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)