Investor Presentation
November 2019
Investor Presentation November 2019 Forward-Looking Statements and - - PowerPoint PPT Presentation
Investor Presentation November 2019 Forward-Looking Statements and Other Disclaimers These materials and the accompanying oral presentation contain forward -looking statements within the meaning of Section 27A of the Securities Act of 1933,
November 2019
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These materials and the accompanying oral presentation contain “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements, other than statements of historical fact, included in this presentation that address activities, events or developments that Concho Resources Inc. (the “Company” or “Concho”) expects, believes
“positioned,” “plan,” “will,” “guidance,” ”maximize,” “outlook,” “goal,” “strategy,” “target,” or other similar expressions, as well as predicted or illustrative rates of return (“ROR”), that convey the uncertainty of future events or
based on certain assumptions and analyses made by the Company based on management’s experience, expectations and perception of historical trends, current conditions, current plans, anticipated future developments, expected financings 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 risk factors and other information discussed or referenced in the Company’s most recent Annual Report on Form 10-K and other filings with the Securities and Exchange Commission (the “SEC”). 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. Information on Concho’s website, including information referenced directly herein such as the Climate Risk Report, is not part of this presentation. These other materials are subject to additional cautionary statements regarding risks and forward looking information. To supplement the presentation of the Company’s financial results prepared in accordance with U.S. generally accepted accounting principles (“GAAP”), this presentation contains certain financial measures that are not prepared in accordance with GAAP, including operating cash flow before working capital changes. See the appendix for a description and reconciliation of the non-GAAP measure presented in this presentation to the most directly comparable financial measure calculated in accordance with GAAP. This presentation also contains the non-GAAP term free cash flow, or FCF. Free cash flow is cash flow provided by operating activities in excess of cash flow used in investing activities for additions to oil and gas properties. The Company believes that free cash flow is useful to investors as it provides measures to compare cash provided by operating activities and exploration and development costs across periods on a consistent basis. For future periods, the Company is unable to provide a reconciliation of free cash flow to the most comparable GAAP financial measure because the information needed to reconcile this measure is dependent on future events, many of which are outside management's control. Additionally, estimating free cash flow to provide a meaningful reconciliation consistent with the Company's accounting policies for future periods is extremely difficult and requires a level
assumptions noted above and herein. The 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),
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, 2018 are estimated utilizing SEC reserve recognition standards and pricing assumptions based on the trailing 12-month average first-day-of-the- month prices of $62.04 per Bbl of oil and $3.10 per MMBtu of natural gas. Cautionary Statement Regarding Production Forecasts and Other Matters Concho’s production forecasts and expectations for future periods and statements regarding drilling inventory and rate-of-return (ROR) 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 or other factors that are beyond Concho’s control.
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CXO acreage as of December 31, 2018, pro forma for transactions announced to date.
TX NM
DELAWARE BASIN MIDLAND BASIN CXO Acreage
Leadership Position in the Permian Basin
860,000 gross (570,000 net) acres
Well Positioned to Deliver Growth & Returns Our Strategy
› Building a great team › Investing in high-margin assets › Generating high-quality returns › Maintaining a strong financial position › High-quality asset portfolio
Midland & Delaware Basins
› Driving cost savings and efficiencies › Free cash flow outlook for 2020 supports return of capital › Commitment to financial discipline
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Disciplined investment & cost management
Delivering On Priorities
Consistent execution Highlight asset quality
Solid operational quarter Strong financial performance Strategic portfolio management Increasing shareholder returns
› Production of 330 MBoepd above high end of guidance › ~20% well cost reduction exceeds 4Q19 target › Controllable cash costs 3% lower y/y › Generated excess cash flow › New Mexico Shelf sale › Accelerates value for legacy assets & improves cost structure › Board authorized initiation of $1.5bn share repurchase program › Shelf sale proceeds jumpstart repurchases
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CXO acreage as of December 31, 2018, pro forma for announced transactions. 4Q19e production guidance Pre-Shelf Sale includes a full quarter of production volumes for the New Mexico Shelf; Post-Shelf Sale volumes based on November 1, 2019 close date and therefore include one month of production volumes for the New Mexico Shelf.
High-Quality Asset Base
CXO Acreage 3Q19 Well
Production Above High End of Guidance
185 206 3Q18 3Q19 4Q19e 287 330 Oil (MBopd) Gas
Quarterly Volumes & 4Q19 Outlook (MBoepd)
Post-Shelf Sale 318-325 MBoepd (64% oil) Pre-Shelf Sale 334-341 MBoepd
Delaware Basin Midland Basin
Diversified portfolio provides capital allocation flexibility
› Federal lands represent 1/5th of total net acreage position › Permit ~1 year in advance of
› 3Q19 total production & oil production above high end of guidance › 4Q19 guidance includes expected impact from remaining spacing tests
prioritize wider spacing
Lower Costs Driving Excess Cash Flow
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Controllable Cash Costs
Cash Expenses excl. GP&T ($ per Boe)
LOE G&A Interest
Operating cash flow before working capital changes is a non-GAAP measure. See appendix for reconciliation to GAAP measure. E&D costs incurred is the sum of exploration and development costs incurred.
$7.46 $5.81 $5.80 $6.14 $6.26 $3.21 $3.02 $2.61 $2.38 $1.86 $3.95 $3.53 $1.99 $1.49 $1.45 $14.62 $12.36 $10.40 $10.02 $9.57 $9.00 2015 2016 2017 2018 3Q19 YE20 Target
Operating Cash Flow (“OCF”) OCF before working capital changes E&D costs incurred Realized price ($/Boe) 2Q19 3Q19 $37.68 $36.74 $779 $665 $668 $706 $785 $670 Financial Highlights ($mm)
Reducing Cash Costs
New Mexico Shelf sale reduces LOE & interest expense Focus on further reducing cash costs
› Deliver cost-efficient growth over the long term
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Free cash flow is a non-GAAP measure. See slide 2 for a definition.
3Q19 oil volumes above guidance
Capital Efficiency Margin Expansion Sustainable Growth Portfolio Management Financial Strength Shareholder Returns
› Develop fewer wells per project on less dense spacing & improve cycle times › Reduce well costs › $9/Boe YE20 controllable cash cost target › Improve price realizations › Sell non-core assets, accelerate value › Exercise capital discipline, maintain strong financial position & flexibility › Drive sustainable free cash flow growth › Increase shareholder returns with dividend growth & share repurchases Asset sale achieves leverage target 2020+ program to prioritize smaller projects with wider spacing to maximize returns Significantly reduced well costs in 3Q19 Controllable cash costs 3% lower y/y Diversifying oil sales beginning 4Q19 Generated excess cash flow in 3Q19 Authorized initiation of $1.5bn share repurchase program Sale of legacy New Mexico Shelf assets
Progress Strategic Focus
8 › Further optimize drilling, completion & facilities design › Increase use of in-basin sand & lower sand costs › Utilize new commercial water solutions › Pre-set casing › Improve wireline efficiency › Reduce drilling days & increase stages per day
Ongoing Plan for Further Reducing Well Costs
$977 $1,008 $808 $791 $1,387 $1,914 $1,278 $1,118
600 800 1000 1200 1400 1600 1800 2000FY18 1Q19 2Q19 3Q19 Delaware Basin Midland Basin $1,223 $1,355 $1,023 $955 Total Program
Reducing Well Costs
Basin-Level DC&E Costs ($ per foot)
1,170 1,250 1,375 4Q18 3Q19 2020e
Basin-level DC&E costs are for operated activity and include drilling, completion and wellsite equipment.
Completion Efficiency
Achieved cost targets Focus on continued improvement in 2020+
↓20% 3Q19 DC&E Costs
↓28% ↓13%
100 150 200 30 60 90 120 150 180
50 75 100 30 60 90 120 150 180
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Northern Delaware Basin Midland Basin
2018-2019 program 180-day cumulative oil production (MBo)
Industry Avg. Industry Avg. CXO Performance Days Days
Cumulative oil production normalized to 7,000’. Industry averages sourced from Enverus; Northern Delaware Basin industry data covers Lea & Eddy counties, NM.
Transitioning to wider spacing Transition to optimal spacing further along
CXO Wider Spacing CXO Closer Spacing
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2018-2019 Project Development
Wells per Reservoir vs. Spacing
Go-Forward Plan: Prioritize Returns
Optimizing Spacing – Illustrative Example
1H19 2018
More suitable for low/volatile commodity price environment Enables resilient, consistent development program Supports sustainable
growth # Wells per Reservoir per Mile-Wide Section ROR Multiple decades
this spacing
% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% 110% 120% 130% $- $10 $20 $30 $404 6 8 10 12 16
NPV per Section
2H19 Dominator
# of Wells per Reservoir Distance Between Wells More Less Closer Wider
2020+ Testing to
program ROR Focus 2018-2019
$0.3 $0.8 $0.4 $1.3 2016 2017 2018 2019e
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Accelerates value from legacy asset Focuses portfolio while maintaining leading Permian resource depth
Improves cash cost structure
~35% of total operated wells)
Achieves debt reduction target & increases returns to shareholders
New Mexico Shelf Asset Sale Transaction Summary
Transaction closed $925mm purchase price (all cash consideration) New Mexico Shelf
CXO operated wells)
Track Record of Portfolio Management
Asset & Infrastructure Monetization Proceeds ($bn)
Total proceeds $2.8bn
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Capital Program Strengthen Balance Sheet Additional Returns to Shareholders Portfolio Enhancement Cash Flow Priorities Free Cash Flow Opportunities
Achieved debt reduction target Additional returns as excess cash materializes
Dividend
Fund with cash flow from
Fund with free cash to maximize returns
Capital Allocation Framework Allocation of Asset Sale Proceeds
Sources ~60% ~40% Uses
Share repurchase
Board Authorizes Initiation of $1.5bn Share Repurchase Program
› Initial share repurchase authorization › Asset sale proceeds jumpstart repurchase; returning ~40% of sale proceeds
Debt reduction Achieved debt reduction target by paying down revolver
13 › Plan around conservative commodity prices › Deliver low double-digit oil production growth › Generate FCF <$50/Bbl WTI $50/Bbl WTI >$50/Bbl WTI › Generate robust FCF › Increase capital returns to shareholders › Financial strength provides flexibility
Capital Allocation Strategy FCF Potential Post Shelf Sale
› Run a steady program with measured rig adds over course of the year › 2020+ program to prioritize smaller projects with wider spacing to maximize returns
$50/Bbl WTI $60/Bbl WTI
~$750 ~$350
2020 FCF Outlook ($mm)
FCF Outlook Post New Mexico Shelf Sale
2020 production growth pro forma for New Mexico Shelf sale.
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Horizontal Wells Drilled by Zone (Gross Operated)
Delaware Basin
~5,000’
Midland Basin
~3,000’
Multiple decades of inventory
Formation 2009 - 2019 Well Count 2018 - YTD19 Brushy Canyon 23
148 29 1st Bone Spring 22 7 2nd Bone Spring 393 32 3rd Bone Spring 180 42 Wolfcamp Sands 52 39 Wolfcamp A 320 113 Wolfcamp B 33 22 Wolfcamp C 9 5 Wolfcamp D 38 13 Total 1,218 302 Formation 2009 - 2019 Well Count 2018 - YTD19 Middle Spraberry 46 33 Jo Mill 8 8 Lower Spraberry 143 93 Wolfcamp A 123 23 Wolfcamp B 126 47 Wolfcamp C 9 6 Wolfcamp D 3 3 Total 458 213
100 150 200 250 30 60 90 120 150 180 Start of '19 4Q19 Target
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Generating Strong Well Performance
180-day Cumulative Oil Production (MBo)
Days CXO Wider Spacing CXO Closer Spacing Industry Avg.
2018-2019 Activity
$1,390
Reducing Well Costs
DC&E Costs ($ per foot)
Cumulative oil production normalized to 7,000’. Industry average sourced from Enverus; industry data covers Lea County, NM. Northern Delaware Basin Wolfcamp A DC&E costs are for operated activity and include drilling, completion and wellsite equipment.
17% 44% 9% 30%
What’s driving the savings?
Drilling Completion Sand Water % of Reduction Target ↓18%+
(prior ↓12%+)
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Top 100 Wells in the Permian Basin by Six Month Cumulative Oil Production
2 4 6 8 10 12 14 16 18 20
Well Count
Source: IHS Enerdeq as of October 15, 2019. Permian wells with production start date January 2017 through March 2019. Peers include APA, CVX, DVN, EOG, FANG, OXY, PE, PXD, QEP, XEC and XOM
2017-2019 Wells Put on Production
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Reduce Flaring Expand Water Recycling Manage Climate Risk
↓50% 2016-2018 Asset-Wide Focus Published Inaugural Report
Available at www.concho.com/corporate-responsibility
Source: Bernstein Research dated July 19, 2019. Peers include APA, CDEV, CVX, FANG, ECA, Endeavor, EOG, NBL, OXY, PE, PXD, WPX, XEC and XOM.
Gas Capture Performance
Texas Permian Basin % Wellhead Gas Flared/Vented for December 2018
20% 14% 9% 9% 6% 5% 4% 3% 3% 2% 2% 1% 1% 1% 1% Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 Peer 6 Peer 7 Peer 8 Peer 9 Peer 10 Peer 11 Peer 12 Peer 13 Peer 14
Non-GAAP Reconciliation 20
The Company provides operating cash flow (“OCF”) before working capital changes, which is a non-GAAP financial measure. OCF before working capital changes represents net cash provided by operating activities as determined under GAAP without regard to changes in operating assets and liabilities, net of acquisitions and dispositions as determined in accordance with GAAP. The Company believes OCF before working capital changes is an accepted measure of an oil and natural gas company’s ability to generate cash used to fund development and acquisition activities and service debt or pay dividends. This non-GAAP measure should not be considered as an alternative to, or more meaningful than, net cash provided by
The following table provides a reconciliation from the GAAP measure of net cash provided by operating activities to OCF before working capital changes: Net cash provided by operating activities $ 665 $ 779 Changes in cash due to changes in operating assets and liabilities: Accounts receivable 52 (144) Prepaid costs and other 5 5 Inventory (1) (1) Accounts payable (11) 6 Revenue payable 25 3 Other current liabilities (29) 20 Total working capital changes 41 (111) Operating cash flow before working capital changes $ 706 $ 668 (in millions) Three Months Ended September 30, Three Months Ended June 30, 2019 2019
59 74 99 85 4Q18 Exit 1Q19 Exit 2Q19 Exit 3Q19 Exit
Activity Overview
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Count
YTD 2019 Activity – Well Counts YTD 2019 Activity – Drilling Rigs & Frac Crews Inventory of Wells Waiting on Completion
Gross Operated
34 33 26 Total Gross Number of Wells Drilled Number of Wells Completed Number of Wells Put on Production Delaware Basin 251 186 210 Midland Basin 120 129 152 Total 371 315 362 Gross Operated Number of Wells Drilled Number of Wells Completed Number of Wells Put on Production Delaware Basin 116 118 127 Midland Basin 97 107 124 Total 213 225 251 Net Operated Number of Wells Drilled Number of Wells Completed Number of Wells Put on Production Delaware Basin 91 96 100 Midland Basin 78 89 103 Total 169 185 203
79.3% 82.1% 80.8% Guidance 2H19 Avg. Rig Count 18 FY19 Gross Operated Activity (# wells) Drilling 270-290 Completing 270-290 Put on Production 330-350 19 Total 1Q19 2Q19 3Q19
33 26 19
8 8 7
Updated as of October 29, 2019 22
1These oil derivative contracts are settled based on the New York Mercantile Exchange (“NYMEX”) – West Texas Intermediate ("WTI") calendar-month average futures price. 2These oil derivative contracts are settled based on the Brent calendar-month average futures price. 3The basis differential price is between Midland – WTI and Cushing – WTI. The majority of these contracts are settled on a calendar-month basis, while certain contracts assumed in connection with the RSP acquisition are settled on a trading-month basis. 4The natural gas derivative contracts are settled based on the NYMEX – Henry Hub last trading day futures price. 5The basis differential price is between NYMEX – Henry Hub and El Paso Permian. 6The basis differential price is between NYMEX – Henry Hub and WAHA.
2019 2021 4Q 1Q 2Q 3Q 4Q Total Total Oil Price Swaps - WTI1: Volume (MBbl) 13,469 12,517 11,075 10,067 9,586 43,245 17,517 Price per Bbl 56.46 $ 57.01 $ 56.88 $ 56.93 $ 57.01 $ 56.96 $ 54.30 $ Oil Price Swaps - Brent2: Volume (MBbl) 2,178 1,456 1,456 1,472 1,472 5,856
62.08 $ 60.12 $ 60.12 $ 60.12 $ 60.12 $ 60.12 $
Oil Costless Collars1: Volume (MBbl) 1,058
62.95 $
Floor price per Bbl 55.43 $
Oil Basis Swaps3: Volume (MBbl) 16,053 14,651 10,647 10,580 10,120 45,998 16,790 Price per Bbl (2.19) $ (0.46) $ (0.65) $ (0.66) $ (0.71) $ (0.60) $ 0.60 $ Natural Gas Price Swaps - HH4: Volume (BBtu) 37,750 35,024 32,313 30,038 28,498 125,873 36,500 Price per MMBtu 2.51 $ 2.46 $ 2.46 $ 2.47 $ 2.47 $ 2.47 $ 2.52 $ Natural Gas Basis Swaps - HH/EPP5: Volume (BBtu) 28,820 25,770 23,960 22,080 21,770 93,580 36,500 Price per MMBtu (0.76) $ (1.06) $ (1.07) $ (1.07) $ (1.07) $ (1.07) $ (0.66) $ Natural Gas Basis Swaps - HH/WAHA6: Volume (BBtu) 9,200 7,280 7,280 7,360 7,360 29,280 10,950 Price per MMBtu (0.77) $ (1.10) $ (1.10) $ (1.10) $ (1.10) $ (1.10) $ (0.66) $ 2020
Updated as of October 29, 2019
4Q19 Guidance
Sale): 318 MBoepd-325 MBoepd › 64% oil mix
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Note: The Company’s capital program guidance excludes acquisitions. All guidance is subject to change without notice depending upon a number of factors, including commodity prices, industry conditions and other factors that are beyond the Company’s control.
Production Total production growth 23% - 27% Oil production growth 22% - 26% Price realizations, excluding commodity derivatives Oil differential (per Bbl) (Relative to NYMEX - WTI; excludes Midland-Cushing basis differential) ($2.00) - ($2.50) Natural gas (per Mcf) (% of NYMEX - Henry Hub) 60% - 80% Operating costs and expenses ($ per Boe, unless noted) Lease operating expense and workover costs $6.00 - $6.50 Gathering, processing and transportation $0.85 - $0.95 Oil and natural gas taxes (% of oil & natural gas revenues) General and administrative ("G&A") expense: Cash G&A expense $2.20 - $2.40 Non-cash stock-based compensation $0.70 - $0.90 DD&A $15.75 - $16.25 Cash exploration and other $0.25 - $0.50 Interest expense ($mm): Cash $200 - $220 Non-cash Income tax rate (%) Capital program ($bn) $2.8 - $3.0 2019 Guidance 7.60% $6 22%