@NFX – 3Q17 Update

3Q17 Key Messages – What You Need to Know We exceeded the mid-point of our 3Q17 net domestic production guidance by 4,650 BOEPD and again raised our 2017 outlook Total Company net production was ~161,700 BOEPD (42% oil and 64% liquids) Anadarko Basin production increased 20% & Anadarko Basin oil production increased more than 25% (3Q17 vs. 2Q17) 3-year plan to deliver double-digit CAGR in production and improving returns We have $428MM of cash on hand Recent STACK pilots are projecting above our 1.1 MMBOE EUR1 TC Recent STACK HBP wells deliver strong results Hoile well sets record STACK IP24 oil rate per 1,000’ SCOOP results show continual improvement through enhanced completions and tighter well density spacing Williston Basin averaged nearly 22,000 BOEPD in 3Q17 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.

Newfield is Focused on Value Creation Tomorrow’s Winners Sustainable Value Creation Proven Execution Increase Bottom-Line Returns High-Grade Drilling Inventory 40% + IRR Oil & Liquids Focused Margin Expansion Development Synergies Data Analytics Profitable Growth Premium Inventory Returns Execution Vast, High Quality Resource Combination of Returns and Growth NAV expansion Premier Capital Structure 3

STACK Freeman & Stark Infill Wells vs. Type Curve “NEW” Freeman pilot (9 infill wells in the Meramec) Average IP30: 1,278 BOEPD (70% oil, 84% liquids) Average IP60: 1,156 BOEPD (67% oil, 83% liquids) Stark pilot (9 infill wells in the Meramec) Average IP30: 1,211 BOEPD (65% oil, 82% liquids) Average IP60: 1,202 BOEPD (65% oil, 82% liquids) “NEW” Average IP90: 1,156 BOEPD (66% oil, 83% liquids) “NEW” Average IP120: 1,121 BOEPD (66% oil, 82% liquids) Freeman & Stark Infill Wells vs. 440 MBO Oil TC 4 Freeman & Stark Infill Wells vs. 1,100 MBOE TC Stark Pilot Freeman Pilot “NEW” Freeman Infills Stark Infills 440 MBO Oil TC “NEW” Freeman Infills Stark Infills 1,100 MBOE TC 0 50 100 150 0 1 2 3 4 5 Cumulative Production (MBOE) Months 0 50 100 0 1 2 3 4 5 Cumulative Production (MBO) Months

Recent Strong STACK HBP Results and Record Setting Oil Well HOILE 1H-25X IP24hr: 5,100 BOEPD 67% Oil GPI: 7,140’ M&M 1H-29 IP24: 1,810 BOEPD 50% Oil GPI: 4,719’ CHANNEL 1H-30X IP30: 1,175 BOEPD 74% Oil GPI: 9,969’ NANCY 1809 1H-32 IP30: 1,233 BOEPD 76% Oil GPI: 4,479’ JOLEE 1H-5 IP30: 1,303 BOEPD 55% Oil GPI: 4,192’ EVELYN 1508 1H-17 IP30: 1,188 BOEPD 53% Oil GPI: 4,842’ KIERA 1506 1H-3X IP60: 928 BOEPD 82% Oil GPI: 10,092’ H&W 1H-28X IP30: 1,852 BOEPD 63% Oil GPI: 9,618’ “NEW” Hoile Well** “NEW” HBP Wells** 440 MBO Oil TC *Utilizes internal and IHS data ** Normalized to 10,000’ lateral length Hoile Peer Well Peer Well Peer Well Burgess NFX has two of the TOP 5 STACK IP24 Oil Wells (oil production per 1,000’) 5 NFX NFX “NEW” Hoile & HBP Wells vs. 440 MBO Oil TC BURGESS 1H-18 - 50 100 0 1 2 3 4 5 Cumulative Production (MBO) Months 0 100 200 300 400 500 IP24 BOPD per 1,000’ TOP 5 STACK IP24 Oil Wells (oil production per 1,000’)*

SCOOP McClelland & Tina Comparison vs. Type Curve 6 “NEW” McClelland & Tina Infill Wells* vs. 1,200 MBOE TC “NEW” McClelland & Tina Infill Wells* vs. 430 MBO Oil TC Tina Wells IP120: 1,465 BOEPD Holinsworth Wells IP24: 3,193 BOEPD McClelland Wells IP30: 1,966 BOEPD “NEW” McClelland Infills Tina Infills 1,200 MBOE TC “NEW” McClelland Infills Tina Infills 430 MBO Oil TC “NEW” McClelland development (8 infill wells in the Woodford) Average IP30: 1,966 BOEPD (36% oil, 70% liquids) Tina development (7 infill wells in the Woodford) “NEW” Average IP90: 1,539 BOEPD (41% oil, 72% liquids) “NEW” Average IP120: 1,465 BOEPD (41% oil, 72% liquids) “NEW” Holinsworth development (7 infill wells in the Woodford) Average IP24: 3,193 BOEPD (33% oil, 69% liquids) *Note: GPI for McClelland/Tina ~ 7,500’ & Holinsworth ~10,000’ 0 50 100 150 200 0 1 2 3 4 5 6 Cumulative Production (MBOE) Months 0 50 100 0 1 2 3 4 5 6 Cumulative Production (MBO) Months

NFX is the “Best-in-Class” Driller 7 NFX NFX NFX NFX Williston Avg. Ft/Day vs. Peers NFX SCOOP Avg. Ft/Day vs. Peers NFX STACK Avg. Ft/Day vs. Peers Active drilling programs in several basins allows rapid transfer of lessons learned Constant benchmarking against peers encourages continual improvement Consistent, active drilling levels creates “manufacturing mindset,” advances efficiency gains 7 *Total depth average feet per day based on 2017 public data from government database

Data Analytics Is Changing The Game For Newfield & Industry Initiated in 2013 Thousands of Oklahoma wells catalogued in database dating back to 2010 > 6 billion usable data points impacting decisions Realized learnings enhance our workforce efficiency Dedicated team uses machine learning algorithms on terabytes of data daily Workforce focuses on new ideas, concepts and optimization instead of data mining Predictive modeling drives operational enhancements, geologic understanding and high grades portfolio Autonomous partner data extraction accelerates learnings on most relevant data State of the art data security protects our data Multivariate analysis translates into industry leading wells, better forecasting, faster decisions & mitigates risk 8

Appendix

2017 Capital investments YTD Total Company ($ in millions) Capital Expenditures: Q1 Q2 Q3 Q4 YTD Exploration & development $186 $271 $304 -- $761 Leasehold $30 $24 $12 -- $66 Pipeline -- $1 -- -- $1 Total Capital Expenditures1 $216 $296 $316 -- $828 1 Excludes ~$97 million in capitalized interest and direct internal costs and ~$20 million in FF&E 10

3Q17 Average Production by Area Production Anadarko Basin Williston Basin Uinta Basin China (Liftings) 1 Oil (bopd) 36,910 14,068 14,458 2,598 NGL (boepd) 31,209 3,768 434 -- Gas (boepd) 36,689 4,072 3,110 -- Total (boepd) 104,808 21,908 18,002 2,598 1 Includes lifted volumes in the quarter. Not reflective of daily rate. 11

2017e Production, Cost and Expense Guidance 12 Domestic China Total Production Oil % 40% 100% 42% NGLs % 21% -- 20% Natural Gas % 39% -- 38% Total (mboepd)1 150.0 – 154.0 4.7 154.7 – 158.7 Expenses ($/boe)2 LOE3,5 $3.48 $15.65 $3.84 Transportation4 $5.58 -- $5.41 Production & other taxes $1.07 $0.18 $1.04 General & administrative (G&A), net5 $3.58 $3.88 $3.59 Interest expense, gross -- -- $2.62 Capitalized interest and direct internal costs -- -- ($2.21) 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 $2 million and $2 million, respectively, associated with remainder of 2017 activity in China

4Q17e Production, Cost and Expense Guidance 13 Domestic China Total Production Oil % 39% -- 39% NGLs % 22% -- 22% Natural Gas % 39% -- 39% Total (mboepd) 162.0 – 174.0 -- 162.0 – 174.0 Expenses ($/boe)1 LOE2,4 $3.20 -- $3.30 Transportation3 $5.58 -- $5.58 Production & other taxes $1.07 -- $1.07 General & administrative (G&A), net4 $3.31 -- $3.44 Interest expense, gross -- -- $2.41 Capitalized interest and direct internal costs -- -- ($1.89) 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 4Q17e transportation / processing fees include ~$13 million of Arkoma unused firm gas transportation and ~$9 million of Uinta oil and gas delivery shortfall fees 4 Total LOE and G&A includes $2 million and $2 million, respectively, associated with Q4 2017 activity in China

Solid capital structure $1.8 bn unsecured credit facility maturing 2020 ~$2.3 bn of total liquidity No fixed debt maturities until 2022 Weighted average fixed debt maturity of ~6 years at 4.3% YTM1 1 Sourced from Bloomberg as of September 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 reflects 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 2.0x YE 2015 YE 2016 Q3 2017

Non-GAAP reconciliation of Adjusted EBITDA 15 Twelve Months Ended December 31, September 30, ($ in millions) 2015 2016 2017 Net Income ($3,362) ($1,230) $345 Adjustments to derive EBITDA: Interest expense, net of capitalized interest $131 $103 $88 Income tax provision (benefit) (1,585) 22 8 Depreciation, depletion and amortization 917 572 455 EBITDA ($3,899) ($533) $896 Adjustments to EBITDA: Ceiling test and other impairment $4,904 $1,028 $0 Non-cash stock-based compensation 25 22 33 Unrealized (gain) loss on commodity derivatives 246 392 73 Other permitted adjustments1 19 59 10 Adjusted EBITDA per credit agreement2 $1,295 $968 $1,012 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 reflects 5th amendment executed 3/18/2016

Oil Hedging Details as of 10/30/17 16 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 4Q 2017 31,000 11,000 11,000 -- $47.52 -- -- -- -- $73.09/$88.01 -- -- -- -- $73.09 -- -- -- -- -- 1Q 2018 6,000 -- -- 44,000 $50.04 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.18/$48.05-$55.98 2Q 2018 6,000 -- -- 42,000 $50.04 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.10/$47.98-$56.04 3Q 2018 6,000 -- -- 36,000 $50.04 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38.88/$47.64-$56.13 4Q 2018 6,000 -- -- 29,000 $50.04 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38.52/$47.00-$56.13 1 Below $73.09 for 4Q17, these contracts effectively result in realized prices that are on average $14.92 per Bbl higher, respectively, than the cash price that otherwise would have been realized. 2 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. 3 Below $38.18 for 1Q18, $39.10 for 2Q18, $38.88 for 3Q18, and $38.52 for 4Q18 these contracts effectively result in realized prices that are $8.87, $8.88, $8.76, and $8.48 per Bbl higher, respectively by quarter, than the cash price that otherwise would have been realized. Denotes update

Oil Hedging Details as of 10/30/17 17 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 1Q 2019 -- -- -- 28,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.71/$50.00-$56.46 2Q 2019 -- -- -- 26,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.73/$50.00-$56.48 3Q 2019 -- -- -- 19,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.82/$50.00-$56.60 4Q 2019 -- -- -- 13,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.73/$50.00-$56.56 3 Below $39.71 for 1Q19, $39.73 for 2Q19, $39.82 for 3Q19, and $39.73 for 4Q19 these contracts effectively result in realized prices that are $10.29, $10.27, $10.18, and $10.27 per Bbl higher, respectively by quarter, than the cash price that otherwise would have been realized.

Oil Hedging Details as of 10/30/17 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. Oil Prices Period $20 $30 $40 $50 $60 $70 $80 4Q 2017 $92 $63 $34 $6 ($23) ($51) ($80) 1Q 2018 $51 $46 $36 $0 ($21) ($66) ($111) 2Q 2018 $50 $45 $35 $0 ($21) ($64) ($108) 3Q 2018 $46 $40 $30 $0 ($18) ($57) ($96) 4Q 2018 $39 $34 $24 $0 ($16) ($48) ($80)

Oil Hedging Details as of 10/30/17 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 1Q 2019 $26 $26 $25 $0 ($9) ($34) ($59) 2Q 2019 $24 $24 $23 $0 ($8) ($32) ($56) 3Q 2019 $18 $18 $17 $0 ($6) ($23) ($41) 4Q 2019 $12 $12 $12 $0 ($4) ($16) ($28)

Gas Hedging Details as of 10/30/17 20 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 4Q 2017 75,000 170,000 $2.73 -- -- $2.87-$3.28 1Q 2018 30,000 190,000 $3.01 -- -- $3.14-$3.73 2Q 2018 150,000 40,000 $2.99 -- -- $2.83-$3.28 3Q 2018 140,000 40,000 $2.99 -- -- $2.83-$3.28 4Q 2018 120,000 40,000 $2.99 -- -- $2.83-$3.28

Gas Hedging Details as of 10/30/17 21 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 1Q 2019 10,000 90,000 $2.91 -- -- $3.00-$3.48 2Q 2019 10,000 -- $2.91 -- -- -- 3Q 2019 10,000 -- $2.91 -- -- -- 4Q 2019 10,000 -- $2.91 -- -- --

Gas Hedging Details as of 10/30/17 22 Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 4Q 2017 $19 $7 ($1) ($10) ($20) ($31) ($43) 1Q 2018 $22 $12 $3 ($2) ($7) ($17) ($27) 2Q 2018 $16 $8 $0 ($8) ($16) ($25) ($34) 3Q 2018 $16 $7 $0 ($7) ($16) ($24) ($32) 4Q 2018 $14 $7 $0 ($6) ($14) ($21) ($29) 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.

Gas Hedging Details as of 10/30/17 23 Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 1Q 2019 $9 $4 $0 ($1) ($5) ($10) ($14) 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) 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, other 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 24