3YR OUTLOOK & 2017 RESULTS

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,” “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 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 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 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 or induced seismicity, and other operating risks. Please see Newfield’s 2017 Annual Report on Form 10-K 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. 2

Forward Looking Statements and Related Matters (continued) 3 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 45 of this presentation.

3YR Plan Objectives – Our Focus is Clear NFX Strong Margins, Returns and Debt Adjusted Growth2 Improved well IRR (>50% pre-tax) across development regions Reduced LOE per boe by ~20% by end of plan 20-30% CAGR in est. cash flow per debt adjusted share Strong Balance Sheet and Capital Structure Maintain strong liquidity during plan period Reduce leverage: Less than 2.0x net debt / EBITDA5 Ability to generate approximately $370MM free cash @ $55/$2.85 Returns Focused Development Plan Near-term drilling focused on highest returns Development drilling in Anadarko Basin 3YR Plan demonstrates continued advancements in well profile/learning curve Improved near-term type curves 4 Strong Margins, Returns and Debt Adjusted Growth Strong Balance Sheet and Capital Structure Returns Focused Development Plan

Strong 3YR Plan Driven By High-Graded STACK Development Drilling Investing: ~$4.2 billion of capital investments thru 2020E1 ~90% allocated to D&C (drill and complete) investments > 400 operated STACK wells placed on production during 3YR Plan Growing (Estimated CAGR): 14-18% in domestic production 17-21% in domestic oil production 15-20% in production per debt adj. share 20-30% in cash flow per debt adj. share Delivering: Estimated ~$370 million in free cash flow thru 20202 ~$1 billion free cash flow potentially generated @ $60/bbl and $3/mmbtu 5 STACK 3YR Plan Assumptions: EUR Range: 1.1 – 1.7 MMBOE7 Well Cost Range (incl. facilities): $7.6 – $8.7 million 3YR Plan Average: 1.3 MMBOE7 EUR @ $7.9 million well cost (incl. facilities) 1 2 3 4 5 6 7 8 9 10 11 12 0 0 50 100 150 200 250 300 0 60 120 180 240 300 360 CUMULATIVE MBOE Months Online STACK 3YR Plan Well Profile

Strong Domestic Production Profile and Debt Adjusted Growth Sustained growth within cash flow Projecting >16 MMBOE increase in production relative to original 3YR Plan 14-18% Annual Production Growth (10-15% Annual Growth in Prior Plan) 15-20% Annualized Production per Debt Adjusted Share Growth 6 144 162 3 182 3 152 170 - 183 195 - 215 225 - 250 2017A 2018E 2019E 2020E MBOEPD Original 3YR Plan (Feb. '17) Updated 3YR Plan (Feb '18)

Anadarko Basin Growth Driven By High-Graded Drilling Program 20-25% Anadarko Basin Production Growth Per Year 7 Nearly 550 operated wells will be placed on production during 3YR Plan Potential to grow production 75-100 MBOEPD over next three years Oil volume annualized growth estimated at 25-30% through 3YR Plan 2017A 2018E 2019E 2020E MBOEPD SCOOP STACK ~100 116 - 128 145 - 165 175 - 200

STACK To Drive Anadarko Basin Production Growth 8 51 48 65-70 51-58 55-65 90-100 120-135 55-65 STACK Annualized Production Growth Estimated to be >30% STACK Oil Annualized Growth Estimated to be 30-40% STACK now accounts for >50% of total Anadarko Basin production Anadarko Basin growth driven by STACK development in 3YR Plan STACK oil production expected to more than double by 2020 STACK liquids* projected to expand 2.5X by 2020 OIL ~23% ~32% ~45% ~25% ~29% ~46% ~25% ~30% ~45% ~28% ~30% ~42% ~45% ~24% ~31% ~45% ~45% ~45% ~22% ~22% ~24% ~33% ~33% ~31% NGL GAS SCOOP STACK * Liquids defined as oil and NGL volumes. 2017A 2018E 2019E 2020E NET MBOEPD GAS GAS2 2017A 2018E 2019E 2020E NGL NGL2 2017A 2018E 2019E 2020E OIL

Strong Cash Flow Profile and Debt Adjusted Growth $300-$1,000 mm Cumulative Free Cash Generating Potential 20-30% Estimated Annualized Growth In Cash Flow per Debt Adjusted Share FCF FCF 9 $1,155 $1,300 $1,400 $1,500 ($2,000) ($1,500) ($1,000) ($500) $0 $500 $1,000 $1,500 $2,000 $2,500 2017A 2018E 2019E 2020E $MM Estimated Cash Flow v. CAPEX Estimate 1,4 CAPEX $55/$2.85 $60/$3.00

Net debt / adj EBITDA5 Long-Term Debt Maturities $ millions No maturities until 1/30/2022 Leverage Decreases Throughout 3YR Plan Expect to lower net debt to adjusted EBITDA throughout 3YR Plan Maintain significant liquidity throughout 3YR Plan Optionality to address long-term debt maturities No maturities within planning horizon (excl. undrawn credit facility) $1.8 billion undrawn credit facility Free cash generating asset base anticipated by 2H18 – 2020 10 Improving Debt Profile $750 $1,000 $700 2018 2018 2019 2020 2021 2022 2023 2023 2025 2024 2.0x <1.8x 2017A 2018E 2019E 2020E

11 Amending 2018 Annual Incentive Pay Metrics 2017 AIP Metrics 2018 AIP Metrics Weight Definition Weight Definition 15% Domestic Production 12.5% Debt Adjusted Production Growth Per Diluted Share 15% Domestic 1P Reserve Replacement 12.5% Proved Reserve Replacement Ratio 15% Domestic Proved Developed F&D 12.5% Proved Development F&D _ _ 12.5% Cash-On-Cash Return 15% Domestic Controllable Expense 12.5% Ongoing Operating Expense 15% Discretionary Cash Flow 12.5% Cash Flow Per Diluted Share _ _ 12.5% Corporate Responsibility 25% Strategic 12.5% Corporate Strategy 100% 100% ~ ~ ~ ~ ~ “NEW” “NEW” “NEW” “NEW” ~

2018 Capital Investment Program Anadarko Basin D&C Capital 140-160 operated wells ~80% of D&C 20-25% estimated production growth YOY 25-30% estimated oil growth YOY Rockies: Williston Basin 20-25 operated wells $90-$100 million free cash flow (2018E) 10% estimated oil growth YOY Uinta – Central Basin 10-15 operated wells HBP-focused drilling Capitalize on recent successes Establish long-term development option ~$920 MM ~$245 MM $ 1.3 Billion Anadarko Basin Rockies Other 12 ~ 90% Drilling & Completions

Asset Overview

Anadarko Basin is a World-Class Resource Play STACK infill pilots drilled to date (78 wells) provide high confidence in 3YR Plan Early encouraging results from 12-well Velta June pilot and Jackson/Florene Black Oil pilot SCORE program expands total net effective reservoir acres in Anadarko Basin to >1,000,000 acres6 Expanded quality inventory into North STACK (Meramec extension), Osage, North SCOOP, Sycamore and Caney Plan to invest approximately $365 million over 80-90 wells to further HBP and delineate plays in 3YR Plan Driving efficiencies through operational leadership “Best-in-Class” driller and top-tier completions lead to improved outlook for well costs and productivity 14 SPRINGER OSWEGO SCORE Hydrocarbon Saturated Column NORTH STACK STACK MERGE NORTH SCOOP SCOOP 150 MILES 1,150 FT

Cumulative Infill Test Results Provide Confidence in 3YR Plan Existing infill developments 78 producing infill wells completed across acreage position Meramec infill density tested from three wells in a single layer to 12 wells in a DSU Infill production results to date in-line with 3YR Plan type curve Stark infill development (10 wells in the Meramec) >100% rate of return Additional horizons for simultaneous development being executed in 2018 STACK 3YR Plan dominated by infill development drilling 15 STACK Stark 10 well PAD Avg. GPI: 9,953’ Avg. IP150: 1,092 BOEPD (65% oil) 0 10 20 30 40 50 60 70 80 90 0 50 100 150 200 250 300 350 0 60 120 180 240 300 360 Well Count AVG. CUMULATIVE MBOE Days Online 78 Infill Well Performance v. 3YR Plan Type Curve 3YR Plan Avg. All Infill (10,000' normalized) Wells (Right Axis)

Well Density Tests Helping Unlock Upside (Velta June) 16 Most “technically comprehensive” spacing pilot Key learnings focused on completion cluster efficiency, intra-well communication, cost/benefit analysis of components of well design, fracture geometry and flowback practices Peak pad production >10,000 BOEPD gross from 5,000’ laterals VELTA JUNE 12-WELL INFILL Lateral Length: 5,000’ Avg. IP30: 1,195 BOEPD (68% Oil) 0 50 100 150 200 0 60 120 180 AVG. CUMULATIVE MBOE Days Online Velta June (Normalized to 10,000’) v. 3YR Plan Type Curve 3YR Plan Velta June Avg. Well Day 30

Eastern Infill Test Pushes Extent of Play Across NFX Position Jackson / Florene 4- well test Lateral Length: 10,146’ AVG. IP120: 996 BOEPD (77% Oil) Eastern STACK Jackson / Florene test Four-well single-layer test in Meramec Estimated ~90% IRR at $55 oil and $2.85 gas Spacing test with original HBP (parents) Annuschat and Bernard wells in the Woodford 17 Annuschat / Bernard HBP wells Avg. Lateral Length: 10,126’ Avg. Cum: 359 MBOE (63% Oil)

CHARLES 1H-19 (MRMC) GPI: 4,892’ IP30: 931 BOEPD (49% Oil) Significant Activity Progressing SCORE Program 18 NFX operated wells OBO wells Industry wells CURRY 21X 1VH (WDFD) GPI: 10,460’ IP30: 1,730 BOEPD (85% Oil) LYNDA 26-23-1XH (SCMR) GPI: 7,605’ IP30: 3,281 BOEPD (23% Oil) PUDGE 1-7-6XH (SCMR) GPI: 7,900’ IP30: 1,578 BOEPD* (5% Oil) TURNER 1H-07-06 (SCMR) GPI: 10,031’ IP30: 1,372 BOEPD (45% Oil) GOSS 1915 1H-8X (MRMC) GPI: 9,772’ IP30: 1,125 BOEPD (47% Oil) WALTERS 1915 1H-22X (MRMC) GPI: 9,662’ IP30: 1,274 BOEPD (68% Oil) Lau 1-4H (OSGE) GPI: 4,440’ IP30: 1,500 BOEPD (20% Oil) MEDILL 1-27H (MRMC) GPI: 4,663’ IP30: 925 BOEPD (77% Oil) LARRY 1H-22X (WDFD) GPI: 9,850’ IP30: 1,930 BOEPD (82% Oil) ANTERO 1-7-6 MXH (SCMR) GPI: 8,766’ IP30: 1,473 BOEPD (47% Oil) WENDLING 1H-30XR (CNEY) GPI: 10,021’ IP30: 1,189 BOEPD (77% Oil) CASTLE 1-8SH (SCMR) GPI: 4,716’ IP30: 1,422 BOEPD (37% Oil) Robert 1507 1H-21 (OSGE) GPI: 4,412’ IP30: 710 BOEPD (59% Oil) BROWN 1706 6-27MH (OSGE) GPI: 4,850’ IP30: 1,099 BOEPD (59% Oil) LANKARD 1706 6-34MH (OSGE) GPI: 4,855’ IP30: 1,585 BOEPD (69% Oil) Bravo 28-20-12 1HC (MRMC) GPI: 9,953’ IP30: 2,063 BOEPD (65% Oil) LOW VALLEY 1807 1LMH-36 (OSGE) GPI: 4,925’ IP30: 1,184 BOEPD (73% Oil) MENDELL 1609 1H-2 (OSGE) GPI: 4,445’ IP30: 1,011 BOEPD (47% Oil) JANE 1509 1H-17 (OSGE) GPI: 4,589’ IP30: 1,383 BOEPD (27% Oil) STEPHEN 1H-27X (WDFD/OSGE) GPI: 8,326’ IP30: 1,549 BOEPD (61% Oil) BRIDWELL 1H-22X (CNEY) GPI: 9,850’ IP30: 713 BOEPD (79% Oil) Mary Lea 1H-33X (CNEY) GPI: 5,366’ IP30: 852 BOEPD (37% Oil) NOTE: Actual production data; not normalized for lateral length *Max monthly volume from public data

3YR PLAN ADDITIONAL RISKED8 ADDITIONAL UNRISKED8 TOTAL Gross Locations 700-800 >5,900 >7,850 >14,500 Newfield’s Expansive Anadarko Basin Resource & Inventory STACK Age Formation Depth Thickness Acreage Penn Oswego Limestone 6,500’-8,500’ 75’-125’ ~45,000 Atoka / Morrow Mississippian Chester (Seal) Meramec Shale 6,800’-10,200’ 100’-600’ ~275,000 Osage 7,000’-10,600’ 50’-300’ ~275,000 Siluro-Dev Woodford Shale 7,300’-11,000’ 50’-125’ ~125,000 Hunton 7,400-11,400’ 250’-450’ ~50,000 SCOOP Age Formation Depth Thickness Acreage Penn Springer “Black Marker” 7,500’-13,500’ 40’-125’ ~20,000 Mississippian Caney 7,700’-14,700’ 60’-100’ ~80,000 Sycamore 7,800’-14,800’ 150’-200’ ~50,000 Siluro-Dev Woodford Shale 8,000’-15,000’ 80’-350’ ~90,000 Hunton 8,500-15,000’ 100’-600’ ~25,000 19 ~3.0 BBOE net unrisked resource9 More Than One Million Net Effective Acres6 3YR Plan 5% Risked Locations 41% Unrisked Locations 54% Anadarko Basin Inventory

Driving STACK Efficiencies Through Operational Leadership NFX has a proven track record of improving margins by lowering costs and driving operational efficiencies 20 Completion Cost ($/bbl)* Drilling Cost ($/GPI) Sample includes 49 wells, data pulled from actual AFEs with NFX WI. Peers include CHK, CLR, DVN, SD, XEC. *Total slurry volume (Sand, Water and Chemicals) pumped for each well $0 $2 $4 $6 $8 $10 $12 $14 Peer 1 Peer 2 Peer 3 Peer 4 NFX Peer 5 $0 $50 $100 $150 $200 $250 $300 $350 $400 $450 Peer 1 Peer 2 Peer 3 Peer 4 Peer 5 NFX

Company Leveraging Strong Williston Basin Performance Utilized learnings from on-anticline activity over the last 200+ wells drilled to show expanded type curve and further push development to off-anticline infills Over 200 additional future locations to develop (drilling >65 wells in the 3YR Plan) Continued one-rig program to deliver production growth and $90-$100 million of free cash flow estimated in 2018 21 NOTE: Actual production data shown, not normalized for lateral length. Wellbores all operated by Newfield. Anderson 4-Well Pad (MB & TF2) GPI: 9,985’ Avg. IP30: 1,724 BOEPD (66% Oil) Jorgenson 4-Well Pad (MB & TF1) GPI: 9,711’ Avg. IP30: 1,979 BOEPD (72% Oil) Lost Bridge 4-Well Pad (MB & TF1) GPI: 9,466’ Avg. IP30: 2,376 BOEPD (72% Oil) Malm 4-Well Pad (MB) GPI: 9,870’ Avg. IP30: 2,078 BOEPD (63% Oil) Sand Creek Federal 4-Well Pad (MB/TF1) GPI: 9,978’ Avg. IP30: 1,840 BOEPD (66% Oil) Moberg 3-Well Pad (TF1, TF2, & TF3) GPI: 10,027’ Avg. IP30: 1,543 BOEPD (69% Oil) WILLISTON 0 50 100 150 200 250 300 350 400 0 1 2 3 4 5 6 7 8 9 10 11 12 Months Online Williston Type Curve Previous TC New TC (2017)

Uinta Basin Provides Deep Inventory of Stacked Horizons Targeted drilling program in 2018 to HBP and further delineate additional horizons ~4,000 feet of oil-saturated reservoir rock across entirety of Newfield’s >225,000 acres Recent wells demonstrate prolific nature of stacked horizons throughout Newfield and industry activity unlocking potential of shallower formations (Castle Peak, Douglas Creek, et. al.) 22 Altamont-Blue Bell Central Basin Myton Monument Butte Gas Saturated Column Oil Saturated Column 40 miles 3,000+ FT 4,000+ FT L.Green River Wasatch Mesa Verde & Mancos UGR

Strong Recent Horizontal Uinta Basin Results Knoll 7H (UB) GPI: 4,430’ IP30: 1,088 BOEPD (92% Oil) Ute Tribal 4-23-3-1W-H1(WST) GPI: ~5,000’ IP30: 1,730 BOEPD Hicken Tribal 15-9-4-3-1E-H1 (U-CP) GPI: ~10,000 IP30: 1,010 BOEPD Powvitch (U-CP) GPI: 8,766’ IP30: 1,313 BOEPD (91% Oil) BB 32-144H-22 (WST) GPI: ~10,000’ IP30: 1,500 BOEPD (89% OIL) BB 34-34EWH-23 (UB) GPI: ~10,000’ IP30: 1,253 BOEPD (89% Oil) Shields 2-Well Pad (UB) GPI: 9,484’ Avg. IP30: 1,299 BOEPD (89% Oil) Bar F 2-Well Pad (UB) GPI: 9,518’ Avg. IP30: 2,452 BOEPD (90% Oil) Leon 2-Well Pad (WST) GPI: 9,615’ Avg. IP30: 2,197 BOEPD (89% Oil) Dallas 2-Well Pad (UB) GPI: 9,441’ Avg. IP30: 1,399 BOEPD (91% OIL) Murray 3-Well Pad (UB & WST) GPI: 9,598’ Avg. IP30: 1,755 BOEPD (90% Oil) Sprouse 3-Well Pad (UB) GPI: 9,629’ Avg. IP30: 1,181 BOEPD (90% Oil) 23 McKinnon 2-Well Pad (UB) GPI: 9,595’ Avg. IP30: 1,219 BOEPD (90% Oil) Oats 2-Well Pad (UB & WST) GPI: 9,618’ Avg. IP30: 2,245 BOEPD (89% Oil) Keller 4-Well Pad (UB & WST) GPI: 9,213’ Avg. IP30: 2,016 BOEPD (89% Oil) BB 32-144H-21 (UB) GPI: 9,477’ IP30: 1,252 BOEPD1 (91% Oil) BB 33-34H-21 (WST) GPI: 9,832’ IP30: 1,369 BOEPD1 (90% Oil) NFX operated wells OBO wells Industry wells NOTE: Actual production data shown, not normalized for lateral length.

2017 Results

2017 Highlights Operational Beat domestic production guidance by delivering 10% growth vs. original guidance of 3-5% Grew proved reserves 33% to ~680 MMBOE 59% proved developed / 58% liquids Further advanced STACK development learnings Consistent infill results from 78 wells Improved well results through enhanced completions Completed most “technically comprehensive” spacing pilot to-date via Velta June 12 well pad with strong initial well performance Raised the Williston Basin type curve mid-year to an average of 1 MMBOE EUR SCORE program results helped expand SCOOP and STACK asset to over 14,000 gross unrisked locations8 and net unrisked resource of ~3 billion barrels of oil equivalent9 Recent Uinta well results provide encouragement for future oil growth option Financial Increased consolidated cash flow from operations before working capital adjustments by over $250 million Maintained strong liquidity position $326 million of cash and cash equivalents at YE17 $1.8 billion undrawn credit facility Free cash flow deficit less than $200 million for 2017 Partially offset by ~$96 million of non-core asset sales during the year Generated net income of $2.13 per diluted share 25

Proved reserves up 33% YOY ~400% proved reserve replacement ratio 58% of proved reserves are liquids 59% of proved reserves are proved developed Anadarko Basin proved reserves up 44% and represent 70% of total company reserves ~60% of Anadarko Basin proved reserves are liquids 680 MMBOE >2.5x Reserve Expansion Operational Performance Drives Strong Reserve Growth 26 181 269 330 477 2014 2015 2016 2017 MMBOE Anadarko Basin YE17 Proved Reserves Liquids Gas Anadarko 70% Uinta 11% Williston 10% Arkoma 9% China <1% YE17 Proved Reserves by Area

4Q17 Domestic Results 4Q DOMESTIC RESULTS 3Q ACTUAL 4Q GUIDANCE 4Q ACTUAL PRODUCTION Oil (mbopd) 65.5 63.2 - 67.9 67.1 NGL (mbopd) 35.6 35.6 - 38.3 36.3 Gas (mmcfpd) 347.5 379.2 - 407.4 398.3 Total (mboepd) 159.1 162.0 - 174.0 169.8 EXPENSES ($/BOE) LOE $3.35 $3.20 $3.18 Transportation* $5.47 $5.58 $4.92 Production & other taxes $1.11 $1.07 $1.33 General & administrative, net $3.59 $3.31 $2.98 Total Expenses $13.51 $13.16 $12.41 CAPEX ($MM) Drilling & Completion $290 $270 $262 Other 36 51 44 Total CAPEX** $326 $321 $306 OPERATIONS Operated rigs 12 - 11 Op. wells placed on production (WI%/NRI%) 52 (73% / 59%) - 32 (65% / 53%) Op. wells placed on production (Average GPI) 8,259‘ - 8,552‘ *Transportation fees include $13 million in each of 3Q17 and 4Q17 associated with firm gas transportation in the Arkoma Basin and $8 million and $5 million of shortfall fees in the Uinta Basin in 3Q17 and 4Q17, respectively. ** 3Q17A and 4Q17A exclude ~$33 million and ~$27 million of capitalized interest and direct internal cost, respectively. 27

4Q17 Basin Results 4Q BASIN RESULTS ANADARKO WILLISTON UINTA ARKOMA PRODUCTION Oil (mbopd) 39.2 13.3 14.6 0.0 NGL (mbopd) 32.4 3.3 0.4 0.2 Gas (mmcfpd) 274.3 22.0 19.4 80.7 Total (mboepd) 117.3 20.3 18.2 13.7 EXPENSES ($/BOE) LOE $1.58 $3.91 $10.89 $3.11 Transportation* $3.88 $5.68 $0.35 $4.20 Production & other taxes $0.92 $3.48 $2.00 $0.79 Total Expenses $6.38 $13.07 $13.24 $8.10 CAPEX ($MM) Drilling & Completion $213 $19 $23 $7 Other $34 $0 $6 - Total CAPEX** $247 $19 $29 $7 OPERATIONS Operated rigs 8 1 1 <1 Op. wells placed on production (WI%/NRI%) 25 (67% / 54%) 4 (38% / 30%) 2 (97% / 78%) 1 (84% / 68%) Op. wells placed on production (Average GPI) 7,991‘ 10,360‘ 8,730‘ 9,695‘ 28 * Transportation fees exclude $13 million and $5 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. ** CAPEX excludes $4 million associated with Corporate FF&E.

NOTE: Pro forma 2016 adjusted for the completed sale of Eagle Ford and S. Texas assets. * 2016A transportation fees include $53 million and $16 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. 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. ** Interest expense guidance reflective of net interest expense. Original guidance issued at gross interest expense of $2.73/boe consolidated corporate expense. *** 2016A and 2017A exclude ~$120 million of capitalized interest and direct internal cost in each year. 2017 Domestic Results 2017 DOMESTIC RESULTS 2016 PF Actual 2017 GUIDANCE 2017 ACTUAL PRODUCTION Oil (mbopd) 54.5 60.0 - 61.6 61.2 NGL (mbopd) 27.7 31.5 - 32.3 31.7 Gas (mmcfpd) 339.3 351.0 - 360.4 356.5 Total (mboepd) 138.8 150.0 - 154.0 152.2 EXPENSES ($/BOE) LOE $3.72 $3.48 $3.47 Transportation* $5.13 $5.58 $5.40 Production & other taxes $0.74 $1.07 $1.14 General & administrative, net $3.78 $3.58 $3.49 Interest expense** $1.93 $1.59 $1.62 Total Expenses $15.30 $15.30 $15.13 CAPEX ($MM) Drilling & Completion $605 $975 $992 Other $129 $125 $161 Total CAPEX*** $734 $1,100 $1,153 OPERATIONS Operated rigs 8 - 12 Op. wells placed on production (WI%/NRI%) 132 (74% / 60%) - 146 (70% / 57%) Op. wells placed on production (Average GPI) 8,267‘ - 8,502‘ 29

2017 Basin Results 2017 BASIN RESULTS ANADARKO WILLISTON UINTA ARKOMA PRODUCTION Oil (mbopd) 33.8 13.3 13.9 0.1 NGL (mbopd) 27.7 3.4 0.4 0.2 Gas (mmcfpd) 229.4 21.9 18.6 83.6 Total (mboepd) 99.7 20.3 17.4 14.2 EXPENSES ($/BOE) LOE $1.76 $4.77 $11.51 $3.15 Transportation* $4.07 $5.70 $0.79 $4.18 Production & other taxes $0.69 $3.00 $1.91 $0.80 Total Expenses $6.52 $13.47 $14.21 $8.14 CAPEX ($MM) Drilling & Completion $841 $70 $69 $12 Other $118 $3 $19 $1 Total CAPEX** $959 $73 $88 $13 OPERATIONS Operated rigs 9 1 1 <1 Op. wells placed on production (WI%/NRI%) 109 (75% / 60%) 19 (53% / 43%) 17 (58% / 47%) 1 (84% / 68%) Op. wells placed on production (Average GPI) 8,136‘ 10,152‘ 8,931‘ 9,695‘ 30 * Transportation fees exclude $54 million and $29 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. ** CAPEX excludes approximately $20 million associated with Corporate FF&E.

APPENDIX

2018 Annual Guidance DOMESTIC GUIDANCE 2017 ACTUAL 2018 ESTIMATES PRODUCTION Oil (mbopd) 61.2 74 NGL (mbopd) 31.7 35 Gas (mmcfpd) 356.5 408 Total (mboepd) 152.2 170 - 183 EXPENSES ($/BOE) LOE $3.47 $3.43 Transportation* $5.40 $5.09 Production & other taxes 3.5% 4.2% 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 32 * 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 $20 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. ** 2017A and 2018E exclude ~$120 million and ~$100 million of capitalized interest and direct internal cost, respectively.

2018 Basin Annual Guidance 2018 BASIN GUIDANCE ANADARKO WILLISTON UINTA ARKOMA PRODUCTION Oil (mbopd) 42 14 16 0 NGL (mbopd) 31 4 0 0 Gas (mmcfpd) 291 20 16 79 Total (mboepd) 116 - 128 20 - 23 18 - 21 12 - 14 EXPENSES ($/BOE) LOE $1.89 $4.81 $10.97 $3.55 Transportation* $4.48 $5.60 $1.03 $4.32 Production & other taxes 3.1% 8.1% 5.2% 5.2% CAPEX ($MM)** $950 - $1,050 $125 - $135 $125 - $135 $5 - $15 33 * Transportation fees exclude $38 million and $20 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. ** CAPEX excludes approximately $30 million associated with Corporate FF&E.

2018 Domestic & Anadarko Quarterly Guidance DOMESTIC GUIDANCE 4Q’17A 1Q’18E 2Q’18E 3Q’18E 4Q’18E PRODUCTION Oil (mbopd) 67.1 71 72 77 75 NGL (mbopd) 36.3 33 34 36 39 Gas (mmcfpd) 398.3 394 402 412 424 Total (mboepd) 169.8 167 – 173** 169 – 177 176 – 186 179 – 191 CAPEX ($MM)* $306 $340 $355 $300 $305 34 ANADARKO GUIDANCE 4Q’17A 1Q’18E 2Q’18E 3Q’18E 4Q’18E PRODUCTION Oil (mbopd) 39.2 40 42 44 42 NGL (mbopd) 32.4 29 30 32 34 Gas (mmcfpd) 274.3 272 288 296 310 Total (mboepd) 117.3 112 – 116 116 – 124 121 – 131 122 – 134 CAPEX ($MM) $247 $255 $260 $235 $250 * 4Q17 and 2018E exclude ~$27 million and ~$100 million of capitalized interest and direct internal cost, respectively. ** Company estimates colder than anticipated weather to have negatively impacted production by approximately 190,000 for 1Q’18E. Estimated increase in gas production Q/Q is primarily related to two high rate of return SCOOP Wet Gas developments that are expected to commence production during the third quarter.

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 $4.70 Production & other taxes 2% (3-years), 7% (thereafter) REALIZATIONS Oil (%WTI) 100% NGLs (%WTI) 52% Gas (%HH) 82% CAPEX ($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’ 35 1 2 3 4 5 6 7 8 9 10 11 12 0 STACK 3YR Plan Assumptions: EUR Range: 1.1 – 1.7 MMBOE7 Well Cost Range (incl. facilities): $7.6 – $8.7 million 3YR Plan Average: 1.3 MMBOE7 EUR @ $7.9 million well cost (incl. facilities) 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 $6.02 Production & other taxes 2% (3-years), 7% (thereafter) REALIZATIONS Oil (%WTI) 97% 97% NGLs (%WTI) 52% 52% Gas (%HH) 83% 83% CAPEX ($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 36 0 50 100 150 200 250 300 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 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 / $0.0555 per MCF gas REALIZATIONS Oil (%WTI) 95% NGLs (%WTI) 60% Gas (%HH) 74% CAPEX ($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 37 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 3YR Plan TC

Oil Hedging Details as of 02/15/18 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts10 Collars11 Collars w/ Short Puts12 1Q 2018 9,000 -- -- 51,000 $52.56 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.76/$48.84-$56.33 2Q 2018 44,000 -- 14,000 -- $54.62 -- -- -- -- -- -- -- -- -- $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 38

Oil Hedging Details as of 02/15/18 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts Collars Collars w/ Short Puts13 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 39

Oil Hedging Details as of 02/15/18 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 1Q 2018 $68 $60 $47 $5 ($23) ($77) ($131) 2Q 2018 $178 $125 $72 $21 ($26) ($79) ($131) 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) 40

Gas Hedging Details as of 02/15/18 Weighted-Average Price Period Volume (mmbtu/d) Swaps Swaps w/ Short Puts14 Collars Collars w/ Short Puts15 1Q 2018 30,000 13,800 200,000 -- $3.01 -- -- -- -- $2.60/$2.97 -- -- -- -- $3.14-$3.72 -- -- -- -- -- 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 41

Gas Hedging Details as of 02/15/18 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 -- -- -- 42

Gas Hedging Details as of 02/15/18 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 1Q 2018 $24 $13 $3 ($2) ($9) ($20) ($31) 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) 43

Propane Hedging Details as of 02/15/18 Weighted-Average Price Period Volume (bbl/d) Swaps ($/gal) 1Q 2018 4,700 $.818 2Q 2018 5,000 $.819 3Q 2018 4,000 $.811 4Q 2018 3,000 $.807 44

Propane Hedging Details as of 02/15/18 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 propane. Propane Prices Period $.50 $.60 $.70 $.80 $.90 $1.00 $1.10 1Q 2018 $5.6 $3.8 $2.1 $0.3 ($1.4) ($3.2) ($5.0) 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) 45

Endnotes 1) Capital Budgets for 2019 and 2020 have not been finalized or approved by the Company’s Board of Directors, which has ultimate authority and discretion over future annual capital budgets. 2) Assumes $55/bbl and $2.85/mmbtu. 3) Based on production guidance issued on February 21, 2017 for full-year 2017 and midpoint of annualized growth target of 12.5% annually for 2018 and 2019. 4) Cash Flow, CAPEX and Free Cash Flow defined per the definitions on page 48. 5) Net Debt calculated as principal balance of debt less cash and cash equivalents on balance sheet and Adjusted EBITDA as defined on page 47. 6) Total Net Effective Reservoir Acreage is a method of calculating the summation of acreage rights owned and prospective in various horizons below each surface acre, where prospective is determined as recoverable prior to application of commercial chance of success. Such amounts do not meet SEC rules and guidelines, may not be reflective of SEC proved reserves or acreage and do not equate to or predict any level of reserves or production. See legend on page 3 for more information. 7) 3YR Plan type curve indicative of anticipated results of wells to be drilled in play during the 3YR Plan and are not indicative of cumulative historical results in play and is indicative of estimated ultimate recovery from the well. 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. See legend on page 3 for more information. 46

Endnotes (continued) 8) Risked locations are defined as gross locations having a reasonable potential for commercial development. Unrisked locations are defined as gross locations prior to applying a chance for commercial success. Such amounts do not meet SEC rules and guidelines, may not be reflective of SEC proved reserves or acreage and do not equate to or predict any level of reserves or production. See legend on page 3 for more information. 9) Unrisked resources are defined as the total estimated hydrocarbons that are expected to be recoverable prior to application of commercial chance of success. Such amounts do not meet SEC rules and guidelines, may not be reflective of SEC proved reserves or acreage and do not equate to or predict any level of reserves or production. See legend on page 3 for more information. 10) 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. 11) The collars for 2Q18 were created by buying back our short puts that were part of 3-way transactions. The short puts were purchased with funds derived by selling 3,000 Bbl/d of $59 call swaptions with an expiry of March 15, 2018. 12) Below $39.76 for 1Q18 and $39.47 for 4Q18 these contracts effectively result in realized prices that are $9.08 and $8.87 per Bbl higher, respectively by quarter, 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. 13) 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. 14) Below $2.60 for 1Q18-3Q18 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. 15) 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. 47

Key Definitions 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. See legend on page 3 for more information. Average Completed Well Cost – Includes capital associated with drilling, completions, facilities and artificial lift. All estimates shown are expected to be within +/- 5% of the values illustrated. Cash Flow – Net income plus DD&A, non-cash stock compensation, deferred tax provision, unrealized loss (gain) on derivative contracts, ceiling text and other impairments, and other non-cash operating items. CNEY – Represents Caney Formation of the Anadarko Basin. 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. All estimates shown are expected to be within +/- 5% of the values illustrated. Debt Adjusted Shares – Fully diluted shares of the Company, plus principal of total outstanding debt less total cash and cash equivalents (Total Net Debt) divided by average closing price of Newfield stock on the NYSE for the month of January 2018 ($33.64/share). Future debt adjusted shares are determined by holding the current enterprise value (Fully Diluted Equity Value, plus Total Net Debt) based on the average closing price of Newfield stock on the NYSE for the month of January 2018, as a multiple of forecasted future EBITDA (one year forward in all subsequent years as determined on January 1st of that year). Free Cash / Free Cash Flow – Determined by subtracting Cash Flow from the aggregate of Capital investments and capitalized expenses, such as interest and general and administrative expenses. 48

Key Definitions GPI – Gross Perforated Interval, which reflects the total feet completed in each horizontal wellbore. IRR – Internal rate of return is a metric used by Company management for capital budgeting and measuring the profitability of potential investments. All IRR’s presented herein were calculated based on $55/bbl and $2.85/mmbtu unless otherwise noted herein. MRMC – Represents Meramec Formation of the Anadarko Basin. OSG – Represents Osage Formation of the Anadarko Basin. Production per Debt Adjusted Share – Estimated production for the year on a total production basis divided by Debt Adjusted Shares calculated utilizing the average closing price of Newfield shares on the NYSE for the month of January. SCMR – Represents the Sycamore Formation of the Anadarko Basin. UB – Uteland Butte Formation of the Uinta Basin. U-CP – Upper Castle Peak Formation of the Uinta Basin. WAS – Wasatch Formation of the Uinta Basin. WDFD – Represents the Woodford Formation of the Anadarko Basin. 49