@NFX – 2Q17 Update

2Q17 Key Messages – What You Need to Know We are on-track to deliver our 3-year plan for double-digit CAGR in production at strip prices We exceeded the mid-point of our 2Q17 domestic production guidance by nearly 4,000 BOEPD net and raised our 2017 outlook Total Company net production was ~150,000 BOEPD (44% oil and 62% liquids), above mid-point of guidance by > 4,000 BOEPD net We have ~$550MM of cash and short-term investments on hand Closed on sale of Bohai Bay during 2Q17 Our recent STACK pilots are projecting above our 1.1 MMBOE EUR1 TC We raised our type curve in the Williston Basin to 1 MMBOE EUR1 >200 operated locations remaining SCOOP results showing continual improvement through enhanced completions Tina infill wells projecting to a 2 MMBOE EUR1 TC 2 1Estimated 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

1.1 MMBOE TC GEN17 HBP wells* 15 GEN17 HBP Wells* Stark Pilot Wells Spacing/DSU 1st well 10 Avg. CWC/well ($MM) $7.7 $8.8 Avg. Stage Count 50 50 Prop/ft 2,100 2,100 Gals/ft 2,100 2,100 Avg. IP30 (BOEPD) 1,255 1,211 % Oil 61% 65% % Liquids 80% 82% “NEW” 9 infill wells in the Meramec Average IP24: 1,500 BOEPD (71% oil, 85% liquids) Average IP30: 1,211 BOEPD (65% oil, 82% liquids) Production projecting above 1,100 MBOE TC Production projecting in-line with recent GEN17 HBP wells Utilizing controlled flowback to minimize drawdown and maximize oil recovery Additional 10-well test (Freeman) on-line and 12-well test (Velta June) drilling Positive Results from Recent Stark Pilot *All wells normalized to 10,000’ lateral length Previous Gen17 HBP Wells Stark Infill Wells vs. GEN17 HBP Wells Stark Pilot 3 Controlled Flowback Stark Wells 0 50 100 150 200 250 300 0 1 2 3 4 5 6 Cumulative Production (MBOE) Months

Dorothy Pilot Outperforming TC After 200 Days Wells Spacing Per DSU 5 CWC/Well ($MM) $5.8 Avg. Stage Count 25 Prop/ft 2,100 Gals/ft 2,100 Avg. IP30 (BOEPD) 1,244 % Oil 64% % Liquids 81% IRR %* 49% After 200 days, cumulative production from Dorothy infill wells is significantly above 1,100 MBOE TC Average IP30: 1,244 BOEPD (64% oil, 81% liquids) Current GEN17 completions aimed at generating more near wellbore complexity and higher productivity Infill wells projecting 49% IRR* Dorothy Pilot Dorothy Infill Wells** vs. 1,100 MBOE TC 4 *IRR% calculated at $50/$3 flat oil/gas prices ** All wells normalized to 10,000’ lateral length 1.1 MMBOE TC Dorothy Infill Wells** STACK

1.1 MMBOE TC “NEW” Eastern HBP Wells Continue to deliver TC or greater results across vast acreage position “NEW” average of 3 recent Eastern HBP wells projecting above 1,100 MBOE TC Average IP24: 1,647 BOEPD (66% oil, 82% liquids) Average IP30: 1,420 BOEPD (65% oil, 82% liquids) Recent Eastern wells projecting >50% IRR* “NEW” Eastern HBP Wells vs. 1,100 MBOE TC & GEN17 HBP Wells Previous GEN17 HBP Wells 5 Eastern STACK Wells Projecting Above TC “NEW Eastern HBP Wells *IRR% calculated at $50/$3 flat oil/gas prices GEN17 HBP wells 0 50 100 150 200 250 300 0 1 2 3 4 5 6 7 Cumulative Production (MBOE) Months

Previous 2017 Tina 5-6 Well/DSUs 8 Well/DSU** Infill Wells/DSU 4-5 7 CWC/Infill Well ($MM) $9.9 $7.2 Prop/ft 930 1,500 Gals/ft 900 2,000 Cluster Spacing 4 x 65’ 8 x 35’ Avg. IP30 (BOEPD) 1,462 1,708 % Liquids 67% 67% IRR%* 36% 73% Optimized completions, tighter density improve economics 17% increase in IP30 avg. rates >25% decrease in completed well costs ~2X increase in completion volumes “NEW” Tina - 7 infill wells exceeding 2,000 MBOE EUR** Estimated IRR: >70% ROR* SCOOP 2017 Infills Show Productivity Gains Tina Infill Wells IP30: 1,708 BOEPD *IRR% and NPV/well calculated at $50/$3 flat oil/gas prices **All wells normalized to 7,500’ lateral length see footnote 1 on page 2 SCOOP Tina Infill Wells vs. Previous Infill Wells 6 SCOOP Oil TC 0 50 100 150 200 250 300 0 1 2 3 4 5 6 Cumulative Production (MBOE) Months Online Previous SCOOP Oil TC Previous Infill Average (19) Tina Infill Average (7)

Williston Basin: Continued Improvements, Expanding Inventory Malm Pad IP24: 3,808 BOEPD (per well) Williston *IRR% calculated at $50/$3 flat oil/gas prices After nearly 200 wells, NFX continues to show performance improvements in development phase Improvements in completion designs enhancing economics 2-3X increase in proppant and fluid volumes Recent wells projecting above 1,000 MBOE TC “NEW” Off-Anticline Malm 4-well pad in-line with 2017 wells Average IP24: 3,808 BOEPD (64% oil, 83% liquids), per well 1-rig projected to deliver YOY production growth and $95MM FCF >200 operated locations remaining 2017 Infill Wells Outperforming Previous Offset Wells “NEW 1,000 MBOE TC” Previous Infill Wells (2012-15) 2017 Infill Wells Wells Spacing Per DSU 7-8 8-9 CWC Per Well ($MM) $8.1 $5.7 Avg. Stage Count 33 54 Prop/ft 332 944 Gals/ft 255 673 IP30 (BOEPD) 1,036 1,883 % Liquids 86% 86% IRR%* 20% 124% 7 0 50 100 150 200 250 300 0 1 2 3 4 5 6 7 8 9 10 11 12 Cumulative Production, MBOE Months Online 2017 Infill Wells (12) New TC (1,000 MBOE) Previous Infill Offsetting Wells (15) Previous TC (680 MBOE)

Appendix

2017 Capital investments YTD Total Company ($ in millions) Capital Expenditures: Q1 Q2 Q3 Q4 FY17 Exploration & development $186 $271 -- -- $457 Leasehold $30 $24 -- -- $54 Pipeline -- $1 -- -- $1 Total Capital Expenditures1 $216 $296 -- -- $512 1 Excludes ~$64 million in capitalized interest and direct internal costs and ~$10 million in FF&E 9

2Q17 Average Production by Area Production Anadarko Basin Williston Basin Uinta Basin China (Liftings) 1 Oil (bopd) 29,370 13,127 13,804 9,129 NGL (boepd) 23,561 3,152 381 -- Gas (boepd) 35,607 3,779 3,042 -- Total (boepd) 88,538 20,058 17,227 9,129 1 Includes lifted volumes in the quarter. Not reflective of daily rate. 10

2017e Production, Cost and Expense Guidance 11 Domestic China Total Production Oil % 41% 100% 42% NGLs % 19% -- 19% Natural Gas % 40% -- 39% Total (mboepd)1 145.4 – 153.8 4.0 149.4 – 157.8 Expenses ($/boe)2 LOE3,5 $3.41 $16.48 $3.76 Transportation4 $5.58 -- $5.43 Production & other taxes $1.07 $0.21 $1.05 General & administrative (G&A), net5 $3.54 $5.02 $3.58 Interest expense, gross -- -- $2.66 Capitalized interest and direct internal costs -- -- ($2.20) Effective Tax rate 0 – 5% 0 – 5% 0 – 5% 1 Total Company and China volumes include impact of Bohai Bay divestiture 2 Cost and expenses are expected to be within 5% of the estimates above 3 Total LOE includes recurring, major expense and non E&P operating expenses 4 2017e transportation / processing fees include ~$52 million of Arkoma unused firm gas transportation and ~$33 million of Uinta oil and gas delivery shortfall fees 5 Total LOE and G&A includes $4 million and $4 million, respectively, associated with remainder of 2017 activity in China

3Q17e Production, Cost and Expense Guidance 12 Domestic China Total Production Oil % 41% -- 41% NGLs % 19% -- 19% Natural Gas % 40% -- 40% Total (mboepd) 151.0 – 157.7 -- 151.0 – 157.7 Expenses ($/boe)1 LOE2,4 $3.26 -- $3.37 Transportation3 $5.71 -- $5.71 Production & other taxes $1.14 -- $1.14 General & administrative (G&A), net4 $3.62 -- $3.76 Interest expense, gross -- -- $2.63 Capitalized interest and direct internal costs -- -- ($2.15) Effective Tax rate 0 – 5% 0% 0 – 5% 1 Cost and expenses are expected to be within 5% of the estimates above 2 Total LOE includes recurring, major expense and non E&P operating expenses 3 2Q17e transportation / processing fees include ~$13 million of Arkoma unused firm gas transportation and ~$8 million of Uinta oil and gas delivery shortfall fees 4 Total LOE and G&A includes $2 million and $2 million, respectively, associated with Q3 2017 activity in China

Domestic Growth Outlook 10 – 15% CAGR 20 – 25% CAGR 88 108 – 118 125 – 135 137 155 – 165 170 – 180 Liquids Gas Liquids Gas 190 – 210 150 – 170 65% 65% 35% 35% 13 1 Excludes production associated with Eagle Ford and south Texas asset sale. See page 16 for details 2 See pages 14-15 for more information on ratios 1 Forecast to be updated in the future Forecast to be updated in the future Domestic production growth forecast driven by the Anadarko Basin Company goal: to maintain Net Debt / adjusted EBITDA ratios of 1.5 – 2.5x2 throughout plan period 4Q16 4Q17e 4Q18e 4Q19e Anadarko Basin Production ( Mboepd )

Solid capital structure $1.8 bn unsecured credit facility maturing 2020 ~$2.4 bn of total liquidity No fixed debt maturities until 2022 Weighted average fixed debt maturity of ~7 years at 4.8% YTM1 1 Sourced from Bloomberg as of June 30, 2017. 2 Net debt represents principal balance of debt less cash on balance sheet. Adjusted EBITDA calculated per Company’s credit agreement definition; YE 2016 and subsequent periods reflect 5th amendment executed 3/18/2016. See next slide. Net debt / adj EBITDA2 Fixed debt maturity schedule $ millions No maturities until 1/30/2022 14 $750 $1,000 $700 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 1.9x 2.0x 1.9x YE 2015 YE 2016 Q2 2017

Non-GAAP reconciliation of Adjusted EBITDA 15 Twelve Months Ended December 31, June 30, ($ in millions) 2015 2016 2017 Net Income ($3,362) ($1,230) $306 Adjustments to derive EBITDA: Interest expense, net of capitalized interest $131 $103 $88 Income tax provision (benefit) (1,585) 22 31 Depreciation, depletion and amortization 917 572 451 EBITDA ($3,899) ($533) $876 Adjustments to EBITDA: Ceiling test and other impairment $4,904 $1,028 $0 Non-cash stock-based compensation 25 22 23 Unrealized (gain) loss on commodity derivatives 246 392 50 Other permitted adjustments1 19 59 43 Adjusted EBITDA per credit agreement2 $1,295 $968 $992 1 Other permitted adjustments per Company’s credit agreement include but are not limited to inventory write-downs, office-lease abandonment, severance and relocation costs 2 Adjusted EBITDA calculated per Company’s credit agreement definition; December 31, 2016 and subsequent periods reflect 5th amendment executed 3/18/2016

2016 Production and costs pro forma for divestitures Domestic 2015 FY 2016 FY Gas (mmcf/d) 339.7 369.5 Crude (mbls/d) 58.5 57.3 NGL (mbls/d) 23.4 29.3 Total Production (mboepd) 138.5 148.2 LOE ($/boe) $4.75 $3.86 Transportation ($/boe) 4.18 5.01 Prod Tax ($/boe) 0.89 0.76 Eagle Ford / South Texas 2015 FY 2016 FY1 Gas 47.2 41.2 Crude 6.2 3.9 NGL 3.1 2.2 Total Production 17.1 12.9 LOE $6.41 $5.27 Transportation 3.12 3.02 Prod Tax 1.13 1.07 Pro Forma Domestic 2015 FY 2016 FY Gas 292.5 339.3 Crude 52.3 54.5 NGL 20.1 27.7 Total Production 121.4 138.8 LOE $4.52 $3.77 Transportation 4.33 5.14 Prod Tax 0.86 0.74 16 1 2016 Eagle Ford and south Texas production represents production through September 23, 2016 or only 267 days (Full-year 2016 production was 3.4 Mmboe).

Oil Hedging Details as of 7/31/17 17 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 3Q 2017 22,304 13,000 13,000 -- $46.49 -- -- -- -- $73.08/$87.90 -- -- -- -- $73.08 -- -- -- -- -- 4Q 2017 25,000 11,000 11,000 -- $46.86 -- -- -- -- $73.09/$88.01 -- -- -- -- $73.09 -- -- -- -- -- 1 Below $73.08 for 3Q17, and $73.09 for 4Q17, these contracts effectively result in realized prices that are on average $14.82 and $14.92 per Bbl higher, respectively, than the cash price that otherwise would have been realized. 2 Above $73.08 plus the call premium of $2.02 for 3Q17, and above $73.09 plus the call premium of $2.05 for 4Q 2017, these contracts effectively lock in the spread between the average short put and swap (less the call premium). Denotes update

Oil Hedging Details as of 7/31/17 18 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 1Q 2018 -- -- -- 12,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38/$46-$56.00 2Q 2018 -- -- -- 12,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38/$46-$56.00 3Q 2018 -- -- -- 12,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38/$46-$56.00 4Q 2018 -- -- -- 12,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38/$46-$56.00 3 Below $38 for 2018, these contracts effectively result in realized prices that are $8.00 per Bbl higher, than the cash price that otherwise would have been realized.

Oil Hedging Details as of 7/31/17 19 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. Oil Prices Period $20 $30 $40 $50 $60 $70 $80 3Q 2017 $70 $49 $29 $8 ($12) ($33) ($53) 4Q 2017 $75 $52 $29 $6 ($17) ($40) ($63) 1Q 2018 $9 $9 $6 $0 ($4) ($15) ($26) 2Q 2018 $9 $9 $7 $0 ($4) ($15) ($26) 3Q 2018 $9 $9 $7 $0 ($4) ($15) ($26) 4Q 2018 $9 $9 $7 $0 ($4) ($15) ($26)

Gas Hedging Details as of 7/31/17 20 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 3Q 2017 75,000 140,000 $2.73 -- -- $2.79-$3.20 4Q 2017 75,000 170,000 $2.73 -- -- $2.87-$3.28 1Q 2018 30,000 110,000 $3.01 -- -- $3.16-$3.74 2Q 2018 30,000 30,000 $3.01 -- -- $2.80-$3.32 3Q 2018 30,000 30,000 $3.01 -- -- $2.80-$3.32 4Q 2018 30,000 30,000 $3.01 -- -- $2.80-$3.32

Gas Hedging Details as of 7/31/17 21 Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 3Q 2017 $15 $5 ($2) ($10) ($19) ($29) ($39) 4Q 2017 $19 $7 ($1) ($10) ($20) ($31) ($43) 1Q 2018 $14 $8 $2 ($2) ($5) ($12) ($18) 2Q 2018 $5 $2 $0 ($2) ($5) ($7) ($10) 3Q 2018 $5 $2 $0 ($2) ($5) ($7) ($10) 4Q 2018 $5 $2 $0 ($2) ($5) ($7) ($10) 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.

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,” “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, estimated future operating costs, expenses and other financial measures, estimated future tax rates, drilling and development plans, the timing of production, planned capital expenditures, 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 and 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, drilling results, our liquidity and the availability of capital resources, operating risks, industry conditions, U.S. and China governmental regulations, financial counterparty risks, the prices of goods and services, the availability of drilling rigs and other support 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, and other operating risks. Please see Newfield’s 2016 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. 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. 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 interests 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, 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. Newfield may use terms in this presentation, such as “EURs”, “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 2016 Annual Report on Form 10-K, its Quarterly Reports on Form 10-Q 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. Forward Looking Statements & Related Matters 22