8-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K

CURRENT REPORT

Pursuant to Section 13 OR 15(d) of the

Securities Exchange Act of 1934

Date of Report (Date of earliest event reported): August 1, 2017

NEWFIELD EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)

Delaware	1-12534	72-1133047
(State or other jurisdiction	(Commission File Number)	(I.R.S. Employer
of incorporation)		Identification No.)

4 Waterway Square Place, Suite 100

The Woodlands, Texas 77380

(Address of principal executive offices)

Registrant’s telephone number, including area code: (281) 210-5100

Not Applicable

(Former name or former address, if changed since last report)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

oWritten communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

oSoliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

oPre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

oPre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 405 of the Securities Act of 1933 (§230.405 of this chapter) or Rule 12b-2 of the Securities Exchange Act of 1934 (§240.12b-2 of this chapter).

Emerging Growth Company  o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   o

Item 2.02  Results of Operations and Financial Condition

On August 1, 2017, Newfield Exploration Company (“Newfield”) issued a press release that announced its prior quarter financial results and provided an update on operations. A copy of that press release is furnished herewith as Exhibit 99.1.

The information in Item 2.02 of this Current Report, including the exhibit attached hereto as Exhibit 99.1, is being furnished and shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Section. The information in Item 2.02 of this Current Report shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, as amended, except as otherwise expressly stated in such filing.

Item 7.01  Regulation FD Disclosure

On August 1, 2017, Newfield posted its @NFX publication, which provided prior quarter highlights and current year and quarter outlook of Newfield’s operations and complete hedging positions. A copy of the publication is furnished herewith as Exhibit 99.2.

The information in Item 7.01 of this Current Report, including the exhibit attached hereto as Exhibit 99.2, is being furnished and shall not be deemed “filed” for the purposes of Section 18 of the Securities Exchange Act of 1934, as amended, or otherwise subject to the liabilities of that Section. The information in Item 7.01 of this Current Report shall not be incorporated by reference into any registration statement or other document pursuant to the Securities Act of 1933, as amended, except as otherwise expressly stated in such filing.

Item 9.01  Financial Statements and Exhibits

(d)Exhibits

99.1	Second Quarter 2017 Financial Results and Update on Operations issued by Newfield on August 1, 2017
99.2	@ NFX Publication posted by Newfield on August 1, 2017

2

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.

	NEWFIELD EXPLORATION COMPANY
Date: August 1, 2017	By:	/s/ Timothy D. Yang
		Timothy D. Yang
		General Counsel and Corporate Secretary

3

Exhibit Index

Exhibit No.	Description
99.1	Second Quarter 2017 Financial Results and Update on Operations issued by Newfield on August 1, 2017
99.2	@ NFX Publication posted by Newfield on August 1, 2017

4

EX-99.1

Exhibit 99.1

Newfield Exploration Reports Second Quarter 2017 Results

The Woodlands, Texas - August 1, 2017 - Newfield Exploration Company (NYSE: NFX) today announced second quarter 2017 unaudited financial and operating results. Additional details can be found in the Company’s @NFX publication, located on its website.

Newfield plans to host a conference call at 10 a.m. CDT on August 2, 2017. To listen to the call, please visit Newfield’s website at http://www.newfield.com. To participate in the call, dial 719-457-2087 and provide conference code 3843455 at least 10 minutes prior to the scheduled start time.

Year-to-date 2017 Highlights

·Second quarter 2017 net production exceeded the mid-point of domestic and international guidance ranges.

·Domestic net production was 141,000 BOEPD (40% oil and 59% liquids), exceeding the mid-point of guidance by nearly 4,000 BOEPD.

·Consolidated net production was approximately 150,000 BOEPD (44% oil and 62% liquids), compared to a guidance mid-point of approximately 145,850 BOEPD.

·The Company today increased the mid-point of its full-year 2017 domestic production outlook.

·The mid-point for 2017 domestic guidance was raised to 149,600 BOEPD (previous guidance: 148,600 BOEPD). The Company now estimates that its year-over-year domestic production growth, adjusted for prior-year asset sales, will be approximately 8%.

·The mid-point estimate for 2017 total company production was reduced to approximately 153,600 BOEPD (original guidance was 155,100 BOEPD). Production from the Newfield operated Pearl Field in the South China Sea was recently suspended due to a mechanical issue associated with a third-party floating, storage and offloading vessel located approximately 10 miles from the field. Due to the uncertainties surrounding the timing of repairs, Newfield has removed from its guidance approximately 5,000 BOPD net from expected future liftings in the second half of 2017.

·At the end of the second quarter, Newfield had approximately $550 million of cash and short-term investments on hand. The cash balance includes the recent closing on the sale of the Company’s asset in Bohai Bay, China.

·Recent operational highlights include:

·In STACK, Newfield has now completed the Company’s fourth operated pilot on increased density spacing. The Stark pilot initiated production from nine infill SXL wells in the Meramec with each well testing “GEN17” completions of 2,100 pounds of proppant per foot and 2,100 gallons of liquid per foot. After 60 days, cumulative average production from the nine infill wells is outperforming

the Company’s 1.1 MMBOE estimated gross type curve. In addition, average per well cumulative 60-day production from the Stark infill wells is in-line with recent held-by-production (HBP) wells with comparable completions, adjusted for lateral length. The Stark infill wells, which averaged 1,211 BOEPD over the 30-day period (65% oil, 82% liquids), are being produced with controlled flowback operations to minimize draw-down and maximize oil recovery.

·Newfield is advancing its learnings in STACK by collecting data on multiple infill well spacing scenarios. In addition to the Stark, the Freeman and Velta June pilots will test 10 and 12-well spacing, respectively. Production results from these pads are expected late this year and early next year.

·In SCOOP, continued improvements in completions have allowed tighter density spacing in the Woodford (5-6 wells/per spacing unit compared to 8-10 wells/per spacing unit today). The Company recently turned to sales seven Tina infill wells with 17% higher 30-day average production (1,708 BOEPD) when compared to previous developments with four to five infill wells/section (1,462 BOEPD). When compared against offset wells drilled over the last several years, the Tina infill wells have nearly twice the proppant and fluid loads with 25% less costs per completed well.

·In the Williston Basin, recent improvements to completion designs have allowed the company to raise its estimated type curve to 1 MMBOE gross. Wells completed year-to-date are projecting more than 80% higher 30-day average production rates of 1,883 BOEPD when compared to 30-day average rates (1,036 BOEPD) from previous wells drilled in close proximity.

“We are on target to deliver the key objectives within our 2017 business plan and we expect to enter 2018 with strong momentum across the company,” said Lee K. Boothby, Newfield Chairman, President and CEO. “We have streamlined our operations to improve our cost structure and margins and we are fortunate to have high-return plays to actively develop in today’s commodity price environment. The advancements we are demonstrating in more mature development plays like SCOOP and the Bakken, are great examples of where we are headed in STACK. We have a deep drilling inventory of quality development opportunities to pursue over the next several decades and we continue to be encouraged by the prospectivity of other horizons on our acreage in the Anadarko Basin. With the exception of our contractor’s recent mechanical issue in China, where we are hopeful that repairs will be completed by year-end, the year 2017 is shaping up to be another strong year of performance for Newfield.”

Second Quarter 2017 Financial and Production Summary

For the second quarter, the Company recorded net income of $98 million, or $0.49 per diluted share (all per share amounts are on a diluted basis). After adjusting for the effect of unrealized derivative gains during the period, net income would have been $85 million, or $0.43 per share.

Revenues for the second quarter were $402 million. Net cash provided by operating activities was $300 million. Discretionary cash flow from operations was $215 million.

Newfield’s total net production in the second quarter of 2017 was approximately 150,000 BOEPD, comprised of 44% oil, 18% natural gas liquids and 38% natural gas. Domestic production in the second quarter was approximately 141,000 BOEPD, comprised of 40% oil, 19% natural gas liquids and 41% natural gas.

2017e Production, Cost and Expense Guidance

	Domestic			China			Total
Production
Oil %	41		%	100		%	42		%
NGLs %	19		%	—			19		%
Natural Gas %	40		%	—			39		%
Total (mboepd)(1)	145.4 - 153.8			4.0			149.4 - 157.8
Expenses ($/boe)(2)
LOE(3),(5)	$	3.41		$	16.48		$	3.76
Transportation(4)	5.58			—			5.43
Production & other taxes	1.07			0.21			1.05
General & administrative (G&A), net(5)	$	3.54		$	5.02		$	3.58
Interest expense, gross	—			—			2.66
Capitalized interest and direct internal costs	—			—			$	(2.20	)
Effective Tax rate	0 - 5		%	0 - 5		%	0 - 5		%

(1)Total Company and China volumes include impact of Bohai Bay divestiture

(2)Cost and expenses are expected to be within 5% of the estimates above

(3)Total LOE includes recurring, major expense and non E&P operating expenses

(4)2017e transportation / processing fees include ~$52 million for Arkoma unused firm gas transportation and ~$33 million for Uinta oil and gas delivery shortfall fees

(5)Total LOE and G&A includes $4 million and $4 million, respectively, associated with remainder of 2017 activity in China

3Q17e Production, Cost and Expense Guidance

	Domestic			China		Total
Production
Oil %	41		%	—		41		%
NGLs %	19		%	—		19		%
Natural Gas %	40		%	—		40		%
Total (mboepd)	151.0 - 157.7			—		151.0 - 157.7
Expenses ($/boe)(1)
LOE(4)	$	3.26		—		$	3.37
Transportation(3)	5.71			—		5.71
Production & other taxes	1.14			—		1.14
General & administrative (G&A), net(4)	$	3.62		—		$	3.76
Interest expense, gross	—			—		2.63
Capitalized interest and direct internal costs	—			—		$	(2.15	)
Effective Tax rate	0 - 5		%	0	%	0 - 5		%

(1)Cost and expenses are expected to be within 5% of the estimates above

(2)Total LOE includes recurring, major expense and non E&P operating expenses

(3)3Q17e transportation / processing fees include ~$13 million for Arkoma unused firm gas transportation and ~$8 million for Uinta oil and gas delivery shortfall fees

(4)Total LOE and G&A includes $2 million and $2 million, respectively, associated with Q3 2017 activity in China

Newfield Exploration Company is an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our U.S. operations are onshore and focus primarily on large scale liquids-rich resource plays. Our principal areas of operation are the Anadarko and Arkoma basins of Oklahoma, the Williston Basin of North Dakota and the Uinta Basin of Utah. We also have oil assets offshore China.

**This release 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 release, all information and statements, including but not limited to information regarding planned capital expenditures, estimated reserves, estimated production targets, estimated future operating costs, expenses and other financial measures, estimated future tax rates, drilling and development plans, the timing of production, planned capital expenditures, and other plans and objectives for future operations, are forward-looking statements.  Although, as of the date of this release, Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks and no assurance can be given that such expectations will prove to have been correct. Actual results may vary significantly from those anticipated due to many factors, including but not limited to commodity prices, drilling results, our liquidity and the availability of capital resources, operating risks, industry conditions, U.S. and China governmental regulations, financial counterparty risks, the prices of goods and services, the availability of drilling rigs and other support services, our ability to monetize assets and repay or refinance our existing indebtedness, labor conditions, severe weather conditions, new regulations or changes in tax or environmental legislation, environmental liabilities not covered by indemnity or insurance, legislation or regulatory initiatives intended to address seismic activity, and other operating risks. Please see Newfield’s 2016 Annual Report on Form 10-K,  Quarterly Reports on Form 10-Q and other subsequent public filings, all filed with the U.S. Securities and Exchange Commission (SEC), for a discussion of other factors that may cause actual results to vary. Unpredictable or unknown factors not discussed in this press release 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 release. 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.

For additional information, please contact Newfield’s Investor Relations department.

Phone: 281-210-5321

Email: IR@newfield.com

	2Q17 Actual
2Q17 Actual Results	Domestic		China		Total
Production/Liftings(1)
Crude oil and condensate (MBbls)	5,132		830		5,962
Natural gas (Bcf)	31.2		—		31.2
NGLs (MBbls)	2,491		—		2,491
Total (MBOE)	12,818		830		13,648
Average Realized Prices(2)(3)
Crude oil and condensate (per Bbl)	$	46.46	$	49.01	$	46.81
Natural gas (per Mcf)	2.61		—		2.61
NGLs (per Bbl)	24.54		—		24.54
Crude oil equivalent (per BOE)	$	29.93	$	49.01	$	31.11
Operating Expenses:(3)
Lease operating (in millions)
Recurring	$	39	$	11	$	50
Major (workovers, etc.)	$	6	$	2	$	8
Lease operating (per BOE)
Recurring	$	3.09	$	13.18	$	3.72
Major (workovers, etc.)	$	0.43	$	1.98	$	0.52
Transportation and processing (in millions)	$	71	$	—	$	71
per BOE	$	5.67	$	—	$	5.32
Production and other taxes (in millions)	$	13	$	—	$	13
per BOE	$	1.03	$	0.14	$	0.97
General and administrative (G&A), net (in millions)	$	49	$	2	$	51
per BOE	$	3.90	$	2.13	$	3.79
Capitalized direct internal costs (in millions)					$	(16	)
per BOE					$	(1.19	)
Other operating expenses (income), net (in millions)					$	—
per BOE					$	0.02
Interest expense (in millions)					$	37
per BOE					$	2.78
Capitalized interest (in millions)					$	(15	)
per BOE					$	(1.15	)
Other non-operating (income) expense (in millions)					$	(2	)
per BOE					$	(0.14	)

(1)Represents volumes lifted and sold regardless of when produced. Includes natural gas produced and consumed in operations of 1.2 Bcf during the three months ended June 30, 2017.

(2)Average realized prices include the effects of derivative contracts. Excluding these effects, the average realized price for domestic and total natural gas would have been $2.75 per Mcf and the average realized price for our domestic and total crude oil and condensate would have been $42.52 per barrel and $43.42 per barrel, respectively. We did not have any derivative contracts associated with our NGL or China production as of June 30, 2017.

(3)All per unit pricing and expenses exclude natural gas produced and consumed in operations.

CONDENSED CONSOLIDATED BALANCE SHEET

(Unaudited, in millions)

	June 30,			December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	522		$	555
Short-term investments	25			25
Derivative assets	33			75
Other current assets	303			294
Total current assets	883			949
Oil and gas properties, net (full cost method)	3,479			3,140
Derivative assets	1			—
Other assets	232			223
Total assets	$	4,595		$	4,312
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Derivative liabilities	$	13		$	97
Other current liabilities	665			587
Total current liabilities	678			684
Other liabilities	67			63
Derivative liabilities	—			3
Long-term debt	2,432			2,431
Asset retirement obligations	156			154
Deferred taxes	55			39
Total long-term liabilities	2,710			2,690
Stockholders’ equity:
Common stock, treasury stock and additional paid-in capital	3,228			3,205
Accumulated other comprehensive income (loss)	(1		)	(2		)
Retained earnings (deficit)	(2,020		)	(2,265		)
Total stockholders’ equity	1,207			938
Total liabilities and stockholders’ equity	$	4,595		$	4,312

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited, in millions, except per share data)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2017			2016			2017			2016
Oil, gas and NGL revenues	$	402		$	381		$	819		$	665
Operating expenses:
Lease operating	58			62			114			123
Transportation and processing	71			66			143			129
Production and other taxes	13			11			27			21
Depreciation, depletion and amortization	110			160			216			337
General and administrative	51			58			98			102
Ceiling test and other impairments	—			522			—			1,028
Other	—			—			1			1
Total operating expenses	303			879			599			1,741
Income (loss) from operations	99			(498		)	220			(1,076		)
Other income (expense):
Interest expense	(37		)	(38		)	(75		)	(79		)
Capitalized interest	15			11			31			20
Commodity derivative income (expense)	28			(133		)	81			(150		)
Other, net	2			—			4			1
Total other income (expense)	8			(160		)	41			(208		)
Income (loss) before income taxes	107			(658		)	261			(1,284		)
Income tax provision (benefit)	9			9			16			7
Net income (loss)	$	98		$	(667	)	$	245		$	(1,291	)
Earnings (loss) per share:
Basic	$	0.49		$	(3.36	)	$	1.23		$	(6.87	)
Diluted	$	0.49		$	(3.36	)	$	1.22		$	(6.87	)
Weighted-average number of shares outstanding for basic earnings (loss) per share	199			198			199			188
Weighted-average number of shares outstanding for diluted earnings (loss) per share	200			198			200			188

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited, in millions)

	Six Months Ended
	June 30,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	245		$	(1,291	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	216			337
Deferred tax provision (benefit)	16			3
Stock-based compensation	20			19
Unrealized (gain) loss on derivative contracts	(46		)	296
Ceiling test and other impairments	—			1,028
Other, net	7			6
	458			398
Changes in operating assets and liabilities	9			(20		)
Net cash provided by (used in) operating activities	467			378
Cash flows from investing activities:
Additions to and acquisitions of oil and gas properties and other	(521		)	(974		)
Proceeds from sales of oil and gas properties	28			29
Net cash provided by (used in) investing activities	(493		)	(945		)
Cash flows from financing activities:
Net proceeds (repayments) of borrowings under credit arrangements	—			(39		)
Proceeds from issuances of common stock, net	2			777
Other, net	(9		)	(11		)
Net cash provided by (used in) financing activities	(7		)	727
Increase (decrease) in cash and cash equivalents	(33		)	160
Cash and cash equivalents, beginning of period	555			5
Cash and cash equivalents, end of period	$	522		$	165

Explanation and Reconciliation of Non-GAAP Financial Measures

Adjusted Net Income (Earnings Stated Without the Effect of Certain Items)

Earnings stated without the effect of certain items is a non-GAAP financial measure. Earnings without the effect of these items are presented because they affect the comparability of operating results from period to period. In addition, earnings without the effect of these items are more comparable to earnings estimates provided by securities analysts. This measure should not be considered an alternative to net income (loss) as defined by generally accepted accounting principles.

A reconciliation of earnings for the second quarter of 2017 stated without the effect of certain items to net income (loss) is shown below:

	2Q17
	(In millions)
Net Income (loss)	$	98
Unrealized (gain) loss on derivative contracts	(13		)
Earnings stated without the effect of the above items	85

Discretionary Cash Flow from Operations

Discretionary cash flow from operations represents net cash provided by operating activities before changes in operating assets and liabilities and is presented because of its acceptance as an indicator of an oil and gas exploration and production company’s ability to internally fund exploration and development activities and to service or incur additional debt. This measure should not be considered an alternative to net cash provided by operating activities as defined by generally accepted accounting principles.

A reconciliation of net cash provided by operating activities to discretionary cash flow from operations is shown below:

	2Q17
	(In millions)
Net cash provided by operating activities	$	300
Net changes in operating assets and liabilities	(85		)
Discretionary cash flow from operations	215

EX-99.2

Exhibit 99.2

@NFX – 2Q17 Update

2Q17 Key Messages – What You Need to Know We are on-track to deliver our 3-year plan for double-digit CAGR in production at strip prices We exceeded the mid-point of our 2Q17 domestic production guidance by nearly 4,000 BOEPD net and raised our 2017 outlook Total Company net production was ~150,000 BOEPD (44% oil and 62% liquids), above mid-point of guidance by > 4,000 BOEPD net We have ~$550MM of cash and short-term investments on hand Closed on sale of Bohai Bay during 2Q17 Our recent STACK pilots are projecting above our 1.1 MMBOE EUR1 TC We raised our type curve in the Williston Basin to 1 MMBOE EUR1 >200 operated locations remaining SCOOP results showing continual improvement through enhanced completions Tina infill wells projecting to a 2 MMBOE EUR1 TC 2 1Estimated ultimate recovery (EUR) refers to potential recoverable oil and natural gas hydrocarbon quantities with ethane processing and depends on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Such amounts do not meet SEC rules and guidelines, may not be reflective of SEC proved reserves and do not equate to or predict any level of reserves or production

1.1 MMBOE TC GEN17 HBP wells* 15 GEN17 HBP Wells* Stark Pilot Wells Spacing/DSU 1st well 10 Avg. CWC/well ($MM) $7.7 $8.8 Avg. Stage Count 50 50 Prop/ft 2,100 2,100 Gals/ft 2,100 2,100 Avg. IP30 (BOEPD) 1,255 1,211 % Oil 61% 65% % Liquids 80% 82% “NEW” 9 infill wells in the Meramec Average IP24: 1,500 BOEPD (71% oil, 85% liquids) Average IP30: 1,211 BOEPD (65% oil, 82% liquids) Production projecting above 1,100 MBOE TC Production projecting in-line with recent GEN17 HBP wells Utilizing controlled flowback to minimize drawdown and maximize oil recovery Additional 10-well test (Freeman) on-line and 12-well test (Velta June) drilling Positive Results from Recent Stark Pilot *All wells normalized to 10,000’ lateral length Previous Gen17 HBP Wells Stark Infill Wells vs. GEN17 HBP Wells Stark Pilot 3 Controlled Flowback Stark Wells 0 50 100 150 200 250 300 0 1 2 3 4 5 6 Cumulative Production (MBOE) Months

Dorothy Pilot Outperforming TC After 200 Days Wells Spacing Per DSU 5 CWC/Well ($MM) $5.8 Avg. Stage Count 25 Prop/ft 2,100 Gals/ft 2,100 Avg. IP30 (BOEPD) 1,244 % Oil 64% % Liquids 81% IRR %* 49% After 200 days, cumulative production from Dorothy infill wells is significantly above 1,100 MBOE TC Average IP30: 1,244 BOEPD (64% oil, 81% liquids) Current GEN17 completions aimed at generating more near wellbore complexity and higher productivity Infill wells projecting 49% IRR* Dorothy Pilot Dorothy Infill Wells** vs. 1,100 MBOE TC 4 *IRR% calculated at $50/$3 flat oil/gas prices ** All wells normalized to 10,000’ lateral length 1.1 MMBOE TC Dorothy Infill Wells** STACK

1.1 MMBOE TC “NEW” Eastern HBP Wells Continue to deliver TC or greater results across vast acreage position “NEW” average of 3 recent Eastern HBP wells projecting above 1,100 MBOE TC Average IP24: 1,647 BOEPD (66% oil, 82% liquids) Average IP30: 1,420 BOEPD (65% oil, 82% liquids) Recent Eastern wells projecting >50% IRR* “NEW” Eastern HBP Wells vs. 1,100 MBOE TC & GEN17 HBP Wells Previous GEN17 HBP Wells 5 Eastern STACK Wells Projecting Above TC “NEW Eastern HBP Wells *IRR% calculated at $50/$3 flat oil/gas prices GEN17 HBP wells 0 50 100 150 200 250 300 0 1 2 3 4 5 6 7 Cumulative Production (MBOE) Months

Previous 2017 Tina 5-6 Well/DSUs 8 Well/DSU** Infill Wells/DSU 4-5 7 CWC/Infill Well ($MM) $9.9 $7.2 Prop/ft 930 1,500 Gals/ft 900 2,000 Cluster Spacing 4 x 65’ 8 x 35’ Avg. IP30 (BOEPD) 1,462 1,708 % Liquids 67% 67% IRR%* 36% 73% Optimized completions, tighter density improve economics 17% increase in IP30 avg. rates >25% decrease in completed well costs ~2X increase in completion volumes “NEW” Tina - 7 infill wells exceeding 2,000 MBOE EUR** Estimated IRR: >70% ROR* SCOOP 2017 Infills Show Productivity Gains Tina Infill Wells IP30: 1,708 BOEPD *IRR% and NPV/well calculated at $50/$3 flat oil/gas prices **All wells normalized to 7,500’ lateral length see footnote 1 on page 2 SCOOP Tina Infill Wells vs. Previous Infill Wells 6 SCOOP Oil TC 0 50 100 150 200 250 300 0 1 2 3 4 5 6 Cumulative Production (MBOE) Months Online Previous SCOOP Oil TC Previous Infill Average (19) Tina Infill Average (7)

Williston Basin: Continued Improvements, Expanding Inventory Malm Pad IP24: 3,808 BOEPD (per well) Williston *IRR% calculated at $50/$3 flat oil/gas prices After nearly 200 wells, NFX continues to show performance improvements in development phase Improvements in completion designs enhancing economics 2-3X increase in proppant and fluid volumes Recent wells projecting above 1,000 MBOE TC “NEW” Off-Anticline Malm 4-well pad in-line with 2017 wells Average IP24: 3,808 BOEPD (64% oil, 83% liquids), per well 1-rig projected to deliver YOY production growth and $95MM FCF >200 operated locations remaining 2017 Infill Wells Outperforming Previous Offset Wells “NEW 1,000 MBOE TC” Previous Infill Wells (2012-15) 2017 Infill Wells Wells Spacing Per DSU 7-8 8-9 CWC Per Well ($MM) $8.1 $5.7 Avg. Stage Count 33 54 Prop/ft 332 944 Gals/ft 255 673 IP30 (BOEPD) 1,036 1,883 % Liquids 86% 86% IRR%* 20% 124% 7 0 50 100 150 200 250 300 0 1 2 3 4 5 6 7 8 9 10 11 12 Cumulative Production, MBOE Months Online 2017 Infill Wells (12) New TC (1,000 MBOE) Previous Infill Offsetting Wells (15) Previous TC (680 MBOE)

Appendix

2017 Capital investments YTD Total Company ($ in millions) Capital Expenditures: Q1 Q2 Q3 Q4 FY17 Exploration & development $186 $271 -- -- $457 Leasehold $30 $24 -- -- $54 Pipeline -- $1 -- -- $1 Total Capital Expenditures1 $216 $296 -- -- $512 1 Excludes ~$64 million in capitalized interest and direct internal costs and ~$10 million in FF&E 9

2Q17 Average Production by Area Production Anadarko Basin Williston Basin Uinta Basin China (Liftings) 1 Oil (bopd) 29,370 13,127 13,804 9,129 NGL (boepd) 23,561 3,152 381 -- Gas (boepd) 35,607 3,779 3,042 -- Total (boepd) 88,538 20,058 17,227 9,129 1 Includes lifted volumes in the quarter. Not reflective of daily rate. 10

2017e Production, Cost and Expense Guidance 11 Domestic China Total Production Oil % 41% 100% 42% NGLs % 19% -- 19% Natural Gas % 40% -- 39% Total (mboepd)1 145.4 – 153.8 4.0 149.4 – 157.8 Expenses ($/boe)2 LOE3,5 $3.41 $16.48 $3.76 Transportation4 $5.58 -- $5.43 Production & other taxes $1.07 $0.21 $1.05 General & administrative (G&A), net5 $3.54 $5.02 $3.58 Interest expense, gross -- -- $2.66 Capitalized interest and direct internal costs -- -- ($2.20) Effective Tax rate 0 – 5% 0 – 5% 0 – 5% 1 Total Company and China volumes include impact of Bohai Bay divestiture 2 Cost and expenses are expected to be within 5% of the estimates above 3 Total LOE includes recurring, major expense and non E&P operating expenses 4 2017e transportation / processing fees include ~$52 million of Arkoma unused firm gas transportation and ~$33 million of Uinta oil and gas delivery shortfall fees 5 Total LOE and G&A includes $4 million and $4 million, respectively, associated with remainder of 2017 activity in China

3Q17e Production, Cost and Expense Guidance 12 Domestic China Total Production Oil % 41% -- 41% NGLs % 19% -- 19% Natural Gas % 40% -- 40% Total (mboepd) 151.0 – 157.7 -- 151.0 – 157.7 Expenses ($/boe)1 LOE2,4 $3.26 -- $3.37 Transportation3 $5.71 -- $5.71 Production & other taxes $1.14 -- $1.14 General & administrative (G&A), net4 $3.62 -- $3.76 Interest expense, gross -- -- $2.63 Capitalized interest and direct internal costs -- -- ($2.15) Effective Tax rate 0 – 5% 0% 0 – 5% 1 Cost and expenses are expected to be within 5% of the estimates above 2 Total LOE includes recurring, major expense and non E&P operating expenses 3 2Q17e transportation / processing fees include ~$13 million of Arkoma unused firm gas transportation and ~$8 million of Uinta oil and gas delivery shortfall fees 4 Total LOE and G&A includes $2 million and $2 million, respectively, associated with Q3 2017 activity in China

Domestic Growth Outlook 10 – 15% CAGR 20 – 25% CAGR 88 108 – 118 125 – 135 137 155 – 165 170 – 180 Liquids Gas Liquids Gas 190 – 210 150 – 170 65% 65% 35% 35% 13 1 Excludes production associated with Eagle Ford and south Texas asset sale. See page 16 for details 2 See pages 14-15 for more information on ratios 1 Forecast to be updated in the future Forecast to be updated in the future Domestic production growth forecast driven by the Anadarko Basin Company goal: to maintain Net Debt / adjusted EBITDA ratios of 1.5 – 2.5x2 throughout plan period 4Q16 4Q17e 4Q18e 4Q19e Anadarko Basin Production ( Mboepd )

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 4.8% YTM1 1 Sourced from Bloomberg as of June 30, 2017. 2 Net debt represents principal balance of debt less cash on balance sheet. Adjusted EBITDA calculated per Company’s credit agreement definition; YE 2016 and subsequent periods reflect 5th amendment executed 3/18/2016. See next slide. Net debt / adj EBITDA2 Fixed debt maturity schedule $ millions No maturities until 1/30/2022 14 $750 $1,000 $700 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 1.9x 2.0x 1.9x YE 2015 YE 2016 Q2 2017

Non-GAAP reconciliation of Adjusted EBITDA 15 Twelve Months Ended December 31, June 30, ($ in millions) 2015 2016 2017 Net Income ($3,362) ($1,230) $306 Adjustments to derive EBITDA: Interest expense, net of capitalized interest $131 $103 $88 Income tax provision (benefit) (1,585) 22 31 Depreciation, depletion and amortization 917 572 451 EBITDA ($3,899) ($533) $876 Adjustments to EBITDA: Ceiling test and other impairment $4,904 $1,028 $0 Non-cash stock-based compensation 25 22 23 Unrealized (gain) loss on commodity derivatives 246 392 50 Other permitted adjustments1 19 59 43 Adjusted EBITDA per credit agreement2 $1,295 $968 $992 1 Other permitted adjustments per Company’s credit agreement include but are not limited to inventory write-downs, office-lease abandonment, severance and relocation costs 2 Adjusted EBITDA calculated per Company’s credit agreement definition; December 31, 2016 and subsequent periods reflect 5th amendment executed 3/18/2016

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).

Oil Hedging Details as of 7/31/17 17 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 3Q 2017 22,304 13,000 13,000 -- $46.49 -- -- -- -- $73.08/$87.90 -- -- -- -- $73.08 -- -- -- -- -- 4Q 2017 25,000 11,000 11,000 -- $46.86 -- -- -- -- $73.09/$88.01 -- -- -- -- $73.09 -- -- -- -- -- 1 Below $73.08 for 3Q17, and $73.09 for 4Q17, these contracts effectively result in realized prices that are on average $14.82 and $14.92 per Bbl higher, respectively, than the cash price that otherwise would have been realized. 2 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 (less the call premium). Denotes update

Oil Hedging Details as of 7/31/17 18 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 1Q 2018 -- -- -- 12,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38/$46-$56.00 2Q 2018 -- -- -- 12,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38/$46-$56.00 3Q 2018 -- -- -- 12,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38/$46-$56.00 4Q 2018 -- -- -- 12,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38/$46-$56.00 3 Below $38 for 2018, these contracts effectively result in realized prices that are $8.00 per Bbl higher, than the cash price that otherwise would have been realized.

Oil Hedging Details as of 7/31/17 19 The following table details the expected impact to pre-tax income (in millions, except prices) from the settlement of our derivative contracts, outlined on the previous slide, at various NYMEX oil prices. Oil Prices Period $20 $30 $40 $50 $60 $70 $80 3Q 2017 $70 $49 $29 $8 ($12) ($33) ($53) 4Q 2017 $75 $52 $29 $6 ($17) ($40) ($63) 1Q 2018 $9 $9 $6 $0 ($4) ($15) ($26) 2Q 2018 $9 $9 $7 $0 ($4) ($15) ($26) 3Q 2018 $9 $9 $7 $0 ($4) ($15) ($26) 4Q 2018 $9 $9 $7 $0 ($4) ($15) ($26)

Gas Hedging Details as of 7/31/17 20 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 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

Gas Hedging Details as of 7/31/17 21 Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 3Q 2017 $15 $5 ($2) ($10) ($19) ($29) ($39) 4Q 2017 $19 $7 ($1) ($10) ($20) ($31) ($43) 1Q 2018 $14 $8 $2 ($2) ($5) ($12) ($18) 2Q 2018 $5 $2 $0 ($2) ($5) ($7) ($10) 3Q 2018 $5 $2 $0 ($2) ($5) ($7) ($10) 4Q 2018 $5 $2 $0 ($2) ($5) ($7) ($10) The following table details the expected impact to pre-tax income (in millions, except prices) from the settlement of our derivative contracts, outlined on the previous slide, at various NYMEX gas prices.

This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The words ““may,” “forecast,” “outlook,” “could,” “budget,” “objectives,” “strategy,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “guidance,” “potential” or other similar expressions are intended to identify forward-looking statements. Other than historical facts included in this presentation, all information and statements, including but not limited to information regarding planned capital expenditures, estimated reserves, estimated production targets, estimated future operating costs, expenses and other financial measures, estimated future tax rates, drilling and development plans, the timing of production, planned capital expenditures, and other plans and objectives for future operations, are forward-looking statements. Although, as of the date of this presentation, Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks and no assurance can be given that such expectations will prove to have been correct. Actual results may vary significantly from those anticipated due to many factors, including but not limited to commodity prices, drilling results, our liquidity and the availability of capital resources, operating risks, industry conditions, U.S. and China governmental regulations, financial counterparty risks, the prices of goods and services, the availability of drilling rigs and other support services, our ability to monetize assets and repay or refinance our existing indebtedness, labor conditions, severe weather conditions, new regulations or changes in tax or environmental legislation, environmental liabilities not covered by indemnity or insurance, legislation or regulatory initiatives intended to address seismic activity, and other operating risks. Please see Newfield’s 2016 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other subsequent public filings, all filed with the U.S. Securities and Exchange Commission (SEC), for a discussion of other factors that may cause actual results to vary. Unpredictable or unknown factors not discussed herein or in Newfield’s SEC filings could also have material adverse effects on Newfield’s actual results as compared to its anticipated results. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. This presentation has been prepared by Newfield and includes market data and other statistical information from sources believed by Newfield to be reliable, including independent industry publications, government publications or other published independent sources. Some data are also based on Newfield’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although Newfield believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. Actual quantities that may be ultimately recovered from Newfield’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Newfield’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates. Newfield may use terms in this presentation, such as “EURs”, “upside potential”, “net unrisked resource”, “gross EURs”, and similar terms that the SEC’s guidelines strictly prohibit in SEC filings. These terms include reserves with substantially less certainty than proved reserves, and no discount or other adjustment is included in the presentation of such reserve numbers. Investors are urged to consider closely the oil and gas disclosures in Newfield’s 2016 Annual Report on Form 10-K, its Quarterly Reports on Form 10-Q and subsequent public filings, available at www.newfield.com, www.sec.gov or by writing Newfield at 4 Waterway Square Place, Suite 100, The Woodlands, Texas 77380 Attn: Investor Relations. In addition, this presentation contains non-GAAP financial measures, which include, but are not limited to, Adjusted EBITDA. Newfield defines EBITDA as net income/loss before income tax expense/benefit, interest expense and depreciation, depletion and amortization. Adjusted EBITDA, as presented herein, is EBITDA before ceiling test impairments, gains/losses on asset sales, non-cash compensation expense, net unrealized (gains) / losses on commodity derivatives and other permitted adjustments. Adjusted EBITDA is not a recognized term under GAAP and does not represent net income as defined under GAAP, and should not be considered an alternative to net income as an indicator of operating performance or to cash flows as a measure of liquidity. Adjusted EBITDA is a supplemental financial measure used by Newfield’s management and by securities analysts, lenders, ratings agencies and others who follow the industry as an indicator of Newfield’s ability to internally fund exploration and development activities. Forward Looking Statements & Related Matters 22