Exhibit 99.2 @NFX – 1Q16 May 3, 2016 @NFX is periodically published to keep stockholders aware of current operating activities at Newfield. It may include estimates of expected production volumes, costs and expenses, recent changes to hedging positions and commodity pricing.

Strong 1Q16 results highlight superior execution High-graded capital investments and reduced expenditures to better align with cash flow De-levered and enhanced liquidity through recent equity offering Enhanced hedge portfolio for 2016 – 17 (~$210 mm in 2016 and ~$55 mm in 20171) 1Q16 average Anadarko Basin net production 78,400 boepd Northern STACK wells tracking above type curve Recent completed STACK SXL well costs $6.9 mm2 Exceeded 1Q16 production guidance mid-point by 500 Mboe Reduced domestic LOE / Boe nearly 40% year-over-year Best-in-class STACK SXL well drilled in 8.3 days 1 Strip prices as of April 29, 2016 2 D&C includes gross drilling, completion, artificial lift and facilities costs 2 Operations execution Advancing the learning curve in the Anadarko Basin Balance sheet reinforcement

2016 capital investments YTD Total Company ($ in millions) Q1 Q2 Q3 Q4 YTD16 Exploration & development Acquisitions Leasehold Pipeline $221 ---- --$221 $1 ---- --$1 $11 ---- --$11 ---- ---- --1 Excludes ~$26 million in capitalized interest and direct internal costs 3 2016e capital investments $625 – $675 mm ~ Two-thirds of 2016e total capital to be invested in 1H16 Total1 $233------$233

1Q16 Average production by area 1 Includes lifted volumes in the quarter. Not reflective of daily rate. 4 Anadarko Basin net production was 53% of total domestic 1Q16 net production Achieved record daily net production in the Williston Basin Production Anadarko Basin Williston Basin Uinta Basin Eagle Ford China (Liftings) 1 Oil (bopd) 26,341 14,495 13,648 3,747 18,055 NGL (boepd) 20,352 3,956 418 1,989 --Gas (boepd) 31,718 4,364 2,960 2,333 --Total (boepd) 78,411 22,815 17,026 8,069 18,055

Anadarko Basin key messages Grew 1Q16 average net production to 78,400 boepd – 53% of total domestic production Drilling remains focused on HBP Northern STACK SXL results tracking above type curve – 24 wells average 30-day rate: 1,057 boepd (69% oil and 83% liquids) – 12 “NEW” wells average 30-day rate: 1,067 boepd (69% oil and 83% liquids) SCOOP continues to deliver – “NEW” SCOOP Oil pad (5 wells) average 30-day rate: 1,360 boepd (59% oil and 79% liquids) – “NEW” SCOOP Springer well average 30-day rate: 1,468 boepd (81% oil and 90% liquids) Record “days-to-depth” lowers STACK drilling costs – 2016 YTD 10,000’ SXL wells drilled on average in 17 days – “NEW” best-in-class STACK 10,045’ SXL well drilled in 8.3 days Newfield acreage 5 Woodford Meramec SCOOP STACK

Recent NFX northern STACK SXL results continue delineation “NEW” JR Barton well (9,898’) IP30*: 1,480 boepd (76% oil) “NEW” Helen well “best-in-class” SXL (10,045’) drilled in 8.3 days completion underway “NEW” Vickie well (10,096’) CWC: $6.9 mm (including facilities) flowing back now Note: IP* denotes three stream rate (oil / gas / NGLs) 1 Includes only 9 wells in 90-day average 6 NFX operated STACK SXL wells 24 NFX operated northern STACK SXL wells 2014+ non-op STACK spuds NFX STACK region “NEW” Wells1 IP30* IP60* IP90* 12 1,067 980 991 3-stream 30-day avg. from 12 “NEW” northern STACK SXL wells: 1,067 boepd (69% oil & 83% liquids)

NFX northern STACK SXL results tracking above type curve Northern STACK SXL actual daily production vs 950 Mboe type curve1 Well Count 24 Boepd 1,200 20 1,000 16 800 12 600 8 400 4 200 0 0 0 50 100 150 200 250 300 Note: 24 wells with at least 7,500’ of gross perforated interval and at least 60 days of production 1 EUR refers to potential recoverable oil and natural gas hydrocarbon quantities with ethane processing and may not be reflective of SEC proved reserves. Actual quantities that may be recovered could vary significantly 2 Includes only 21 wells for 90 day rate. 7 Average daily production (Boepd) 24 Northern Wells2 30 days60 days90 days 1,057887740 Well Count Northern STACK Wells 950 Mboe1 Days online

NFX STACK SXL drilling days continue to improve 10,000’ Laterals 45 40 35 30 25 20 15 10 5 0 2012 2 Wells 2013 8 Wells 2014 23 Wells 2015* 51 Wells 2016YTD* 8 Wells 2016e* 35 Wells BIC* Note: *Wells drilled from mid-2015 forward are “drill out to TD” due to presetting surface casing. 8 Days to TD Recent “best-in-class” STACK SXL well drilled in 8.3 days 2016e plan includes 35 SXL wells and 20 XL wells 39 31 25 21 17 14 8

Industry leading results – Williston Basin Skaar Pad (XL wells) Skaar Middle Bakken Average Avg. WI Avg. NRI 94% 76% Lateral length (ft) 24 IP Rate (Bopd) Gross EUR (Mboe) 1 4,900’ 2,460 615 % Oil % NGLs 63% 18% LOE/Boe Oil transportation ($ / Bbl) $3.50 $2.50 Oil differential ($ /Bbl) $5.50 Tax (% of revenue) 10% Avg. ROR 3 Pad NPV ($ mm) 3 66% $16.3 1 EUR refers to potential recoverable oil and natural gas hydrocarbon quantities with ethane processing and may not be reflective of SEC proved reserves. Actual quantities that may be recovered could vary significantly 2 Gross completed well cost includes gross drilling, completion, artificial lift and facilities costs 3 Pre-tax ROR/NPV based on price deck of $45/50/55 per bbl and $2.25/2.50/2.75 per Mmbtu for 2016-18 and flat thereafter 9 PAD Gross CWC ($ mm) 2$4.0

Appendix

2016e Production, cost and expense guidance Domestic China Total Production Oil (Mmbls) NGLs (Mmbls) Natural Gas (Bcf) 20.0 – 20.6 9.2 – 9.6 125 – 130 4.5 ---- 24.5 – 25.1 9.2 – 9.6 125 – 130 Expenses ($ mm)1 LOE2 Transportation3 Production & other taxes $200 260 45 $254 260 46 $54 --1 General & administrative (G&A), net Interest expense, gross $165 154 $7 --$172 154 Capitalized interest and direct internal costs Effective Tax rate4 ($103) 2% --1% ($103) 1% Note: Based on strip commodity prices 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 Estimated transportation / processing fees include ~$52MM Arkoma unused firm gas transportation and ~$21MM Uinta oil and gas delivery shortfall fees 4 The effective tax rate reflects expected future valuation allowances recorded against deferred tax assets generated by ceiling test impairments 11 Total (Mmboe)50.0 – 52.0 4.55 4.5 – 56.5

2Q16e Production, cost and expense guidance Domestic China Total Production Oil (Mmbls) NGLs (Mmbls) Natural Gas (Bcf) 5.0 – 5.2 2.5 – 2.8 33 1.4 ---- 6.4 – 6.6 2.5 – 2.8 33 Expenses ($ mm)1 LOE2 Transportation3 Production & other taxes $50 66 11 $64 66 11 $14 ---- General & administrative (G&A), net Interest expense, gross $42 38 $2 --$44 38 Capitalized interest and direct internal costs Effective Tax rate4 ($26) 2% --1% ($26) 1% Note: Based on strip commodity prices 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 Estimated transportation / processing fees include ~$13MM Arkoma unused firm gas transportation and ~$3MM Uinta oil and gas delivery shortfall fees 4 The effective tax rate reflects expected future valuation allowances recorded against deferred tax assets generated by ceiling test impairments 12 Total (Mmboe)13.0 – 13.5 1.4 14.4 – 14.9

Oil hedging details as of 04/29/16 2016 Activity: $62 $60 $58 $56 $54 $52 $50 $48 • Permatized remainder of max-payout structures (3-way collars and swaps + short puts) for time periods after 2Q16 Entered into new swaps for May16-Dec17 Note: all permatized volumes are effectively back at a ‘market price’ and can now be re-hedged • • Q116 Q216 Q316 Q416 Q117 Q217 Q317 Q417 Effective Price An Example (using 3Q16) • 3-way collars ($75/$90-$96) – max payout is the $15 spread between the $90 long put and the $75 short put Swap + short puts ($74.44/$90.03) – max payout is difference between the swap and the short put ($15.59) We permatized $14.25 per barrel by purchasing calls 15,000 barrels/d are now locked in at $41.59 + $14.25 = effective realized price of $55.84 per barrel 50 45 40 35 30 25 20 15 10 5 0 • • • Q116 Q216 Q316 Q416 Q117 Q217 Q317 Q417 Permatized Volume Pre-2016 Permatized Volume Swap Volume 13 Effective Realized Price ($/bbl) Daily Volume (KB/d) 59.59 58.96 55.84 55.63 55.21 53.76 51.97

Oil hedging details as of 04/29/16 SWAPS PUTS1 CALLS2 PUTS3 0 33,000 7,000 17,000 — — — — — $73.48/89.97 — — — — $68.64 — — — — $75.00/90.00-$96.30 1Q 2016 7,000 — — $69.21 — 15,000 27,000 43,000 16,000 $41.59 — — — — $74.44/90.03 — — — — $73.76 — — — — $75.00/90.00-$95.98 3Q 2016 39,000 — — $73.63 — 1 Below $73.48 per Bbl for 1Q 2016, $74.44 for 2Q16, $74.44 for 3Q16, $74.35 for 4Q16, these contracts effectively result in realized prices that are on average $16.49, $15.55, $15.59, and $15.55 per Bbl higher, respectively, than the cash price that otherwise would have been realized. 2 Above $68.64 per Bbl plus the call premium of $3.27 per Bbl for 1Q 2016, above $69.21 plus the call premium of $3.44 for 2Q16 , above $73.76 plus the call premium of $1.12 for 3Q16, and above $73.63 plus the call premium of $1.28 for 4Q16, 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 2016, 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. Note: We have entered into swaption contracts that would potentially hedge 4.048 MMBO of 2H16 production at a swap price of $42 and 0.368 MMBO at a swap price of $50 if exercised on their expiration in June, 2016. Any future potential settlement value will be excluded herein unless and until the swaptions are exercised. 14 Denotes update 15,000$41.59——— 4Q 2016 23,000—$74.35/89.90—— 16,000———$75.00/90.00-$95.98 8,700 $42.23——— 2Q 2016 27,000—$74.44/89.99—— 19,000———$75.00/90.00-$96.32 PERIOD VOLUME (BBL/D) WEIGHTED-AVERAGE PRICE SWAPS W/ SHORT PURCHASED COLLARS W/ SHORT

Oil hedging details as of 04/29/16 SWAPS PUTS1 CALLS2 PUTS3 17,000 15,000 28,000 13,000 $45.43 — — — — $73.73/89.23 — — — — $74.29 — — — — $75.00/90.00-$95.52 1Q 2017 20,000 — — $74.05 — 17,000 13,000 13,000 — $45.43 — — — — $73.08/87.90 — — — — $73.08 — — — — — 3Q 2017 11,000 — — $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. 15 17,000$45.43——— 4Q 201711,000—$73.09/88.01—— ————— 17,000$45.43——— 2Q 201710,000—$73.10/88.09—— 10,000———$75.00/90.00-$95.69 PERIOD VOLUME (BBL/D) WEIGHTED-AVERAGE PRICE SWAPS W/ SHORT PURCHASED COLLARS W/ SHORT

Oil hedging details as of 04/29/16 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. 1Q 2016 $71 $71 $71 $71 $71 $70 $51 $11 3Q 2016 $86 $72 $59 $45 $31 $18 $7 ($7) 1Q 2017 $75 $59 $44 $29 $13 ($2) ($17) ($32) 3Q 2017 $55 $39 $24 $8 ($7) ($23) ($39) ($54) 16 4Q 2017 $53 $37 $22 $6 ($10) ($25) ($41) ($57) 2Q 2017 $64 $48 $33 $18 $2 ($13) ($29) ($44) 4Q 2016 $80 $66 $53 $39 $25 $12 $1 ($13) 2Q 2016 $80 $72 $64 $56 $48 $40 $17 ($27) Oil Prices Period $20 $30 $40 $50 $60 $70 $80 $90

Gas hedging details as of 04/29/16 50,000 30,000 $3.39 — — $4.00 - $4.54 1Q 2016 30,000 — $4.00 - $4.54 — 30,000 — — — $4.00 - $4.54 3Q 2016 30,000 — $4.00 - $4.54 75,000 80,000 $2.73 — — $2.64 - $2.93 1Q 2017 80,000 — $2.64 - $2.93 75,000 80,000 $2.73 — — $2.64 - $2.93 3Q 2017 80,000 — $2.64 - $2.93 Note: We have entered into swaption contracts that would potentially hedge 18.4 TBtu of 2H16 production at a swap price of $2.25 and 18.4 TBtu at a swap price of $2.30 if exercised on their expiration date of June 23, 2016. Any future potential settlement value will be excluded herein unless and until the swaptions are exercised. 17 4Q 2017 75,000 $2.73— 2Q 2017 75,000 $2.73— 4Q 2016——— 2Q 2016——— PERIOD VOLUME (MMBTU/D) WEIGHTED-AVERAGE PRICE SWAPS COLLARS

Gas hedging details as of 04/29/16 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. 1Q 2016 $12 $5 ($3) ($9) ($16) 3Q 2016 $6 $3 $0 ($1) ($4) 1Q 2017 $10 ($2) ($16) ($30) ($44) 3Q 2017 $10 ($2) ($17) ($31) ($45) 18 4Q 2017$10($2)($17)($31)($45) 2Q 2017$10($2)($16)($31)($45) 4Q 2016$6$3$0($1)($4) 2Q 2016$5$3$0($1)($4) Gas Prices Period$2$3$4$5$6

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,” “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, and other operating risks. Please see Newfield’s 2015 Annual Report on Form 10-K and Quarterly Report on Form 10-Q for 1Q 2016, both 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 2015 Annual Report on Form 10-K and 1Q 2016 Quarterly Report on Form 10-Q, 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. 19