INVESTOR UPDATE - Battalion Oilbattalionoil.com/wp-content/uploads/2020/03/BATL-March...2020/03/25 · them; revisions to reserve estimates as a result of changes in commodity prices;

Photo credit: © 2020 Battalion Oil Corp.Q1 2020 Safety Stand Down, Ward County, TexasPre-Dawn Drilling Safety Meeting

M A R C H 2 O 2 OINVESTOR UPDATE

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This presentation contains forward-looking statements that are intended to be covered by the safe harbor within the meaning of the Private Securities Litigation Reform Act of 1995 as stated in Section27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Statements that are not strictly historicalstatements constitute forward-looking statements and may often, but not always, be identified by the use of such words such as “expects,” “believes,” “intends,” “anticipates,” “plans,” “estimates,”“guidance,” “target,” “potential,” “possible,” or “probable” or statements that certain actions, events or results “may,” “will,” “should,” or “could” be taken, occur or be achieved. The forward-lookingstatements include statements about the expected future reserves, production, financial position, business strategy, revenues, earnings, costs, capital expenditures and debt levels of the Company, andplans and objectives of management for future operations. Forward-looking statements are based on current expectations and assumptions and analyses made by Battalion and its management inlight of experience and perception of historical trends, current conditions and expected future developments, as well as other factors appropriate under the circumstances. However, whether actualresults and developments will conform to statements regarding oil, natural gas liquids or gas reserves is subject to a number of material risks and uncertainties, including but not limited to: further andsubstantial declines in oil, natural gas liquids or natural gas prices; risks relating to any unforeseen liabilities; the level of success in exploration, development and production activities; adverse weatherconditions that may negatively impact development or production activities; the timing of exploration and development expenditures; inaccuracies of reserve estimates or assumptions underlyingthem; revisions to reserve estimates as a result of changes in commodity prices; impacts to financial statements as a result of impairment write-downs; risks related to levels of indebtedness andperiodic redeterminations of the borrowing base under the Company’s credit agreement; Battalion’s ability to generate sufficient cash flows from operations to meet the internally funded portion of itscapital expenditures budget; Battalion’s ability to obtain external capital to finance exploration and development operations and acquisitions; the ability to successfully complete any potentialacquisitions for value and the risks related thereto; the impacts of hedging on results of operations; uninsured or underinsured losses resulting from oil and natural gas operations; Battalion’s ability toreplace oil and natural gas reserves; and any loss of senior management or key technical personnel. Battalion’s 2019 Annual Report on Form 10-K and subsequent, quarterly reports on Form 10-Q andcurrent reports on Form 8-K, and other Securities and Exchange Commission (“SEC”) filings discuss some of the important risk factors identified that may affect Battalion’s business, results ofoperations, and financial condition. Battalion undertakes no obligation to revise or update publicly any forward-looking statements except as required by law.

This presentation contains Battalion’s 2020 production, capital expenditure and operating expense guidance. The actual levels of production, capital expenditures and operating expenses may behigher or lower than these estimates due to, among other things, uncertainty in drilling schedules, changes in market demand and unanticipated delays in production. These estimates are based onnumerous assumptions. All or any of these assumptions may not prove to be accurate, which could result in actual results differing materially from estimates. No assurance can be made that any newwells will produce in line with historical performance, or that existing wells will continue to produce in line with expectations. Battalion’s ability to fund its 2020 and future capital budgets is subject tonumerous risks and uncertainties, including volatility in commodity prices and the potential for unanticipated increases in costs associated with drilling, production and transportation.

This presentation includes references to certain non-GAAP financial information, such as adjusted EBITDA, adjusted general and administrative expense, and the PV-10 value of proved reserves. Thesemeasures are presented based on management's belief that they will enable a user of the financial information to understand the impact of these items on reported results. Additionally, thispresentation provides a beneficial comparison to similarly adjusted measurements of prior periods. These financial measures are not measures of financial performance under GAAP and should not beconsidered as an alternative to GAAP. These financial measures may not be comparable to similarly named non-GAAP financial measures that other companies may use and may not be useful incomparing the performance of those companies to Battalion's performance.

This presentation has been prepared by Battalion and includes market data and other statistical information from third-party sources, including independent industry publications, governmentpublications or other published independent sources. Although Battalion believes these third-party sources are reliable as of their respective dates, Battalion has not independently verified the accuracyor completeness of this information. Some data are based on Battalion’s good faith estimates, which are derived from its review of internal sources as well as the 3rd-party sources described above.

Management’s use of the term estimated ultimate recovery (“EUR”) in this presentation describes estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from being included infilings with the SEC. These are more speculative than estimates of proved, probable and possible reserves and accordingly are subject to substantially greater risk of being actually realized, particularlyin areas or zones where there has been limited or no drilling history. We include EUR to demonstrate what we believe to be the potential for future drilling and production by Battalion.

Actual quantities that may be ultimately recovered may differ substantially from estimates. Factors affecting ultimate recovery include the scope of the operators' ongoing drilling programs, which willbe directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatoryapprovals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of potential resources may also change significantly as thedevelopment of the properties underlying Battalion's mineral interests provides additional data. This presentation also contains Battalion’s internal estimates of its potential drilling locations, whichmay prove to be incorrect in a number of material ways and may. Actual results may be substantially different than estimates.

Disclaimer: Forward Looking Statements

WHY HERE?

Overpressured, oily position in Delaware Basin Well hedged, low-decline PDP production base Limited drilling obligations, substantially all HBP Firm H2S treating capacity with flow assurance

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Executive Summary

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Key Milestones Since Q2 2019

WHY NOW?

Nimble & can quickly maneuver to market conditions Strong balance sheet, capable of neutral FCF Positioned to achieve scale via responsible M&A Upside from inventory @ breakeven below $30 WTI

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Financial Restructuring

Office Consolidation

Substantial G&A Reduction

Integrated New Team

Reduced Well Costs

ESG Stewardship Focus

Secured Flow Assurance (H2S)

Reduced Expenses

Obtained AGI Permit

Listed on NYSEA (“BATL”)

New Strategy

New Board

New Name

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WHY BATTALION?

Battalion is not Halcon Consistent record of organic value creation Broad & deep experience in Permian operations Focused on capital discipline & accountability

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Distinct Future from Halcon’s Past; Organic Growth vs. M&A

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Acquisition & Asset Ownership Summary vs. Historical Leverage & WTI Benchmark Price

Ch.11 Ch.11

Appalachia

Eagle Ford / Eaglebine

Bakken / Three Forks

Tuscaloosa Marine Shale

Delaware: Hackberry

Delaware: Monument

Delaware: West Quito

Halcon Battalion

His

tori

cal

A&

D

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A 1H 2012: Halcon formed via recapitalization of Ram Energy

C E FD

(Fir

st a

cqu

isit

ion

to

exi

t)

LTM

Ne

t Le

vera

ge

WTI

NY

MEX

($

/Bb

l)

B

C

Q4 2013: Last acquisition of many major foundation assets

Q3 2016: Halcon emerged from chapter 11

D Q1 2018: Divestiture of legacy asset base; become pure play Delaware

E

F

Q3 2019: Emergence from restructuring resulting in strong balance sheet

Q1 2020: Battalion team in formation and ready for BATL

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Current Management History Together Across Multiple Companies

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Management’s Prior Experience Executive Management Team

24 years of experience

Previously CEO at Ajax Resources

VP of Southern Division at EP Energy; joined El Paso in ‘07

Prior roles including Peoples Energy, Holditch & Associates and Halliburton

30+ Years of experience

Previously CFO at Ajax Resources and US CFO at Hill + Knowlton Strategies

Started career working with E&P clients at Coopers & Lybrand and later at The Houston Exploration Company

14 years of experience

Previously VP, Operations at Ajax Resources

Business Area Manager of Permian Division at EP Energy

Started with El Paso in ‘05 as an operations engineer

Richard H. Little, Chief Executive Officer

Ragan T. Altizer, Chief Financial Officer

Daniel P. Rohling, Chief Operating Officer

Battalion management has evaluated and/or exploited among the most prolific hydrocarbon producing regions in the US

o Focused operations in unconventional basins including Permian, Eagle Ford, Haynesville and Uinta

o Conducted operations across over 800,000 net acres

Most recently led the executive management team of Ajax Resources, which sold to Diamondback in Oct-18 for $1.24B

Over 400 horizontal wells drilled and participated in over $7B in A&D in the Permian Basin alone

The team has a significant track record of driving down costs and improving returns in challenging areas during challenging times

Permian Basin

Uinta Basin

Barnett

Haynesville

Wilcox

Eagle Ford

Acreage Operated:

800,000+Unconventional:

>90%Permian Focus:

>30%

Oil-Rich Position in the Delaware Basin with 1.0MMBo EURs

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Highest-return field with 1.0 MMBo EUR wells

Net Acreage: ~22,216 with ~95% average W.I.

~8,100 Gross / ~5,600 Net oil production (76 % oil)

38 Gross producing wells

Opportunities to trade land to optimize laterals / WI


~3,400 Gross/ ~2,300 Net oil production (44 % oil)


Stable, low-decline PDP base


~4,500 Gross/ ~3,300 Net oil production (61 % oil)


No further activity required in 2020 to hold position

Balanced and complementary co-located asset base

Net Acreage: ~52,368 (2,000+ Gross total locations)

~16,000 Gross / ~11,000 Net oil production (62 % oil)

Mo

nu

men

tW

est

Qu

ito

Hac

kber

ryTo

tal D

elaw

are

MonumentWest Quito

Hackberry

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400

0 120 240 360 480 600 720

Tho

usa

nd

s

Significant Experience in Horizontal, Permian Development

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Total D&C Cost ($/Ft) Total D&C Cost ($/Ft) Total D&C Cost ($/Ft)

Lease Operating Expense ($/Boe) Lease Operating Expense ($/Boe) Lease Operating Expense ($/Boe)

Daily Cumulative Gross Oil Production (Bopd) Daily Cumulative Gross Oil Production (Bopd) Daily Cumulative Gross Oil Production (Bopd)

S Midland: 180K net acres / 350+ HZ Wells N Midland: 25K net acres / 50+ HZ Wells BATL Delaware: 52K net acres / 9 HZ Wells Drilled

$407

$357

$296

2014 2015 2016

$7.71

$6.31

$4.70

2014 2015 2016

$1,185

$1,096

$972

2016 2017 2018

$9.60

$6.08

$4.07

2016 2017 2018

$1,530

$1,265

$855

2018 Q1 19 Q4 19

$9.23 $9.22

$6.86

2018 Q1 19 Q4 19

(27)%

(39)%

(18)%

(58)%

(32)%

(26)%

0

100

200

300

400

0 120 240 360 480 600 720

Tho

usa

nd

s

0

100

200

300

400

0 120 240 360 480 600 720

2017 / 2018: 15 Wells

2015 / 2016: 7 Wells2019: 8 Wells2017 / 2018: 13 Wells

2016 / 2017: 95 Wells2012 / 2013: 11 Wells

…Consistently Improving Operations and Lowering Costs

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Monument Draw West Quito Draw

0 10 20 30 40 50 60

0'

2,500'

5,000'

7,500'

10,000'

12,500'

15,000'

17,500'

20,000'

22,500'

0 10 20 30 40 50 60

5,000’ Laterals

7,500’ Laterals

10,000’ Laterals

BATL Well BATL Well

…by Connecting Drilling Operations and Geosciences

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Shale Carbonate

0

20

40

60

80

100

120

15,000' 16,000' 17,000' 18,000' 19,000' 20,000'

10,000'

12,000'

14,000'

16,000'

18,000'

20,000'

22,000'

0 4 8 12 16 20

HUNTER 2601AH

HUNTER A 2602H

Rat

e o

f P

enet

rati

on

(Fe

et/H

r)

Dep

th v

s. D

ays:

Lat

eral

Using 3D seismic inversion, geosteering team elected to deviate from original drilling plan due to evidence of limestones (green) while drilling first of two twin wells

Resulted in 40% higher ROP from 17,000’-20,000’, 3 less bits and nearly 6 less days to rig release ($500K of savings)

AVG ROP: 43AVG ROP: 60

2602 Deviation from plan

2602

2601

1,000’

Source: Proprietary data permitted to be shared by WesternGeco.

…and by Connecting Completions Operations and Geosciences

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Mapping Carbonate Content to Lower Stimulation CostManaging Pump Design Stage by Stage to Mitigate Costs

jdr

Cost Correlation Driving Savings in Q1 2020 and Beyond

$25K

$30K

$35K

$40K

$45K

Well 1 Well 2 Well 3 Well 4 Well 5 Well 6

0.80

0.85

0.90

0.95

1.00

Cost/Stage (L) Frac Gradient, psi/ft (R)

Frac

Gra

die

nt

(psi

/ft)

Carbonate Content

Leveraging seismic inversion to draw correlations between frac gradient and stimulation cost

Driving savings by mitigating impact of carbonates and modifying completion design from stage to stage

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6

9

12

15

18

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15

20

25

30

Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19

Sulfur (MLbpd)

Gas (MMcfpd)

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+20 35

+35 70

+200 270

Jun-19 Q3'19 Dec-19 Q1'20 Dec-20 AGI Total

Leading the Industry in Significant H2S Treating Capacity

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Substantial Reduction in Unit Cost

Daily Throughput Capable of Handling Higher Concentrations Commissioned liquid redox plant at Everest CPF

in Q2 2019 with inconsistent run-times

Designed and implemented process and mechanical changes in Q3 2019 to substantially improve throughput and cost structure

Completed expansion of facility in Q1 2020 with addition of third processing train, doubling capacity to 70 MMcfpd

Obtained permit to construct Acid Gas Injection (“AGI”) facility from TX RRC in Q1 2020

Permit secures long term flow assurance as well as upside from potential offset producers

H2S Capacity Expansion (MLbpd)

$0.00

$2.00

$4.00

$6.00

$8.00

$10.00

$0.00

$2.50

$5.00

$7.50

$10.00

Jul-19 Aug-19 Sep-19 Oct-19 Nov-19 Dec-19

$/Lb $/Mcf

2.9

1.9

5.2

2.7

3.7

3.1

2018 2019 2018 2019 2018 2019

Crude Oil Produced Water Chemical

Focus on Health & Safety Awareness and Improvement …

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Note: Spill rate calculated as LTM volume of liquids spilled divided by LTM volume produced multiplied by 1,000,000

LTM Trailing Spill Rate

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200

400

600

800

1,000

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33% 48% 17%

Spill Occurrences per 1,000,000 bbl of Oil Production Performed 7,307 proactive EHS efforts in 2019

581 Orientation sessions with new contractors and 30 Emergency Response Drills conducted in 2019 emphasizing safety and stop work authority

Field EHS staff equipped with H2S monitors as well as thermal imaging cameras to identify and address any leaks or releases promptly

Implementing field-wide digital hazard observation platform to streamline communication

Consistently Outperforming TRIR Benchmarks

0.00

0.20

0.40

0.60

0.80

1.00

1.20

Jan

-19

Feb

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Mar

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Ap

r-1

9

May

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Jun

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Jul-

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g-1

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Oct

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No

v-1

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9Industry Benchmark: 1.00

AXPC Benchmark: 0.65

0.06

0.110.12 0.13 0.13 0.14 0.14 0.15

0.18

0.25

0.61

0.00

0.05

0.10

0.15

0.20

0.25

BATL Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 1 Peer 9

Leading Performance in Flaring Intensity (Mcf/Bbl)(1)

… And Striving for Environmental Stewardship & Social Responsibility

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(1) Source: 2/18/20 TXRRC flaring report. Peers include: AXAS, CDEV, CPE, LPI, OAS, QEP, RING, ROSE, SM, and XEC

Peer group leader for low level of flaring intensity (1)

Sulfur incinerator online in Q1’20 reducing emissions

20+ Vapor Recovery Units in Q1 2020

Nearly all oil production piped to CPF minimizing trucking

100% of water piped to SWD

Active Leak Detection & Repair Program

Key Highlights

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Consolidated Corporate Office

Male Female

Q4 2019 Financial Highlights

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YE 2019 Capitalization & Liquidity Summary

Increased annual oil production Annual growth of 6% over 2018 to 10,356 Bopd for FY 2019 with Q4 2019 oil production of 11,489 Bopd

Decreased operating costs $18.28/Boe in Q4 2019 from $36.98/Boe in Q4 2018 and $30.40/Boe in Q3 2019

Decreased adjusted G&A$3.22/Boe in Q4 2019 from $5.08/Boe in Q4 2018 and $4.92/Boe in Q3 2019

Generated adjusted LTM EBITDA of $90 MMCompared to $91 MM for 2018 and $130 MM from Q4 2019 annualized Adjusted EBITDA of $33 MM

Generated LTM Net Leverage of 1.54xPeer-leading leverage @ YE 2019 Entering 2020 from a position of strength

Hedged 94% of YE’19 PDP @ >$56.00 in Bal 20Protecting base cash flow with plain-vanilla swaps and collars

$0,000 12/31/19

Cash & Cash Equivalents $5,701

RBL Indebtedness $144,000

Total Indebtedness, Net $138,299

RBL Borrowing Base $240,000

Less: Indebtedness ($144,000)

Less: Letters of Credit ($2,308)

Plus: Cash $5,701

Availability $99,393

Adjusted EBITDA, LTM $89,719

Adjusted EBITDA, LQA $130,316

Net Leverage, LTM 1.54x

Net Leverage, LQA 1.06x

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With Downside Protection in Place ($125MM MTM Value @ 3/20)

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0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022

Swaps

2 Way Collars

Downside Fixed Price Hedged Oil Volume (Bopd)

Q2 2020 Q3 2020 Q4 2020 Q1 2021 Q2 2021 Q3 2021 Q4 2021 Q1 2022 Q2 2022 Q3 2022 Q4 2022

Fixed Collar, Bopd 4,000 4,000 4,000 0 0 0 0 0 0 0 0

Fixed Swap, Bopd 3,000 3,000 3,000 6,000 5,000 4,000 4,000 4,000 4,000 4,000 4,000

Basis, Bopd 7,000 7,000 7,000 6,000 5,000 4,000 4,000 4,000 4,000 4,000 4,000

Roll, Bopd 7,000 7,000 7,000 6,000 5,000 4,000 4,000 4,000 4,000 4,000 4,000

Collar (Floor), $/Bbl $53.13 $53.13 $53.13 0 0 0 0 0 0 0 0

Fixed Swap, $/Bbl $57.14 $57.96 $57.49 $53.21 $52.45 $51.91 $51.91 $51.50 $51.50 $51.50 $51.50

Basis, $/Bbl + $0.73 + $0.78 + $0.79 + $0.91 + $0.89 + $0.85 + $0.85 + $0.88 + $0.88 + $0.88 + $0.88

Roll, $/Bbl + $0.48 + $0.49 + $0.47 + $0.24 + $0.17 + $0.14 + $0.14 + $0.00 + $0.00 + $0.00 + $0.00

Total Price, $/Bbl $56.06 $56.46 $56.25 $54.36 $53.51 $52.90 $52.90 $52.38 $52.38 $52.38 $52.38

Uniquely Positioned Today to Scale Opportunistically

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LTM Net Leverage

Source: SEC filings and company disclosures; peers include: AXAS, CPE, CDEV, ESTE, OAS, QEP, REI, ROSE

$2.67 $2.72 $2.74 $3.03

$4.30 $4.50 $4.64 $4.77 $4.85

$0.00

$1.00

$2.00

$3.00

$4.00

$5.00

$6.00

Peer 1 Peer 2 BATL Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8

1.11x

1.54x 1.76x 1.85x 1.89x

2.42x

2.81x 2.96x

3.09x

0.00x

0.50x

1.00x

1.50x

2.00x

2.50x

3.00x

3.50x

Peer 1 BATL Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8

Total G&A ($/Boe)

Average: $3.80 / Boe

Average: 2.00x

Reliable FCF from PDP & Near Term Inventory for Responsible Growth

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YE 2019 SEC Audited Reserves Premium Drilling Inventory in Monument (10,000’ Lateral)

Oil Volume by Reservoir Category

PDP: 52.7%

PDNP: 5.6%

PUD: 41.7%

3rd BS Upside151 Locations

Wolfcamp A99 Locations (24 PUDs)

Wolfcamp B113 Locations

Woodford UpsideOffset operator tests

1st/2nd BS Upside153 Locations

Note: Differences in PV-10 value and standardized measure attributable to future income taxes discounted at 10%.

Upside

Primary Target(s)

Swiftly Calibrating Activity According to Market Environment

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YE 19 NSAI PUD

PD

YE 2019 DUC; POL Q1 20

2019 Actuals FY 2020 Guidance

FY Q4 Initial Revised

Oil Production, MBopd 10.4 11.5 11.1 – 11.7 10.3 – 10.8

Total Production, MBoepd 18.0 20.3 18.5 – 19.5 17.5 – 18.5

Rig Count 4.0 → 1.0 1.0 1.0 0.4

Wells POL 17 3 12 – 14 6 – 7

Total D&C Capex, $MM $162 $24 $105 – $115 $45 – $55

D&C Cost per Well, $/ft ~$1,350 $855 $1,000 – $1,250 $800 – $1,100

LOE, $/Boe $7.98 $6.86 $6.00 – $7.50

Infrastructure Capex, $MM $84 $11 $15 – $20 $12 – $18

H2S Capacity, MLbpd 35 35 70

G&A, $MM $42 $5 $20 – 25 $18 – 22

Suspending remaining 2020 discretionary activity to

preserve cash flow

Contact:John-Davis Rutkauskas(832) 538-0551

Photo credit: © 2020 Battalion Oil Corp.Q1 2020 Safety Stand Down, Ward County, TexasPre-Dawn Drilling Safety Meeting

Documents

INVESTOR UPDATE - Battalion Oilbattalionoil.com/wp-content/uploads/2020/03/BATL-March...2020/03/25 · them; revisions to reserve estimates as a result of changes in commodity prices;