2. Forward-looking Statements
Statements made by representatives of Legacy Reserves LP (the “Partnership”) during
the course of this presentation that are not historical facts are forward-looking
statements. These statements are based on certain assumptions made by the
Partnership based on management’s experience and perception of historical trends,
current conditions, anticipated future developments and other factors believed to be
appropriate. Such statements are subject to a number of assumptions, risks and
uncertainties, many of which are beyond the control of the Partnership, which may cause
actual results to differ materially from those implied or expressed by the forward-looking
statements. These include risks relating to financial performance and results, availability
of sufficient cash flow to pay distributions or make payments on our notes and execute
our business plan, prices and demand for oil and natural gas, our ability to replace
reserves and efficiently exploit our current reserves, our ability to make acquisitions on
economically acceptable terms, and other important factors that could cause actual
results to differ materially from those anticipated or implied in the forward-looking
statements. Please see the factors described in the Partnership’s Annual Report on
Form 10-K for the year ended December 31, 2012 in Item 1A under “Risk Factors” and
subsequent filings with the Securities and Exchange Commission. The Partnership
undertakes no obligation to publicly update any forward-looking statements, whether as a
result of new information or future events.
2
3. Legacy Reserves LP Overview
Legacy (NASDAQ: LGCY) IPO’d in January 2007 and
has a consistent track record of growing its oil-weighted
asset base and delivering unitholder value
Current Enterprise Value: $2.5 billion
$1.6 billion market cap(1)
$860 million of net debt
Tax-advantaged quarterly cash distribution of $0.585/unit
($2.34 annualized) provides 8.3% yield(1)
Straight-forward structure
18% insider ownership
No IDRs
Long-lived, oil-weighted properties afford stable, lowdecline asset base that is well suited for an MLP
Core competencies have driven 43% distribution growth
since IPO including 12 consecutive distribution increases
Evaluating acquisitions and development projects
Financing capital requirements
Executing the plan
(1) Based on closing price as of 1/8/13 of $28.30.
3
4. Core Asset Areas
Reserve Breakdown(1)
11%
Overview
• 88.4 MMBoe PF proved reserves(1)
• 69% Oil and NGLs
• 88% PDP
• 20,043 Boe/d current production(2)
• Proved R/P of 12.1(3)
• Over 80% of reserves are operated
• Approx. 8,000 gross producing wells
12%
76%
Permian Basin
Rocky Mountain
Mid-Continent
5%
31%
64%
Permian Basin
• 67.6 MMBoe PF proved reserves(1)
• 64% Oil and NGLs
• 85% PDP
• 15,564 Boe/d current production(2)
(1)
(2)
(3)
SEC proved reserves at Dec. 31, 2012
as disclosed in Legacy’s Form 10-K
plus estimated proved reserves from
2013 acquisitions.
Q3 2013 production.
Based on estimated pro forma proved
reserves and Q3 2013 production.
Oil
Gas
NGL
Rocky Mountain
• 10.8 MMBoe PF proved reserves(1)
• 96% Oil and NGLs
• 95% PDP
• 2,216 Boe/d current production(2)
Mid-Continent
• 9.9 MMBoe PF proved reserves(1)
• 72% Oil and NGLs
• 98% PDP
• 2,195 Boe/d current production(2)
4
5. Permian Basin: Our Home and a Great Fit for an MLP
Discovered in 1921, the Permian Basin is
one of the most prolific basins in the U.S.
Industry Production Activity
Cumulative production of over 30 billion Bbls
Currently producing ~1.4 million Bbl/d and ~4.9
Bcf/d (Sep ’13)
Oil production increased 34% since Jan ’11
Multiple producing formations
Established and expanding infrastructure
with constructive regulatory environment
Long-lived reserves
Predictable, shallow decline rates
Fragmented ownership
Over 1,275 companies currently operating in the
basin
Top 5 owners represent less than one third of
total ownership(1)
Permian holds over 90% of our PUDs
Source:
Map Source:
(1)
Texas Railroad Commission (Districts 7C, 8 & 8A) and the New Mexico Oil Conservation Division.
Midland Map Company.
Ownership based on 2011 total production. Permian Basin includes Texas Railroad Commission Districts 7C, 8, 8A as well as Lea and Eddy Counties, New Mexico.
5
6. Acquisitions Drive Growth
Disciplined evaluation approach to making
acquisitions of mature, long-lived oil and
natural gas properties with high concentration
of PDP reserves.
$280
30
$221
24
25
$197
$200
19
16
$150
20
$137
15
15
$100
11
$100
10
8
2013 opportunities: 160 screened, 75
evaluated, 11 closed (7%)
$50
Eleven acquisitions of producing properties for
$100 million made in 2013 at attractive
metrics, and current acquisition pipeline looks
strong
27
$250
($ Total Deal Value)
2012 acquisitions of approximately $635
million
35
$32
5
3
$8
0
$0
2006 2007 2008 2009 2010 2011 2012 2013
Total Deal Value
# of Transactions
6
(# of Transactions)
Averaged over $200 million of acquisitions
annually during 2007, 2008, 2010 and 2011
40
$300
Approximately $1.6 billion of acquisitions
since 2006 focused in the Permian Basin,
Mid-Continent and Rockies
Purchased at an average of 5.6x
estimated FTM cash flow
$ 635
$350
$ 700
8. Quarterly Cash Distribution Profile
Quarterly Distribution per Unit
$0.700
$160
Cumulative distributions since
inception = $14.080/unit
WTI Spot Price ($ / Bbl)
$140
$0.525 $0.53
$0.52
$0.55 $0.555
$0.54 $0.545
$0.57
$0.56 $0.565
$0.575
$0.58 $0.585
$120
$100
$0.49
$0.500
$0.45
$80
$0.43
$0.41
$0.42
$0.400
$60
$40
$0.300
$20
$0.200
$0
1Q
2Q
3Q
2007
4Q
1Q
2Q
3Q
2008
4Q
1Q
2Q
3Q
2009
4Q
1Q
2Q
3Q
2010
4Q
1Q
2Q
3Q
2011
4Q
1Q
2Q
3Q
4Q
1Q
2012
2Q
3Q
2013
Legacy has increased its quarterly distribution by 3.5% year-over-year and 42.7% since its IPO
8
($ / Bbl)
(Quarterly Distribution / Unit)
$0.600
9. Hedging Strategy
Clear objective to reduce cash flow volatility to protect our borrowing base and future
distribution levels
Target approximately 85% of estimated PDP production over the next 18-24 months
on a rolling quarterly basis with declining percentage hedging thereafter
Approximately 84% of expected PDP crude oil production and approximately 55% of
expected PDP natural gas production hedged through 2015 at favorable prices
Hedge production from acquisitions for 3-5 years upon signing of a purchase and sale
agreement to help lock-in acquisition economics
Hedge within our bank group to capitalize on right-way risk and reduce capital
constraints
Primarily use swaps, 3-way collars and enhanced swaps
All hedges (both prior and current) are costless
Hedge interest rates to further mitigate volatility
9
10. Key Investment Highlights
High-quality, liquids-rich asset portfolio
69% Liquids
12.1 R/P(1)
Strong track record
123 acquisitions of producing properties worth approximately $1.6 billion
12 consecutive quarters of distribution growth
Extensive, Low-Risk development Drilling Inventory
Over 700 low-risk development opportunities
Experienced and Incentivized Management Team
18% of outstanding units held by management/insiders
No Incentive Distribution Rights promotes unitholder alignment with 100% of
incremental cash flows going to LPs
Conservative Financial and Hedging Policy
2.8x Debt/LQA EBITDA with no near-term debt maturities(2)
Substantial hedge portfolio
(1)
(2)
Based on estimated pro forma proved reserves (proved reserves as of 12/31/12 plus estimated proved reserves from 2013 acquisitions) and Q3 2013 production.
Annualized Q3 2013 Adjusted EBITDA ($76.2 million) which excludes pro forma effects for acquisitions.
10
12. Conservative Capital Structure
($ in millions)
September 30, 2013
Cash and cash equivalents
$4.1
Long-term debt:
Revolving credit facility due 2016
8% Senior Notes due 2020 (1)
6.625% Senior Notes due 2021 (1)
$314.0
300.0
250.0
Total Debt
$864.0
Market Capitalization
$1,627.6
Total Enterprise Value (TEV)
$2,487.6
Borrowing Base
Liquidity
$489.9
PF LQA Adjusted EBITDA (2)
$305.0
PF Proved Reserves (MMBoe)
PF Proved Developed Reserves (MMBoe)
Avg. Daily Production (Boe/d) (3)
88.4
79.9
20,043
Annual Distribution ($/unit)
Closing Unit Price (1/8/2014)
Distribution Yield
(1)
(2)
(3)
$800.0
$2.34
$28.30
8.3%
Reflects face value of the notes.
Annualized Q3 2013 Adjusted EBITDA ($76.2 million) which excludes pro forma effects for acquisitions.
Q3 2013 production.
12
14. Oil and Natural Gas Hedging Summary
Approximately 84% of expected PDP crude oil
production hedged through 2015 at a
weighted-averaged floor price of $92.80 / Bbl
enhanced swaps
Approximately 55% of expected PDP natural
gas production hedged through 2015 at a
weighted-averaged price of $4.40 / MMBtu
1,600
$140.00
$110.53
$96.78
1,200
800
$91.56
$66.34
$112.21
$106.40
$104.20
$89.67
$88.37
$85.00
$71.78
$108.15
(MBbls Hedged)
Uses a combination of swaps, three-way collars and
Oil 3-Way Collars Summary
$64.67
$63.37
$60.00
$35.00
$0.00
0
Q4 2013
Natural Gas Hedging Summary(2)
2014
2015
2016
2017
Avg. 3W Short Call (Price)
Avg. 3W Short Put (Price)
Oil Hedging Summary(1)
4,800
10,000
$4.32
$94.18
4,000
8,000
6,000
(MBbls Hedged)
(BBtu Hedged)
$70.00
400
3W Collars (MBbls)
Avg. 3W Long Put (Price)
$4.58
4,000
$4.33
$4.30
2,000
-
3,200
$90.87
2,400
1,600
$92.45
$88.86
$87.34
800
$90.50
Q4 2013
2014
2015
Swaps
(1)
(2)
$105.00
2016
Q4 2013
Swaps
2014
2015
3W Collars
2016
2017
2018
Enhanced Swaps
Hedging prices reflect a weighted average of swap prices, long put prices on 3-way collars, and enhanced swap prices.
Natural gas hedge prices reflect Waha (West Texas), ANR-OK, and CIG (Rockies) indexes.
14
15. Permian Basin Drilling Opportunities
Note: Reflects proved and unproved locations as well as prospective acreage. Well costs are based on current estimates.
15
16. Ownership Structure and Governance
Significant insider ownership
No IDRs yields lower cost of
capital and ensures
unitholder alignment
Founding Investors,
Directors
and Management
Public
Unitholder voting rights
similar to typical LLC
structure
100%
18% Limited
Partner Interest
Independent Reserve
Engineers:
LaRoche Petroleum
Consultants, Ltd.
Legacy Reserves
GP, LLC
82% Limited
Partner Interest
Independent board
members enhance
corporate governance
<0.1% General
Partner Interest
Legacy Reserves LP
(NASDAQ:LGCY)
Independent Auditors:
BDO USA, LLP
$1.0 Bn Revolving Credit Facility
with $800MM Borrowing Base
$300MM 8.00% Senior Notes
$250MM 6.625% Senior Notes
100% Ownership Interest
Legacy Reserves Operating LP
16
17. Adjusted EBITDA Reconciliation
The following presents a reconciliation of “Adjusted EBITDA”, which is a non-GAAP measure, to its nearest comparable GAAP
measure. “Adjusted EBITDA” should not be considered as an alternative to GAAP measures, such as net income, operating
income, cash flow from operating activities, or any other GAAP measure of financial performance. Adjusted EBITDA is defined as
net income (loss) plus interest expense; income taxes; depletion, depreciation, amortization and accretion; impairment of longlived assets; (gain) loss on sale of partnership investment; (gain) loss on disposal of assets; equity in (income) loss of equity
method investees; unit-based compensation expense related to LTIP unit awards accounted for under the equity or liability
methods; minimum payments earned in excess of overriding royalty interests; EBITDA applicable to equity method investee; net
(gains) losses on commodity derivatives; and net cash settlements received (paid) on commodity derivatives.
The management of Legacy Reserves LP uses Adjusted EBITDA as a tool to provide additional information and metrics relative to
the performance of Legacy’s business. Legacy’s management believes that Adjusted EBITDA is useful to investors because this
measure is used by many companies in the industry as a measure of operating and financial performance and is commonly
employed by financial analysts and others to evaluate the operating and financial performance of the Partnership from period to
period and to compare it with the performance of other publicly traded partnerships within the industry. Adjusted EBITDA may not
be comparable to a similarly titled measure of other publicly traded limited partnerships or limited liability companies because all
companies may not calculate Adjusted EBITDA in the same manner.
17
18. Reg G Reconciliation
($ in millions)
2007
Net income (loss)
2008
($55.7)
2009
$158.2
2010
2011
2012
9M 2013
($92.8)
$10.8
$72.1
$68.6
$11.6
Interest expense
7.1
21.2
13.2
25.8
18.6
20.3
36.1
Income taxes
0.3
0.0
0.6
0.5
1.0
1.1
0.6
28.4
63.3
58.8
62.9
88.2
102.1
118.5
Impairment of long-lived assets
3.2
76.9
9.2
13.4
24.5
37.1
23.4
(Gain) loss on disposal of assets
0.5
0.6
0.4
0.6
(0.6)
(2.5)
0.5
(0.1)
(0.1)
(0.0)
(0.1)
(0.1)
(0.1)
(0.4)
1.0
1.1
3.1
5.5
4.0
3.5
3.6
Depletion, depreciation, amortization and accretion
Equity in income of partnership
Unit-based compensation expense
Minimum payments earned in excess of overriding royalty interest
EBITDA applicable to equity method investee
Net cash settlements received (paid) on commodity derivatives
(1)
(2)
0.7
(2)
Net (gains) losses on commodity derivatives
Adjusted EBITDA
(1)
0.4
85.2
(176.9)
75.5
1.4
(6.8)
(38.5)
18.1
0.2
(40.2)
52.5
20.1
0.6
5.9
(4.7)
$120.4
$141.0
$201.4
$197.6
$70.2
$104.1
$208.5
A portion of minimum payments earned in excess of overriding royalties earned under a contractual agreement expiring December 31, 2019. The remaining amount of the
minimum payments are recognized in net income.
EBITDA applicable to equity method investee is defined as the equity method investee’s net income plus interest expense and depreciation.
18
