Investor Presentation
HOWARD WEIL ENERGY CONFERENCE
MARCH 2015
Forward-Looking Statements and Other Disclaimers
This presentation contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements, other than statements of historical fact, included in this
presentation that address activities, events or developments that Concho Resources Inc. (the “Company”) expects, believes or anticipates will or may occur in the future are forward-looking statements. Forward-looking statements contained in this
presentation specifically include statements, estimates and projections regarding the Company's future financial position, operations, performance, business strategy, capital expenditure budget, liquidity and capital resources, the timing and success of
specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. The words “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other similar
expressions are intended to identify forward-looking statements, which generally are not historical in nature. However, the absence of these words does not mean that the statements are not forward-looking. These statements are based on certain
assumptions made by the Company based on management's experience, expectations and perception of historical trends, current conditions, anticipated future developments and other factors believed to be appropriate. Forward-looking statements are
not guarantees of performance. Although the Company believes the expectations reflected in its forward-looking statements are reasonable and are based on reasonable assumptions, no assurance can be given that these assumptions are accurate or
that any of these expectations will be achieved (in full or at all) or will prove to have been correct. Moreover, such statements are subject to a number of assumptions, risks and uncertainties, many of which are beyond the control of the Company, which
may cause actual results to differ materially from those implied or expressed by the forward-looking statements. These include the factors discussed or referenced in the “Risk Factors” section of the Company's most recent Form 10-K and Form 10-Q
filings; risks relating to declines in the prices the Company receives for its oil and natural gas; uncertainties about the estimated quantities of oil and natural gas reserves; drilling and operating risks, including risks related to properties where the Company
does not serve as the operator and risks related to hydraulic fracturing activities; the adequacy of the Company’s capital resources and liquidity including, but not limited to, access to additional borrowing capacity under the Company’s credit facility; the
effects of government regulation, permitting and other legal requirements, including new legislation or regulation of hydraulic fracturing and the export of oil and natural gas; environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well
fluids, toxic gas or other pollution into the environment, including groundwater contamination; difficult and adverse conditions in the domestic and global capital and credit markets; risks related to the concentration of the Company’s operations in the
Permian Basin of Southeast New Mexico and West Texas; disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver the Company’s oil, natural gas liquids and natural gas and other processing and transportation
considerations; shortages of oilfield equipment, services and qualified personnel and increases in costs for such equipment, services and personnel; potential financial losses or earnings reductions from the Company’s commodity price management
program; risks and liabilities related to the integration of acquired properties or businesses; uncertainties about the Company’s ability to successfully execute our business and financial plans and strategies; uncertainties about the Company’s ability to
replace reserves and economically develop its current reserves; general economic and business conditions, either internationally or domestically; competition in the oil and natural gas industry; uncertainty concerning the Company’s assumed or possible
future results of operations; and other important factors that could cause actual results to differ materially from those projected. Accordingly, you should not place undue reliance on any of the Company’s forward-looking statements. Any forward-looking
statement speaks only as of the date on which such statement is made, and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except as required
by applicable law.
This presentation includes financial measures that are not in accordance with generally accepted accounting principles (“GAAP”), including EBITDAX. While management believes that such measures are useful for investors, they should not be used as a
replacement for financial measures that are in accordance with GAAP. For a reconciliation of EBITDAX to the nearest comparable measure in accordance with GAAP, please see the Appendix.
The Securities and Exchange Commission (“SEC”) requires oil and natural gas companies, in their filings with the SEC, to disclose proved reserves, which are those quantities of oil and natural 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 (using the trailing 12-month average first-day-of-the-month prices), 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.
The SEC also permits the disclosure of separate estimates of probable or possible reserves that meet SEC definitions for such reserves; however, the Company currently does not disclose probable or possible reserves in its SEC filings.
In this presentation, proved reserves attributable to the Company at December 31, 2014 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the-month prices of $91.48 per
Bbl of oil and $4.35 per MMBtu of natural gas. The Company’s estimate of its total proved reserves at December 31, 2014 is based on reports prepared by Cawley, Gillespie & Associates, Inc. and Netherland, Sewell & Associates, Inc., independent
petroleum engineers. The Company may use the terms “unproved reserves,” “resource potential,” “EUR” per well, “upside potential” and “prospective acreage” to describe estimates of potentially recoverable hydrocarbons that the SEC rules prohibit from
being included in filings with the SEC. These are based on analogy to the Company’s existing models applied to additional acres, additional zones and tighter spacing and are the Company’s internal estimates of hydrocarbon quantities that may be
potentially discovered through exploratory drilling or recovered with additional drilling or recovery techniques. These quantities may not constitute “reserves” within the meaning of the Society of Petroleum Engineer’s Petroleum Resource Management
System or SEC rules. EUR estimates, resource potential and identified drilling locations have not been fully risked by Company management and are inherently more speculative than proved reserves estimates. Actual locations drilled and quantities that
may be ultimately recovered from the Company’s interests could differ substantially. There is no commitment by the Company to drill all of the drilling locations, which have been attributed to these quantities. Factors affecting ultimate recovery include the
scope of the Company’s ongoing drilling program, which will be directly affected by the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory
approvals and other factors; and actual drilling results, including geological and mechanical factors affecting recovery rates. Estimates of unproved reserves, resource potential, per well EUR and upside potential may change significantly as development of
the Company’s oil and natural gas assets provide additional data. The Company’s production forecasts and expectations for future periods are dependent upon many assumptions, including estimates of production decline rates from existing wells and the
undertaking and outcome of future drilling activity, which may be affected by significant commodity price declines or drilling cost increases.
2
Concho Resources
Strategic acreage position in the Permian Basin
• ~1.1 MM gross (700,000 net) acres
• Core areas in the Delaware Basin, Midland Basin and
New Mexico Shelf
High quality, long life reserve base
• 637.2 MMBoe estimated proved reserves
• ~3.7 BBoe of total resource potential, including proved
reserves
Leading Permian operator
• Delivering industry-leading well results
NEW MEXICO
TEXAS
• Optimizing drilling and completion techniques, maximizing
resource recovery and returns
• Executing returns-based, disciplined capital program
Acreage, proved reserves and resource potential as of December 31, 2014.
3
Dynamics of U.S. Oil Production, Price and Rig Count
$160
1,800
CXO Performs through Cycles
• Proven strategy and high-quality assets endure price cycles
• Drilling program flexible to lower commodity prices
• Service costs adjusting to current environment
$140
1,600
1,400
1,200
$100
1,000
$80
800
Oil Rig Count
WTI Oil Price ($/Bbl)
$120
$60
600
$40
400
U.S. Oil Production (YoY % Growth)
$20
$0
2007
200
-0.2%
7.1%
-1.5%
2008
2009
2.2%
2010
3.3%
2011
Oil Price ($/Bbl)
14.9%
14.6%
2012
2013
15.5%
2014
0
2015
U.S. Oil Rig Count
Source: U.S. oil rig count data from Baker Hughes. U.S. Oil production annual growth from EIA.
4
Proven Strategy Endures Cycles
• Concentrated, high-quality acreage position in the Delaware Basin, Midland
Basin and New Mexico Shelf
• Significant inventory of horizontal drilling locations
• Expanded acreage position during 2014 with “bolt-on” additions and leasing
Invest in High
Quality Assets
Deliver Measured
Growth
• Maintaining financial strength and liquidity a top priority
• Exited 2014 at 1.4x debt-to-EBITDAX1
Keep a Strong
Balance Sheet
Execute a
Disciplined Capital
Program
1EBITDAX
• Production and proved reserves CAGR since IPO of 35% and 32%, respectively
• Low-cost operator with F&D costs reflective of capital-efficient horizontal
development program
• Disciplined capital program with flexibility
• Strong hedge position
is a non-GAAP measure. See appendix for reconciliation to GAAP measure. Net debt is as of December 31, 2014, and pro-forma for the February 2015 equity offering.
5
Track Record of Measured Growth
2014 Production
Growth
22%
Year-over-Year
Track Record of Measured Growth,
Prudent Financial Management
45
4.0x
40.9
40
33.6
Production (MMBoe)
35
29.8
Avg. FYE
Debt-to-EBITDAX1: 1.8x
30
3.0x
2.5x
23.6
25
2.0x
20
15.6
1.5x
15
10.9
10
5
1.0x
7.1
5
0.5x
0
0.0x
2007
2008
2009
2010
Production (MMBoe)
1EBITDAX
FYE Debt-to-EBITDAX1
2007-2014
Production
CAGR
35%
3.5x
2011
2012
2013
2014
1
FYE Debt-to-EBITDAX
is a non-GAAP measure. See appendix for reconciliation to GAAP measure.
6
Northern Delaware Basin
• Significant resource captured from large acreage position
and multiple target zones
Acreage Position
~365,000 gross
(255,000 net) acres
• Continue to deliver industry-leading results in the
Northern Delaware Basin
• Added 36 new horizontal wells with at least 30 days of
production data in 4Q14
Current Rig Count
13 Horizontal Rigs
• Avg. lateral length: 4,851’
• Avg. 30-day IP rate: 883 Boepd (73% oil)
• Avg. 24-hour peak rate: 1,387 Boepd
EDDY
CULBERSON
LEA
• 2015 focus: Ongoing completion design optimization and
downspacing tests in the Avalon shale and 2nd Bone
Spring
LOVING
C X O AC R E AG E
CXO 4Q14 HZ WELL
Acreage as of December 31, 2014.
7
Capturing Significant Resource
NORTHERN DELAWARE BASIN
Deep Inventory of Identified Horizontal Locations
Avg. Peak Rate (Boepd)
30-Day (% Oil)
24-Hour
Identified
Locations
Wells per
Section
942
700
4
721 (46%)
1,279
1,500
4 to 6
13
492 (71%)
967
1,400
4
2nd Bone Spring
226
918 (76%)
1,442
3,200
4 to 6
3rd Bone Spring
56
663 (85%)
1,088
1,400
4
Wolfcamp Shale
15
768 (43%)
1,232
1,600
4
Formation
Well
Count1
Brushy Canyon
13
623 (83%)
Avalon Shale
59
1st Bone Spring
Concho’s 365,000 gross acres are prospective for six zones with
downspacing potential
1Wells
with a minimum of 30 days of production at December 31, 2014.
8
Enhancing Well Results and Controlling Costs
NORTHERN DELAWARE BASIN
Consistently Enhancing Horizontal
Well Results
18% Increase in Avg. Peak 30-Day Rates
FY14 vs. FY13
Controlling Costs While Increasing
Completion Intensity
1,473
1,315
+40%
1,187
1,133
936
795
728
672
2011
2012
Avg. Peak 30-Day (Boepd)
Well Count
Avg. Lateral Length
56
4,008’
75
4,246’
2013
2014
Avg. Peak 24-Hr (Boepd)
106
4,291’
146
4,777’
2013
2014
Cost/Treated Lateral Foot ($/ft)
Proppant/Treated Lateral Foot
9
Optimizing Completions and Improving Recoveries – 2nd Bone Spring
NORTHERN DELAWARE BASIN
Enhanced Completion vs.
Base Completion
Optimizing Completions
Avg. Stages/Well
Avg. Proppant/Well
30%+
160
140
Base
Enhanced
Base
Enhanced
Maximizing Returns
Completion
Count
Enhanced Avg.
49
Well Cost
($MM)
ROR
$60/$3.50**
$6.5 - $7.0
50% - 60%
Avg. Cumulative Production1
80%+
120
75%
Increase
100
80
60
40
20
0
Base Avg.
139
$5.5 - $6.0
20% - 30%
**Assumes no service cost reductions from YE14
1Production
0
30
60
Base Avg.
90
Days
120
150
180
Enhanced Avg.
data normalized for a 4,300’ lateral.
10
Southern Delaware Basin
Acreage Position
~275,000 gross
(170,000 net) acres
• Outstanding well results driven by enhanced geologic
model and completion design
LOVING
• Added 11 new horizontal wells with at least 30 days of
production data in 4Q14
WARD
• Avg. lateral length: 6,706’
• Avg. peak 30-day rate: 1,271 Boepd (78% oil)
Current Rig Count
4 Horizontal Rigs
• Avg. peak 24-hour rate: 1,590 Boepd
• High-graded and added “bolt-on” acreage around core
Southern Delaware Basin position
REEVES
• 2015 focus: Optimizing well spacing, field development
pattern and completion design
PECOS
C X O AC R E AG E
CXO 4Q14 HZ WELL
Acreage as of December 31, 2014.
11
Midland Basin
Horizontal Core
Acreage Position
~200,000 gross
(110,000 net) acres
• Targeting oil-prone, repeatable Wolfcamp and Spraberry zones
• Strong well results driven by drilling and completion optimization
ANDREWS
• Added 15 new horizontal wells with at least 30 days of production
data in 4Q14
MARTIN
• Avg. lateral length: 5,835’
• Avg. peak 30-day rate: 846 Boepd (82% oil)
Current Rig Count
3 Horizontal Rigs
GLASSCOCK
ECTOR
• Avg. peak 24-hour rate: 1,077 Boepd
• 2015 focus: Increasing average lateral length and optimizing well
spacing and completion design
MIDLAND
Deep Inventory of Identified Horizontal Locations
CRANE
UPTON
REAGAN
C X O AC R E AG E
CXO 4Q14 HZ WELL
Formation
Identified
Locations
Wells per
Section
Avg. Lateral
Length
Spraberry
550
4
1.0 - 1.5 mile
Upper Wolfcamp
1,150
4
1.0 - 1.5 mile
Lower Wolfcamp
400
4
1.0 - 1.5 mile
Average lateral length for horizontal inventory increased 20%
year-over-year
Concho’s 200,000 gross acres are prospective for multiple zones
with downspacing potential
Acreage as of December 31, 2014.
12
New Mexico Shelf
Acreage Position
~160,000 gross
(110,000 net) acres
• Deep inventory of high-return, low-cost locations
• 1,600 horizontal Yeso locations
CHAVES
• 1,000 vertical Yeso locations
CHAVES
• Horizontal drilling and completion technology
expanding play boundaries
Current Rig Count
2 Horizontal Rigs
• Added 13 new horizontal wells with at least 30 days
of production data in 4Q14
• Avg. peak 30-day rate: 408 Boepd (83% oil)
• Avg. peak 24-hour rate: 585 Boepd
EDDY EDDY
LEA
LEA
• Avg. well cost: $3 MM to $4 MM
• 2015 focus: Horizontal development drilling and
optimizing completion design
C X O AC R E AG E
CXO 4Q14 HZ WELL
Acreage as of December 31, 2014.
13
Strong Financial Position with Capital Flexibility
Returns-Based, Disciplined
Capital Program for 2015
2015 Drilling & Completion
Capital Program
• Preserving financial strength and liquidity a high priority
11%
• Realizing service cost reductions and anticipate further reductions
during 2015
• Targeting 16% to 20% annual production growth in 2015
• Total capital program ~$2.0 BN
2015 D&C
Program
$1.8 BN
95% Operated
90% Horizontal
17%
• $1.8 BN for drilling and completions
• $200 MM for facilities, midstream and other
• Flexibility to adjust drilling and capital programs
72%
• 2015 hedge position covers ~55% anticipated oil production at
$84.15/Bbl1
1Q15 Production Guidance:
127 - 131 MBoepd
1Based
Delaware Basin
Midland Basin
New Mexico Shelf
on 2015 production guidance midpoint.
14
Key Takeaways
• Proven strategy, quality assets and experienced
team to weather commodity price cycles
• Service costs adjusting to lower commodity prices
• Optimizing drilling and completion techniques,
improving resource recovery and returns
• Maintaining financial strength is a top priority
• Executing a returns-based, disciplined capital
program with operational flexibility
15
Appendix
2015 Operational & Financial Outlook
(UPDATED AS OF FEBRUARY 25, 2015)
Production
Year-over-year growth
16% - 20%
Oil mix
63% - 65%
Price realizations, excluding commodity derivatives (% of NYMEX)
Crude oil (per Bbl)
Natural gas (per Mcf)
1Q15 Outlook
Production:
127 - 131 MBoepd
90% - 93%
100% - 120%
Operating costs and expenses ($/Boe, unless noted)
LOE
Direct LOE
Oil & gas taxes (% of oil & gas revenues)
$8.00 - $8.50
8.25%
G&A
Cash G&A
$3.40 - $3.90
Non-cash stock-based compensation
$1.10 - $1.20
DD&A
Exploration
$24.00 - $26.00
$1.50 - $2.50
Interest expense ($ MM)
Cash
Non-cash
Income tax rate (%)
Current taxes ($ MM)
Capital expenditures ($ BN)
$215 - $225
$10
38%
$40 - $50
$2.0
17
Hedge Position
(UPDATED AS OF FEBRUARY 25, 2015)
First Quarter
2015
Third Quarter
Second Quarter
Fourth Quarter
Total
Oil Swaps: (a)
Volume (Bbl)
Price (Bbl)
$
4,240,000
88.32
$
4,579,000
83.05
$
4,314,000
82.83
$
4,109,000
82.47
$
17,242,000
84.15
Oil Basis Swaps: (b)
Volume (Bbl)
Price (Bbl)
$
3,915,000
(3.47)
$
3,836,500
(3.45)
$
3,634,000
(3.44)
$
3,404,000
(3.38)
$
14,789,500
(3.44)
Natural Gas Swaps: (c)
Volume (MMBtu)
Price (MMBtu)
$
5,850,000
4.16
$
5,915,000
4.16
$
5,980,000
4.16
$
5,980,000
4.16
$
23,725,000
4.16
Natural Gas Basis Swaps: (d)
Volume (MMBtu)
Price (MMBtu)
$
1,350,000
(0.13)
$
1,365,000
(0.13)
$
1,380,000
(0.13)
$
1,380,000
(0.13)
$
5,475,000
(0.13)
2016
Oil Swaps: (a)
Volume (Bbl)
Price (Bbl)
$
12,499,000
83.43
Oil Basis Swaps: (b)
Volume (Bbl)
Price (Bbl)
$
1,464,000
(2.48)
(a)
(b)
(c)
(d)
2017
$
168,000
87.00
The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price.
The basis differential price is between Midland – WTI and Cushing – WTI.
The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price.
The basis differential price is between the El Paso Permian delivery point and NYMEX – Henry Hub delivery point.
18
EBITDAX Reconciliation (Unaudited)
The Company defines EBITDAX as net income (loss), plus (1) exploration and abandonments expense, (2) depreciation, depletion and amortization expense, (3) accretion expense, (4) impairments of
long-lived assets, (5) non-cash stock-based compensation expense, (6) bad debt expense, (7) ineffective portion of cash flow hedges, (8) (gain) loss on derivatives not designated as hedges, (9) cash
receipts from (payments on) derivatives not designated as hedges, (10) (gain) loss on disposition of assets, net, (11) interest expense, (12) loss on extinguishment of debt, (13) federal and state income
taxes on continuing operations and (14) similar items listed above that are presented in discontinued operations. EBITDAX is not a measure of net income or cash flow as determined by GAAP.
The Company’s EBITDAX measure (which includes continuing and discontinued operations) provides additional information which may be used to better understand our operations. EBITDAX is one of
several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income, as an
indicator of our operating performance. Certain items excluded from EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost
of capital and tax structure, as well as the historic cost of depreciable assets, none of which are components of EBITDAX. EBITDAX, as used by us, may not be comparable to similarly titled measures
reported by other companies. We believe that EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team, and by other users, of our
consolidated financial statements. For example, EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production
companies without regard to financial or capital structure, and to assess the financial performance of our assets and our company without regard to capital structure or historical cost basis.
Three Months Ended
(in thousands)
Net Income (loss)
Exploration and abandonments
Depreciation, depletion and amortization
Accretion of discount on asset retirement obligations
Impairments of long-lived assets
Non-cash stock-based compensation
Bad debt expense
Ineffective portion of cash flow hedges
(Gain) loss on derivatives not designated as hedges
Cash receipts from (payments on) derivatives not designated as hedges
(Gain) loss on disposition of assets, net
Interest expense
Loss on extinguishment of debt
Income tax expense (benefit) from continuing operations
Discontinued operations
EBITDAX
December
2014
$ 129,896 $
214,176
264,138
1,910
431,675
12,458
(765,010)
98,157
611
52,537
69,032
$ 509,580 $
31,
2013
105,789
71,752
214,833
1,637
9,800
(33,651)
5,343
(449)
56,401
32,214
463,669
Years Ended
2014
2013
$ 538,175 $ 251,003
284,821
109,549
979,740
772,608
7,072
6,047
447,151
65,375
47,130
35,078
(890,917)
123,652
71,983
(32,341)
9,308
1,268
216,661
218,581
4,316
28,616
317,785
118,237
(12,081)
$ 2,033,225 $ 1,685,592
December
2012
2011
$ 431,689 $ 548,137 $
39,840
11,394
575,128
400,022
4,187
2,444
439
29,872
19,271
(127,443)
23,350
23,536
(84,854)
372
1,139
182,705
118,360
251,041
261,800
64,701
(26,343)
$ 1,475,628 $ 1,275,159 $
31,
2010
2009
2008
204,370 $
(9,802) $ 278,702 $
10,130
10,632
37,617
211,487
162,975
95,240
1,079
690
510
11,614
7,880
8,382
12,931
9,040
5,223
870
(1,035)
2,905
(1,336)
87,325
156,857
(249,870)
(13,824)
82,416
(6,354)
58
114
(777)
60,087
28,292
29,039
101,613
(28,890)
148,230
55,254
56,039
53,792
742,994 $ 475,208 $ 401,303 $
2007
25,360
29,097
49,262
296
4,777
3,841
821
20,274
1,815
(368)
36,042
8,673
37,502
217,392
19