FEBRUARY 2018

2017 EARNINGS PRESENTATION

2

Certain Disclosures

Forward Looking StatementsThis presentation contains forward-looking statements. These forward-looking statements can be identified by use of forward-looking terminology including “may,” “could,” “should,” “assume,” “estimate,” “project,” “believe,” “plan,” “expect,” “anticipate,” “intend,” “forecast,” “continue” or other similar words. These statements discuss future operating or financial performance or events. Descriptions of Legacy’s objectives, goals, targets, plans, strategies, budgets and projected financial and operating performance are also forward-looking statements. These statements represent our present expectation or beliefs concerning future events and are not guarantees. Such statements speak only as of the date they are made, and Legacy does not undertake any obligation to update any forward-looking statement. We caution that forward-looking statements involve risks and uncertainties and are qualified by important factors that could cause actual events or results to differ materially from those expressed or implied in any such forward-looking statements. Investors are also urged to consider closely the disclosure relating to “Risk Factors” and “Forward-Looking Statements” in Legacy’s Annual Report on Form 10-K for the year ended December 31, 2017 to be filed on or about February 23, 2018 (the “Annual Report”), and subsequent filings with the Securities Exchange Commission (the “SEC”). The Annual Report is available from Legacy’s website at www.legacylp.com. You can also obtain the Annual Report from the SEC by visiting EDGAR.

Reserve EstimatesThe 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,” “resource potential,” “development potential,” “potential bench” 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, which are available from Legacy’s website at www.legacylp.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 LocationsOur estimates of gross identified potential drilling locations (as used herein, “locations”, “identified locations,” “identified horizontal locations” or “identified drilling locations”) are prepared internally by our engineers, geologists and management and are based upon a number of assumptions inherent in the estimates process. Management, with the assistance of our engineers and other professionals, as necessary, conducts a topographical analysis of our unproved prospective acreage to identify potential well pad locations. Our 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. We then multiply this calculation by a pooling factor where appropriate. We generally assume minimum 5,000’ laterals. Management uses these estimates to, among other things, evaluate our acreage holdings and formulate plans for drilling. A number of factors could cause the number of wells we actually drill 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.

Non-GAAP Financial MeasuresLegacy’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.Our reference to PV-10 is numerically equivalent to the standardized measure of discounted future net cash flows determined in accordance with the rules and regulations of the SEC.

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37%

28%2%

33%65%

16% 2%

17%46%

28%

1%

25%

Legacy at a Glance

Longstanding Midland, Texas-based operator (NASDAQ: LGCY)

Stable PDP footprint

Q4’17 daily production of 48.3 MBoepd (41% liquids)(1)

Underlying PDP decline rate of 11.9%(1)(2)(3) and PDP R/P of 9.4 years(1)(3)

Significant horizontal potential in the Permian and East Texas

Identified 588 gross (408 net) operated horizontal Permian drilling locations on

40,600 gross / 31,500 net acres, 92% of which is held by production

— Last 46 horizontal wells brought online have average IP30 rates of ~840 Boe/d

Identified 258 gross (182 net) operated horizontal East Tx drilling locations on 40,000

gross / 30,000 net acres, representing about 18% of our 215,000 gross / 165,000 net

acres in the area, targeting the Cotton Valley Sands and Bossier/Haynesville Shales

Continued two-rig development plan yields 23 years of inventory(4)

$1,150MM ($1,053MM PDP)176 MMBoe (166 MMBoe PDP)48.3 MBoepd

(1) Pro forma to exclude contribution from the Texas Panhandle assets divestitures that closed on February 6, 2018 (the “Panhandle Sale”).(2) Represents weighted average three-year PDP production decline rate.(3) Source: 2017 SEC reserve report, pro forma for the Panhandle Sale (SEC price of $51.31 and $3.07 for oil and gas, respectively) (the “Reserve Report”). (4) Represents total identified horizontal locations divided by an assumed 18 wells per rig drilled per year.

Permian Basin

Rocky MountainMid-Continent

East Texas

Headquarters

Q4’17 Production by Region(1) Proved Reserves by Region(1)(3) Proved PV-10 by Region(1)(3)

Note: Darker shading represents increased reserve concentration.

MT

ND

SD

WY

NE

CO KS

NM

OK

TX

4

Oil Production Growth: Record annual production of 49.2 MBoe/d in Q4’17 representing a 23% QoQ increase in oil production and volumes at the high end of guidance

LOE: $9.41 LOE per Boe in Q4, down 12% from Q4’16

JDA Success: Brought 5 new horizontal Permian wells online in Q4’17, representing 47 wells since commencement of the JDA program

Ended the year with 21 DUCs, 20 of which we expect to bring online in Q1’18 via batch completions

$141MM Acceleration Payment to TPG Sixth Street Partners (TSSP) and amending our JDA in August 2017 increased our exposure to our then-current wells and future development potential

TSSP elected to participate in a second tranche of 26 wells plus 9 wells in the JDA’s area of mutual interest; expect to spud final well in mid-2018

Asset Sales: Completed $23MM of asset sales in 2017 which relieved $8.4MM in P&A liabilities and negative LTM cash flow

Completed an additional $27MM in divestitures YTD’18 including non-core PDP in the Texas Panhandle and acreage that we did not intend to drill

Bolt-on Acquisitions: Completed $19MM of acquisitions adding 49 horizontal operated identified locations in the Permian and/or increasing our NRI in existing near-term drilling prospects

Compressed Leverage Metrics: Reduced Pro Forma Total Debt / EBITDA by 2.1x in 2017(1)

Gained Additional GSO Investment and Achieved Voting Power in Notes: Repurchased $187MM of our 6.625% Senior Notes at $0.70, funded by draw from increased $400MM 2nd Lien Term Loan Commitment; gained meaningful voting power in our Senior Notes and captured discount

2017 Review

(1) Total Debt is as of February 21, 2018. EBITDA is LTM as of 12/31/17. Both figures are pro forma for the Panhandle Sale. See slide 15.

5

Operated Permian Horizontal Acreage with Identified Locations

Midland Basin

Central Basin Platform

Delaware Basin

Northwest Shelf

Identified LocationsActive Horizontal Rigs

Total Acreage

Gross Net

6,400 5,900

Source: Company data and estimates. Acreage statistics herein tie to identified, operated horizontal locations. See Annual Report for total acreage statistics.

Total Acreage

Gross Net

10,900 7,200

Total Acreage

Gross Net

12,700 10,700

Total Acreage

Gross Net

10,600 7,800

Total Acreage

Gross Net

Total 40,600 31,500

6

Total Permian Acreage

Midland Basin

Central Basin Platform

Delaware Basin

Northwest Shelf

Identified Locations

Active Horizontal RigsOther Permian (Op + Non-Op)

Source: Company data and estimates. See Annual Report for total acreage statistics.

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Operated Horizontal Development Inventory

Legacy has identified attractive drilling locations by coordinating the efforts of its land, geology, operations and business development teams

Legacy and industry activity within and around Legacy’s acreage positions is also helping to de-risk these prospects

Legacy’s Reserve Report only includes 16 gross / 10 net operated horizontal PUDs

Ongoing technical analysis suggests the addition of 830 gross (580 net) locations in its Permian and East TX core operating regions

Source: Company data and estimates.(1) PUD locations contained in Reserve Report plus Identified Horizontal Locations(2) Spacing based on analogous, nearby development.

Operated Horizontal Drilling Locations - Permian and East TxWells

PDP at YE'17 Total Identified Locations perGross Net Gross Net Section

PermianMidland Basin

Lower Sprayberry 12 10 64 47 8Wolfcamp 18 15 186 146 8Devonian – – 5 4 5

Delaware BasinBrushy Canyon – – 28 15 41st Bone Spring 3 2 21 13 42nd Bone Spring 11 6 19 12 43rd Bone Spring 14 9 9 7 4Wolfcamp – – 88 62 8

Central Basin PlatformSan Andres – – 106 60 6

Northwest ShelfSan Andres – – 22 17 4Yeso – – 2 2 4Abo / Wolfcamp – – 28 19 4Devonian - - 10 5 5

Total Permian 58 43 588 408

East TexasFreestone

Cotton Valley Sands – – 70 58Shelby

Bossier + Haynesville Shales - - 188 124 Total East Tx - - 258 182

Total 58 43.1 846 590

(1)

(2)

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2018 Capital Budget

Free cash flow neutral program drives projected 47% oil-production growth and 46% EBITDA growth YoY in 2018

Similar gross capital figures to 2017; net capital increase is driven by higher average working interest following the Acceleration Payment to TSSP

Operational efficiencies drive capital efficiency

Increased size of batch completions in areas with adequate infrastructure

Obtained dedicated frac fleet

Efficiencies offset by assumed capital increase driven by consumables, equipment rentals, labor and inflation

Maintain potential to increase capital spending

Goal to remain cash flow neutral / positive

Likely to commence East Tx horizontal development or additional Permian delineation opportunities

$190MM

2018 Net Capital by Category & Permian County

$225MM Net ($345MM Gross)

Operated Permian Hz Dev Non-Op Hz Dev

Workovers / Recompletions / Vertical Facilities / Other

Lea32%

Howard31%

Martin16%

Midland6%

Reagan3%

Andrews1%

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Permian D&C Capital by Bench

2018 Permian D&C Detail

$190MM

$203MM Total Net

Economics of Scale

Single well Multi-well

~95% multi-well drilling allows for optimized batch completions and leverages historical infrastructure investments

Lateral Length by County

–

2,500

5,000

7,500

10,000

12,500

~7,400’ Wtd. Avg.

Actively engaged in discussions to extend Midland Basin lateral lengths

42%Wolfcamp37%

Bone Spring

20%Spraberry

1% San Andres

% of Capital Budget

‘

‘

‘

‘

‘

10

Horizontal Permian Program Development

Hz Wells Drilled by Qtr and County

13

9 10

7

–

2

4

6

8

10

12

14

Q1'18 Q2'18 Q3'18 Q4'18

Lea Howard Midland Martin

Andrews Reagan Grand Total

Hz Wells Brought Online by Qtr and County

39 drilled in 2018 48 brought online in 2018

22

4

11 11

–

5

10

15

20

25

Q1'18 Q2'18 Q3'18 Q4'18

Lea Howard Midland Martin

Andrews Reagan Grand Total

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Projected Well Economics – 2018 Forecasted Development

County/Bench Lateral

Length (Ft.) Gross D&C Cost ($MM)

Peak 30-Day Rate (Boe/d)

EUR (MBOE) % Oil EUR

Howard CountyLwr. Spraberry 7,500-10,000 $6.4-$7.5 700-800 850-950 80%-85%Wolfcamp A 7,500-10,000 $6.6-$7.7 500-1,000 500-1,000 81%-86%

Lea County1st Bone Spring 5,000-7,500 $5.6-$7.2 650-950 500-850 70%-75%2nd Bone Spring 5,000-7,500 $5.7-$7.2 450-700 380-560 81%-85%3rd Bone Spring(1) 7,500 $6.8-$7.2 550-650 550-650 80%-84%

Martin CountyWolfcamp B 10,000 $8.2-$8.6 800-900 750-850 78%-82%

Midland CountyLwr. Spraberry 5,000 $5.5-$5.9 525-575 550-600 74%-78%Wolfcamp B 5,000 $5.5-$5.9 575-625 600-650 74%-78%

(1) Negatively impacted compared to historical results due to drilling of replacement wells with mechanical issues.

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2018 Guidance vs. Historicals

(1) Pro forma to exclude contribution from the Panhandle Sale.(2) ‘18E based on mid-point of range. 2H’17 actuals annualized where appropriate.(3) Represents the projected percentage of assumed WTI crude oil prices.(4) Excludes ad valorem and production taxes.(5) Consistent with our definition of Adjusted EBITDA, these figures exclude LTIP and transaction-related expenses. (6) 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. A reconciliation of this measure to the

nearest comparable GAAP measure is available on our website.Note: Figures above assume NYMEX strip pricing at 2/15/2018 (2018 Avg Oil $59.59 / $2.80 Gas)

(1) (2)2H'17 Actual Δ: '18E vs. 2H'17

($ in thousands unless otherwise noted) Excl. Panhandle Sale 18E Range # %

Production:

Oil (Bbls/d) 15,819 19,000 - 21,400 4,381 27.7%

Natural Gas Liquids (Bbls/d) 2,464 1,875 - 2,075 (489) (19.9%)

Gas (Mmcf/d) 170.4 162.0 - 176.0 (1.4) (0.8%)

Total (Boe/d) 46,688 47,875 - 52,808 3,653 7.8%

Weighted Average NYMEX Differentials:

Oil (per Bbl) ($3.22) ($4.00) - ($3.25)

NGL realization(3) 55% 52% - 63%

Natural gas (per Mcf) ($0.27) ($0.35) - ($0.20)

Expenses:

Lease operating expenses(4) $80,509 $175,000 - $195,000 $23,982 14.9%

Ad valorem and production taxes (% of revenue) 6.84% 7.40% - 7.90%

Cash G&A expenses (5) $18,267 $34,000 - $38,000 ($534) (1.5%)

Adjusted EBITDA(6) $138,612 $300,000 - $360,000 $52,776 19.0%

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$226

$330

-

100

200

300

400

2017 2018E

Summary Financial Projections

Projected Adjusted EBITDA growth driven by an 47% increase in oil production while maintaining free cash flow neutrality

Oil Production (mbopd) Adjusted EBITDA ($MM)(1)

Capital Expenditures ($MM)(2) Adjusted EBITDA less Capex ($MM)(1)

13.8

20.2

-

5

10

15

20

25

2017 2018E

$177

$225

-

100

200

300

2017 2018E

$49

$105

-

50

100

150

2017 2018E

(1) 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. A reconciliation of this measure to the nearest comparable GAAP measure is available on our website.

(2) References development capital which specifically excludes acquisitions.Source: Mid-point of guidance per February 21, 2018 earnings release.

$

+47% +46%

$

$

14

Transition Steps Taken & Completed

Goal Description

Build Production Growth Program

Successfully built the backbone of a technical operations and development team with horizontal expertise that is scalable to a much larger drilling and completion programPoised to accelerate development of inventoryThe horizontal East Texas program will add significant natural gas production growth that will also fuel value accretion of associated Legacy-owned midstream assets

Capture More Permian Hz

Opportunities

Dramatically increased our share of the existing and future development under the JDA with TSSP by making a $141 million Acceleration Payment and amended the JDALeveraged our specific knowledge, experience and local presence to make select, discreet acquisitions totaling $15 million since 1/1/17 that increase ownership, extend planned laterals, add nearby locations, or otherwise increase our identified horizontal locationsContinue to work with industry players to execute trades to enhance our interests in near-term development opportunities at the expense of other, less-desirous tracts

Control Costs LOE per Boe declined by 44% since 2014 and is projected to be ~$10 per Boe in 2018, consistent with 2H’17Programmatic reduction in drilling days and batch completions continue to reduce D&C costs

Protect and Grow PDP Cash Flows

Significant, low-decline base supports balance sheet and fuels growth initiativesRemain a successful acquirer and operator of PDP assetsApproximately 64% and 59% of 2018 oil and gas production is hedged(1); currently pursuing 2019 oil swaps

Rationalize Portfolio

Sell assets that do not exhibit i) growth potential or ii) sufficient cash flow profileSold a negative cash flow CO2 Flood property. Eliminated significant P&A liability and a large CO2 purchase contract for 25% of the remaining liability.Sold several disjointed, negative cash flow properties with large P&A liabilitySold Panhandle asset, an asset with a very high well count and low average daily rate with no growth potential and large P&A liability

Other potential opportunities identified

Current Ambitions

Leverage / StructureEvaluate and opportunistically pursue alternatives to change our legal structure and tax status as a partnership, materially reduceour outstanding debt and extend our near term maturity debt

December repurchase from Fir Tree funded with GSO 2nd Lien provided meaningful voting power in our Senior Notes and captured discount

Accelerate Development to Capture Upside

Depending on the availability of cash flows, accelerating development of high-return, identified horizontal drilling locations within existing Permian and East Texas acreage

Legacy has taken and is taking several proactive steps to position the Company to profitably generate material production and Adjusted EBITDA growth and develop its sizeable inventory of identified horizontal development locations

Achieved

(1) See slide 24.

15

$502

$339

$233 $246

–

$100

$200

$300

$400

$500

$600

2018 Apr 2019 Dec 2020 Aug 2021 Dec 2021

Revolving Credit Facility 2nd Lien Term LoanSenior Notes

Balance Sheet Progress

(1) Total Debt is as of February 21, 2018. EBITDA is LTM as of 12/31/17. Both figures are pro forma for the Panhandle Sale. (2) Reduced by $1.9MM and $0.8MM in outstanding letters of credit and increased by $2.0MM and $1.2MM in cash at YE’16 and YE’17, respectively.(3) $400MM facility allows $61MM of incremental funds available through October 25, 2019.(4) 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.(5) 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. A reconciliation of this measure to the

nearest comparable GAAP measure is available on our website.

Debt Maturities

(4)

Using the mid-point of our guided 2018E EBITDA(5) and capital budget ranges, we project exiting YE’18 with a Total Debt / EBITDA of ~4.0x

We are evaluating and will opportunistically pursue alternatives to materially reduce our outstanding indebtedness and extend our near-term maturing indebtedness

YE'16 YE'17 PF(1) Chg

Revolving credit facility due 2019 $463.0 $502.012% 2nd Lien Term Loan due 2021 60.0 338.68% Senior Notes due 2020 233.0 233.06.625% Senior Notes due 2021 432.7 245.6

Total Debt $1,188.6 $1,319.2

Borrowing Base $600.0 $575.0

Liquidity(2) 137.1 73.5

2nd Lien Commitments $300.0 $400.0

Remaining 2nd Lien Availability(3) 240.0 61.4

Credit Statistics:

LTM PF Adj. EBITDA $155.8 $240.8

Revolver / EBITDA 3.0x 2.1x (0.9x)Secured Debt / EBITDA 3.4x 3.5x 0.1xTotal Debt / EBITDA 7.6x 5.5x (2.1x)

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Asset Detail

17

Source: Company data and estimates.(1) Includes 2 wells, one of which lost 2/3 of its lateral due to an incident, resulting in lost production.

Acreage Position and Legacy / Offset Hz Activity

Lea County – Recent Activity Update

InventoryZone PDP Locations Total

1st Bone 3 13 16 2nd Bone 11 5 16 3rd Bone 14 3 17 Upper Wolfcamp – 32 32 Lower Wolfcamp – 32 32 Total 28 85 113

Legacy has generated strong well results in recent wells drilled in Lea County and continues to identify attractive drilling locations

Assets include 3,200 gross (2,307 net) acres

Average 30-day IP Rates realized since JDA commencement:

3rd Bone Spring – 910 Boe/d2nd Bone Spring – 706 Boe/d1st Bone Spring – 831(2) Boe/d

18

3rd BS Landing/ Wolfcamp Frac

Oil on Pits Lower Wolfcamp

CXO Blue Jay Fed #1H30/IP 1,904 BOEPD

LGCY #62H30/IP 1,378 BOEPD

XEC Lea 7#1H30/IP 894 BOEPD

EOG Della 29 Federal Com 701H30/IP 1,231 BOEPD

CXO Blue Jay Fed Com #2H30/IP 1,694 BOEPD

LGCY #59H30/IP 1,404 BOEPD

Chisolm Lea South 25 Fed Com WCA #12HDrilling Complete

CXO Mas Fed #4H30/IP 1,288 BOEPD

MTDR Airstrip 31 18 35 RN #201H24/IP 926 BOEPD

Lea County Offset Wolfcamp Development

Source: Company data and estimates, DI Desktop.

Activity by Legacy and offset operators in the area has extended the Wolfcamp play to Northern Lea County.

CXO Mas Fed #1H&2HAPD Filed

Strong correlation zone to zone

19

Borden

Martin

Midland Glasscock

Howard County – Recent Activity Update

Increased number, length and working interest in drilling locations through leasing, acreage swaps and acquisitions

Ongoing, active swap discussions with nearby operator offers upside to current location count

Source: Company data and estimates.(1) Does not include potential upside from Upper/Middle Spraberry.

Original Properties

2015 Acquisition

2017 Acquisitions (Light = Non-op)

2016 Acquisitions (Light = Non-op)

Acreage Map

Legacy has increased its acreage position in Howard County by 116%, or 1,848 acres net acres, since it started drilling in the area in 2015

Inventory(1)

Zone PDP Locations TotalLower Spraberry 12 12 24Wolfcamp A 12 12 24Total 24 24 48

1 Mile

Lower Spraberry

Wolfcamp A

660’

660’

Well-Spacing Diagram(1)

Assets include 4,118 gross (3,441 net) acresAverage 30-day IP Rates realized since JDA commencement:

Wolfcamp A – 910 Boe/dLwr Spraberry – 891 Boe/d

20

Andrews County Horizontal San Andres Position

Legacy’s position in the area comprises 10,886 gross / 7,166 net acres and 106 gross / 60 net drilling locations that have been de-risked by successful operators in the area

Legacy’s Engineering and Operations professionals have significant experience in the area managing producing wells, waterflood and recompletion programs

Development plan requires very little infrastructure investment, leveraging Legacy-owned SWD assets

Source: Company data, DI Desktop, IHS.

Forge/Lime Rock Fisher 76C #6H 366 BOPD 30/IP; 564 MBOE EUR

Pacesetter Univ. JV 14#3H 856 BOPD 30/IP; 925 MBOE EUR

Pacesetter Welborn 20#1H 236 BOPD 30/IP; 344 MBOE EUR

Lime Rock Univ. 13 #4414H; 514 BOPD + 221

MCF 24’/IP

Ring Univ. 14Q#1H; 535 BOPD 30/IP

Acreage Map

Ector Midland

21

East Texas – Summary Overview of Horizontal Inventory

Freestone Area – 31 vintage Hz Cotton Valley sand wells were completed using outdated D&C techniques

31 well averages

— Average lateral length of 2,885’

— Average EUR of 6.5 Bcf

— Average 2.3 Bcf / 1,000’

70 identified drilling locations

— Longer laterals

— Modern completions and staging

— Midstream control enhances economics

Shelby Area

Well-positioned in Shelby Trough

Latest completions with modern sand loadings averaged 2.1 Bcf / 1,000’

Legacy has 19,129 gross / 12,641 net unitized acres held by production

12 units (~81% of net acres) are >70+% WI

Currently permitting 6 locations

Gathering & processing contracts are in place

Freestone AreaBossier Sand Hz Prospect70 locations

Shelby AreaBossier & Haynesville Shale Hz Prospect188 locations

Areal View of East Texas Horizontal Prospects

Source: Company data and estimates.

22

Appendix

23

$18.37 $19.08

$19.89 $18.98

$13.03

$10.77 $10.58 $10.00

–

$5.00

$10.00

$15.00

$20.00

$25.00

2011 2012 2013 2014 2015 2016 2017 2018E

$ /

Boe

LOE per Boe has declined by 44% from 2014 through 2017 and is projected to be approximately $10 in 2018

Ongoing Expense Control

Source: Company filings and management estimates.

Legacy has proactively cut expenses by 44% since 2014 driven by coordinated efforts at all levels of the organization to deliver value to all stakeholders through the downturn

LOE per Boe Since 2011

~

24

Added 1,000 Bbls/d of 2018 oil swaps at $63.68 year-to-date

Currently working to add 2019 oil swaps

Set forth below are the effective oil and gas prices (before the impacts of differentials) and after the impact of hedges(1):

Hedge Summary + Price Sensitivities

(1) Figures based on mid-point of 2018 guidance.

% Natural Gas Hedged(1)% Oil Hedged(1)

59%

42%

0%

10%

20%

30%

40%

50%

60%

70%

2018 2019

64%

0%0%

10%

20%

30%

40%

50%

60%

70%

2018 2019

Effective Oil Price Effective Gas Price2018 2019 2018 2019

$40 $48.02 $40.00 $2.50 $2.93 $2.86$50 $52.23 $50.00 $2.75 $3.03 $3.00$60 $57.90 $60.00 $3.00 $3.13 $3.15$70 $61.81 $70.00 $3.25 $3.24 $3.30

Avg

WTI

O

il Pr

ice

Avg.

Hen

ry

Hub

Gas

Pr

ice