january 2015 investor presentation · investor presentation january 2015. forward-looking...
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INVESTOR PRESENTATIONJANUARY 2015
Forward-Looking Statements
2
Statements made by representatives of Legacy Reserves LP (the “Partnership”) during thecourse of this presentation that are not historical facts are forward-looking statements. Thesestatements are based on certain assumptions made by the Partnership based onmanagement’s experience and perception of historical trends, current conditions, anticipatedfuture developments and other factors believed to be appropriate. Such statements are subjectto a number of assumptions, risks and uncertainties, many of which are beyond the control ofthe Partnership, which may cause actual results to differ materially from those implied orexpressed by the forward-looking statements. These include risks relating to financialperformance and results, availability of sufficient cash flow to pay distributions or makepayments on our notes and execute our business plan, prices and demand for oil and naturalgas, our ability to replace reserves and efficiently exploit our current reserves, our ability tomake acquisitions on economically acceptable terms, and other important factors that couldcause 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 onForm 10-K for the year ended December 31, 2013 in Item 1A under “Risk Factors” andsubsequent filings with the Securities and Exchange Commission. The Partnership undertakesno obligation to publicly update any forward-looking statements, whether as a result of newinformation or future events.Any reserve information pertaining to assets acquired after December 31, 2013 and presentedherein is based on our internal evaluation and interpretation and has not been independentlyverified or estimated.
Legacy Reserves LP Overview
3
Midland, Texas-based Master Limited Partnership (NASDAQ: LGCY)
Focused on owning and operating long-lived oil and natural gas properties with stable, low-decline production
Today’s presentation will focus on:Current 22% yield offers attractive, tax-advantaged distribution
Experienced and aligned management team has delivered value through all commodity cycles
Great balance sheet positions us for future success
Note: Represents the Partnership’s reserves after giving effect to the WPX Acquisition.Darker shaded area represents increased reserve concentration
4,970 7,582 8,225 9,61113,071 14,811
19,668
32,109
0
6,000
12,000
18,000
24,000
30,000
36,000
2007 2008 2009 2010 2011 2012 2013 Q3'14
$70 $104 $120 $141$201 $198
$273$311
$0
$75
$150
$225
$300
$375
2007 2008 2009 2010 2011 2012 2013 Q3'14A
Proven History of Unlevered Growth…
4
Average Daily Production (Boe / d)
Adjusted EBITDA ($ MM)
$0.200
$0.300
$0.400
$0.500
$0.600
$0.700
$0
$20
$40
$60
$80
$100
$120
$140
$160
(Qua
rter
ly D
istr
ibut
ion
/ Uni
t)($ / B
bl)
Legacy has increased its quarterly distribution by 4.3% year-over-year and 48.8% since its IPO
…Consistent Distributions Through Volatile Oil
5
1Q 2Q 3Q 4Q
Cumulative distributions since inception = $16.485/unit
$0.52
2007
$0.57$0.565$0.56$0.555$0.55$0.545$0.54
$0.53$0.525
$0.49
$0.45
$0.43$0.42$0.41
$0.575$0.58 $0.585 $0.59 $0.595
$0.61
Quarterly Distribution per Unit
WTI Spot Price ($ / Bbl)
$0.61
1Q 2Q 3Q 4Q
2008
1Q 2Q 3Q 4Q
2009
1Q 2Q 3Q 4Q
2010
1Q 2Q 3Q 4Q
2011
1Q 2Q 3Q 4Q
2012
1Q 2Q 3Q 4Q
2013
1Q 2Q 3Q
2014
6
Rapid Industry Development in the Permian
Source: Drilling Info
58% of current basin-wide oil production is less than 3 years old and exhibits steep declines; a reduction in basin-wide rig count could result in dramatically lower production
7
Emerging Permian Potential
System Series
Lamar Tansill TansillYates Yates7 Rivers 7 RiversQueen QueenGrayburg GrayburgSan Andres San AndresGlorieta Glorieta
U. ClearforkTubb
1st BS Sand L. ClearforkU. Spraberry
2nd BS Sand L. Spraberry
3rd BS Sand
CiscoCanyonStrawnAtoka
MorrowChester
U. NiagaranL. NiagaranAlexandrian
KinderhookWoodford
KinderhookWoodford
Upper Silurian Upper SilurianDevonian Devonian Devonian Devonian
L. Mississippian Lime
Silu
rian
U. Miss. Lime
Fusselman Fusselman Fusselman Fusselman
Upper Silurian Upper Silurian
Barnett Shale
Mississippian Lime
Mississippian Lime
Mississippian Lime
Devonian
Pen
nsyl
vani
anM
issi
ssip
pian
Meramecosage
Kinderhook
Barnett Shale Barnett Shale
KinderhookWoodford
KinderhookWoodford
StrawnAtoka
Morrow
StrawnAtoka
Dev
onia
n
CiscoCanyonStrawnAtoka
CiscoCanyon
Dean
CiscoCanyonStrawnAtoka
Morrow
CiscoCanyon
WolfcampWolfcamp
HuecoBolsum
Yeso
PaddockBlineberry
TubbDrinkard
Upper Leonard
Bon
e Sp
ring
AboWichita Albany
Leonard
Wolfcamp
Per
mia
n
Wolfcamp Wolfcamp
GlorietaSan Andres
Whi
te H
orse
Wor
d
Whi
te H
orse
Wor
d
Del
awar
e M
ount
ain
Bell Canyon
Cherry Canyon
Brushy Canyon
GrayburgQueen
Ochoa
Whi
te H
orse
Wor
d
Goa
t See
p C
apita
n
Guadalupe7 Rivers
YatesTansill
SaladoCastileSaladoRustler
Dewey Lake
Salado SaladoRustler
Dewey Lake
Delaware Basin Central Basin Platform
Northwest Shelf Midland Basin
Dewey LakeRustler
Dewey LakeRustler
Current Legacy Producing Zones
Current Industry Hz Drilling Activity
Legacy produces from nearly every productive formation across the Permian Basin.
Current industry horizontal development (green shading) only represents a fraction of the entire strata.
2014 Asset Transition
8
(1) Independent reserve estimate as of 12/31/13 per the 10-K.(2) Includes WPX Acquisition based on internal proved reserve estimates as of 12/31/13 based on SEC benchmark
pricing.(3) Includes Caprock and Sheridan County, MT acquisitions (together the “Bolt-On Acquisitions”) based on internal
estimates per press release dated 3/26/14.
Permian Basin Rocky Mountain Mid‐Continent
Standalone(1)
(88% PD)Acquisitions(2)(3)
(99% PD)Pro Forma (92% PD)
87.6 MMBoe 55.0 MMBoe 142.6 MMBoe
Oil Gas NGL
78%
11%11%
11%
89%
52%
41%
7%
65%
30%
5% 17%
70%
13%
47%
46%
8%
Note: Represents the Partnership’s reserves after giving effect to the WPX Acquisition.Darker shaded area represents increased reserve concentration
Capital Structure
9
(1) Outstanding revolver balance as of October 30, 2014 per 10-Q disclosure.(2) Pro forma proved reserves and production inclusive of WPX Acquisition and Bolt-on Acquisitions. For further disclosure please see footnotes on page 8.
($ in millions)
September 30, 2014
Cash and cash equivalents $3.0
Long-term debt:Revolving credit facility due 2019 (1) $65.0
8% Senior Notes due 2020 300.0
6.625% Senior Notes due 2021 550.0
Total Debt $915.0
Market Capitalization $774.0
Preferred Equity 237.5
Total Enterprise Value (TEV) $1,923.5
Borrowing Base $950.0
Liquidity $887.9
Pro Forma Proved Reserves (MMBoe) (2) 142.6
Pro Forma Proved Developed Reserves (MMBoe) 131.5Daily Production (Boe/d) 32,109
Annual Distribution ($/unit) $2.44Closing Unit Price (1/8/2015) $11.19Distribution Yield 21.8%
Relative Strength of Our Balance Sheet
10
(1) Debt outstanding based on latest public filings; EBITDA based on annualized Q1 2015 Bloomberg consensus estimates(2) Peer Avg. consists of ARP, BBEP, EVEP, LINE, LRE, MCEP, MEMP and VNR(3) Wtd. Peer Avg. weights the average of the peers based on debt outstanding(4) Alerian Avg. consists of the constituents within the Alerian MLP index.
0.00x
1.00x
2.00x
3.00x
4.00x
5.00x
6.00x
LGCY Peer Avg. Wtd. Peer Avg. Alerian Avg.
Deb
t / E
BIT
DA
(1)
Costless Hedging Strategy
11
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
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
Hedge interest rates to further mitigate volatility
(1) Based of Q3 2014 daily production held flat through 2018
81%
68%
21%
9%3%
72% 76%
20%14%
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
Q4 2014 2015 2016 2017 2018
% Oil % Gas
Percentage of Volumes Hedged(1)
Hedging Commodity Basis Exposure
12
0%
20%
40%
60%
80%
100%
Q4 2014 2015
Hedged at Basis NYMEX Exposure
% H
edge
d (1
)
Q1-Q3 2014 Midland-to-Cushing differential has suffered due to infrastructure constraints
Currently seeing meaningful pricing improvement due to BridgeTex and other pipeline completions
We are opportunistically layering on trades and to-date have added the following position:
MidCush: 9,000 barrels a day during Q1 at $-2.34
Natural Gas
NWPL ($0.09)
NGPL ($0.10)
SoCal $0.29
San Juan
($0.06)
WAHA ($0.06)
Crude Oil
NWPL ($0.13)
NGPL ($0.15)
SoCal $0.19
San Juan
($0.12)
WAHA ($0.10)
Upon agreeing to the WPX Acquisition, we layered on basis swaps on top of our NYMEX hedges
We have hedged our natural gas basis exposure on all of our natural gas assets
Corporate-wide, we have the following NYMEX gas exposure
0% of hedged volumes in Q4 2014
24% of hedged volumes in 2015
0%
20%
40%
60%
80%
100%
Q1 2015 2015
Hedged at Basis NYMEX Exposure
% H
edge
d (1
)
(1) % of existing swaps, collars and enhanced swaps
Investment Rationale
13
High-quality, geographically diversified, low-decline asset portfolio54% Liquids
11.2 PD R/P
Experienced, aligned, and incentivized Insiders15% of outstanding units held by Insiders
Strong track record through commodity cycles132 acquisitions worth approximately $2.1 billion
31 consecutive quarterly distributions
Great balance sheetNo near-term debt maturities
Only 7% drawn on $950 million borrowing base
Substantial hedge portfolio
Attractive long-term investment opportunity given tax-efficient current yield of 22%
14
Appendix
First and Only MLP with 3rd Party Drop-Down Opportunities
15
Recent Strategic Alliance with WPX established newly-created IDRs
10% issued and vested
20% issued and unvested: vesting hinges on consummation of additional “acquisitions”
70% remains at LGCY and available to issue to parties with attractive inventory of current & future drop-downs
Acquisitions are expected to be focused on long-lived oil and natural gas properties with stable, low-decline production
Our IDRs are different. Relative to others’ IDRs, they are intended to:
Increase Scope
Enhance Economics
Ensure Alignment
Potential Partner
LGCY
Cash, Units, and/or IDRs
Assets
Strategic Alliance with WPX Energy
16
On May 6th, we announced a Strategic Alliance with WPX. Initial acquisition is 2,680 Piceance Basin natural gas wells
Consideration: $355 million in cash + newly-created Incentive Distribution Units (IDRs)
10% of LGCY’s IDRs issued to WPX and immediately vested
WPX can vest in up to an additional 20% of IDRs through future drop-downs to LGCY
276 Bcfe (46 MMBoe) proved reserves (100% PDP)
Escalating working interest: initial 29% steps up to 37% on 1/1/15, then to 41% on 1/1/16
83% natural gas, 15% NGL, 2% oil
Operatorship remains with WPX
63 MMcfe/d (10.5 MBoe/d) Q3E 2014 production
12.0 R/P ratio
Key Economic Terms Asset Highlights
Location Map
Borrowing base increased to $950 million
On May 13, closed $300mm tack-on to 6.625% Senior Notes due 2021
On June 17, closed $180mm Series B 8% Perpetual Preferred equity
Financing
LGCY’s New IDR: Comparison to “Typical” IDRs
17
Similarities Offer Comfort Differences Offer Advantages
IDR Distributions (i.e. Payout) based on one schedule of LGCY distribution “splits” (% of marginal cash flow above target)
MQD, First Target, and Second Target “splits” based on standard 100%, 115%, and 125% of baseline distribution per unit ($0.59/unit for LGCY)
IDR Holders are incentivized to do more dropdowns
Far-reaching Scope
Typical structures have access to one source for dropdowns
LGCY can team with multiple strategic allies
Favored Economics
Highest “split” is 23% vs 48%
Reset mechanism
Conversion right
Vesting and forfeiture
Focused Alignment
Management & GP do not own IDRs
IDR Holders do not own any of the GP
IDRs dilute both LP & GP
IDRs earned through actual dropdowns vs. prospective dropdowns
Quarterly Distribution Per LP Unit
GP / Unitholders IDRs
Minimum $0.5900 100% 0%
First Threshold Above $0.5900 Up to $0.6785 100% 0%
Second Threshold Above $0.6785 Up to $0.7375 87% 13%
Thereafter Above $0.7375 77% 23%
Investment Rationale of WPX Acquisition
18
Strategic Alliance
High Quality MLP Assets
Increased Scale and Diversification
Attractive Economics
WPX is a world-class Rockies operator with a deep inventory of MLP-friendly assetsUnmatched experience, infrastructure, and economics in the Piceance Basin
IDRs incentivize both parties to make future transactions WPX can vest in up to an additional 20% of the IDRs by dropping more assets into LGCY
Enhanced acquisition platform – this transaction, including the newly-established IDRs, creates a template for future deals with 3rd parties
Low decline, 100% PDP assets in the heart of the Piceance Basin 10% avg. annual PDP terminal decline rate(1), excluding escalating working interest Escalating working interest holds production roughly flat over the next few years
2,680 producing wells with an average age of 9.1 years mitigate risks (predictable production curves, minimal single well risk)
Adds 46 MMBoe of internally estimated proved reserves and over 10.5 MBoe/d of Q3 2014 production, increases of over 50%
Scale enhances credit profile and earnings potential Pro forma 54% liquids balances LGCY’s commodity mix and expands optionality in current commodity price environment
Drives immediate and long-term accretion to unitholdersLow production decline and increasing working interest structure minimize maintenance capexFlatter NYMEX gas curve and 100% PDP content allow for increased “hedgability”
(1) 3-year average from 2017 – 2019
IDR Key Terms
19
Units: 1,000,000 IDRs authorized and available for issuance by LGCY
WPX: Issued 300,000 IDRs
Vesting: 100,000 IDRs immediately vest; 200,000 IDRs are available to vest at a rate of 10,000 per $35.5 million of future transactions, provided however that ~66,667 will be forfeited at each of the next three anniversaries of issuance if not already vested
Reset: IDR splits can reset upon 4 consecutive distributions in the “high-splits”
IDR Unitholder receives LP unit equivalent of the average of the last two distributionsNumber of resets is unlimited
Conversion Right: Under certain circumstances, LGCY can fully retire IDRs for LP Unit Equivalent
If >$0.90 but <$1.00, 1.2x LP Unit EquivalentIf >$1.00 but <$1.10, 1.1x LP Unit EquivalentIf >$1.10 1.0x LP Unit Equivalent
Founding Investors, Directors
and ManagementPublic
Legacy Reserves Operating LP
100%
18% LimitedPartner Interest
<0.1% General Partner Interest
100% Ownership Interest
82% LimitedPartner
Interest & Series A+B Preferred
Units
$1.5 Bn Revolving Credit Facility(1)
$300MM 8.00% Senior Notes$550MM 6.625% Senior Notes
1MM authorized IDRs (100k initially
vested); No LP voting
rightsLegacy Reserves LP
(NASDAQ:LGCY)
Quarterly DistributionPer LP Unit
GP / Unitholders IDRs
Minimum $0.5900 100% 0%
First Threshold Above $0.5900 Up to $0.6785 100% 0%
Second Threshold Above $0.6785 Up to $0.7375 87% 13%
Thereafter Above $0.7375 77% 23%
Legacy ReservesGP, LLC
(1) $950 million borrowing base
WPX & Other
Potential Parties
Natural Gas Hedging Summary(1)
Oil and Natural Gas Hedging Summary
20
Oil 3-Way Collars Summary
(BB
tu H
edge
d)
(MB
bls
Hed
ged)
(MB
bls
Hed
ged)
Oil Hedging Summary(2)
(1) Natural gas hedge prices reflect a weighted average of NYMEX, Waha (West Texas), ANR-OK, and CIG (Rockies) index swap prices (excluding basis swaps) and long put prices on 3-way collars.
(2) Oil hedge prices reflect a weighted average of swap prices, long put prices on 3-way collars, and enhanced swap prices.
$110.71 $111.84 $106.40 $104.20$96.59 $89.69 $88.37 $85.00
$71.59 $65.08 $63.37 $60.00
$0.00
$35.00
$70.00
$105.00
$140.00
0
400
800
1,200
1,600
Q4 2014 2015 2016 2017
3W Collars (MBbls) Avg. 3W Short Call (Price)Avg. 3W Long Put (Price) Avg. 3W Short Put (Price)
$4.64
$4.38
$4.26 $4.25 -
5,000
10,000
15,000
20,000
25,000
30,000
Q4 2014 2015 2016 2017
Swaps 3W Collars
$94.22
$92.10
$88.86
$87.34$90.50
-
800
1,600
2,400
3,200
4,000
Q4 2014 2015 2016 2017 2018
Swaps 3W Collars Enhanced Swaps
Gas 3-Way Collars Summary
$5.03 $5.01 $5.08$5.54
$4.65 $4.21 $4.25 $4.25$4.00 $3.66 $3.75 $3.75
$0.00
$1.00
$2.00
$3.00
$4.00
$5.00
$6.00
-
2,000
4,000
6,000
8,000
10,000
Q4 2014 2015 2016 2017
3W Collars (Bbtu) Avg. 3W Short Call (Price)Avg. 3W Long Put (Price) Avg. 3W Short Put (Price)
(BB
tu H
edge
d)
Successful Historical Use of Hedging to Protect Cash Flows
21
Annual Revenues Plus Hedging Annual Adjusted EBITDA
Annual Revenues Without Hedging Annual Hedging Settlements
$112
$215$137
$216
$337 $346
$485
$0
$100
$200
$300
$400
$500
$600
2007 2008 2009 2010 2011 2012 2013
$0
($40)
$53
$20 $1 $6
($7)
($60)
($20)
$20
$60
$100
2007 2008 2009 2010 2011 2012 2013
$70$104 $120
$141
$201 $198
$273
$0
$50
$100
$150
$200
$250
$300
2007 2008 2009 2010 2011 2012 2013
$112$175 $190
$237
$338 $352
$478
$0
$100
$200
$300
$400
$500
$600
2007 2008 2009 2010 2011 2012 2013
Note: Acreage, proved, and 3P numbers are as of 12/31/13
WPX Company Overview
22
WPX Energy (NYSE: WPX), based in Tulsa, Oklahoma, has a $2.4 billion market cap, $4.3 billion TEV (as of 12/1/14), and reported $230 million of Q3 2014 adjusted EBITDAX
Operates in three primary basins: Piceance, Williston, and San Juan
Additional operations in the Powder River Basin, Marcellus, Argentina, and Colombia
Portfolio Summary(1)
Net Production: 1.2 Bcfe/d
1P Reserves: 4.8 Tcfe
3P Reserves: 16.9 Tcfe
20,000 drillable locations
Piceance Overview – Increasing Activity & Efficiencies
Running 9 rigs and drilling 285 wells in 2014,
compared to 7 rigs and 210 wells spud in 2013
Lowest-cost operator in the Piceance Basin
• 34% less D&C capital costs
• 57% less operating lifting costs
Williston• 106 MMBoe Proved• 176 MMBoe 3P• 81k Net Acres
Marcellus• 328 Bcfe Proved• 1,555 Bcfe 3P• 88k Net Acres
San Juan• 517 Bcfe Proved• 1,645 Bcfe 3P• 161k Net Acres
Piceance• 3,019 Bcfe Proved• 11,878 Bcfe 3P• 221k Net Acres
Source: WPX filings, WPX investor presentation, including footnotes therein(1) Portfolio summary as of YE 2013 and excludes contribution from international operations (WPX’s 69%
ownership in APCO, as well as additional acreage owned by WPX).
23
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 long-
lived 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 (benefit) related to LTIP unit awards accounted for under the equity or
liability methods; minimum payments earned in excess of overriding royalty interests earned; equity in EBITDA of equity method
investee; net (gains) losses on commodity derivatives; and net cash settlements received (paid) on commodity derivatives; and
transaction expenses related to acquisitions.
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.
Reg G Reconciliation
24
(1) Minimum payments received 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.(2) EBITDA applicable to equity method investee is defined as the equity method investee's net income plus interest expense and depreciation.
($ in millions)
2007 2008 2009 2010 2011 2012 2013 Q3 14
Net income (loss) ($55.7) $158.2 ($92.8) $10.8 $72.1 $68.6 ($35.3) $63.8
Interest expense 7.1 21.2 13.2 25.8 18.6 20.3 50.1 19.1
Income taxes 0.3 0.0 0.6 0.5 1.0 1.1 0.6 0.3
Depletion, depreciation, amortization and accretion 28.4 63.3 58.8 62.9 88.2 102.1 158.4 48.0
Impairment of long-lived assets 3.2 76.9 9.2 13.4 24.5 37.1 85.8 4.8
(Gain) loss on disposal of assets 0.5 0.6 0.4 0.6 (0.6) (2.5) 0.6 (1.7)
Equity in income of partnership (0.1) (0.1) (0.0) (0.1) (0.1) (0.1) (0.6) (0.1)
Unit-based compensation expense 1.0 1.1 3.1 5.5 4.0 3.5 4.8 1.0
Minimum payments received in excess of overriding royalty interest earned (1) 1.1 0.3
Equity in EBITDA of equity method investee (2) 0.7 0.2
Net (gains) losses on commodity derivatives 85.2 (176.9) 75.5 1.4 (6.8) (38.5) 13.5 (56.0)
Net cash settlements received (paid) on commodity derivatives 0.2 (40.2) 52.5 20.1 0.6 5.9 (7.1) (2.4)
Transaction expenses related to acquisitions 0.4
Adjusted EBITDA $70.2 $104.1 $120.4 $141.0 $201.4 $197.6 $272.7 $77.7