March 2019

Legacy Reserves Overview

This presentation shall not constitute an offer, nor a solicitation of an offer, of the sale or purchase of any securities or any of the businesses or assets described herein, nor shall any securities of Legacy Reserves Inc.

(“Legacy”) be offered or sold, in any jurisdiction in which such an offer, solicitation or sale would be unlawful.

Forward-Looking Information

This presentation includes “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, including, without

limitation, statements regarding the evaluation of financial, transactional, and other strategic alternatives, the expected future growth and dividends of Legacy, and plans and objectives of management for future operations. All

statements, other than statements of historical facts, included in this presentation that address activities, events or developments that Legacy expects, believes or anticipates will or may occur in the future, are forward-looking

statements. Words such as “anticipates,” “expects,” “intends,” “plans,” “targets,” “projects,” “believes,” “seeks,” “schedules,” “estimated,” and similar expressions are intended to identify such forward-looking statements. These

forward-looking statements rely on a number of assumptions concerning future events and are subject to a number of uncertainties, factors and risks, many of which are outside the control of Legacy, which could cause results

to differ materially from those expected by management of Legacy. Such risks and uncertainties include, but are not limited to, the structure and timing of any financial, transactional or other strategic alternative and whether

any such financial, transaction or other strategic alternative will be completed; realized oil and natural gas prices; production volumes, lease operating expenses, general and administrative costs and finding and development

costs; future operating results; and the factors set forth under the heading “Risk Factors” in Legacy’s filings with the U.S. Securities and Exchange Commission (the “SEC”), including Legacy’s Annual Report on Form 10-K,

Quarterly Reports on Form 10-Q and Current Reports on Form 8-K. The reader should not place undue reliance on these forward-looking statements, which speak only as of the date of this presentation. Unless legally

required, Legacy undertakes no obligation to update publicly any forward-looking statements, whether as a result of new information, future events or otherwise.

Reserve Estimates

The SEC permits oil and natural gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms. Legacy discloses proved reserves but does

not disclose probable or possible reserves. “Proved reserves” are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically

producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire,

unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. Legacy may use terms in this presentation that the SEC’s guidelines strictly

prohibit in SEC filings, such as “estimated ultimate recovery” or “EUR,” “development potential,” and similar terms to estimate oil and natural gas that may ultimately be recovered. Legacy defines EUR as estimates of the sum

of reserves remaining as of a given date and cumulative production as of that date from a currently producing or hypothetical future well, as applicable. These broader classifications do not constitute reserves as defined by the

SEC. Estimates of such broader classification of volumes are by their nature more speculative than estimates of proved, probable and possible reserves as used in SEC filings and, accordingly, are subject to substantially

greater uncertainty of being actually realized. You should not assume that such terms are comparable to proved, probable and possible reserves or represent estimates of future production from properties or are indicative of

expected future resource recovery. Actual locations drilled and quantities that may be ultimately recovered will likely differ substantially from these estimates. Factors affecting ultimate recovery include the scope of Legacy’s

actual drilling program, availability of capital, drilling and production costs, commodity prices, availability of drilling services and equipment, actual encountered geological conditions, lease expirations, transportation constraints,

regulatory approvals, field spacing rules, actual drilling results and recoveries of oil and natural gas in place, and other factors. These estimates may change significantly as the development of properties provides additional

data.

Reserve engineering is a complex and subjective process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way and the accuracy of any reserve estimate is a function of the

quality of available data and of engineering and geological interpretation and judgment. Investors are also urged to consider closely the disclosure relating to “Risk Factors” in the Annual Report and subsequent filings with the

SEC by Legacy, which are available from Legacy’s website at www.legacyreserves.com or on the SEC’s website at www.sec.gov, for a discussion of the risks and uncertainties involved in the process of estimating reserves.

Identified Drilling Locations; Adjusted Net Acreage; Net Lateral Footage; and Small Tracts

Legacy’s estimates of gross identified potential drilling locations (as used herein, “locations”, “identified locations,” “identified horizontal locations” or “identified drilling locations”) are prepared internally by Legacy’s engineers,

geologists and management and are based upon a number of assumptions inherent in the estimates process. Management, with the assistance of Legacy’s engineers and other professionals, as necessary, conducts a

topographical analysis of Legacy’s unproved prospective acreage to identify potential well pad locations. Legacy’s engineers and geologists then apply well spacing assumptions based on industry activity in analogous regions.

A net location is calculated as a formula of a gross location multiplied by the ratio of net acreage over gross acreage. Legacy then multiplies this calculation by a pooling factor where appropriate. Legacy generally assumes

minimum 5,000’ laterals. Management uses these estimates to, among other things, evaluate Legacy’s acreage holdings and formulate plans for drilling. A number of factors could cause the number of wells Legacy actually

drills to vary significantly from these estimates, including the availability of capital, drilling and production costs, oil and natural gas prices, lease expirations, regulatory approvals and other factors. Adjusted net acreage is

calculated as a formula of Legacy ‘s net acreage multiplied by the sum of Legacy’s ownership interest in the prospective benches as a percentage of the net acres of all prospective benches underlying the net acreage with

each such percentage ownership multiplied by Legacy’s net revenue basis in such prospective bench. Adjusted net acreage is not comparable to net acreage and is a concept used by management in analyzing trades of

acreage. Net lateral footage is calculated as a formula of gross lateral footage of identified locations multiplied by Legacy’s working interest. Small Tracts represent horizontal prospects that are non-op positions and/or <1 mile

in length.

Non-GAAP Financial Measures

Legacy’s management uses Adjusted EBITDA as a tool to provide additional information and a metric relative to the performance of Legacy’s business. Legacy’s management believes that Adjusted EBITDA is useful to

investors because this measure is used by many companies in the industry as a measure of operating and financial performance and is commonly employed by financial analysts and others to evaluate the operating and

financial performance of Legacy from period to period and to compare it with the performance of our peers. Adjusted EBITDA may not be comparable to a similarly titled measure of such peers because all entities may not

calculate Adjusted EBITDA in the same manner. Adjusted EBITDA should not be considered as an alternative to GAAP measures, such as net income, operating income, cash flow from operating activities or any other GAAP

measure of financial performance.

Forward Looking Statements

2

Significant, stable, low-decline PDP generates strong cash flow and provides solid foundation

□ Q4‘18 daily production of 47.5 Mboepd (39% oil / 44% liquids)

□ Proved reserves of 165 Mmboe(1) (96% PDP)

□ Proved developed value of >$1.3 billion(1) (SEC pricing)

□ Average forecast 3-year decline of only 14%(1)(2)

□ PDP R/P of ~9 years(1)(3)

Go-forward strategy is focused on development of multi-year, operated inventory in the Permian

and East Texas

□ Permian – Midland Basin, Delaware Basin, Central Basin Platform

Broad, diversified operated position including acreage in the core of the Midland,

Delaware, and Central Basin Platform

551 / 407 identified operated hz. gross / net locations(4)

Large accumulation of “small tracts” acreage (non-operated and/or <1 mile operated)

and other non-core operated acreage helps Legacy to tactically realize further

operated upside through trades (e.g. increasing lateral lengths, adding to core tracts)

□ East Texas – Shelby Trough Hayneville / Bossier

20k consolidated, undeveloped net acres in the Shelby Trough with attractive offset

results from XTO, Comstock, and other operators

267 / 178 identified operated hz. gross / net locations(4) (Haynesville / Bossier)

□ East Texas – Freestone Cotton Valley

17k core net acres targeting the Cotton Valley Sands

70 / 58 identified operated hz. gross / net locations(4)

Corporate positioning supports Legacy’s ability to execute on its go-forward plan

□ Proven management team with deep industry experience

□ Established capability to cost-effectively manage producing properties and efficiently

develop horizontal resource plays

□ Conversion from MLP to C-Corp completed mid-2018

□ Ongoing non-core divestiture program helping Legacy streamline its portfolio and reduce

liabilities, freeing up capital to invest in core asset development

In 2018, company raised >$56 MM through 27 transactions at an average 6.1x

EBITDA multiple while also relieving ~$28MM in go-forward P&A liability

Legacy Reserves OverviewLegacy Reserves (NASDAQ: LGCY) is a long-standing Midland, Texas-based company with assets in the Permian, East Texas,

Rockies, and Mid-Continent. Legacy prides itself in prudent operations and efficient resource development.

Legacy Asset FootprintLegacy Company Highlights

Note: Darker shading represents counties with

increased reserve concentration.

_____________________________________

(1) Source: 2018 SEC reserve report (oil price of $65.56 and gas price of $3.10; the “Reserve Report”).

(2) Represents weighted average three-year PDP production decline rate, calculated from Q1’19 to Q1’22 forecast production from the Reserve Report.

(3) Represents PDP Reserves from the Reserve Report divided by annualized Q4’18 production.

(4) PUD locations contained in Reserve Report plus Identified Horizontal Locations.

3

Region Decline Rate (%)(3)

% of Total

Q4'18 Production

Permian Hz 28% 28%

Permian Other 8% 20%

Rockies (Ex. Piceance) 13% 5%

Piceance 6% 23%

East Texas 9% 23%

Mid-Con 4% 1%

Total 14% 100%

Large, Stable, Low-Decline Resource BaseGenerates Strong Cash Flow and Underpins Legacy Value

Q4’18 Production 2018 Proved Reserves by Region(1) Proved PV-10 by Region(1)

PDP Decline Rate and Production Allocation by Region Index Map / Legend

_____________________________________

(1) Source: 2018 SEC reserve report (oil price of $65.56 and gas price of $3.10; the “Reserve Report”).

(2) PV-10 associated with Spraberry and Lea fields.

(3) Represents weighted average three-year PDP production decline rate, calculated from Q1’19 to Q1’22 production from the 2018 Reserve Report.

Note: Darker shading represents counties

with increased reserve concentration.

Oil39%

NGL5%

Gas56%

47.5

Mboed

29%

2%

30%

39%165 MMboe

(96% PDP)

8%

32%

13%

47%

$1,350 MM

Permian(2)

Piceance

Other

East Texas

4

Table at right represents Legacy’s identified

operated locations; Legacy has identified these

through rigorous internal review, cross

referencing land, geology, and engineering

analyses

Identified prospects have been largely de-risked

by development activity of both Legacy and

other offset operators

Legacy’s identified operated horizontal

development locations (888 gross / 644 net)

illustrate the significant potential beyond its

Reserve Report PUDs (14 gross / 11 net hz

wells)

The table excludes locations representing:

□ Permian “small-tracts” acreage that is

typically non-operated or too small to

develop independently today

□ Overriding royalty interests (ORRIs)

□ Potential future locations stemming from

reversion of term assignments

Deep Go-Forward Development InventoryLegacy Has Identified Nearly 900 Operated Development Locations in its Core Areas

_____________________________________

Source: Company data and estimates.

(1) PUD locations contained in Reserve Report plus Identified Horizontal Locations

(2) Spacing based on Company technical work and supported by analogous, nearby development.

(1)

(2)

Legacy Identified Operated Location Summary

5

Wells

Total Identified Locations per

Gross Net Section

Midland Basin

Spraberry 84 68 4 - 8

Wolfcamp 111 97 4 - 8

Cline 4 3 8

Delaware Basin

1st Bone Spring 17 12 4

2nd Bone Spring 25 16 4

3rd Bone Spring 5 3 4

Barnett 16 11 8

Brushy 34 24 4

Wolfcamp 102 68 8

Woodford 16 9 8

Central Basin Platform

Clearfork 10 7 5

San Andres 65 37 5

Northwest Shelf

Abo 5 3 4 - 8

Canyon Shale 22 16 4San Andres 35 30 5

Total Permian 551 407

Freestone

Cotton Valley Sands 70 58

Shelby

Bossier + Haynesville Shales 267 178

Total East Tx 337 236

Total ID'd Locations 888 644

East Texas

Permian

_____________________________________

Source: Company data and estimates. See Annual Report for total acreage statistics as of YE’18.

Note: the above figures exclude any acreage where Legacy owns overriding royalty interests (“ORRIs” or any acreage that may revert to Legacy under prior term assignment).

Permian Position OverviewDiverse Position Across Core Areas of the Permian

Central Basin

Platform

Gross Net

9,700 6,000

20,500 11,900

30,200 17,900

Northwest Shelf

Gross Net

10,600 9,100

42,200 23,900

52,800 33,000Midland Basin

Gross Net

10,100 9,100

26,700 10,900

36,800 20,000

Tracts - Identified Locations

Active Legacy Horizontal Rigs

#’s - Operated Horizontal Acreage

#’s – Small Tracts Acreage

#’s – Total Acreage

6

Delaware Basin

Gross Net

13,100 9,500

22,600 2,600

35,700 12,100

Total Company

Gross Net

43,500 33,700

112,000 49,500

155,500 83,200

Permian Position OverviewStrong Operated Drilling Results in Core Areas of the Delaware and Midland Basins

Legacy has brought online 90 horizontal wells since 2015, showing strong results to-date

Legacy Acreage Position and Operated / Offset Hz Activity

36 Legacy operated hz wells brought online in area since 2015

3,200 gross acres / 2,307 net acres in prospect area

Average 30-day IP Rates:

□ 3rd Bone Spring – 1,161 Boe/d

□ 2nd Bone Spring – 769 Boe/d

□ 1st Bone Spring – 798 Boe/d

Legacy Position Detail

54 Legacy operated hz well brought online in Midland Basin since 2015

4,258 gross acres / 3,513 net acres in prospect area

Average 30-day IP Rates:

□ Wolfcamp A – 905 Boe/d

□ Lower Spraberry – 905 Boe/d

Very strong results out of Martin County with peak rates of nearly 1,100

bbls/d before installation of artificial lift

Borden

Glasscock

Andre

ws

Lea

Loving Winkler

Eddy

Original Properties

2015 Acquisition

2017 Acquisitions

2016 Acquisitions

(Light = Non-op)

2018 Trades / JOA

Legacy Operated Delaware Basin Results: Lea County, NM Legacy Operated Midland Basin Results: Howard County, TX

Martin

Midland

_____________________________________

Source: Company data as of Q4’18 and Company estimates.

7

Permian Position OverviewAccumulation of Small Tracts Provides Material Value Through Non-Op Development and Trades

Midland

Basin

Delaware

Basin

Central

Basin

Platform

Northwest

Shelf Total

Tract Count 113 45 88 140 386

Gross

Acreage26,700 22,900 20,500 42,200 112,300

Avg Gross

Tract Size

(Acres)

236 509 233 301 291

Net Acreage 10,900 2,600 11,900 23,900 49,300

Prospect

Benches

Wolfcamp

Spraberry

Wolfcamp

Bone Spring

San Andres

Clearfork

Wichita Albany

Strawn

Barnett

San Andres

Yeso

Abo

Wolfcamp

Summary of Owned Small Tracts(1)

Legacy’s historical focus on PDP acquisitions in the Permian Basin has

yielded a large portfolio of small tracts (typically <1 mile) prospective

for horizontal development

Acreage is only counted if our geologic review corresponds to nearby

industry activity

Legacy is actively engaged in discussions to monetize tracts, most

likely via trades for contiguous near-term drilling prospects

Meaningful value creation potential achievable when combined with

offsetting, drillable prospects

Example of Small Tract Trade Value

In addition to value created through non-operated participation on small

tracts position, Legacy has traded small tracts to improve economics of

near-term drilling by adding to operated acreage and increasing lateral

length

Legacy completed 5 trades with 4 counterparties since 2017:

Increased avg. lateral length for 125 drilling locations

comprising 6 hz. prospects by 31%

Added 107,000 net lateral feet

Monetized many undrillable / unquantified assets by bolting on

to near-term drilling prospects, further enhancing economics

with longer laterals and greater efficiencies of scale

5,840

7,640

Before After

Increased Average Lateral Length for 6 Horizontal Prospects (feet)

+31%

_____________________________________

Source: Company data.

(1) Excludes any acreage where Company owns ORRIs or any acreage that may revert to them under prior term assignment.

8

21,000 gross / 17,400 net horizontal acres identified on 120,000

gross / 107,800 net total acres

Primary Target: Cotton Valley Sands

Secondary Targets: Rodessa, Pettet, Bossier Shale, Cotton

Valley Lime

98% held by production

Ownership of gathering system and processing plant improves

current and future operating costs; future development by

Legacy and offset operators will enhance the value of the

midstream system

East Texas Position OverviewLarge Positions with Development Potential in the Haynesville / Bossier and Cotton Valley

Shelby Area

Freestone Area – 70 Identified Operated Locations Shelby Area – 267 Identified Operated Locations

Freestone Area

29,700 gross / 19,750 net horizontal acres

Primary Target: Haynesville & Bossier Shale

Secondary Target: James Lime

Well-positioned in Shelby Trough with attractive offset results

(significant activity just across the Sabine River in Louisiana, on

trend with Legacy acreage)

80+% of net acres are >70+% WI

Permits approved on 3 federal locations; currently permitting 4

additional locations

Gathering & processing contracts are in place

_____________________________________

Source: Company data and estimates, public data.

9

East Texas Position OverviewOffset / Analogue Well Results Showcase Strong Development Potential

0

2,500

5,000

7,500

10,000

12,500

15,000

0 10 20 30 40 50 60

Months of Production

0

2,500

5,000

7,500

10,000

12,500

15,000

0 10 20 30 40 50 60

Months of Production

Cum Mmcf 31-Well Avg:

EUR: 2.2 Bcf / 1,000’ Lateral

IP-30: 23.7 Mmcf/d

5 yr Cum: 7.0 Bcf

31-Well Avg.

Analog Well Performance

Cum Mmcf

Precedent results limited to wells completed from 2006-2010 that

employed dated completion techniques

Enhanced completion design anticipated to further improve economics:

□ Cased-hole completion

□ Tighter stage spacing and higher fluid and sand volumes (stage

spacing 250’ vs 500’+; sand and fluid volumes increase of 2.1x

and 2.5x, respectively)

□ Expected IP: 23 Mmcf/d

□ Expected EUR: 2.4 Bcf / 1,000’ Lateral

4-Well Avg:

EUR: 2.2 Bcf / 1,000’ Lateral

IP-30: 11.8 Mmcf/d

5 yr Cum: 12.1 Bcf

Bossier

Haynesville

4-Well Avg.

Freestone Area: Hz Results Normalized to 5,000’ Shelby Area: Hz Results Normalized to 7,500’

Latest 4 offset wells completed 2014-2016 (shown above) utilized

1,800-2,200 lbs/ft of proppant

Enhanced completion design with tighter stage spacing and greater

fluid and proppant volumes (~3,000 ppf sand) will be employed to

further improve economics

□ Expected IP: Choke limited 13 Mmcf/d

□ Expected EUR: 2.5 Bcf / 1,000’ Lateral

Awaiting production results from the first of XTO’s 2018 completions

adjacent to Legacy position; Legacy is also participating in a well

currently drilling within its acreage position

_____________________________________

Source: Company data and estimates, PI/Dwights.

10

East Texas Position OverviewShelby Position Offset by Strong Wells and Top-Tier Regional Operators

XTO – Brahmaputra 1HB

30/IP: 10.7 MMcfd

Proppant (lbs/ft): 1,956

Lat. Length: 8,694’

1st Prod: Oct 2015

XTO – Volga B 1H

30/IP: 9.3 MMcfd

Proppant (lbs/ft): 2,218

Lat. Length: 6,135’

1st Prod: June 2016

XTO – Pechora B1

30/IP: 11.0 MMcfd

Proppant (lbs/ft): 1,831

Lat. Length: 6,720’

1st Prod: July 2014

Comstock – Jordan 16-21

30/IP: 15.3 MMcfd

Proppant (lbs/ft): 2,424

Lat. Length: 7,430’

1st Prod: Jan 2016

XTO – Murray 1H

30/IP: To Come

Proppant (lbs/ft): To Come

Lat. Length: To Come

1st Prod: To Come

Bossier Haynesville

1

2

43

5

1

2

3

4

5

______________________________

Source: Company data and estimates, DrillingInfo.

6

XTO – La Plata 1H

30/IP: To Come

Proppant (lbs/ft): To Come

Lat Length: 6,794’

Currently being completed

6

XTO – Cornhuskers-Hurricanes B1

30/IP: 14.2 MMcfd

Proppant (lbs/ft): 2,261

Lat. Length: 9,798’

1st Prod: Nov 2018

7

7

11

Kyle Hammond

President & Chief Operating Officer

COO since 2015

Previously CEO of FireWheel Energy, a

Permian PE-backed oil and gas company

VP Operations of XTO Permian from

2003 to 2011 and East Texas Freestone

Operations Manager from 1999-2003

Experienced Senior Management Team

Complementary senior management team with deep experience and relevant expertise

Dan Westcott

Chief Executive Officer

Previously served as CFO

Previously served as a Principal at

Blackstone’s GSO Capital Partners,

focused on investments in the

energy and power industries

Micah Foster

Chief Accounting Officer

CAO since 2012

Joined Legacy’s predecessor in 2006 in

a variety of accounting roles

Previously worked as an auditor for

Ernst & Young

Bert Ferrara

General Counsel

GC since 2018

Previously served as Associate and

Deputy GC

Previously worked in land at Concho

and investment banking at Morgan

Stanley

Cory Elliott

Chief Information Officer

Recently promoted to CIO; covers

IT, HR, and Real Estate

Has served Legacy since 2013

Prior, served the IT infrastructure

groups for various E&P and OFS

companies

Robert Norris

Chief Financial Officer

Previously served as a Principal for

The Catalyst Group, an Austin-

based private equity fund

Prior, served in various senior

strategy and corporate development

roles at Oil States International, Inc.,

and its spin-off, Civeo Corporation

12

Appendix

13

Legacy Capitalization Summary

In September 2018, exchanged $130 MM of Senior Notes due 2020 and 2021 for Convertible Senior Notes due 2023

In total, Legacy has executed $32.6 MM of debt to equity conversions since Q3 2018 across its 3 tranches of Senior Notes

_____________________________________

(1) Excludes the Springing maturity date of August 1, 2020, if greater than or equal to $15MM of Senior Notes is outstanding on July 1, 2020.

(2) Effective May 22, 2019, the Borrowing Base is reduced to $570 million.

(3) Reduced by $1.1MM in outstanding letters of credit and increased by $3.3MM in cash.

(4) Adjusted EBITDA is estimated LTM as of 12/31/18 and is pro forma for recent asset sales.

Adjusted EBITDA is a Non-GAAP financial measure. This measure does not include pro forma adjustments permitted under our credit agreements relating to acquired and divested oil or gas properties

unless indicated otherwise. A reconciliation of this measure to the nearest comparable GAAP measure is available on our website.

Debt Maturities

(1)

($ in millions unless otherwise noted)

12/31/18

Recent Conv /

Exch 12/31/18 PF

Revolving credit facility due 2019 $541 – $541

12% 2nd Lien Term Loan due 2021(1) 339 – 339

8% Senior Notes due 2020 209 – 209

6.625% Senior Notes due 2021 131 (2) 129

8% Convertible Senior Notes due 2023 128 (21) 108

Total Debt $1,348 ($22) $1,325

Shares (MM) 109.4 5.4 114.8

Liquidity & Credit Statistics:

Borrowing Base(2) $575

Liquidity(3) 36

2nd Lien Commitments $400

Remaining 2nd Lien Availability 61

LTM PF Adj. EBITDA(4) $273

Revolver / Adj. EBITDA 2.0x

Secured Debt / Adj. EBITDA 3.2x

Total Debt / Adj. EBITDA 4.9x

$108

$129 $209

$339

$541

$0

$100

$200

$300

$400

$500

$600

Apr 2019 Dec 2020 Aug 2021 Dec 2021 Sep 2023

Maturity Date

Revolving Credit Facility 2nd Lien Term Loan

8% Senior Notes 6.625% Senior Notes

8% Convertible Senior Notes

14

(1)