@NFX – YE16 Update and Outlook

1 Net unrisked resource 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 Today’s key messages – What you need to know Our plans include: transitioning STACK to development and creating additional efficiencies using cash on hand to accelerate development in the Anadarko Basin testing more than 1 billion barrels of net unrisked resource potential1 on our asset base positioning the organization to achieve sustainable, double-digit production growth within cash flow in the future delivering strong domestic oil and domestic production growth rates for 2017 – 19 growing our average daily production in the Anadarko Basin to 150 – 170 MBOEPD in the 4Q19e 2

2016 highlights 3 Superior Execution Consolidated and domestic production exceeds initial guidance mid-point by 10% and 8%, respectively Domestic costs and expenses down >25% per boe since 2014 High-graded Portfolio STACK Acquisition expands footprint Overlaps legacy acres Adds exposure to volatile oil window Extensional leasing in STACK Eagle Ford/ S. Texas sale for ~$380 MM reloads balance sheet Anadarko Basin Outperforms Production grew 38% Y-o-Y (61% liquids); Oil production up >40% Y-o-Y Raised STACK type curve 15% to 1.1 Mmboe1 “Upsized” completions outperform Basin cost structure helps to lower per boe domestic LOE nearly 25% Y-o-Y 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

2016 Production and capital investments by area 138,800 boepd $749 million High-graded investments with 82% capital allocated to the Anadarko Basin Anadarko Basin net production was up 38% Y-o-Y Anadarko Basin net oil production was up > 40% Y-o-Y STACK oil production was up >75% Y-o-Y 4 Anadarko Basin Other Other 1 Excludes production associated with Eagle Ford and south Texas asset sale. See page 16 for details. 2 Excludes ~$121 million in capitalized interest and direct internal costs and excludes acquisitions. 82% 18% Domestic Capital Investments 2 Anadarko Basin 62% 38% Domestic Production by Area 1

2017e Production and capital investments by area 142,500 – 145,500 boepd ~$1.0 billion 2017e domestic production up 3 – 5% over 2016 volumes, pro-forma for asset sales ~85% capital allocated to the Anadarko Basin Plan assumes an average of ~10 rigs in Anadarko Basin Investing in 2017 to test >1.0 billion barrels of potential net unrisked resource2 No investments in China, expected to deliver ~$70 million in cash flow at $55 per Bbl Brent oil 5 Anadarko Basin Other Other 1 Excludes capitalized interest and direct internal costs 2 Net unrisked resource 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 85% 15% Domestic Capital Investments 1 Anadarko Basin 67% 33% Domestic Production by Area

Domestic growth outlook 10 – 15% CAGR 20 – 25% CAGR 88 105 – 115 125 – 135 137 150 – 160 170 – 180 Liquids Gas Liquids Gas 190 – 210 150 – 170 65% 65% 35% 35% Domestic production growth forecast driven by the Anadarko Basin Plan assumes an average of ~10 rigs in the Anadarko Basin throughout the plan period Commodity price range: Oil $50 - $60 WTI and Gas $3 HH Plan does not include exploratory successes, acquisitions or divestitures Company goal: to maintain Net Debt / adjusted EBITDA ratios of 1.5 – 2.5x2 throughout plan period 6 1 Excludes production associated with Eagle Ford and south Texas asset sale. See page 16 for details 2 See page 9 for more information on ratios 1 4Q16 4Q17e 4Q18e 4Q19e Anadarko Basin Production ( Mboepd )

NFX to deliver double-digit domestic CAGRs (2017 – 19e) 15% CAGR 10% CAGR 20% CAGR 15% CAGR $50/$3 $60/$3 7 Domestic oil growth forecast driven by the Anadarko Basin Plan assumes an average of ~10 rigs in the Anadarko Basin throughout the plan period Commodity price range: Oil $50 - $60 WTI and Gas $3 HH Plan does not include exploratory successes, acquisitions or divestitures Company goal: to maintain Net Debt / adjusted EBITDA ratios of 1.5 – 2.5x1 throughout plan period 1 See page 9 for more information on ratios 2017e 2018e 2019e Domestic Oil Production

Shift to Anadarko Basin leads to lower costs 32% 67% Anadarko Basin as a % of Domestic Production Anadarko Basin grows from 32% of domestic production in 2014 to 67% in 2017e Domestic costs per boe down >25% from 2014 to 2017e 1 Excludes firm gas transportation fees and oil and gas delivery shortfall fees 8 Tax 1 Domestic Costs ($/boe) $16.05 $11.95 2014 2017e LOE Net G&A Transportation Production Tax TOTAL 2014 2017e

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 4.9% YTM1 1 Sourced from FactSet as of December 31, 2016. 2 Net debt represents principal balance of debt less cash on balance sheet. Adjusted EBITDA calculated per credit agreement definition; YE 2016 reflects 5th amendment executed 3/18/2016. See slide 25. Net debt / adj EBITDA2 Fixed debt maturity schedule $ millions No maturities for 5 years 9 $750 $1,000 $700 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 1.9x 1.9x 2.0x YE 2014 YE 2015 YE 2016

Anadarko Basin overview ~400,000 net acres in the Anadarko Basin ~90% HBP on “legacy” STACK acreage Acquired ~40,000 net acres in STACK in 2016 Expanded STACK footprint to the north >8,000 gross locations and ~2.4 billion barrels of net unrisked resource1 2017 – 19e plan assumes an average of ~10 rigs in the Anadarko Basin 85 – 95% capital allocated to the Anadarko Basin SCOOP STACK 10 Recent Extensional Leasing 1 Net unrisked resource 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

STACK results from recent “upsized” completions Current completion design: 2,100 lbs/ft & 2,100 gals/ft Recent “upsized” completions are performing above current 1.1 Mmboe type curve Evaluating completions and well spacing in 2017 1 All wells normalized to 10,000’ lateral length STACK 11 > 80% liquids > 60% oil 1.1 MMBOE Type Curve Recent Wells 0 5 10 0 40 80 120 0 20 40 60 80 100 Well Count MBOE Days Online Recent Upsized Completions 1

STACK spacing pilots outperforming type curve Initial results from the Chlouber and Dorothy pilots are outperforming the 1.1 Mmboe type curve Current completion design: 2,100 lbs/ft & 2,100 gals/ft 9 operated STACK infill pilots planned for 2017, participating in additional pilots 1 All wells normalized to 10,000’ lateral length 12 > 80% liquids > 60% oil > 80% liquids > 60% oil 1.1 MMBOE Type Curve Dorothy Pilot 1.1 MMBOE Type Curve Chlouber Pilot 0 50 100 150 0 20 40 60 80 100 MBOE Days Online Dorothy Pilot vs Type Curve 1 0 50 100 150 0 20 40 60 80 100 MBOE Days Online Chlouber Pilot vs Type Curve 1

Efficiencies and the move to pad drilling enhance productivity 13 1 Assumes 2-3 well pads. All other data for single well pads. ~2x the rig productivity since 2014 Average days to drill the lateral on an SXL down ~40% since 2014 “Best-in-class” SXL drilled in 5.9 days Down ~40% e ~11 ~14 ~17 21 - 24 2014 2015 2016 2017 Budget * STACK Wells – Rig – Year 1 14 8.8 5.9 2014 2016 Days to Drill STACK SXL “Lateral” (10,000’) AVG Lateral Days BIC Lateral Days

Appendix

YE16 proved reserves Domestic proved reserves are 99% of total ~180% proved reserve replacement ratio 55% of proved reserves are liquids 61% of proved reserves are proved developed Anadarko Basin proved reserves up 23% Y-o-Y and now represent 64% of total proved reserves 55% of Anadarko Basin proved reserves are liquids 513 Mmboe 15 >75% CAGR Williston Uinta Anadarko Basin Arkoma China 64% 10% 13% 12% 1% Proved Reserves by Area 35 116 181 269 330 2012 2013 2014 2015 2016 Mmboe Anadarko Basin Proved Reserves Liquids Gas

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).

2016 Average production by area Production Anadarko Basin Williston Basin Uinta Basin China (Liftings) 1 Oil (bopd) 28,932 12,344 13,104 14,673 NGL (boepd) 23,309 3,675 456 -- Gas (boepd) 33,711 3,615 2,779 -- Total (boepd) 85,952 19,634 16,339 14,673 1 Includes lifted volumes in the quarter. Not reflective of daily rate. Anadarko Basin net production was up 38% driven by STACK, which grew >100% Y-o-Y Anadarko Basin net oil production was up >40% Y-o-Y driven by STACK oil production, which grew >75% Y-o-Y 17

2017 Planned Activity Assumptions1 STACK SCOOP Operated Wells Spud: 85 – 90 ~50 Average Gross CWC: $7.5 – 8.0 million $7.5 – 8.0 million Average Completion: 2,100 lbs/ft & 2,100 gals/ft 1,500 lbs/ft & 2,000 gals/ft Average WI/NRI: 77%/62% 57%/46% Average Lateral Length: 8,750’ 8,061’ LOE ($/boe): $2.17 $1.30 Oil Transportation ($/Bbl): $1.50 N/A Gas/NGL Trans/Processing ($/Mcfe): $0.92 $0.95 Realizations Oil (%WTI): 98% 93% Gas (%HH): 90% 89% NGLs (%WTI): 43% 43% 18 1 Cost and expenses are expected to be within 5% of the estimates above

2017e Production, cost and expense guidance 19 Domestic China Total Production Oil % 40% 100% 43% NGLs % 20% -- 19% Natural Gas % 40% -- 38% Total (mboepd)1 142.5 – 145.5 5.7 – 6.0 148.2 – 151.5 Expenses ($/boe)2 LOE3 $3.43 $17.48 $3.97 Transportation4 $5.62 -- $5.40 Production & other taxes $1.16 $0.17 $1.12 General & administrative (G&A), net $3.42 $4.18 $3.45 Interest expense, gross -- -- $2.73 Capitalized interest and direct internal costs -- -- ($2.25) Effective Tax rate5 0 – 5% 0 – 5% 0 – 5% 1 Total Company and China volumes assume mid-year 2017 Bohai Bay divestiture close 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 ~$48.3 million Arkoma unused firm gas transportation and ~$36.8 million Uinta oil and gas delivery shortfall fees 5 Estimated China tax rate reflects a 25% taxation in-country

1Q17e Production, cost and expense guidance 20 Domestic China Total Production Oil % 40% 100% 44% NGLs % 19% -- 18% Natural Gas % 41% -- 38% Total (mboepd) 132.0 – 134.2 6.5 – 7.5 138.5 – 141.7 Expenses ($/boe)1 LOE2 $3.80 $13.33 $4.28 Transportation3 $5.89 -- $5.60 Production & other taxes $1.18 $0.22 $1.13 General & administrative (G&A), net $3.76 $3.29 $3.74 Interest expense, gross -- -- $2.98 Capitalized interest and direct internal costs -- -- ($2.41) Effective Tax rate4 0 – 5% 20 – 25% 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 1Q17e transportation / processing fees include ~$12.4 million Arkoma unused firm gas transportation and ~$9.0 million Uinta oil and gas delivery shortfall fees 4 Estimated China tax rate reflects a 25% taxation in-country

Oil Hedging Details as of 02/21/17 21 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 1Q 2017 17,000 15,000 28,000 13,000 $45.43 -- -- -- -- $73.73/$89.23 -- -- -- -- $74.29 -- -- -- -- $75.00/$90.00-$95.52 2Q 2017 17,000 10,000 20,000 10,000 $45.43 -- -- -- -- $73.10/$88.09 -- -- -- -- $74.05 -- -- -- -- $75.00/$90.00-$95.69 3Q 2017 17,000 13,000 13,000 -- $45.43 -- -- -- -- $73.08/$87.90 -- -- -- -- $73.08 -- -- -- -- -- 4Q 2017 17,000 11,000 11,000 -- $45.43 -- -- -- -- $73.09/$88.01 -- -- -- -- $73.09 -- -- -- -- -- 1 Below $73.73 per Bbl for 1Q 2017, $73.10 for 2Q17, $73.08 for 3Q17, and $73.09 for 4Q17, these contracts effectively result in realized prices that are on average $15.50, $14.99, $14.82 and $14.92 per Bbl higher, respectively, than the cash price that otherwise would have been realized. 2 Above $74.29 per Bbl plus the call premium of $1.11 per Bbl for 1Q 2017, above $74.05 plus the call premium of $1.47 for 2Q17, 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 or short put and long put (less the call premium). 3 Below $75.00 per Bbl in 2017, these contracts effectively result in realized prices that are on average $15.00 per Bbl higher than the cash price that otherwise would have been realized. Denotes update

Oil Hedging Details as of 02/21/17 22 Oil Prices Period $20 $30 $40 $50 $60 $70 $80 $90 1Q 2017 $75 $59 $44 $29 $13 ($2) ($17) ($32) 2Q 2017 $64 $48 $33 $18 $2 ($13) ($29) ($44) 3Q 2017 $55 $39 $24 $8 ($7) ($23) ($39) ($54) 4Q 2017 $53 $37 $22 $6 ($10) ($25) ($41) ($57) Denotes update 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.

Gas Hedging Details as of 02/21/17 23 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 1Q 2017 75,000 140,000 $2.73 -- -- $2.79-$3.20 2Q 2017 75,000 140,000 $2.73 -- -- $2.79-$3.20 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 Denotes update

Gas Hedging Details as of 02/21/17 24 Gas Prices Period $1.75 $2.00 $2.50 $3.00 $3.50 $4.00 $5.00 1Q 2017 $20 $15 $5 ($2) ($9) ($19) ($38) 2Q 2017 $20 $15 $5 ($2) ($9) ($19) ($38) 3Q 2017 $20 $15 $5 ($2) ($10) ($19) ($39) 4Q 2017 $24 $19 $7 ($1) ($10) ($20) ($43) 1Q 2018 $17 $14 $8 $2 ($2) ($5) ($18) 2Q 2018 $6 $5 $2 $0 ($2) ($5) ($10) 3Q 2018 $6 $5 $2 $0 ($2) ($5) ($10) 4Q 2018 $6 $5 $2 $0 ($2) ($5) ($10) Denotes update 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.

Non-GAAP reconciliation of Adjusted EBITDA 25 Twelve Months Ended December 31, ($ in millions) 2014 2015 2016 Net Income $900 ($3,362) ($1,230) Adjustments to derive EBITDA: Interest expense, net of capitalized interest $147 $131 $103 Income tax provision (benefit) 526 (1,585) 22 Depreciation, depletion and amortization 903 917 572 EBITDA $2,476 ($3,899) ($533) Adjustments to EBITDA: Ceiling test and other impairment $ - $4,904 $1,028 Gain on sale of Malaysia business (373) - - Non-cash stock-based compensation 28 25 22 Unrealized (gain) loss on commodity derivatives (649) 246 392 Other permitted adjustments1 9 19 59 Adjusted EBITDA per credit agreement2 $1,491 $1,295 $968 1 Other permitted adjustments per amended credit agreement include but are not limited to inventory write-downs, office-lease abandonment, severance and relocation costs 2 Adjusted EBITDA calculated per credit agreement definition; December 31, 2016 reflects 5th amendment executed 3/18/2016

Forward looking statements & 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,” “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, 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. 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, China and U.S. 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 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 and 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 actual 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 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 (loss) income before income tax (benefit) expense, interest expense and depreciation, depletion and amortization. Adjusted EBITDA, as presented herein, is EBITDA before ceiling test impairments, gains on asset sales, non-cash compensation expense and net unrealized (gains) / losses on commodity derivatives. 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 alternatives 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. 26