1. business and industrial
2. energy
3. natural gas

Investor Presentation
JUNE 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 filing; 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 its 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.
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,
actual drilling results, including geological and mechanical factors affecting recovery rates, and other factors. 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 top-tier well results
NEW MEXICO
TEXAS
• Leveraging technology to maximize resource recovery,
returns and efficiencies
• Improving cost structure
Acreage, proved reserves and resource potential as of December 31, 2014.
3
The Concho Advantage
•
Concentrated, high-quality acreage positions in the Delaware Basin, Midland Basin and New
Mexico Shelf
High-Quality Assets • Successful track record of strategic and “bolt-on” acquisitions with development upside
Leveraging
Technology
Improving Capital
Efficiency
Strong Financial
Position
•
Multi-decade drilling inventory
•
Optimizing drilling and completion techniques
•
Maximizing resource recovery, returns and efficiencies
•
Efficient knowledge transfer throughout portfolio
•
Production and proved reserves CAGR since IPO of 35% and 32%, respectively
•
Low-cost operator with F&D costs reflective of capital-efficient horizontal program
•
Increased FY15 production growth target with capital outlook flat-to-down
•
Executing a returns-based, disciplined capital program
•
Strong hedge position for FY15 and FY16
4
Recent Results Highlight Execution Strength
1Q15
OIL PRODUCTION
Marks 21st
Consecutive Quarter
of Crude Oil
Production Growth
Total Production Growth
30% Growth
Year-over-Year
132.2
Delaware Basin Growth Engine:
Horizontal Production Growth
124.8
113.5
107.8
101.6
63% Growth
Year-over-Year
1Q14
2Q14
3Q14
4Q14
1Q15
Total Production (MBoepd)
68.9
64.5
55.2
49.1
Oil Production Growth
42.3
38% Growth
Year-over-Year
89.6
82.1
72.7
65.0
68.5
1Q14
1Q14
2Q14
3Q14
4Q14
Oil Production (MBopd)
2Q14
3Q14
4Q14
1Q15
1Q15
Horizontal Production Growth (MBoepd)
5
2015 Capital Program
Rig Program Progression
Capital Program Allocation
12%
37
35
30
↓19 Rigs
since 4Q14
12%
24
76%
FY15 OUTLOOK
Production Growth
Target
18% to 22%
CAPTURING
SERVICE
COST REDUCTIONS
~20% Savings
vs. YE14 Well Costs
18
Delaware Basin
Midland Basin
New Mexico Shelf
$1.8 BN to $2.0 BN Total Capital Program
4Q14
Jan-15
Feb-15
Mar-15 Current
Average Rig Count
•
More production growth with less
capital than initially planned
•
Flexibility to build momentum heading
into 2016
6
Northern Delaware Basin
• Significant resource captured from large
acreage position and multiple target zones
ACREAGE POSITION
~365,000 gross
(255,000 net) acres
• Continue to deliver industry-leading results in
the northern Delaware Basin
• Added 42 new horizontal wells with at least
30 days of production data in 1Q15
CURRENT RIG
COUNT
11 Horizontal Rigs
• Avg. lateral length: 5,020’
• Avg. 30-day peak rate: 891 Boepd (73%
oil)
EDDY
LEA
• Avg. 24-hour peak rate: 1,430 Boepd
• Strong results in the oil-rich Avalon Shale
CULBERSON
LOVING
C X O AC R E AG E
CXO 1Q15 HZ WELL
• 3 new wells with at least 30 days of
production data in 1Q15
• Avg. 30-day peak rate: 1,586 Boepd
(77% oil)
• Avg. 24-hour peak rate: 2,487 Boepd
Acreage as of December 31, 2014.
7
Execution-Driven Capital Efficiency
NORTHERN DELAWARE BASIN
Operational
Efficiencies that
Improve Returns and
Withstand Price
Cycles
Drilling Days
36
Drilling Cost/Lateral Foot ($/Ft)
Lateral Length
Up 17%
(39)%
27
$589
24
(25)%
22
$545
$483
1Q12
1Q13
1Q14
1Q15
$442
Feet Drilled/Day
667
+79%
587
536
372
1Q12
1Q13
1Q14
1Q15
1Q12
1Q13
1Q14
1Q15
8
Resource and Results
NORTHERN DELAWARE BASIN
Deep Inventory of Identified Horizontal Locations
Avg. Peak Rate (Boepd)
30-Day (% Oil)
24-Hour
Identified
Locations
Wells per
Section
972
700
4
763 (49%)
1,337
1,500
4 to 6
14
517 (72%)
977
1,400
4
2nd Bone Spring
249
923 (76%)
1,454
3,200
4 to 6
3rd Bone Spring
63
645 (85%)
1,063
1,400
4
Wolfcamp Shale
17
801 (40%)
1,269
1,600
4
Formation
Well
Count1
Brushy Canyon
19
632 (82%)
Avalon Shale
62
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 March 31, 2015.
9
Southern Delaware Basin
• Strong well results driven by enhanced geologic
model and completion design
LOVING
ACREAGE POSITION
~275,000 gross
(170,000 net) acres
WARD
• Added 8 new horizontal wells with at least 30
days of production data in 1Q15
• Avg. lateral length: 5,088’
CURRENT RIG
COUNT
3 Horizontal Rigs
• Avg. 30-day peak rate: 997 Boepd (79% oil)
• Avg. 24-hour peak rate: 1,238 Boepd
REEVES
PECOS
C X O AC R E AG E
CXO 1Q15 HZ WELL
Acreage as of December 31, 2014.
10
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 12 new horizontal wells with at least 30 days of
production data in 1Q15
MARTIN
• Avg. lateral length: 6,343’
CURRENT RIG
COUNT
2 Horizontal Rigs
• Avg. 30-day peak rate: 742 Boepd (83% oil)
GLASSCOCK
ECTOR
MIDLAND
Deep Inventory of Identified Horizontal Locations
CRANE
UPTON
REAGAN
C X O AC R E AG E
CXO 1Q15 HZ WELL
Acreage as of December 31, 2014.
• Avg. 24-hour peak rate: 957 Boepd
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
11
New Mexico Shelf
• Deep inventory of high-return, low-cost
locations
ACREAGE POSITION
~160,000 gross
(110,000 net) acres
• 1,600 horizontal Yeso locations
CHAVES
• 1,000 vertical Yeso locations
CURRENT RIG
COUNT
2 Horizontal Rigs
• Horizontal drilling and completion
technology expanding play boundaries
• Added 7 new horizontal wells with at
least 30 days of production data in 1Q15
EDDY
LEA
• Avg. 30-day peak rate: 331 Boepd
(84% oil)
• Avg. 24-hour peak rate: 511 Boepd
• Avg. well cost: $2.5 MM to $3.5 MM
C X O AC R E AG E
CXO 1Q15 HZ WELL
Acreage as of December 31, 2014.
12
Key Takeaways
Optimizing drilling and completion techniques,
improving resource recovery and returns
Executing a returns-based, disciplined capital
program with operational flexibility
Maintaining financial strength is a top priority
Service costs adjusting to lower commodity prices
Proven strategy, quality assets and experienced
team to weather commodity price cycles
Capital efficiency driving 20% production growth
with 35% less capital year-over-year
13
Appendix
2015 Operational & Financial Outlook
Production
2Q15 OUTLOOK
Production:
138 - 142 MBoepd
Year-over-year growth
18% - 22%
Oil mix
63% - 65%
Price realizations, excluding commodity derivatives (% of NYMEX)
Crude oil (per Bbl)
Natural gas (per Mcf)
90% - 93%
100% - 120%
Operating costs and expenses ($/Boe, unless otherwise noted)
LOE
Direct LOE
Oil & gas taxes (% of oil & gas revenues)
$7.75 - $8.25
8.25%
G&A
Cash G&A
$3.40 - $3.90
Non-cash stock-based compensation
$1.20 - $1.30
DD&A
Exploration
$23.00 - $25.00
$1.50 - $2.50
Interest expense ($ MM)
Cash
Non-cash
Income tax rate (%)
$210 - $220
$10
38%
Current taxes ($ MM)
$40 - $50
Capital expenditures ($ BN)
$1.8 - $2.0
(UPDATED AS OF MAY 4, 2015)
15
Hedge Position
2Q15 - 4Q15
OIL HEDGES
15.7 MMBbls
~65% Production1
2016 OIL HEDGES
14.9 MMBbls
Second Quarter
Oil Swaps: (a)
Volume (Bbl)
Price (Bbl)
Oil Basis Swaps: (b)
Volume (Bbl)
Price (Bbl)
Natural Gas Swaps: (c)
Volume (MMBtu)
Price (MMBtu)
Natural Gas Basis Swaps: (d)
Volume (MMBtu)
Price (MMBtu)
(a)
(b)
(c)
(d)
2015
Third Quarter
Fourth Quarter
Total
2016
2017
$
5,114,000
80.62 $
5,719,000
77.19 $
4,904,000 15,737,000 14,859,000
5,568,000
78.84 $
78.82 $
80.48 $
65.60
$
4,680,500
(3.08) $
5,384,000
(2.69) $
4,692,000 14,756,500 14,357,000
1,810,000
(2.79) $
(2.85) $
(2.14) $
(1.78)
$
5,915,000
4.16 $
5,980,000
4.16 $
5,980,000 17,875,000
4.16 $
4.16
$
1,365,000
(0.13) $
1,380,000
(0.13) $
1,380,000
4,125,000
(0.13) $
(0.13)
The index prices for the oil contracts 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.
(UPDATED AS OF MAY 19, 2015)
1Based
on 2015 production guidance midpoint.
16