4Q14 Earnings€¦ · CXO 4Q14 HZ WELL . Acreage Position ~365,000 gross (255,000 net) acres ....

4Q14 Earnings

FEBRUARY 26, 2015

Forward-Looking Statements and Other Disclaimers

2

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 adjusted net income and EBITDAX. We also provide reserve replacement ratio and drill-bit F&D cost. 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 adjusted net income and EBITDAX to the nearest comparable measure in accordance with GAAP and for our definitions of reserve replacement ratio and drill-bit F&D cost, 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.

Concho Resources

3

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

• 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.

NEW MEXICO

TEXAS

Fourth Quarter 2014 Results

4

Financial

Operational • Excellent total production growth of 29% and oil production growth of 31% year-over-year • Strong production growth driven by Delaware Basin horizontal program

• $1.15 diluted EPS; $0.88 adjusted EPS1 • EBITDAX1 of $509.6 MM, up 10% year-over-year

1Adjusted net income and EBITDAX are non-GAAP measures. See appendix for reconciliations to GAAP measures.

97.0 101.6

107.8 113.5

124.8

4Q13 1Q14 2Q14 3Q14 4Q14

Total Production Growth

62.5 65.0

68.5 72.7

82.1

4Q13 1Q14 2Q14 3Q14 4Q14

Oil Production Growth

35.9

42.3

49.1

55.2

64.5

4Q13 1Q14 2Q14 3Q14 4Q14

Delaware Basin Horizontal Production Growth

29% Growth Year-over-Year



66%

34%

4Q14 Production Mix

Total Production (MBoepd) Oil Production (MBopd) Crude Oil Natural Gas Horizontal Production Growth (MBoepd)

Full Year 2014 Highlights

5

• 22% total production growth and 25% crude oil production growth over 2013 • Enhanced drilling and completion techniques throughout assets are improving play economics and capital efficiency

• $4.88 diluted EPS; $4.02 adjusted EPS1 • Record annual EBITDAX1 of $2.0 BN, up 21% year-over-year • Capital expenditures excluding acquisitions in-line with $2.6 BN capital budget • Exited FY14 in a strong financial position with 1.7x debt-to-EBITDAX1 and flexible 2015 capital program

1Adjusted net income and EBITDAX are non-GAAP measures. See appendix for reconciliations to GAAP measures.

Financial

Operational

$217 $401 $475

$743

$1,275 $1,476

$1,686

$2,033

2007 2008 2009 2010 2011 2012 2013 2014

EBITDAX Growth

64%

36%

FY14 Production Mix

38% CAGR

Crude Oil Natural Gas EBITDAX ($MM)

8.3 12.5

20.1 28.3

40.3

49.2

57.9

72.1

2007 2008 2009 2010 2011 2012 2013 2014

Oil Production Growth

36% CAGR

Oil Production (MBopd)

Record Proved Reserves

91 137

212

324

387

447

503

637

2007 2008 2009 2010 2011 2012 2013 2014

Proved Reserves (MMBoe)

• 27% proved reserves growth and 24% proved developed reserves growth

• Horizontal proved reserves increased 107% • 428% reserve replacement ratio1

• $14.02/Boe drill-bit F&D cost1

Track Record of Proved Reserves Growth

Capital Efficient Horizontal Development Driving Reserve Growth

6

Capture and de-risk significant resource

Optimize operations to maximize recovery and capital efficiency

Total Resource Potential ~3.7 BBoe

Capture

Optimize

32% CAGR

1Reserve replacement ratio and drill-bit F&D cost are non-GAAP measures. See appendix for an explanation of how we calculate and use the reserve replacement ratio and drill-bit F&D cost.

2014 Proved Reserves Growth

27% Year-over-Year

Northern Delaware Basin

7

CXO ACREAGE CXO 4Q14 HZ W ELL

Acreage Position ~365,000 gross

(255,000 net) acres

Current Rig Count 15 Horizontal Rigs

• Significant resource captured from large acreage position and multiple target zones

• 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

• Avg. lateral length: 4,851’ • Avg. 30-day IP rate: 883 Boepd (73% oil) • Avg. 24-hour peak rate: 1,387 Boepd

• 2015 focus: Ongoing completion design optimization and downspacing tests in the Avalon shale and 2nd Bone Spring

Acreage as of December 31, 2014.

EDDY LEA

CULBERSON LOVING

Capturing Significant Resource

8 1Wells with a minimum of 30 days of production at December 31, 2014.

Concho’s 365,000 gross acres are prospective for six zones with downspacing potential

NORTHERN DELAWARE BASIN

Brushy Canyon

Avalon Shale

1st Bone Spring

2nd Bone Spring

3rd Bone Spring

Wolfcamp Shale

Well Count1

Avg. Peak Rate (Boepd)

30-Day (% Oil) 24-Hour

13

13

56

59

226

15

623 (83%)

492 (71%)

663 (85%)

942

967

1,088

1,279

1,442

1,232

721 (46%)

918 (76%)

768 (43%)

Formation Identified Locations

700

1,400

1,400

1,500

3,200

1,600

Wells per Section

4

4

4

4 to 6

4 to 6

4

Deep Inventory of Identified Horizontal Locations

Enhancing Well Results and Controlling Costs

9


2013 2014

Cost/Treated Lateral Foot ($/ft)

Proppant/Treated Lateral Foot

Controlling Costs While Increasing Completion Intensity

672 728

795

936

1,187 1,133

1,315

1,473

2011 2012 2013 2014

Avg. Peak 30-Day (Boepd) Avg. Peak 24-Hr (Boepd)

Consistently Enhancing Horizontal Well Results

18% Increase in Avg. Peak 30-Day Rates FY14 vs. FY13

56 4,008’

75 4,246’

106 4,291’

146 4,777’

Well Count Avg. Lateral Length

+40%

0

20

40

60

80

100

120

140

160

0 30 60 90 120 150 180

Base Avg. Enhanced Avg.

Optimizing Completions and Improving Recoveries – 2nd Bone Spring

10


Enhanced Completion vs. Base Completion

Avg.

Cum

ulat

ive

Prod

uctio

n1

Days

75% Increase

1Production data normalized for a 4,300’ lateral.

Maximizing Returns

Base Enhanced Base Enhanced

Optimizing Completions

Avg. Stages/Well Avg. Proppant/Well

30%+ 80%+

Enhanced Avg.

Base Avg.

Count

49

139

Completion Well Cost ($MM)

$6.5 - $7.0

$5.5 - $6.0

ROR $60/$3.50**

50% - 60%

**Assumes no service cost reductions from YE14

20% - 30%

Southern Delaware Basin


(170,000 net) acres


11

• Outstanding well results driven by enhanced geologic model and completion design


• Avg. lateral length: 6,706’ • Avg. peak 30-day rate: 1,271 Boepd (78% oil) • Avg. peak 24-hour rate: 1,590 Boepd

• High-graded and added “bolt-on” acreage around core Southern Delaware Basin position

• 2015 focus: Optimizing well spacing, field development pattern and completion design



PECOS

REEVES

WARD

LOVING

Midland Basin

Horizontal Core Acreage Position ~200,000 gross

(110,000 net) acres


12

• Targeting oil-prone, repeatable Wolfcamp and Spraberry zones • Strong well results driven by drilling and completion optimization • Added 15 new horizontal wells with at least 30 days of production

data in 4Q14 • Avg. lateral length: 5,835’ • Avg. peak 30-day rate: 846 Boepd (82% oil) • Avg. peak 24-hour rate: 1,077 Boepd

• 2015 focus: Increasing average lateral length and optimizing well spacing and completion design



ANDREWS MARTIN

ECTOR MIDLAND

GLASSCOCK

UPTON CRANE

REAGAN

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

Spraberry Upper Wolfcamp Lower Wolfcamp

Wells per Section

4

4

4

Formation Identified Locations

550

400

1,150

Avg. Lateral Length

1.0 - 1.5 mile

1.0 - 1.5 mile

1.0 - 1.5 mile

Deep Inventory of Identified Horizontal Locations

New Mexico Shelf


(110,000 net) acres


13

• Deep inventory of high-return, low-cost locations • 1,600 horizontal Yeso locations • 1,000 vertical Yeso locations

• Horizontal drilling and completion technology expanding play boundaries


• Avg. peak 30-day rate: 408 Boepd (83% oil) • Avg. peak 24-hour rate: 585 Boepd • Avg. well cost: $3 MM to $4 MM

• 2015 focus: Horizontal development drilling and optimizing completion design



LEA EDDY

CHAVES

EDDY LEA

CHAVES

Strong Financial Position with Capital Flexibility

14

72%

17%

11%

2015 Drilling & Completion Capital Program

• Preserving financial strength and liquidity a high priority

• Realizing service cost reductions and anticipate further reductions during 2015

• Total capital program ~$2.0 BN

• $1.8 BN for drilling and completions • $200 MM for facilities, midstream and other

• Targeting 16% to 20% annual production growth in 2015

• Expect to average ~26 rigs in FY15 with additional flexibility

• 2015 hedge position covers ~55% anticipated oil production at $84.15/Bbl1

Returns-Based, Disciplined Capital Program for 2015

1Based on 2015 production guidance midpoint.

2015 D&C Program $1.8 BN

95% Operated 90% Horizontal

Delaware Basin Midland Basin New Mexico Shelf 1Q15 Production Guidance: 127 - 131 MBoepd

Appendix

2015 Operational & Financial Outlook

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1Q15 Outlook Production:

127 - 131 MBoepd

Production

Year-over-year growth 16% - 20%

Oil mix 63% - 65%

Price realizations, excluding commodity derivatives (% of NYMEX)

Crude oil (per Bbl) 90% - 93%

Natural gas (per Mcf) 100% - 120%

Operating costs and expenses ($/Boe, unless noted)

LOE

Direct LOE $8.00 - $8.50

Oil & gas taxes (% of oil & gas revenues) 8.25%

G&A

Cash G&A $3.40 - $3.90

Non-cash stock-based compensation $1.10 - $1.20

DD&A $24.00 - $26.00

Exploration $1.50 - $2.50

Interest expense ($ MM)

Cash $215 - $225

Non-cash $10

Income tax rate (%) 38%

Current taxes ($ MM) $40 - $50

Capital expenditures ($ BN) $2.0

(UPDATED AS OF FEBRUARY 25, 2015)

Hedge Position

17

2015 First Quarter Second Quarter Third Quarter Fourth Quarter Total Oil Swaps: (a) Volume (Bbl) 4,240,000 4,579,000 4,314,000 4,109,000 17,242,000 Price (Bbl) $ 88.32 $ 83.05 $ 82.83 $ 82.47 $ 84.15 Oil Basis Swaps: (b) Volume (Bbl) 3,915,000 3,836,500 3,634,000 3,404,000 14,789,500 Price (Bbl) $ (3.47) $ (3.45) $ (3.44) $ (3.38) $ (3.44) Natural Gas Swaps: (c) Volume (MMBtu) 5,850,000 5,915,000 5,980,000 5,980,000 23,725,000 Price (MMBtu) $ 4.16 $ 4.16 $ 4.16 $ 4.16 $ 4.16 Natural Gas Basis Swaps: (d) Volume (MMBtu) 1,350,000 1,365,000 1,380,000 1,380,000 5,475,000 Price (MMBtu) $ (0.13) $ (0.13) $ (0.13) $ (0.13) $ (0.13) 2016 2017 Oil Swaps: (a) Volume (Bbl) 12,499,000 168,000 Price (Bbl) $ 83.43 $ 87.00

Oil Basis Swaps: (b) Volume (Bbl) 1,464,000 Price (Bbl) $ (2.48)

(a) The index prices for the oil price swaps are based on the NYMEX – West Texas Intermediate (“WTI”) monthly average futures price. (b) The basis differential price is between Midland – WTI and Cushing – WTI. (c) The index prices for the natural gas price swaps are based on the NYMEX – Henry Hub last trading day futures price. (d) The basis differential price is between the El Paso Permian delivery point and NYMEX – Henry Hub delivery point.

(UPDATED AS OF FEBRUARY 25, 2015)

Adjusted Net Income Reconciliation (Unaudited)

18

Three Months Ended Years Ended December 31, December 31, (in thousands, except per share amounts) 2014 2013 2014 2013 Net income - as reported $ 129,896 $ 105,789 $ 538,175 $ 251,003 Adjustments for certain non-cash and unusual items: (Gain) loss on derivatives not designated as hedges (765,010) (33,651) (890,917) 123,652 Cash receipts from (payments on) derivatives not designated as hedges 98,157 5,343 71,983 (32,341) Impairments of long-lived assets 431,675 - 447,151 65,375 Leasehold abandonments 197,570 35,930 217,326 49,758 Loss on extinguishment of debt - - 4,316 28,616 (Gain) loss on disposition of assets, net 611 (449) 9,308 1,268 Other 1,081 11,393 1,081 11,393 Discontinued operations: Gain on disposition of assets - - - (19,599) Tax impact1 13,648 (7,204) 53,106 (88,511) Change in statutory effective income tax rates (7,945) (21,876) (7,945) (21,876) Adjusted net income $ 99,683 $ 95,275 $ 443,584 $ 368,738 Adjusted earnings per share: Basic $ 0.88 $ 0.91 $ 4.03 $ 3.52 Diluted $ 0.88 $ 0.91 $ 4.02 $ 3.51

Effective tax rates 38.0% 38.8% 38.0% 38.8%

1The tax impact is computed utilizing the Company's adjusted statutory effective federal and state income tax rates shown in the table above.

EBITDAX Reconciliation (Unaudited)

19

Three Months Ended Years Ended December 31, December 31, (in thousands) 2014 2013 2014 2013 Net income $ 129,896 $ 105,789 $ 538,175 $ 251,003 Exploration and abandonments 214,176 71,752 284,821 109,549 Depreciation, depletion and amortization 264,138 214,833 979,740 772,608 Accretion of discount on asset retirement obligations 1,910 1,637 7,072 6,047 Impairments of long-lived assets 431,675 - 447,151 65,375 Non-cash stock-based compensation 12,458 9,800 47,130 35,078 (Gain) loss on derivatives not designated as hedges (765,010) (33,651) (890,917) 123,652 Cash receipts from (payments on) derivatives not designated as hedges 98,157 5,343 71,983 (32,341) (Gain) loss on disposition of assets, net 611 (449) 9,308 1,268 Interest expense 52,537 56,401 216,661 218,581 Loss on extinguishment of debt - - 4,316 28,616 Income tax expense from continuing operations 69,032 32,214 317,785 118,237 Discontinued operations - - - (12,081) EBITDAX $ 509,580 $ 463,669 $ 2,033,225 $ 1,685,592

The Company defines EBITDAX as net income, 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) (gain) loss on derivatives not designated as hedges, (7) cash receipts from (payments on) derivatives not designated as hedges, (8) (gain) loss on disposition of assets, net, (9) interest expense, (10) loss on extinguishment of debt, (11) federal and state income taxes on continuing operations and (12) similar items listed above that are presented in discontinued operations. EBITDAX is not a measure of net income or cash flows 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 the Company’s operations. EBITDAX is one of several metrics that the Company uses as a supplemental financial measurement in the evaluation of its business and should not be considered as an alternative to, or more meaningful than, net income, as an indicator of 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 the Company, may not be comparable to similarly titled measures reported by other companies. The Company believes that EBITDAX is a widely followed measure of operating performance and is one of many metrics used by the Company’s management team, and by other users, of the Company’s consolidated financial statements. For example, EBITDAX can be used to assess the Company’s 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 the Company’s assets and the Company without regard to capital structure or historical cost basis.

Reserve Replacement Ratio & Drill-Bit F&D Cost (Unaudited)

20

Reserve replacement ratio is a non-GAAP measure. The Company uses the reserve replacement ratio as an indicator of the Company’s ability to replenish annual production volumes and grow its reserves, thereby providing some information on the sources of future production. It should be noted that the reserve replacement ratio is a statistical indicator that has limitations. The ratio is limited because it typically varies widely based on the extent and timing of discoveries and property acquisitions. Its predictive and comparative value is also limited for the same reasons. In addition, since the ratio does not embed the cost or timing of future production of new reserves, it cannot be used as a measure of value creation. The reserve replacement ratio of 428% was calculated by dividing net proved reserve additions of 175.1 MMBoe (the sum of extensions, discoveries, revisions and purchases) by production of 40.9 MMBoe.

Finding and development cost is a non-GAAP measure used to assist in an evaluation of how much it costs the Company, on a per Boe basis, to add proved reserves. Drill-bit finding and development costs are calculated by dividing the sum of exploration costs and development costs of $2.6 billion by total reserve extensions and discoveries of 182 MMBoe. This calculation does not include the future development costs required for the development of proved undeveloped reserves.

Reserve Replacement Ratio

Drill-Bit F&D Cost

4Q14 Earnings€¦ · CXO 4Q14 HZ WELL . Acreage Position ~365,000 gross (255,000 net) acres ....

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