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 NEW MEXICO Delivering industry-leading well results 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
WTI Oil Price ($/Bbl) Dynamics of U.S. Oil Production, Price and Rig Count $160 $140 $120 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 1,800 1,600 1,400 $100 $80 1,200 1,000 800 Oil Rig Count $60 600 $40 $20 U.S. Oil Production (YoY % Growth) 400 200-0.2% -1.5% 7.1% 2.2% 3.3% 14.6% 14.9% 15.5% $0 2007 2008 2009 2010 2011 2012 2013 2014 2015 Oil Price ($/Bbl) U.S. Oil Rig Count 0 Source: U.S. oil rig count data from Baker Hughes. U.S. Oil production annual growth from EIA. 4
Proven Strategy Endures Cycles Invest in High Quality Assets Deliver Measured Growth 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 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 Keep a Strong Balance Sheet Maintaining financial strength and liquidity a top priority Exited 2014 at 1.4x debt-to-ebitdax 1 Execute a Disciplined Capital Program Disciplined capital program with flexibility Strong hedge position 1 EBITDAX 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
Production (MMBoe) Track Record of Measured Growth 2014 Production Growth 22% Year-over-Year 45 40 Track Record of Measured Growth, Prudent Financial Management 40.9 4.0x 3.5x 2007-2014 Production CAGR 35% 35 30 25 20 15 10 5 5 Avg. FYE Debt-to-EBITDAX 1 : 1.8x 7.1 10.9 15.6 23.6 29.8 33.6 3.0x 2.5x 2.0x 1.5x 1.0x 0.5x FYE Debt-to-EBITDAX 1 0 2007 2008 2009 2010 2011 2012 2013 2014 Production (MMBoe) FYE Debt-to-EBITDAX 1 0.0x 1 EBITDAX is a non-gaap measure. See appendix for reconciliation to GAAP measure. 6
Northern Delaware Basin Acreage Position ~365,000 gross (255,000 net) acres Current Rig Count 13 Horizontal Rigs EDDY LEA 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 2 nd Bone Spring CULBERSON LOVING CXO ACRE AG E CXO 4Q14 HZ W ELL Acreage as of December 31, 2014. 7
Capturing Significant Resource NORTHERN DELAWARE BASIN Deep Inventory of Identified Horizontal Locations Formation Well Count 1 Avg. Peak Rate (Boepd) 30-Day (% Oil) 24-Hour Identified Locations Wells per Section Brushy Canyon 13 623 (83%) 942 700 4 Avalon Shale 59 721 (46%) 1,279 1,500 4 to 6 1 st Bone Spring 13 492 (71%) 967 1,400 4 2 nd Bone Spring 226 918 (76%) 1,442 3,200 4 to 6 3 rd Bone Spring 56 663 (85%) 1,088 1,400 4 Wolfcamp Shale 15 768 (43%) 1,232 1,600 4 Concho s 365,000 gross acres are prospective for six zones with downspacing potential 1 Wells 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 Controlling Costs While Increasing Completion Intensity 18% Increase in Avg. Peak 30-Day Rates FY14 vs. FY13 1,473 1,315 1,187 1,133 +40% 936 672 728 795 Well Count Avg. Lateral Length 2011 2012 2013 2014 Avg. Peak 30-Day (Boepd) 56 4,008 75 4,246 Avg. Peak 24-Hr (Boepd) 106 4,291 146 4,777 2013 2014 Cost/Treated Lateral Foot ($/ft) Proppant/Treated Lateral Foot 9
Optimizing Completions and Improving Recoveries 2 nd Bone Spring NORTHERN DELAWARE BASIN Optimizing Completions Enhanced Completion vs. Base Completion Avg. Stages/Well Avg. Proppant/Well 160 30%+ 80%+ 140 Base Enhanced Base Enhanced Completion Enhanced Avg. Base Avg. Maximizing Returns Count 49 139 Well Cost ($MM) $6.5 - $7.0 $5.5 - $6.0 ROR $60/$3.50** 50% - 60% 20% - 30% **Assumes no service cost reductions from YE14 Avg. Cumulative Production 1 120 100 80 60 40 20 0 0 30 60 90 120 150 180 Days Base Avg. 75% Increase Enhanced Avg. 1 Production data normalized for a 4,300 lateral. 10
Southern Delaware Basin Acreage Position ~275,000 gross (170,000 net) acres Current Rig Count 4 Horizontal Rigs LOVING WARD Outstanding well results driven by enhanced geologic model and completion design Added 11 new horizontal wells with at least 30 days of production data in 4Q14 Avg. lateral length: 6,706 Avg. peak 30-day rate: 1,271 Boepd (78% oil) Avg. peak 24-hour rate: 1,590 Boepd REEVES 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 CXO ACRE AG E CXO 4Q14 HZ W ELL Acreage as of December 31, 2014. 11
Midland Basin Horizontal Core Acreage Position ~200,000 gross (110,000 net) acres ANDREWS MARTIN 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 Current Rig Count 3 Horizontal Rigs GLASSCOCK Avg. peak 30-day rate: 846 Boepd (82% oil) Avg. peak 24-hour rate: 1,077 Boepd ECTOR MIDLAND 2015 focus: Increasing average lateral length and optimizing well spacing and completion design Deep Inventory of Identified Horizontal Locations CRANE UPTON Formation Spraberry Identified Locations 550 Wells per Section 4 Avg. Lateral Length 1.0-1.5 mile REAGAN Upper Wolfcamp 1,150 4 1.0-1.5 mile Lower Wolfcamp 400 4 1.0-1.5 mile CXO ACRE AG E CXO 4Q14 HZ W ELL 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 Current Rig Count 2 Horizontal Rigs CHAVES CHAVES 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 Added 13 new horizontal wells with at least 30 days of production data in 4Q14 Avg. peak 30-day rate: 408 Boepd (83% oil) EDDY EDDY LEA LEA Avg. peak 24-hour rate: 585 Boepd Avg. well cost: $3 MM to $4 MM 2015 focus: Horizontal development drilling and optimizing completion design CXO ACRE AG E CXO 4Q14 HZ W ELL Acreage as of December 31, 2014. 13
Strong Financial Position with Capital Flexibility Returns-Based, Disciplined Capital Program for 2015 Preserving financial strength and liquidity a high priority 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 $1.8 BN for drilling and completions $200 MM for facilities, midstream and other Flexibility to adjust drilling and capital programs 2015 hedge position covers ~55% anticipated oil production at $84.15/Bbl 1 2015 Drilling & Completion Capital Program 17% 11% 72% 2015 D&C Program $1.8 BN 95% Operated 90% Horizontal 1Q15 Production Guidance: 127-131 MBoepd Delaware Basin Midland Basin New Mexico Shelf 1 Based on 2015 production guidance midpoint. 14
Key Takeaways Proven strategy, quality assets and experienced team to weather commodity price cycles Service costs adjusting to lower commodity prices Optimizing drilling and completion techniques, improving resource recovery and returns Maintaining financial strength is a top priority Executing a returns-based, disciplined capital program with operational flexibility 15
Appendix
2015 Operational & Financial Outlook (UPDATED AS OF FEBRUARY 25, 2015) Production Year-over-year growth 16% - 20% Oil mix 63% - 65% Price realizations, excluding commodity derivatives (% of NYMEX) Crude oil (per Bbl) 90% - 93% Natural gas (per Mcf) 100% - 120% Operating costs and expenses ($/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 1Q15 Outlook Production: 127-131 MBoepd Non-cash $10 Income tax rate (%) 38% Current taxes ($ MM) $40 - $50 Capital expenditures ($ BN) $2.0 17
Hedge Position (UPDATED AS OF FEBRUARY 25, 2015) 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. 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 Years Ended December 31, December 31, (in thousands) 2014 2013 2014 2013 2012 2011 2010 2009 2008 2007 Net Income (loss) $ 129,896 $ 105,789 $ 538,175 $ 251,003 $ 431,689 $ 548,137 $ 204,370 $ (9,802) $ 278,702 $ 25,360 Exploration and abandonments 214,176 71,752 284,821 109,549 39,840 11,394 10,130 10,632 37,617 29,097 Depreciation, depletion and amortization 264,138 214,833 979,740 772,608 575,128 400,022 211,487 162,975 95,240 49,262 Accretion of discount on asset retirement obligations 1,910 1,637 7,072 6,047 4,187 2,444 1,079 690 510 296 Impairments of long-lived assets 431,675-447,151 65,375-439 11,614 7,880 8,382 4,777 Non-cash stock-based compensation 12,458 9,800 47,130 35,078 29,872 19,271 12,931 9,040 5,223 3,841 Bad debt expense - - - - - - 870 (1,035) 2,905 - Ineffective portion of cash flow hedges - - - - - - - - (1,336) 821 (Gain) loss on derivatives not designated as hedges (765,010) (33,651) (890,917) 123,652 (127,443) 23,350 87,325 156,857 (249,870) 20,274 Cash receipts from (payments on) derivatives not designated as hedges 98,157 5,343 71,983 (32,341) 23,536 (84,854) (13,824) 82,416 (6,354) 1,815 (Gain) loss on disposition of assets, net 611 (449) 9,308 1,268 372 1,139 58 114 (777) (368) Interest expense 52,537 56,401 216,661 218,581 182,705 118,360 60,087 28,292 29,039 36,042 Loss on extinguishment of debt - - 4,316 28,616 - - - - - - Income tax expense (benefit) from continuing operations 69,032 32,214 317,785 118,237 251,041 261,800 101,613 (28,890) 148,230 8,673 Discontinued operations - - - (12,081) 64,701 (26,343) 55,254 56,039 53,792 37,502 EBITDAX $ 509,580 $ 463,669 $ 2,033,225 $ 1,685,592 $ 1,475,628 $ 1,275,159 $ 742,994 $ 475,208 $ 401,303 $ 217,392 19