 300 330

3-S

tre

am C

um

ula

tive

Pro

du

ctio

n (

MB

oe

/1,0

00

')

Time (Days)

Enhanced Completions & Spacing Driving Resource Recovery Uplift in Legacy West

F-26 - Day 230

23.5 MBoe (67% oil)

~11 wells/section density

North Platte 44-13 - Day 360

28.0 MBoe (58% oil)

~11 wells/section density

K-22 - Day 135

13.1 MBoe (69% oil)

~16 wells/section density

North Platte 44-13 Pad

Proppant Intensity: ~2,000 ppf

Fluid Intensity: ~1680 gpf

Stage Spacing: ~100 ft

West 80-Acre SRL TC

Proppant Intensity: 1,000 ppf

Fluid Intensity: 840 gpf

Stage Spacing: 225 ft

F-26 Pad

Proppant Intensity: ~2,000 ppf

Fluid Intensity: ~1260 gpf

Stage Spacing: ~100 ft

K-22 Pad

Proppant Intensity: ~2,050 ppf

Fluid Intensity: ~2,520 gpf

Stage Spacing: ~125 ft

Higher density spacing on K-22 providing ~50% increase in per section resource recovery

• Downspacing test (K-22 pad) completed in 2Q18

continues to perform inline with offset results on a

per well basis

• Drilled on ~40-acre spacing (16 wells/section)

• F-26 pad completed in 1Q18 and North Platte 44-13

pad completed in 3Q17

• Drilled on ~60-acre spacing (11 wells/section)

• All pads incorporated enhanced completion design

and are significantly outperforming previous area

type curve

1212

Encouraging Results from French Lake

• Contiguous leasehold in rural Weld County

• Accommodates XRL (9,500’) development

• Initial XRL appraisal wells are encouraging

• 6 of 8 are outperforming their respective type curve

• State Longhorn has a coil tubing BHA stuck in the lateral

• Recently added artificial lift

• Mustang had failed casing

• Recently executed joint development plan

• Progressing toward unlocking the value of this acreage bloc

0

2

4

6

8

10

12

14

16

18

0 30 60 90 120 150 180 210 240 270 300 330 360

3-S

tre

am C

um

ula

tive

Pro

du

ctio

n (

Mb

oe

/1,0

00

')

Time (Days)

Mustang V41-34-33

State Longhorn D14-11-12

Central 80-Acre XRL TC

Proppant Intensity: 1,000 ppf

Fluid Intensity: 600-850 gpf

Stage Spacing: 225 ft

West 80-Acre XRL TC

Proppant Intensity: ~1,000 ppf

Fluid Intensity: ~600-850 gpf

Stage Spacing: ~ 200 ft

French Lake 80-Acre XRL (8 well avg)

Proppant Intensity: ~2,000 ppf

Fluid Intensity: ~1760 gpf

Stage Spacing: ~130 ft

1313

2018 Guidance – Focused on Profitable Growth

• 2018 Program is weighted to the back half

• ~50% Wattenberg growth in 4Q18 versus 4Q17

• >50% annual production growth in 2019

• 2018 exit leverage < 0.5x Debt to EBITDAX

• Free cash flow positive in 4Q19(2)

• Expected average annual Wattenberg oil differential of $6.00 per Bbl in

2018(3)

Guidance 4Q18

FY18

Pro-forma(4) FY18

Production (Mboe/d) 17.6 – 18.2 15.8 – 16.0 17.5 – 17.7

Lease Operating Expense ($/Boe) $3.90 - $4.30 $4.95 - $5.05 $5.65 - $5.75

Gas Plant and Midstream Opex ($/Boe) $1.20 - $1.40 $1.37 - $1.47 $1.70 - $1.80

Severance Tax Ad/Valorem

(as a % of revenue)

7% - 8%

Recurring Cash G&A ($MM) (1) $32.5 - $33.5

(1) Recurring cash G&A guidance is a non-GAAP measure that is defined as GAAP G&A expense less stock based compensation. The Company does not guide to GAAP G&A expense as it has excessive uncertainty due to the stock based compensation portion of GAAP G&A

(2) Assumes October 1, 2018 strip pricing

(3) Assumes actual differential for first nine months of 2018 and strip pricing as of October 1, 2018 for remainder of year

(4) Pro-forma represents the Company estimate for the full year 2018 excluding results for the Mid-Continent operations

1414

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

• Pro-active hedging philosophy to protect revenues

• Disciplined capital allocation and returns focused production growth

1515

Appendix

1616

Guidance – Wattenberg Operations

1Q18

Wattenberg

2Q18

Wattenberg

3Q18

Wattenberg

4Q18(E)

Wattenberg

FY18(E)

Wattenberg

Production (Mboe/d) 13.7 15.1 16.8 17.6 – 18.2 15.8 – 16.0

Lease Operating Expense ($/Boe) $6.00 $6.01 $4.26 $3.90 - $4.30 $4.95 - $5.05

Gas Plant and Midstream Opex ($/Boe) $1.92 $1.59 $1.00 $1.20 - $1.40 $1.37 - $1.47

1717

Hedged Volumes*

• 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

7,000

8,500

9,330

8,500 8,500

3,000

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

10,000

4Q18 1Q19 2Q19 3Q19 4Q19 1Q20

Oil Hedges

Oil Collars (bopd) Oil Swaps (bopd)

$59.33

$58.07

$58.32

$59.94 $59.94

$63.48$43.00/

$53.50

$50.29/

$62.23

$54.35/

$66.80

$60.00/

$75.86$60.00/

$75.86

12,600

19,100

12,505

10,000 10,000

0

5,000

10,000

15,000

20,000

25,000

4Q18 1Q19 2Q19 3Q19 4Q19

Natural Gas Hedges

NYMEX Collars (mcfpd) NYMEX Swaps (mcfpd) CIG Fixed Swaps (mcfpd)

$2.75/

$3.35

$2.75/

$3.22

$2.75/

$3.22

$3.13

$2.17

$2.17

$2.17$2.17

Floating

Index MMBtu/Day

Weighted Average

Basis Differential to

NYMEX Henry Hub

(per MMBtu)

4Q18 CIG 12,600 $0.67

1Q19 CIG 7,600 $0.665

*Hedges as of 11/1/18.

1818

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

Net income (94,276)$ 93,356$ 4,328$ (5,768)$ 13,870$ 4,859$ 43,363$

Exploration 3,407 651 - 3,386 29 221 (6)

Depreciation, depletion and amortization 21,212 11,689 7,350 9,126 7,508 9,564 10,987

Abandonment and impairment of unproved properties - - - - 2,502 2,477 430

Unused commitments - - - - 21 - -

Stock-based compensation (1) 1,725 8,340 2,646 1,035 1,008 2,184 1,741

Severance costs (1) - - 1,605 - - - 279

Advisor fees related to CEO search and strategic alternatives (1) - - - 2,774 - - -

Interest expense 4,568 1,283 265 313 357 805 608

Derivative loss - - 2,762 12,603 8,742 22,012 16,078

Derivative cash settlements - - - (1,464) (4,312) (7,310) (8,322)

Gain on sale of oil and gas properties - - - - - (26,720)

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) - - -

Adjusted EBITDAX 26,322$ 18,930$ 21,273$ 21,629$ 29,725$ 34,812$ 38,438$

(1) Included as a portion of general and administrative expense in the consolidated statements of operations.

1919

12/31/17 PV-10 Reconciliation

PV-10 values are non-GAAP financial measures as defined by the SEC. The Company believes that the presentation of PV-10 value is relevant and useful to its investors because it presents the

discounted future net cash flows attributable to reserves prior to taking into account corporate future income taxes and the Company's current tax structure. The Company further believes

investors and creditors use pre-tax PV-10 values as a basis for comparison of the relative size and value of its reserves as compared with other companies.

The GAAP financial measure most directly comparable to pre-tax PV-10 is the standardized measure of discounted future net cash flows ("Standardized Measure"). With respect to PV-10

calculated as of an interim date, GAAP does not provide for disclosure of standardized measure on an interim basis. It is not practical to calculate the taxes for the related interim period.

The following table presents a reconciliation of GAAP Standardized Measure to the non-GAAP financial measure of PV-10.

(in thousands)

PV-10 (1) $ 598,498

Present value of future income taxes discounted at 10% (2) –

Standardized Measure $ 598,498

(1) The 12-month average benchmark pricing used to estimate SEC proved reserves and PV-10 value for crude oil and natural gas was $51.34 per Bbl of WTI crude oil and $2.98 per MMBtu of natural gas at Henry Hub before differential adjustments. Year-end 2017

benchmark prices for oil, and natural gas were both 20% higher from year-end 2016 SEC pricing. After differential adjustments, the Company's SEC pricing realizations for year-end 2017 were $46.76 per Bbl of oil, $19.57 per Bbl of NGLs, and $2.45 per Mcf of natural

gas.

(2) The tax basis of the Company's oil and gas properties as of December 31, 2017 provides more tax deduction than income generation when reserve estimates were prepared using 2017 SEC pricing.