Newfield Exploration (NFX) 8-K Newfield Exploration Reports Second Quarter 2018 Results

Exhibit 99.2

2Q18 UPDATE Exhibit 99.2

Forward Looking Statements and Related Matters This presentation contains 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. The words “may,” “forecast,” “outlook,” “could,” “budget,” “objectives,” “strategy,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “prospective,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “guidance,” “potential” or other similar expressions are intended to identify forward-looking statements. Other than historical facts included in this presentation, all information and statements, including but not limited to information regarding planned capital expenditures, estimated reserves, estimated production targets and commodity mix, estimated pre-tax wellhead rates of return, estimated future operating costs and other expenses and other financial measures, estimated future tax rates, drilling and development plans, the timing of production, and other plans and objectives for future operations, are forward-looking statements. Although, as of the date of this presentation, Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks, some of which are beyond Newfield’s control and are difficult to predict. No assurance can be given that such expectations will prove to have been correct. Actual results may vary significantly from those anticipated due to many factors, including but not limited to commodity prices and our ability to hedge commodity prices, drilling results, changes in commodity mix, accessibility to economic transportation modes and processing facilities, our liquidity and the availability of capital resources, operating risks, failures and hazards, industry conditions, governmental regulations in the areas in which we operate, including water regulations, financial counterparty risks, the prices of goods and services, the availability of drilling rigs and other oilfield services, our ability to monetize assets and repay or refinance our existing indebtedness, labor conditions, severe weather conditions, new regulations or changes in tax or environmental legislation, environmental liabilities not covered by indemnity or insurance, legislation or regulatory initiatives intended to address seismic activity or induced seismicity, and other operating risks. Please see Newfield’s 2017 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other subsequent public filings, all filed with the U.S. Securities and Exchange Commission (SEC), for a discussion of other factors that may cause actual results to vary. Unpredictable or unknown factors not discussed herein or in Newfield’s SEC filings could also have material adverse effects on Newfield’s actual results as compared to its anticipated results. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this presentation and are not guarantees of performance. Unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 2

Forward Looking Statements and Related Matters (continued) This presentation has been prepared by Newfield and includes market data and other statistical information from sources believed by Newfield to be reliable, including independent industry publications, government publications or other published independent sources. Some data are also based on Newfield’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although Newfield believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. Actual quantities that may be ultimately recovered from Newfield’s assets may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Newfield’s ongoing drilling program, which will be directly affected by commodity prices (including our ability to hedge commodity prices) and our pre-tax wellhead rates of return, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation and processing constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates and commodity mix. Newfield may use terms in this presentation, such as “EURs,” “unrisked locations,” “risked locations,” “net effective reservoir acreage,” “upside potential,” “net unrisked resource,” “gross EURs,” and similar terms that the SEC’s guidelines strictly prohibit in SEC filings. These terms include reserves with substantially less certainty than proved reserves, and no discount or other adjustment is included in the presentation of such reserve numbers. Investors are urged to consider closely the oil and gas disclosures in Newfield’s 2017 Annual Report on Form 10-K and subsequent public filings, available at www.newfield.com, www.sec.gov or by writing Newfield at 4 Waterway Square Place, Suite 100, The Woodlands, Texas 77380 Attn: Investor Relations. In addition, this presentation contains non-GAAP financial measures, which include, but are not limited to, Adjusted EBITDA. Newfield defines EBITDA as net income/loss before income tax expense/benefit, interest expense and depreciation, depletion and amortization. Adjusted EBITDA, as presented herein, is EBITDA before ceiling test impairments, gains/losses on asset sales, non-cash compensation expense, net unrealized (gains) / losses on commodity derivatives and other permitted adjustments. Adjusted EBITDA is not a recognized term under GAAP and does not represent net income as defined under GAAP, and should not be considered an alternative to net income as an indicator of operating performance or to cash flows as a measure of liquidity. Adjusted EBITDA is a supplemental financial measure used by Newfield’s management and by securities analysts, lenders, ratings agencies and others who follow the industry as an indicator of Newfield’s ability to internally fund exploration and development activities. NOTE: All numbered references throughout document are defined in Endnotes beginning on page 28 of this presentation. 3

2Q18 Highlights: Anadarko Basin Drives Outperformance 2Q18 reached new heights for the Company Domestic net production up >30% Y-o-Y: 186,700 BOEPD (39% oil, 62% liquids) Anadarko Basin net production up >45% Y-o-Y: 131,100 BOEPD (32% oil, 61% liquids) Anadarko Basin liquids production up >50% Y-o-Y: >80,000 barrels per day (7% above guidance) Anadarko Basin oil production up >40% Y-o-Y: >42,000 BOPD (in-line with guidance) Discretionary cash flow exceeded capital investment by $11 million Raising full-year production and capital guidance 2018E Domestic production outlook of 180-190 MBOEPD (up from 175-185 MBOEPD) 2018E Anadarko Basin production outlook of 125-135 MBOEPD (up from 120-130 MBOEPD) 2018E Capital budget increased 4% to approximately $1,350 million to reflect increased working interest and non-operated activity in high-return projects Successful Meramec assessments in NW STACK providing inventory confidence Newfield holds approximately 24,000 net acres in this region Expect to operate over 70% of the development Approximately 80% HBP by year-end 2018 4

Raising 2018 Guidance Based on Strong Anadarko Results 5 “NEW” “NEW” Domestic Production Guidance (mboepd) Anadarko Basin Production Guidance (mboepd) Raising 2018E domestic and Anadarko Basin production expectations (on BOE basis) based on strong 1H18 results and reiterating total oil volumes 2018E Domestic and Anadarko Basin production now expected to grow 18-25% and 25-35%, respectively DOMESTIC

1H18 Anadarko Basin Adjustments From Partner Activity 6 Avg. 1H18: >124,000 BOEPD Gas: 39% / NGL: 28% / Oil: 33% $515 $573 ~ $25 ~ $35 Orig. Guidance Higher Op. WI & Operated Outspend Incremental OBO 1H18 Actual $mm Anadarko Basin CAPEX 69% 8% 23% OBO Production Oil 34% 31% 35% Operated Production Gas NGLs

Unlocking Resource Expansion in NW STACK SCORE Program NW STACK Assessment Successes STACK Walters 1H-22X Avg. GPI: 9,662’ IP30: 1,274 boepd (68% Oil) CHARLES 1H-19 Avg. GPI: 4,892’ IP30: 931 boepd (49% Oil) Hyden 1H-17x Avg. GPI: 9.755’ IP30: 1,555 boepd (40% Oil) GOSS 1H-8X Avg. GPI: 9,772’ IP30: 1,125 boepd (47% Oil) Recent Newfield operated wells demonstrate prolific nature of NW STACK Recent well highlights (IP30s): CHARLES 1H-19: ~900 boepd (49% oil) JAKE 1H-21X: >1,500 boepd (73% oil) WALTERS 1H-22X: >1,250 boepd (68% oil) HYDEN 1H-17X: >1,500 boepd (40% oil) GOSS 1H-8X: >1,100 boepd (47% oil) Newfield controls approximately 24,000 net acres (>70% operated3) in key area of interest 7 Jake 1H-21X Avg. GPI: 10,056’ IP30: 1,533 boepd (73% Oil) * Average cumulative performance normalized to 10,000’ lateral length. 0 1 2 3 4 5 6 0 50 100 150 200 250 300 350 400 0 2 4 6 8 10 12 WELL COUNT AVG. CUMULATIVE MBOE Months Online 3YR Plan Recent NW STACK Wells (5)* Well Count

Newfield Has Led Development of Water Solutions in STACK 8 Since 2015, NFX has invested >$80 MM on permanent water pipelines and infrastructure ~75 miles of permanent “dual” pipe (effectively ~150 miles) 30,000 Bbl/d Barton water recycling and treatment facility >13 million barrels of water storage in STACK Operational benefits of infrastructure across STACK Reduced operating cost and improved efficiencies Reduced reliance on trucking and related services No history of operational integrity issues on existing pipeline infrastructure Existing Permanent Water Pipelines Future Permanent Water Pipelines Barton Water Treatment Facility 8

Net debt / adj EBITDA4 Long-Term Debt Maturities $ millions No maturities until 1/30/2022 Leverage Profile Improvement Ahead of Schedule FCF generation in 2Q18 has placed Net debt / adj. EBITDA at 1.7x (Ahead of FY18 guidance) Expanding liquidity to over $2.4 billion $2.0 billion undrawn unsecured credit facility $293 million cash $125 million undrawn line of credit 9 Improving Debt Profile 2018E Guidance 2Q18 Actual “Ahead of Schedule” 1.7x 1.8x 2018E 2019E 2020E $750 $1,000 $700 2018 2018 2019 2020 2021 2022 2023 2024 2025 2026

2Q18 Results

2Q18 Domestic Results 1Q18 ACTUAL 2Q18 GUIDANCE 2Q18 ACTUAL PRODUCTION Oil (mbopd) 72 72 74 NGL (mbopd) 35 37 43 Gas (mmcfpd) 401 402 422 Total (mboepd) 174 172-180 187 EXPENSES ($/BOE)* LOE $3.43 $3.43 $3.13 Transportation** $5.01 $4.95 $4.85 Production & other taxes $1.53 4.7% $1.52 General & administrative, net $3.35 $3.44 $2.95 CAPEX ($MM)*** $345 $360 $365 OPERATIONS Operated rigs 11 - 13 Op. wells placed on production (WI%/NRI%) 54 (54% / 44%) - 49 (85% / 68%) Op. wells placed on production (Average GPI) 8,312‘ - 7,925’ *Guidance numbers for Expenses shown on annual basis. **Actual transportation fees include $12 million associated with firm gas transportation in the Arkoma Basin in each of 1Q18A and 2Q18A, as well as $4 million of shortfall fees in the Uinta Basin in 1Q18A. *** CAPEX excludes ~$28 million of capitalized interest and direct internal cost in each of 1Q18A and 2Q18A. 11

2Q18 Basin Results ANADARKO WILLISTON UINTA ARKOMA PRODUCTION Oil (mbopd) 42.1 14.3 17.6 0.0 NGL (mbopd) 38.3 3.4 0.6 0.4 Gas (mmcfpd) 304.4 19.9 14.7 81.0 Total (mboepd) 131.1 21.0 20.7 13.9 EXPENSES ($/BOE) LOE $2.29 $5.59 $9.87 $3.24 Transportation* $4.37 $5.66 $1.13 $4.44 Production & other taxes $0.95 $4.26 $2.69 $0.72 Total Expenses $7.61 $15.51 $13.69 $8.40 CAPEX ($MM) Drilling & Completion $284 $41 $25 ($2) Other $7 $1 $2 $1 Total CAPEX** $291 $42 $27 ($1) OPERATIONS Operated rigs 11 1 1 0 Op. wells placed on production (WI%/NRI%) 40 (89% / 70%) 6 (70% / 57%) 3 (74% / 59%) NA Op. wells placed on production (Average GPI) 7,513’ 10,052’ 9,173’ NA 12 * Transportation fees exclude $12 million of firm gas transportation in the Arkoma. ** CAPEX excludes $6 million associated with Corporate FF&E.

2018 Annual Guidance DOMESTIC GUIDANCE 2017 ACTUAL 2018 ESTIMATES* PRODUCTION Oil (mbopd) 61.2 74 NGL (mbopd) 31.7 41 Gas (mmcfpd) 356.5 425 Total (mboepd) 152.2 180 - 190 EXPENSES ($/BOE) LOE $3.47 $3.47 Transportation** $5.40 $4.93 Production & other taxes 3.5% 4.6% General & administrative, net $3.49 $3.10 Interest expense, net $1.62 $1.36 CAPEX ($MM) Drilling & Completion $992 $1,210 Other $161 $140 Total CAPEX*** $1,153 $1,350 CHINA GUIDANCE Production (mbopd) 4.7 3 - 5 13 * Individual product guidance ranges do not necessarily sum to total production guidance range. ** 2017A transportation fees include $54 million and $29 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. 2018E transportation fees include approximately $36 million and $13 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. *** 2017A and 2018E exclude ~$124 million and ~$114 million of capitalized interest and direct internal costs, respectively. Includes ~$31 million of Corporate FF&E for 2018E.

2018 Quarterly Guidance DOMESTIC GUIDANCE 1Q18 Actual 2Q18 Guidance 2Q18 Actual 3Q18E* 4Q18E* PRODUCTION Oil (mbopd) 72 72 74 73 – 77 73 – 77 NGL (mbopd) 35 37 43 40 – 46 40 – 46 Gas (mmcfpd) 401 402 422 420 – 450 420 – 450 Total (mboepd) 174 172-180 187 185 – 195 185 – 195 CAPEX ($MM) $345 $360 $365 $365 $275 14 *Individual product guidance ranges do not necessarily sum to total production guidance range. ANADARKO GUIDANCE 1Q18 Actual 2Q18 GUIDANCE 2Q18 Actual 3Q18E* 4Q18E* PRODUCTION Oil (mbopd) 40 42 42 42 – 44 42 – 44 NGL (mbopd) 31 33 38 36 – 40 36 –40 Gas (mmcfpd) 279 288 304 310 – 330 310 – 330 Total (mboepd) 117 120-126 131 130 – 140 130 – 140 CAPEX ($MM) $282 $265 $291 $265 $220 China Production (mboepd) 3 7-9 9 2 – 3

APPENDIX

STACK 3YR Plan Assumptions: EUR Range: 1.1 – 1.7 MMBOE1 Well Cost Range (incl. facilities): $7.6 – $8.7 million 3YR Plan Average: 1.3 MMBOE1 EUR @ $7.9 million well cost (incl. facilities) STACK 3YR Plan Modeling Assumptions MODELING ASSUMPTIONS STACK PRODUCTION Avg. IP30 (BOEPD) 1,300 Avg. IP30 (% oil / % liquids) 59% / 79% Avg. EUR (mboe) 1,300 Avg. EUR (oil mbo / liquids mboe) 455 / 860 First Five Year Cum (mboe) 675 First Five Year Cum (mbo) 275 EXPENSES ($/BOE) LOE $1.80 Oil transportation $1.73 Gas/NGL transportation/processing $4.70 Production & other taxes 5% (3 years) / 7% (thereafter)* REALIZATIONS** Oil (%WTI) 100% NGLs (%WTI) 43% Gas (%HH) 84% CAPEX ($MM) Avg. gross completed well cost (incl. facilities) $7.9 OPERATIONS Avg. operated rigs/year 6 – 8 Est. op. wells placed on production (WI%/NRI%) 414 (77% / 62%) Op. wells avg. GPI 8,907’ 16 1 2 3 4 5 6 7 8 9 10 11 12 0 *Reflects recent Oklahoma Regulatory Changes to Gross Production Tax Rate. **Approximate realizations relative to NYMEX STRIP pricing as of July 2018. 0 50 100 150 200 250 300 0 60 120 180 240 300 360 CUMULATIVE MBOE Months Online STACK 3YR Plan Well Profile

MODELING ASSUMPTIONS SCOOP Oil SCOOP Wet Gas PRODUCTION Avg. IP30 (BOEPD) 1,035 1,750 Avg. IP30 (mbo oil / mboe liquids) 695 / 870 420 / 1,100 Avg. EUR (mboe) 1,695 2,700 Avg. EUR (oil mbo / liquids mboe) 610 / 1,170 270 / 1,500 First Five Year Cum (mboe) 722 1,357 First Five Year Cum (mbo) 298 179 EXPENSES ($/BOE) LOE $1.65 $1.65 Oil transporation $0.00 $0.00 Gas/NGL transportation/processing $6.10 $6.02 Production & other taxes 5% (3 years) / 7% (thereafter)* REALIZATIONS** Oil (%WTI) 96% 96% NGLs (%WTI) 46% 46% Gas (%HH) 86% 86% CAPEX ($MM) Avg. gross completed well cost (incl. facilities) $8.6 $9.2 OPERATIONS Avg. operated rigs/year 1-2 1-2 Est. op. wells placed on production (WI%/NRI%) 104 (57% / 46%) 30 (67% / 56%) Op. wells avg. GPI 9,438’ 9,423’ SCOOP 3YR Plan Modeling Assumptions 17 *Reflects recent Oklahoma Regulatory Changes to Gross Production Tax Rate **Approximate realizations relative to NYMEX STRIP pricing as of July 2018. 0 100 200 300 400 500 600 0 1 2 3 4 5 6 7 8 9 10 11 12 MBOE Months Online SCOOP Wet Gas 3YR Plan Type Curve 0 50 100 150 200 250 300 0 1 2 3 4 5 6 7 8 9 10 11 12 MBOE Months Online SCOOP Oil 3YR Plan Type Curve

MODELING ASSUMPTIONS Williston PRODUCTION Avg. IP30 (BOEPD) 2,121 Avg. IP30 (% oil / % liquids) 65% / 83% Avg. EUR (mboe) ~1,050 Avg. EUR (oil mbo / liquids mboe) 686 / 884 First Five Year Cum (mboe) 642 First Five Year Cum (mbo) 416 EXPENSES ($/BOE) LOE $4.70 Oil transportation $1.90 Gas/NGL transportation/processing $15.67 Production & other taxes 10% for oil / $0.0555 per MCF gas REALIZATIONS* Oil (%WTI) 95% NGLs (%WTI) 51% Gas (%HH) 74% CAPEX ($MM) Avg. gross completed well cost (incl. facilities) $6.0 OPERATIONS Avg. operated rigs/year 1 Est. op. wells placed on production (WI%/NRI%) 67 (57% / 47%) Op. wells avg. GPI 9,552’ Williston Basin 3YR Plan Modeling Assumptions 18 *Approximate realizations relative to NYMEX STRIP pricing as of July 2018. 0 100 200 300 400 0 1 2 3 4 5 6 7 8 9 10 11 12 MBOE Months Online Williston Basin 3YR Plan Type Curve

Oil Hedging Details as of 07/16/18 Denotes update 19 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts5 Collars Collars w/ Short Puts6 3Q 2018 60,000 3,500 -- -- $56.58 -- -- -- -- $44.00/$56.78 -- -- -- -- -- -- -- -- -- -- 4Q 2018 28,000 3,500 -- 21,000 $55.81 -- -- -- -- $44.00/$56.78 -- -- -- -- -- -- -- -- -- $39.47/$48.34-$56.60

Oil Hedging Details as of 07/16/18 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts Collars Collars w/ Short Puts8 1Q 2019 -- -- -- 36,500 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $40.47/$50.53-$57.02 2Q 2019 -- -- -- 33,500 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $40.48/$50.51-$57.04 3Q 2019 -- -- -- 27,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $40.80/$50.69-$57.26 4Q 2019 -- -- -- 19,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $40.82/$50.71-$57.32 20

Oil Hedging Details as of 07/16/18 The following table details the expected impact to pre-tax income (in millions, except prices) from the settlement of our derivative contracts, outlined on the previous slide, at various NYMEX oil prices. 21 Oil Prices Period $20 $30 $40 $50 $60 $70 $80 3Q 2018 $206 $151 $93 $41 ($20) ($78) ($137) 4Q 2018 $113 $88 $59 $20 ($18) ($67) ($115) 1Q 2019 $33 $33 $32 $2 ($10) ($43) ($75) 2Q 2019 $31 $31 $30 $2 ($9) ($40) ($70) 3Q 2019 $25 $25 $24 $2 ($7) ($32) ($56) 4Q 2019 $17 $17 $17 $1 ($5) ($22) ($40) Denotes update

Gas Hedging Details as of 07/16/18 22 Weighted-Average Price Period Volume (mmbtu/d) Swaps Swaps w/ Short Puts8 Collars Collars w/ Short Puts9 3Q 2018 180,000 40,000 10,000 30,000 $2.97 -- -- -- -- $2.60/$2.97 -- -- -- -- $2.90-$3.15 -- -- -- -- $2.30/$2.87-$3.32 4Q 2018 150,000 66,500 39,900 10,100 $2.97 -- -- -- -- $2.66/$3.03 -- -- -- -- $2.88-$3.28 -- -- -- -- $2.30/$2.87-$3.32 Denotes update

Gas Hedging Details as of 07/16/18 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 1Q 2019 10,000 100,000 $2.91 -- -- $3.00-$3.47 2Q 2019 10,000 -- $2.91 -- -- -- 3Q 2019 10,000 -- $2.91 -- -- -- 4Q 2019 10,000 -- $2.91 -- -- -- 23

Gas Hedging Details as of 07/16/18 The following table details the expected impact to pre-tax income (in millions, except prices) from the settlement of our derivative contracts, outlined on the previous slide, at various NYMEX gas prices. 24 Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 3Q 2018 $20 $11 ($1) ($12) ($23) ($35) ($47) 4Q 2018 $19 $11 $0 ($11) ($23) ($36) ($48) 1Q 2019 $10 $5 $0 ($1) ($6) ($11) ($16) 2Q 2019 $1 $0 $0 ($1) ($1) ($1) ($2) 3Q 2019 $1 $0 $0 ($1) ($1) ($1) ($2) 4Q 2019 $1 $0 $0 ($1) ($1) ($1) ($2) Denotes update

Propane Hedging Details as of 07/16/18 25 Weighted-Average Price Period Volume (bbl/d) Swaps ($/gal) 3Q 2018 5,000 $.830 4Q 2018 3,000 $.807 Denotes update

Propane Hedging Details as of 07/16/18 The following table details the expected impact to pre-tax income (in millions, except prices) from the settlement of our derivative contracts, outlined on the previous slide, at various Mont Belvieu non-tet prices. 26 Propane Prices Period $.50 $.60 $.70 $.80 $.90 $1.00 $1.10 3Q 2018 $6.4 $4.5 $2.5 $0.6 ($1.3) ($3.3) ($5.2) 4Q 2018 $3.6 $2.4 $1.2 $0.1 ($1.1) ($2.2) ($3.4) Denotes update

Non-GAAP reconciliation of Adjusted EBITDA 27 ($ in millions) QTD Twelve Months Ended 3Q17 4Q17 1Q18 2Q18 June 30, 2018 Net Income $87 $95 $86 $119 $387 Adjustments to derive EBITDA: Interest expense, net of capitalized interest 22 23 23 22 90 Income tax provision (benefit) (19) (38) 13 14 (30) Depreciation, depletion and amortization 124 127 133 151 535 EBITDA $214 $207 $255 $306 $982 Adjustments to EBITDA: Ceiling test and other impairment - - - - - Non-cash stock based compensation 5 9 9 16 39 Unrealized (gain) loss on commodity derivatives 34 95 79 78 286 Other permitted adjustments* 1 3 1 (6) (1) Adjusted EBITDA** $254 $314 $344 $394 $1,306 Long-term debt $2,450 Less: Cash 293 Net debt $2,157 Net debt / Adjusted EBITDA 1.7 *Other permitted adjustments per Company’s credit agreement include, but are not limited to, inventory write-downs, office-lease abandonment, severance and relocation costs. ** Adjusted EBITDA calculated per Company’s credit agreement definition.

Endnotes 3YR Plan type curve indicative of anticipated results of wells to be drilled in play during the 3YR Plan and is representative of estimated ultimate recovery from the well and are not indicative of cumulative historical results in play. Estimated ultimate recovery (EUR) refers to potential recoverable oil and natural gas hydrocarbon quantities with ethane processing and depends on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Such amounts do not meet SEC rules and guidelines, may not be reflective of SEC proved reserves and do not equate to or predict any level of reserves or production. Realizations do not factor in transportation fees associated with selling crude in-field. YTD Differentials through June 30, 2018. Gulf Coast based on HSC pricing. Haynesville based on Perryville pricing. Bakken based on 84% of NNG Ventura. Marcellus based on DOM SOUTH pricing. Anadarko based on MC R-AVG pricing. DJ Basin based on CIG pricing. Permian based on WAHA pricing. Percent operated defined as number of government defined sections that Newfield believes it has appropriate working interest to operate development as of June 30, 2018. Net debt represents principal balance of debt less cash on balance sheet. Adjusted EBITDA calculated per Company’s credit agreement definition; The Amended and Restated Credit Agreement dated March 23, 2018. A full reconciliation begins on page 27. Below $44.00 for 3Q18 and 4Q18, these contracts effectively result in realized prices that are on average $12.78 per Bbl higher than the cash price that otherwise would have been realized. Below $39.47 for 4Q18 these contracts effectively result in realized prices that are $8.87 per Bbl higher than the cash price that otherwise would have been realized. We have converted several of our 3-way structures into swaps by buying short puts, selling long puts, and buying calls, then embedding the option cost into the swap price. Below $40.47 for 1Q19, $40.48 for 2Q19, $40.80 for 3Q19, and $40.82 for 4Q19 these contracts effectively result in realized prices that are $10.06, $10.03, $9.89, and $9.89 per Bbl higher, respectively by quarter, than the cash price that otherwise would have been realized. Below $2.60 for 3Q18 and below $2.66 for 4Q18, these contracts effectively result in realized prices that are on average $.37 per MMBtu higher, than the cash price that otherwise would have been realized. Below $2.30 for 3Q18-4Q18 these contracts effectively result in realized prices that are $.57 per MMBtu higher than the cash price that otherwise would have been realized. These 3-way structures were created by selling a $2.30 put to enhance collars already in place. 28

Key Definitions 3YR Plan Assumptions – Estimated production, costs, expenses (inclusive of CAPEX) shown are expected to be within +/- 5% of the values illustrated. Commodity prices based on NYMEX STRIP pricing as of June 30, 2018. Adjusted EBITDA / Net Debt – See reconciliation beginning on page 27. Discretionary Cash Flow – Cash flow from operations before changes in operating assets and liabilities. Controllable Capital / Capital Investment (CAPEX) – Defined as capital expenditures associated with the drilling, completion, facilities, artificial lift, recompletions and plugging and abandoning of wellbores plus FF&E, seismic and leasehold capital expenditures and construction capital and other capital associated with oil and gas assets, excluding capitalized interest and overhead costs1. Free Cash / Free Cash Flow – Determined by subtracting Controllable Capital from Cash Flow. GPI – Gross Perforated Interval, which reflects the total feet completed in each horizontal wellbore. IP30 – Average production rate over the peak 30-day period of time following first production. Operated by Others / Non-Operated (“OBO” / “Non-Op”) – Well costs and associated production from projects operated by others Operational Integrity Issues – Issues from normal use of equipment and excludes any issues as a result of third party vandalism or natural disasters. Well Cost – Includes capital associated with drilling, completions, facilities and artificial lift. 29