Resilient Portfolio Delivers Cash Returns February 2019 Exhibit 99.1
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. Anadarko believes that its expectations are based on reasonable assumptions. No assurance, however, can be given that such expectations will prove to have been correct. A number of factors could cause actual results to differ materially from the projections, anticipated results, or other expectations expressed in this presentation, including Anadarko’s ability to successfully execute upon its capital program; to efficiently identify and deploy capital resource; to meet financial and operating guidance and achieve the production growth, cash flow levels and returns identified in this presentation; to successfully complete the transaction identified in this presentation and realize the expected benefits; to timely complete and commercially operate the projects, infrastructure and drilling prospects identified in this presentation; to successfully drill, complete, test and produce the wells identified in this presentation; to successfully complete the share-repurchase and debt-reduction programs; evaluate dividend increases; to achieve further drilling cost reductions, efficiencies and market improvements; to successfully plan, secure additional government and partner approvals, enter into long-term sales contracts, take FID and the timing thereof, finance, build, achieve expected cost savings, and operate the necessary infrastructure and LNG park in Mozambique. See “Risk Factors” in the company’s 2017 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other public filings and press releases. Anadarko undertakes no obligation to publicly update or revise any forward-looking statements. Please see the appendix slides or our website at www.anadarko.com under “Investor Relations” for reconciliations of the differences between any non-GAAP financial measure used in this presentation and the most directly comparable GAAP financial measures. Cautionary Note to Investors - The U.S. Securities and Exchange Commission (SEC) permits oil and gas companies, in their filings with the SEC, to disclose only proved, probable and possible reserves that meet the SEC’s definitions for such terms. We may use terms in this presentation, such as “resources,” “net resources,” “net recoverable resources,” and similar terms that the SEC’s guidelines strictly prohibit us from including in filings with the SEC. These quantities may not constitute "reserves" within the meaning of the SEC’s rules. EUR estimates and drilling locations have not been risked by our management. Actual quantities that may be ultimately recovered from our interests may differ substantially. Factors affecting ultimate recovery include the scope of our ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling risks, lease expirations, transportation constraints, regulatory approvals and other factors; and our actual drilling results, including geological and mechanical factors affecting recovery rates. Such estimates may change significantly as development of our oil and gas assets provide additional data. U.S. Investors are urged to consider closely the oil and gas disclosures in our Form 10-K for the year ended December 31, 2017, File No. 001-08968, available from us at www.anadarko.com or by writing to us at: Anadarko Petroleum Corporation, 1201 Lake Robbins Drive, The Woodlands, Texas 77380 Attn: Investor Relations. You can also obtain this form from the SEC by calling 1-800-SEC-0330. 2 Cautionary Language
COMPLEMENTARY AND DIVERSIFIED PORTFOLIO Anadarko’s Investment Philosophy * Expectation based on $60/Bbl WTI and $60/Bbl Brent, and $3/Mcf HH Note: See Appendix for non-GAAP financial measures Within Adjusted DCF at $50 per Bbl Oil Price Environment Significant Adjusted Free Cash Flow ~$1.4B at $60/$60/$3* INVEST GENERATE Attractive Cash Returns Buybacks, Debt Reduction, & Dividends DELIVER U.S. Onshore Scalable, Short-Cycle Investments Midstream MLP Predictable Cash Source Mozambique LNG Sustainable Future Cash Flow Conventional Oil Stable, High-Margin Cash Flow
SHARE REPURCHASES$3.75B DEBT REDUCTIONS$0.60B ANNUALIZED DIVIDEND~$600MM Committed to Ongoing Capital Returns 1 Includes proceeds used to repurchase shares, to reduce and retire debt, and to fund dividend payments 2 Includes 12/31/18 consolidated cash balance and ~$2.0 billion of expected cash proceeds from the sale of midstream assets 3 Cash returns are defined as cash proceeds used to repurchase shares and fund dividend payments. Amounts in above graph represent cash returns as a percentage of 12/31/17 market capitalization. 4 Peer group Includes: APA, CHK, COP, CVX, DVN, EOG, HES, MRO, NBL, OXY, PXD COMPLETED YE 2018 TWO-YEAR CAPITAL RETURNS1: ~$5.0B $1.25B $1.40B Reviewed Quarterly REMAINING PROGRAMS AVAILABLE CASH2: ~$3.3B PEER-LEADING CASH RETURNS3 TO SHAREHOLDERS
Discipline Drives Free Cash Flow Yield 1 Assumes a $50/Bbl for WTI and Brent, and $3/Mcf HH 2 S&P FCF Yield Calculated as the weighted average S&P 500 TTM FCF divided by weighted-average market capitalization as of 12/31/2018; APC Adjusted FCF Yield Calculated as the expected APC Adjusted FCF divided by APC market capitalization of $21.7B as of 12/31/2018 Note: See Appendix for non-GAAP financial measures and Definitions FIXED CAPITAL PROGRAM AT A $50 GLOBAL OIL PRICE1 2019E ~6% FCF YIELD ~13% FCF YIELD ~$1.4B Adj. FCF ~$2.9B Adj. FCF ~4% FCF YIELD S&P 500 FCF YIELD
Capital Efficiency Lowers Free Cash Flow Breakeven BREAKEVEN ENHANCEMENT DRIVERS RETURNS FOCUS Leverage Premium Oil Markets Transition Delaware Basin to FCF Harvest FCF From Conventional Oil Exercise Efficient Capital Allocation Share Repurchases Debt Reductions Dividend Increases 1 2 3 ~$54 ~$49 ~$45 ALL-IN CASH FLOW BREAK-EVEN OIL PRICE1 AFTER DIVIDEND2 2019E 2020E 2021E 1 Breakeven is defined as the WTI and Brent oil price that generates APC adjusted discretionary cash flow equal to APC capital investment plus annual dividend 2 Assumes current annualized dividend of ~$600 million Note: See Appendix for non-GAAP financial measures
Leverage to Premium Oil Markets ~70% of Oil Portfolio Benefits from Premium Pricing OIL PRICING BASIS1 1 Oil pricing basis is for APC net oil volume, except for the Delaware Basin which is for APC net operated volume, and is pro forma for the completion of the Cactus II pipeline and related infrastructure 2 Premium Coastal pricing includes the following crudes; MEH, LLS, HLS, Brent, and Poseidon 100% BRENT 100% BRENT 100% WTI 100% Premium Coastal ROCKIES DELAWARE BASIN1 GULF OF MEXICO ALGERIA GHANA 100% Premium Coastal 2
Balance Sheet Strength 2018 CONSOLIDATED ADJ. EBITDAX: $7.4B ANADARKO 2018E Adj. EBITDAX $6.2B Pro Forma Debt1 $10.7B Strong Investment-Grade Profile: E&P Sector Targeting BBB+ & Baa1 Pro Forma Debt-to-EBITDA ~1.75x WES 2018E Adj. EBITDA2 $1.2B Pro Forma Debt3 $6.8B Strong Investment-Grade Profile: Midstream Sector Separate Capital Structure 1 12/31/18 debt balance pro forma for the assumed completion of announced plans to retire ~$900 million of debt maturing in 2019 2 Represents mid-point of WES 2018 Adjusted EBITDA guidance 3 12/31/18 pro forma debt balance includes an incremental adjustment of $2.0 billion for the cash consideration portion of the midstream asset transaction with WES in 1Q19 Note: See Appendix for non-GAAP financial measures
MLP Simplification Enhances Cash Delivery to APC Cumulative Cash Returned ~$8.0B THROUGH 2018 Marketable Securities1 ~$8.0B ~$2.0B Cash Proceeds ~$0.6B Pro Forma Annualized Distributions 1 Market price as of 12/31/18 and pro forma for the close of the midstream simplification transaction in 1Q19 2019E Midstream Capital Relief & Enhanced Liquidity
Portfolio Delivers Near-Term Free Cash Flow U.S. ONSHORE CONVENTIONAL OIL MIDSTREAM MLP Stable Annual Distribution Operational Control Oil-Levered Portfolio Access to Premium Markets Short-Cycle Investments Infrastructure Advantaged
2019 Full-Year Expectations TOTALOIL RATE 260-270 410-435 MMBOEMBOPD SALES VOLUMES 1 Excludes the expected WES capital investments of $1.3 - $1.4 billion and any potential 2019 post-Mozambique FID capital investments * Based on $50/Bbl WTI and $50/Bbl Brent, and $3/Mcf HH Note: See Appendix for non-GAAP financial measures and Definitions $4,300 - $4,700 CAPITAL PROGRAM1 ($ MILLIONS) at $50/$50/$3* ~25% $4.3-$4.7 CFROIC ADJUSTED DCF ($BILLION) at $50/$50/$3*
Reduced U.S. Upstream Methane Intensity1 ~30% Continued enhancements to design & operation of low-emission facilities Visit Our Website to View Complete HSE & Sustainability Report and Multi-Year Scorecard Committed to Safe & Sustainable Operations VISION IMPROVEMENTS Increased Weighting of HSE Performance to 20% Employee Compensation Metric Incorporating Total Workforce & Severity Our highest priority is the safety of all employees, contractors & communities 1 Water and emission reductions are 2017 results compared to 2015 results Reduced U.S. Fresh Water Usage1 50+% Committed to sustainable water management practices Published Climate Change Risk Assessment November 2018
Premier U.S. Onshore Business WORLD-CLASS ASSETS Attractive Breakevens Decades of Inventory Midstream Advantaged 6+ BBOE NET RESOURCES FOCUS AREAS EMERGING RESOURCE DELAWARE BASIN RIGS ~10 CREWS ~5 OPERATED WELLS TO SALES 150+ CAPITAL ($MM) ~$1,400 DJ BASIN RIGS ~4 CREWS ~3 OPERATED WELLS TO SALES 250+ CAPITAL ($MM) ~$1,300 POWDER RIVER BASIN RIGS ~1 CREWS ~1 OPERATED APPRAISAL WELLS 10+ CAPITAL ($MM) ~$250 Appraising ~300,000 Gross Acres in Turner Oil Fairway DELAWARE BASIN DJ BASIN POWDER RIVER BASIN Note: All numbers are 2019 expectations Capital includes non-operated and non-drill capital, and excludes expected WES capital investments
CUM OIL (MBO) PRODUCTION MONTH CONTINUING TO ENHANCE WELL PRODUCTIVITY4 Operatorship Controls Development Pace and Strategy Foundational Infrastructure Largely Complete Expected to be Free Cash Flow Positive by YE 2020 Delaware Basin: Progressing Toward Scalable Development 1 8,000-foot lateral length 2 ~3 BBOE within the Wolfcamp-A, 1+ BBOE within additional intervals 3 Pro forma for the sale of midstream assets expected to close In 1Q19 4 Source: RSEG; Other operators include the top-10 companies based on cumulative well count since 2013 Top-Tier Position Net Acres ~240,000 Decades of Inventory Drilling Locations1 ~9,000 Stacked Oil Potential Net Resources2 4+ BBOE CULBERSON WARD WINKLER LOVING REEVES NEW MEXICO TEXAS IMPROVING ROCK & FLUID QUALITY WESTERN GAS OWNED MIDSTREAM INFRASTRUCTURE3 10 MILES APC ACREAGE: ~590,000 Gross Acres, 70% Operatorship Pipelines (Oil, Gas and Water) Oil Treating Facility Gas Plant Anadarko Other Operators INFRASTRUCTURE-ADVANTAGED ACREAGE
Market Current Oil Equity Pipeline3 Future Oil Equity Pipeline3 Current NGL Pipeline Houston/ Mt. Belvieu Corpus Christi Lone Star Plains Cactus II Enterprise Sand Hills BASIN TAKEAWAY SECURED Delaware Basin: Maximizing Product Delivery & Price Discovery 1 Expected capacities at year end 2019. Pro forma for the sale of midstream assets, expected to close In 1Q19, all infrastructure will be owned by WES. 2 Pro forma for the completion of the Cactus II pipeline and related infrastructure 3 Equity interests are owned by WES FIRM AGREEMENTS Product % Operated Volumes Oil 50% Today 100% Expected2 Gas 80% NGL 100% INFRASTRUCTURE1 IN PLACE BY YE19 1.5 Bcf/d Gas Processing TANKLESS GATHERING Reduces Truck Traffic Improves Environmental Footprint Reduces Well Site Complexity ~90% OIL GATHERED ON PIPELINE 190+ MBOPD Oil Treating 800+ MBbl/d Water-Disposal
Delaware Basin: Silvertip Demonstrates Development Potential Avalon 1st Bone Spring 2nd Bone Spring 3rd Bone Spring Wolfcamp A Wolfcamp B SILVERTIP-A SPACING Future Potential Initial Silvertip-A Campaign 1 MILE REEVES LOVING WINKLER WARD APC Acreage 10 MILES NEW MEXICO TEXAS SILVERTIP AREA: 22 Contiguous Sections REMARKABLE SILVERTIP WELL RESULTS 2019 WOLFCAMP-A TYPE CURVE Cumulative Normalized Production Dry MBOE/1,000 Feet Days On Line WC-A Target 2 WC-A Target 3 WC-A Target 4 WC-A Target 1 3RD Bone Spring WC-A 2019 TC Oil ~60% Liquids ~80%
Delaware Basin: Wolfcamp-A Economics 1 Assumes full ethane recovery 2 Well cost reflects full pad development estimate and is equivalent to 2018 estimate of $8.0 million adjusted for increased lateral length 3 Based on $3/Mcf HH 4 Includes non-operated well locations 5 Does not include Wolfcamp-A WOLFCAMP-A TYPE WELL (52% WI, 40% NRI) EUR (MBOE)1 1,700+ Well Cost (MM)2 $8.5 BTAX ROR3 ~50% at $50/BO ~85% at $60/BO Location Inventory4 ~4,700 Lateral Length (ft.) 8,000 ~3 BBOE NET RESOURCES Months 1+ BBOE Net Resources in Additional Intervals5 950 - 1,400+ MBOE Well EUR1 50 - 70% Liquids Composition ~4,200 Mid-Lateral Length Locations 2019 Plan 90+% Extended Length Laterals 60+% Pad Development
DJ Basin: Competitive Advantages Improve Cash Flow Size of a Large-Cap Net Production (BOE/d) 250,000+ Royalty Advantage APC Mineral Sections 40% NPV10 Uplift1 10+ Years Inventory Drilling Locations2 ~3,000 OPPL Mt. Belvieu NGL HUB Cushing WTI HUB Conway NGL HUB Market Oil Equity Pipeline4,5 NGL Equity Pipeline5 NGL Pipeline Rail Option Texas Express St. James RAIL Front Range White Cliffs & Saddlehorn 1 Based on $50/Bbl WTI and $3/Mcf HH 2 8,000-foot lateral length 3 Expected by year-end 2019 4 Pro forma for the sale of midstream assets that is expected to close In 1Q19 5 WES owns an equity interest 5 MILES WESTERN GAS OWNED MIDSTREAM INFRASTRUCTURE4 APC Acreage APC Mineral Interest Pipelines (Oil and Gas) Oil Treating Facility Gas Plant DJ DEVELOPMENT AREA 400,000+ net acres Oil Treating Online ~155 MBOPD Gas Processing 1.5+ Bcf/d3 Latham I Plant Online by Mid-Year 2019 BASIN TAKEAWAY SECURED
DJ Basin: Development Economics DJ BASIN TYPE WELL (85% WI, 76% NRI) EUR (MBOE)1 750 Well Cost (MM)2,3 $3.4 BTAX ROR4 85+% at $50/BO 100+% at $60/BO Location Inventory5 ~3,000 Lateral Length (ft.) 8,000 ~2 BBOE NET RESOURCES 1 Assumes full ethane recovery 2 Full pad development estimate 3 Well cost equivalent to 2018 estimate of $2.7 million adjusted for increased lateral length and $0.2 million of development enhancements 4 Based on $3/Mcf HH 5 Includes only operated well locations
PRB: Strategically Built Position Competitive Basin Entry Consolidated Operating Position Stacked Pay Opportunities 5,000’+ Stacked Potential CONVERSE COUNTY 1 Producing wells prior to July 2018 normalized to mid-lateral length of 8,000 feet 2015 ANADARKO TURNER DISCOVERY WELLS 2,500-4,000 BOE/d (70-80% Oil) TURNER ACTIVITY - 24 HOUR IPs1 TURNER FAIRWAY APC Acreage APC Discovery Wells Industry Drilled Attractive Acquisition Metrics ~$2,500 per Acre POWDER RIVER BASIN 2014 2019 APC Discovered Southern Turner Fairway Validated Trend and Resource Potential Secured Top-Tier Leasehold Commenced Appraisal & Delineation Program 2,100-5,100 BOE/d (~50% Oil) 2,600-5,300 BOE/d (80-90% Oil)
Gulf of Mexico: Stable Cash Flow Delivery LOUISIANA HEIDELBERG MARCO POLO HOLSTEIN HORN MOUNTAIN MARLIN CONSTITUTION LUCIUS Three-Year Outlook Annual FCF1,2 (Billions) ~$1.2 Production (BOE/d) ~140,000 Annual Capital3 (Billions) ~$0.5 2019E OPERATED ACTIVITY PV10 Development Breakevens~$20/Bbl 30 MILES Operated Production Facilities 30-Mile Tieback Radius APC Working Interest Blocks 1 Based on $50/Bbl WTI and $3/Mcf HH 2 Represents asset-level free cash flow which is unburdened by corporate expenses and income tax 3 Excludes exploration capital Note: See Appendix for non-GAAP financial measures DRILLSHIPS 1+ Rigs ~5 Wells WELL ACTIVITY Lucius, North Hadrian, K2, Constellation PLATFORM RIGS 2 Rigs ~5 Wells WELL ACTIVITY Holstein, Horn Mountain BTAX ROR1~90% Margin1~$35/BOE
Algeria and Ghana: Brent Leveraged & Low Capital Intensity APC WI Block Unitized Field Boundary Oil Field Gas/Condensate Appraisal Area Export Pipeline BLOCK 404A BLOCK 208 HBNS CPF Ourhoud CPF El Merk CPF ALGERIA 2019E CAPITAL (Millions) ~$60 WEST CAPE THREE POINTS Mahogany Akasa Teak Jubilee Unit (27% PI) DEEPWATER TANO Ntomme Tweneboa Enyenra Wawa TEN Complex (19% PI) 20 MILES 32 KM GHANA 2019E CAPITAL (Millions) ~$140 2019E Margin1 ~$40 $/BOE 2019E Margin1 ~$30 $/BOE Three-Year Outlook Annual FCF1,2 (Billions) ~$0.8 Sales Volume (BOE/d) ~85,000 Annual Capital (Billions) ~$0.2 1 Based on $50/Bbl Brent and $3/Mcf HH 2 Represents asset-level free cash flow which is unburdened by corporate expenses and income tax Note: See Appendix for non-GAAP financial measures 10 MILES 16 KM Central Storage
Mozambique LNG: Significant Long-Term Cash Delivery 1 Total five-year net investment is post-FID and net of expected project finance drawdowns 2 Based on $60/Bbl Brent (real 2019 dollars) and assumes project financing OFFSHORE AREA 4 ILLUSTRATION NOT TO SCALE ANADARKO OFFSHORE AREA 1 Orca Tubarão Tubarão Tigre PROSPERIDADE GOLFINHO/ATUM AQUIFER LAND AVAILABLE FOR ONSHORE DEVELOPMENT AFUNGI LNG PARK 0 2.5 KILOMETERS MOF ~40 KILOMETERS LNG EXPORT JETTY APC WI Block Initial Development Natural-Gas Field RESETTLEMENT VILLAGE Area 1 Operator Area 4 Operator Shared Interest MOZAMBIQUE LNG Net Recoverable Resource750 MMBOE Liquefaction Capacity12.88 MTPA Competitive Onshore Costs$600/tonne GOLFINHO / ATUM 1ST TWO TRAINS LNG LNG Total Five-Year Net Investment1 ~$2.0B to ~$2.5B Expected Payback Period ~3.5 Years From First LNG2
Avg. Annual APC Cash Requirement ~$400MM to ~$500MM Mozambique LNG: Anticipated Funding & Accounting * Includes onshore facility, offshore wells and infrastructure, project support, contingency, and financing (premia, fees, and interest) costs INITIAL GOLFINHO/ATUM TWO-TRAIN DELIVERY ~$20B* GROSS PROJECT COSTS APC SHARE OF PROJECT FINANCE ~55% to ~65% ~$2.8B to ~$3.3B APC 26.5% WI Share ~$5.3B APC NET CASH REQUIREMENT ~$2B to ~$2.5B Drawn Over ~5-Year Project Construction Period Integrated LNG Project Model Maximizes Project Economics PROPORTIONATE CONSOLIDATION OF PROJECT DEBT, CAPEX, REVENUE & EXPENSE 24
DEVELOPMENT PLAN APPROVED1 Mozambique LNG: Line of Sight to FID LEGAL & CONTRACTUAL FRAMEWORK IN PROGRESS Anticipated 1H2019 FID 1 Initial Golfinho/Atum two-train development 2 All numbers are approximate 3 Subject to execution Note: See Glossary for formal names of companies with executed SPAs Post-FID Capital ~2/3 Project Financed Pre-FID 2019 Capital $200MM PROJECT FINANCING ONSHORE SITE PREPARATION OFFTAKE AGREEMENTS ~9.5 MTPA SPAs (MTPA)2 EXECUTED Tokyo Gas & Centrica 2.6 Shell 2.0 CNOOC 1.5 EdF 1.2 Tohoku 0.3 FINALIZED3 Two Additional SPAs 2.0
APPENDIX
Divested Sales-Volume Summary
Non-GAAP Financial Measures; Management Estimates & Assumptions This list of non-GAAP financial measure definitions and related reconciliations is intended to satisfy the requirements of Regulation G of the Securities Exchange Act of 1934, as amended. The Company undertakes no obligation to publicly update or revise any non-GAAP financial measure definitions or related reconciliation. Non-GAAP financial measures exclude certain amounts that are included in the corresponding financial measures determined in accordance with GAAP. The following slides include reconciliations of GAAP to non-GAAP financial measures and statements indicating why management believes the non-GAAP financial measures provide useful information for investors. This non-GAAP information should be considered by the reader in addition to, but not instead of, the financial statements prepared in accordance with GAAP. The non-GAAP financial information presented may be determined or calculated differently by other companies and may not be comparable to similarly titled measures. Non-GAAP financial measures provided in this presentation for specific asset areas are calculated using the same methodology as the consolidated measure. Corporate general and administrative expenses are included in consolidated Adjusted EBITDAX (Margin), but excluded from EBITDAX and EBITDA by asset area as these expenses are not considered an operating expense of the asset area. Corporate expenses and income taxes are included in consolidated FCF, but excluded from FCF by asset area as these items are not allocated to specific asset areas. Management has presented herein certain estimates about future performance, results, and financial position. Such estimates generally reflect current or explicitly assumed future commodity strip prices as well as management's assumptions about future drilling plans, performance, and production mix, among other factors. These forward-looking estimates are illustrative and are not intended to reflect the results we will achieve for the periods presented. Actual results may differ materially from the estimates presented herein. Management has also presented herein certain forward-looking non-GAAP financial measures, including Adjusted EBITDAX (Margin), EBITDAX, EBITDA, DCF, Adjusted DCF, FCF, and adjusted FCF. Due to the forward-looking nature of the aforementioned non-GAAP financial measures, management cannot reliably predict certain of the necessary components of the most directly comparable forward-looking GAAP measures, such as future impairments and future changes in working capital. Accordingly, the company is unable to present a quantitative reconciliation of such forward-looking non-GAAP financial measures to their most directly comparable forward-looking GAAP financial measures. Reconciling items in future periods could be significant.
Non-GAAP Financial Measures Adjusted EBITDAX (Margin) / Adjusted EBITDA (EBITDA) The Company defines Adjusted EBITDAX (Margin) as net income (loss) attributable to common stockholders before interest expense; income taxes; depreciation, depletion, and amortization (DD&A); exploration expense; gains (losses) on divestitures, net; impairments; total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives; restructuring charges; and (gains) losses on early extinguishment of debt. The Company’s definition of Adjusted EBITDAX (Margin) excludes gains (losses) on divestitures, net and exploration expense as they are not indicators of operating efficiency for a given reporting period. DD&A and impairments are excluded from Adjusted EBITDAX (Margin) as a measure of operating performance because capital expenditures are evaluated at the time capital costs are incurred. Adjusted EBITDAX (Margin) also excludes interest expense to allow for assessment of operating results without regard to Anadarko’s financing methods or capital structure. Finally, income tax expense (benefit) and total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives are excluded from Adjusted EBITDAX (Margin) because these items are not considered a measure of asset operating performance. For Midstream assets, the Company refers to this measure as EBITDA because exploration expense is not relevant. Management believes that the presentation of Adjusted EBITDAX (Margin) provides information useful in assessing the Company’s operating and financial performance across periods. Years Ended December 31, millions 2018 2017 Net income (loss) attributable to common stockholders (GAAP) $ 615 $ (456 ) Interest expense 947 932 Income tax expense (benefit) 733 (1,477 ) Depreciation, depletion and amortization 4,254 4,279 Exploration expense 459 2,535 (Gains) losses on divestitures, net (20 ) (674 ) Impairments 800 408 Total (gains) losses on derivatives, net, less net cash from settlement of commodity derivatives (407 ) 156 Restructuring charges 53 21 (Gains) Losses on early extinguishment of debt (2 ) 2 Consolidated Adjusted EBITDAX (Margin) (Non-GAAP) $ 7,432 $ 5,726 Total Barrels of Oil Equivalent (BOE) 243 245 Consolidated Adjusted EBITDAX (Margin) per BOE (Non-GAAP) $ 30.58 $ 23.37
Non-GAAP Financial Measures Discretionary Cash Flow from Operations (DCF) and Free Cash Flow (FCF) The Company defines DCF as net cash provided by (used in) operating activities before changes in accounts receivable; changes in accounts payable and other current liabilities; other items, net; and certain nonoperating and other excluded items. The Company defines FCF as DCF, less capital expenditures. Management believes that these measures are useful to management and investors as a measure of a company’s ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company’s performance from period to period. To assist in measuring the Company’s performance, management will also evaluate Anadarko on a deconsolidated basis, which excludes WES. Years Ended December 31, millions 2018 2017 Net cash provided by (used in) operating activities (GAAP) $ 5,929 $ 4,009 Add back Increase (decrease) in accounts receivable 211 147 (Increase) decrease in accounts payable and other current liabilities (348 ) 32 Other items, net 264 127 Certain nonoperating and other excluded items — 21 Discretionary cash flow from operations (Non-GAAP)* $ 6,056 $ 4,336 Less APC capital expenditures 5,007 4,344 WES capital expenditures 1,178 956 Free cash flow (Non-GAAP) $ (129 ) $ (964 ) *Includes $147 million current tax expense for the year ended December 31, 2017, related to asset monetizations.
Adjusted Discretionary Cash Flow from Operations (Adjusted DCF) and Adjusted Free Cash Flow (Adjusted FCF) The Company defines adjusted discretionary cash flow from operations as net cash provided by (used in) operating activities adjusted by changes in accounts receivable; changes in accounts payable and other current liabilities; other items; certain nonoperating and other excluded items; and Western Gas Partners, LP (WES)/Western Gas Equity Partners, LP (WGP) distributions to third parties. The Company defines Adjusted FCF as Adjusted DCF, less APC capital expenditures, which excludes WES. Management believes that these measures are useful to management and investors as a measure of a company’s ability to internally fund its capital expenditures and to service or incur additional debt. These measures eliminate the impact of certain items that management does not consider to be indicative of the Company’s performance from period to period. To assist in measuring the Company's performance, management will also evaluate Anadarko on a deconsolidated basis, which excludes WES. Non-GAAP Financial Measures *Includes $181 million of Powder River Basin acquisitions in 2018, of which $176 million was unbudgeted. Years Ended December 31, millions 2018 2017 Net cash provided by (used in) operating activities (GAAP) $ 5,929 $ 4,009 Adjusted by: Increase (decrease) in accounts receivable 211 147 (Increase) decrease in accounts payable and other current liabilities (348) 32 Other items, net 264 127 Certain nonoperating and other excluded items — 21 WES/WGP distributions to third parties (495) (444) Adjusted discretionary cash flow from operations (Non-GAAP)* $ 5,561 $ 3,892 Less APC capital expenditures* (excludes WES) 5,007 4,344 Adjusted free cash flow (Non-GAAP) $ 554 $ (452 )
Glossary of Abbreviations and Definitions ADJ: Adjusted APC: Anadarko Petroleum Corporation AVG: Average B: Billion Bbl: Barrel BBOE: Billion Barrels of Oil Equivalent BCF/d: Billion Cubic Feet per Day BO: Barrel of Oil BOE: Barrel of Oil Equivalent BOE/d: Barrel of Oil Equivalent per Day BTAX: Before Tax Centrica: Centrica LNG Company Ltd., a subsidiary of Centrica plc CFROIC*: Cash Flow Return on Invested Capital CNOOC: CNOOC Gas and Power Singapore Trading & Marketing Pte. Ltd. Corp: Corporate CPF: Centralized Production Facility CUM: Cumulative DCF: Discretionary Cash Flow DJ: Denver Julesburg E: Expected EdF: Électricité de France, S.A. E&P: Exploration and Production EBITDA: Earnings Before Interest, Tax, Depreciation, and Amortization EBITDAX: Earnings Before Interest, Tax, Depreciation, Amortization, and Exploration Expense EUR: Estimated Ultimate Recovery Expl: Exploration FCF: Free Cash Flow FID: Final Investment Decision Ft: Feet GAAP: Generally Accepted Accounting Principles GOM: Gulf of Mexico H: Half HBNS: Hassi Berkine Sud (South) HH: Henry Hub HLS: Heavy Louisiana Sweet HSE: Health, Safety, and Environment Int’l: International IP: Initial Production KM: Kilometers LLS: Louisiana Light Sweet LNG: Liquefied Natural Gas MBbl/d: Thousand Barrels per Day MBO: Thousand Barrels of Oil MBOE: Thousand Barrels of Oil Equivalent MBOPD: Thousand Barrels of Oil per Day Mcf: Thousand Cubic Feet of Natural Gas MEH: Magellan East Houston MLP: Master Limited Partnership MM: Millions MMBOE: Million Barrels of Oil Equivalent MOF: Marine Offtake Facility MTPA: Million Tonnes per Annum NGL: Natural Gas Liquids NPV10: Net Present Value (Discounted at 10%) NRI: Net Revenue Interest NYSE: New York Stock Exchange OPPL: Overland Pass Pipeline PI: Participation Interest PRB: Powder River Basin PV10: Present Value (Discounted at 10%) Q: Quarter ROR: Rate of Return RSEG: RS Energy Group S&P: Standard & Poor’s Shell: Shell International Trading Middle East Ltd. SPA: Sale and Purchase Agreement TC: Type Curve TEN: Tweneboa, Enyenra, Ntomme Tohoku: Tohoku Electric Power Company, Inc. Tokyo Gas: Tokyo Gas Co., Ltd. TTM: Trailing Twelve Months U.S.: United States of America VS: Versus WC-A: Wolfcamp-A WES: Western Gas Partners, LP WI: Working Interest WTI: West Texas Intermediate YE: Year End (APC Consolidated CFFO – WGP CFFO + WGP distributions to APC) (Stockholders’ Equity + Anadarko Debt) *CFROIC =