1Q18 UPDATE

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 Report 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 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 (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 location,” “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

First Quarter Highlights: Delivering On Our Plan We are “on track” to deliver our 2018 guidance and 3YR Plan 1Q18 domestic net production up 25% Y-o-Y: 173,600 BOEPD (41% oil, 61% liquids) 1Q18 Anadarko net production up 34% Y-o-Y: 117,500 BOEPD (34% oil, 60% liquids) 1Q18 capital spending of $345 million Reiterated full-year capital investment plan of approximately $1.3 billion (excluding capitalized internal costs) 3YR Plan designed to generate significant Free Cash Flow Proactively planning for our future Minimized impact of higher natural gas differentials in the Anadarko Basin through long-term agreements with various counterparties Expanded unsecured credit facility by $200 million to $2.0 billion (extended term to May 2023) Continued success with STACK development Stark 10-well Meramec pad reached payout in approximately 12 months Learnings from Velta June 12-well Meramec pad being applied across Anadarko Basin Stronger than anticipated net production from Western STACK HBP program 4 “RECORD”

Strong Domestic Production Driven by Anadarko Basin 5 “NEW” “NEW” Domestic Production Guidance (mboepd) Anadarko Basin Production Guidance (mboepd) Increased 2018E domestic production expectations based on strong 1Q results (ahead of 3YR Plan objectives) Raised Anadarko Basin 2018E guidance based on strong well performance On track to deliver on 3YR Plan (20% and 15% annualized growth in Anadarko Basin and Domestic production, respectively) DOMESTIC

Operated Meramec Development Supports 3YR Plan 6 STACK Existing infill developments Upcoming infill developments Stark - 10 well INFILL Avg. GPI: 9,953’ VELTA JUNE - 12 well INFILL Avg. GPI: 4,864’ Rodenburg - 8 well INFILL Avg. GPI: 9,463’ Margie - 6 well INFILL Avg. GPI: 10,149’ Jackson / Florene* - EFFECTIVE 6 WELL MERAMEC INFILL* Avg. GPI: 10,146’ NOTE: Production data represents infill well averages normalized to 10,000’ laterals. *Four Meramec wells drilled ~1,700’ apart in one layer. Development Projects In-Line / Above 3YR Plan TC REACHED PAYOUT in ~12 MONTHS 0 50 100 150 200 250 300 350 0 2 4 6 8 10 12 AVG. CUMULATIVE MBOE Months Online 3YR Plan VELTA JUNE STARK RODENBURG MARGIE JACKSON / FLORENE

Strong Gas Results in Western STACK HBP Program Western STACK HBP STACK LOIS 1H-36 Avg. GPI: 4,672’ IP24: 1,842 boepd (40% Oil) Sawyer 1H-27x Avg. GPI: 7,733’ IP24: 2,483 boepd (54% Oil) Sandrock 1H-12x Avg. GPI: 9,438’ IP24: 29,382 mcfepd (0% Oil) Debbie 1H-3x Avg. GPI: 9,666’ IP24: 27,678 mcfepd (8% Oil) Recent Newfield operated wells demonstrate prolific nature of region IP24 for key wells: Sandrock 1H-12X: >29,000 mcfepd Debbie 1H-3X: >27,500 mcfepd Sawyer 1H-27X: 2,483 boepd Lois 1H-36: 1,842 boepd Wells drilled for HBP purposes Preserves long-term future development option Western STACK acreage substantially HBP’d 7

Proactive Marketing Unlocking 1Q18 Premium Realizations Anadarko Basin crude receiving top-tier pricing amongst US basins (blended average of approximately 100% of WTI) Relative to other basins (Williston @ $3/bbl discount and Permian @ $8/bbl discount3), Anadarko Basin crude (specifically the STACK barrel) generates premium realizations 8 Basin 1Q18 Crude % of WTI2 1Q18 NGL % of WTI2 1Q18 Gas % of HHub2 STACK ~100% 43% 84% SCOOP 96% 46% 97% Williston 95% 51% 96% Uinta 75% 46% 79% Arkoma NA NA 87% Domestic 92% 45% 90% Additional benefits from NFX’s proactive efforts to mitigate risk of wider Mid-Con differentials: Contracted capacity expansions through Enable add >200,000 mmbtu/d total capacity by YE2018 Gathering arrangements and physical sales to outside markets yielding premium pricing Marketing solutions yield premium prices (current in-basin differentials yielding 50-60% of Henry Hub)

Net debt / Adj EBITDA4 Long-Term Debt Maturities $ millions No maturities until 1/30/2022 Leverage Decreases Throughout 3YR Plan Expect to lower net debt to Adjusted EBITDA ratio throughout 3YR Plan Improved liquidity with recent expansion of Credit Facility $2.0 billion undrawn unsecured credit facility (+$200 million); term extended to May 2023 Optionality to address long-term debt maturities No maturities within planning horizon 9 Improving Debt Profile “NEW” “NEW” $750 $1,000 $700 2018 2018 2019 2020 2021 2022 2023 2024 2025 2026 1.9x <1.8x 1Q18A 2018E 2019E 2020E

1Q18 Results

1Q18 Domestic Results 4Q17 ACTUAL 1Q18 GUIDANCE 1Q18 ACTUAL PRODUCTION Oil (mbopd) 67 71 72 NGL (mbopd) 36 33 35 Gas (mmcfpd) 398 394 401 Total (mboepd) 170 167-173 174 EXPENSES ($/BOE)* LOE $3.18 $3.43 $3.52 Transportation** $4.92 $5.09 $5.02 Production & other taxes $1.33 4.2% $1.53 General & administrative, net $2.98 $3.44 $3.35 CAPEX ($MM)*** $306 $340 $345 OPERATIONS Operated rigs 11 - 11 Op. wells placed on production (WI%/NRI%) 32 (65% / 53%) - 54 (54% / 44%) Op. wells placed on production (Average GPI) 8,552‘ - 8,312’ *Guidance numbers for Expenses shown on annual basis. **Actual transportation fees include $13 million and $12 million associated with firm gas transportation in the Arkoma Basin during 4Q17A and 1Q18A, respectively, as well as $5 million and $4 million of shortfall fees in the Uinta Basin in 4Q17 and 1Q18, respectively. *** CAPEX excludes ~$28 million of capitalized interest and direct internal cost related to both 4Q17A and 1Q18A. 11

1Q18 Basin Results ANADARKO WILLISTON UINTA ARKOMA PRODUCTION Oil (mbopd) 40.2 14.0 17.0 0.0 NGL (mbopd) 30.9 3.4 0.6 0.2 Gas (mmcfpd) 278.8 18.2 16.7 84.1 Total (mboepd) 117.5 20.4 20.3 14.3 EXPENSES ($/BOE) LOE $2.06 $4.96 $10.44 $3.03 Transportation* $4.06 $5.69 $1.77 $4.12 Production & other taxes $1.05 $4.02 $2.37 $0.81 Total Expenses $7.17 $14.66 $14.57 $7.96 CAPEX ($MM) Drilling & Completion $264 $22 $34 $1 Other $18 $0 $1 $0 Total CAPEX** $282 $22 $35 $1 OPERATIONS Operated rigs 9 1 1 0 Op. wells placed on production (WI%/NRI%) 43 (52% / 42%) 4 (40% / 33%) 7 (76% / 61%) NA Op. wells placed on production (Average GPI) 8,399’ 10,138’ 6,733’ NA 12 * Transportation fees exclude $12 million and $4 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. ** CAPEX excludes $5 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 38 Gas (mmcfpd) 356.5 412 Total (mboepd) 152.2 175 - 185 EXPENSES ($/BOE) LOE $3.47 $3.43 Transportation* $5.40 $4.95 Production & other taxes 3.5% 4.7% General & administrative, net $3.49 $3.44 Interest expense, net $1.62 $1.42 CAPEX ($MM) Drilling & Completion $992 $1,160 Other $161 $140 Total CAPEX** $1,153 $1,300 CHINA GUIDANCE Production (mbopd) 4.7 3 - 5 13 * 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 ~$38 million and ~$21 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 GUIDANCE 1Q18 ACTUAL 2Q18E 3Q18E 4Q18E PRODUCTION Oil (mbopd) 71 72 72 77 75 NGL (mbopd) 33 35 37 38 42 Gas (mmcfpd) 394 401 402 412 430 Total (mboepd) 167-173 174 172 – 180 179 – 187 183 – 194 CAPEX ($MM) $340 $345 $360 $295 $300 14 *China estimates include first quarter lifting of 261,000 barrels and planned liftings of approximately 750,000 barrels in second quarter. Additional liftings totaling approximately 500,000 barrels are planned in the second half of 2018. ANADARKO GUIDANCE 1Q18 GUIDANCE 1Q18 ACTUAL 2Q18E 3Q18E 4Q18E PRODUCTION Oil (mbopd) 40 40 42 44 42 NGL (mbopd) 29 31 33 34 37 Gas (mmcfpd) 272 279 288 294 320 Total (mboepd) 112 – 116 117 120 – 126 122 – 132 126 – 139 CAPEX ($MM) $255 $282 $265 $250 $245 China Production (mboepd)* 2 – 3 3 7 – 9 2 – 3

APPENDIX

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 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) *Reflects recent Oklahoma Regulatory Changes to Gross Production Tax Rate *Realizations relative to NYMEX STRIP pricing as of March 31, 2018 Denotes update 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 *Realizations relative to NYMEX STRIP pricing as of March 31, 2018 Denotes update 0 100 200 300 400 500 600 700 0 1 2 3 4 5 6 7 8 9 10 11 12 MBOE Months Online SCOOP Wet Gas 3YR Plan Type Curve 0 50 100 150 200 250 300 350 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 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 04/26/18 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts5 Collars6 Collars w/ Short Puts7 2Q 2018 47,000 -- 14,000 -- $54.90 -- -- -- -- -- -- -- -- -- $50.59-$56.70 -- -- -- -- -- 3Q 2018 53,000 3,500 -- -- $54.75 -- -- -- -- $44.00/$56.78 -- -- -- -- -- -- -- -- -- -- 4Q 2018 25,000 3,500 -- 21,000 $54.08 -- -- -- -- $44.00/$56.78 -- -- -- -- -- -- -- -- -- $39.47/$48.34-$56.60 Denotes update 19

Oil Hedging Details as of 04/26/18 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 04/26/18 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 2Q 2018 $188 $133 $77 $23 ($26) ($82) ($137) 3Q 2018 $174 $125 $73 $28 ($27) ($79) ($131) 4Q 2018 $100 $77 $50 $14 ($21) ($67) ($112) 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) 21

Gas Hedging Details as of 04/26/18 Weighted-Average Price Period Volume (mmbtu/d) Swaps Swaps w/ Short Puts9 Collars Collars w/ Short Puts10 2Q 2018 160,000 40,000 10,000 30,000 $2.99 -- -- -- -- $2.60/$2.97 -- -- -- -- $2.90-$3.15 -- -- -- -- $2.30/$2.87-$3.32 3Q 2018 150,000 40,000 10,000 30,000 $2.99 -- -- -- -- $2.60/$2.97 -- -- -- -- $2.90-$3.15 -- -- -- -- $2.30/$2.87-$3.32 4Q 2018 120,000 66,500 39,900 10,100 $2.99 -- -- -- -- $2.66/$3.03 -- -- -- -- $2.88-$3.28 -- -- -- -- $2.30/$2.87-$3.32 22

Gas Hedging Details as of 04/26/18 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 04/26/18 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. Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 2Q 2018 $18 $10 $0 ($10) ($21) ($32) ($43) 3Q 2018 $17 $9 $0 ($10) ($20) ($31) ($42) 4Q 2018 $17 $9 $0 ($9) ($20) ($31) ($42) 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) 24

Propane Hedging Details as of 04/26/18 Weighted-Average Price Period Volume (bbl/d) Swaps ($/gal) 2Q 2018 5,000 $.819 3Q 2018 4,000 $.811 4Q 2018 3,000 $.807 25

Propane Hedging Details as of 04/26/18 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. Propane Prices Period $.50 $.60 $.70 $.80 $.90 $1.00 $1.10 2Q 2018 $6.1 $4.2 $2.3 $0.4 ($1.5) ($3.5) ($5.4) 3Q 2018 $4.8 $3.3 $1.7 $0.2 ($1.4) ($2.9) ($4.5) 4Q 2018 $3.6 $2.4 $1.2 $0.1 ($1.1) ($2.2) ($3.4) 26

Non-GAAP reconciliation of Adjusted EBITDA 27 ($ in millions) Twelve Months Ended December 31, March 31, 2016 2017 2018 Net Income $(1,230) $427 $366 Adjustments to derive EBITDA: Interest expense, net of capitalized interest 103 89 90 Income tax provision (benefit) 22 (41) (35) Depreciation, depletion and amortization 572 467 494 EBITDA $(533) $942 $915 Adjustments to EBITDA: Ceiling test and other impairment $1,028 - - Non-cash stock based compensation 22 34 31 Unrealized (gain) loss on commodity derivatives 392 83 195 Other permitted adjustments* 59 8 9 Adjusted EBITDA** $968 $1,067 $1,150 *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. NFX 1Q18 Actuals for WTI and HHub were $62.87/bbl and $3.00/mmbtu, respectively. Williston and Permian discount to WTI based on April 2018 pricing indexes. Net Debt calculated as principal balance of debt less cash and cash equivalents on balance sheet and Adjusted EBITDA as defined on page 28. 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. The collars for 2Q18 were created by buying back our short puts that were part of 3-way transactions. 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 2Q18-3Q18 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 2Q18-4Q18 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 March 31, 2018. Adjusted EBITDA – See page 27 for a reconciliation. Controllable Capital (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. Free Cash / Free Cash Flow – Determined by subtracting Controllable Capital from the aggregate of cash flow and capitalized expenses, such as interest and general and administrative expenses at 3YR Plan Assumptions. GPI – Gross Perforated Interval, which reflects the total feet completed in each horizontal wellbore. IP24 – Average peak initial production rate over a 24-hour period of time. Well Cost – Includes capital associated with drilling, completions, facilities and artificial lift. 29