Exhibit 99.1

Newfield Exploration Reports Fourth Quarter and Full-year 2017 Results

Fourth Quarter net production attains company record of nearly 170,000 BOEPD

Crude oil net production exceeds 67,000 BOPD in fourth quarter

Anadarko Basin fourth quarter net production averages record 117,000 BOEPD

Total Company proved reserves increase 33% over prior year to 680 MMBOE

The Woodlands, Texas - February 20, 2018 - Newfield Exploration Company (NYSE: NFX) today announced full-year and fourth quarter 2017 unaudited financial and operating results. Additional details can be found in the Company’s @NFX publication, located on its website http://www.newfield.com.

Newfield plans to host a conference call at 10 a.m. CST on February 21, 2018. To listen to the call, please visit Newfield’s website at http://www.newfield.com. To participate in the call, dial 323-794-2094 and provide conference code 7828350 at least 10 minutes prior to the scheduled start time.

Highlights

·Fourth quarter 2017 net production exceeded guidance expectations.

·Domestic net production was 169,800 BOEPD (40% oil and 61% liquids), exceeding mid-point guidance by approximately 1,750 BOEPD. The better than expected results during the quarter were primarily related to higher volumes from the Anadarko Basin, which reached more than 117,000 BOEPD (12% increase from the prior quarter).

·There were no liftings during the fourth quarter of 2017 from China. Following recent repairs to the Pearl Field’s third-party storage vessel, production in China resumed in early 2018 with a lifting planned for the first quarter.

·Full-year 2017 domestic net production significantly exceeded original guidance expectations.

·Domestic net production grew approximately 10% over the prior year (excluding 9,400 BOEPD of production associated with the 2016 sale of the Company’s Texas assets) and averaged 152,000 BOEPD (40% oil and 61% liquids). Original 2017 guidance was for 3-5% growth.

·For the full year, Anadarko Basin production grew 16% over the prior year and averaged nearly 100,000 BOEPD (34% oil and 62% liquids). Lease operating expenses (LOE) in the Anadarko Basin averaged $1.76 per BOE for the year, the lowest LOE within the Company’s portfolio.

·At the end of the fourth quarter, the Company had $326 million of cash on hand.

·Recent operational highlights include:

·The Company turned to sales its most “technically comprehensive” spacing pilot to-date — the Velta June — which has 12 wells (drilled on four separate pads) located in the Meramec formation.  This 5,000’ lateral development reached combined peak production from the pads in excess of 10,000 BOEPD gross. Newfield operates the Velta June with a 48% working interest.

·The information obtained from the Velta June development will be applied to the entirety of the STACK development with key learnings on completion cluster efficiencies, intra-well communication, well design cost/benefit analysis, fracture geometry and flowback practices.

·Newfield has now completed nearly 80 infill wells in STACK and has tested from four to 12 wells per section in the Meramec horizon. The results have shown the ability to generate strong returns across the acreage from the Stark 10-well development located in the west, to the Jackson/Florene spacing test located to the east. Additional information regarding performance to date and the recent Jackson/Florene test is available in @NFX presentation.

·In 2017, Newfield allocated capital to test additional prospective horizons on its acreage in the Anadarko Basin. This endeavor was dubbed “SCORE” — the Sycamore, Caney, Osage Resource Expansion. Since early 2017, Newfield has drilled or participated in approximately 20 SCORE wells. In addition to successful Newfield operated and industry wells in the Sycamore, Caney and Osage, Newfield recently extended the prolific STACK Meramec play to the northwest and the North SCOOP oil play was extended to the east.

·One distinct highlight was the Larry well, completed in the black oil window along the eastern edge of Newfield’s North SCOOP play. This SXL well had a gross IP30 of more than 1,900 BOEPD, of which more than 80% was oil. Newfield remains highly encouraged by its North SCOOP development and plans significant HBP drilling activity in its three-year plan (3YR Plan).

·Newfield continued to grow its daily production in the Williston Basin with a single operated-rig. In the fourth quarter of 2017, net production averaged 20,300 BOEPD. In 2018, the Company expects to continue to run a single rig and grow production approximately 7% year-over-year.

·Uinta Basin production continued to grow during 2017 with the deployment of a single operated-rig. Fourth quarter 2017 net production averaged 18,200 BOEPD. Recent efforts have focused exclusively on unlocking the value of the Central Basin through lower well costs and improved well productivity.

·Newfield has recently drilled more than 20 wells in the Central Basin, largely under a joint venture drilling agreement. This program successfully reduced completed well costs and enhanced well productivity. Newfield plans to continue to run a single rig in the Central Basin in 2018 related primarily to HBP operations. The Company holds interests in approximately 225,000 net acres in the basin.

Fourth Quarter and Full-Year 2017 Financial and Production Summary

For the fourth quarter, the Company recorded net income of $95 million, or $0.47 per diluted share (all per share amounts are on a diluted basis). Earnings were impacted by one time tax benefits of 47 million or $0.24 per share, due to the Tax Reform Act repeal of AMT and refundable AMT tax credits, and an unrealized derivative loss of $95 million, or $0.48 per share. After adjusting for the effect of the tax benefit and unrealized derivative loss during the period, net income would have been $143 million, or $0.71 per share.

Revenues for the fourth quarter were $509 million. Net cash provided by operating activities was $311 million. Discretionary cash flow from operations was $342 million. Newfield’s total net production in the fourth quarter of 2017 was 15.6 MMBOE, comprised of 40% oil, 21% natural gas liquids and 39% natural gas.

For the full year, the Company recorded net income of $427 million, or $2.13 per diluted share (all per share amounts are on a diluted basis). Earnings were impacted by one time tax benefits of $61 million, or $0.30 per share, due to the Tax Reform Act repeal of AMT and refundable AMT tax credits, $17 million, or $0.09 per share due to the carryback of net operating losses, and an unrealized derivative loss of $83 million, or $0.41 per share. After adjusting for the effect of the tax benefit and unrealized derivative losses during the period, net income would have been $432 million, or $2.15 per share.

Revenues for the full year were $1,767 million. Net cash provided by operating activities was $952 million. Discretionary cash flow from operations was $1,062 million. For the full-year 2017, Newfield’s net production was 57.3 MMBOE, of which 1.7 MMBOE was from offshore China.

Proved Reserves and Costs Incurred

Newfield’s year-end 2017 proved reserves were up 33% year-over-year to 680 MMBOE (over 99% domestic). Crude oil and natural gas prices used to calculate reserves  were $51.34 per barrel (up 20%) and $2.98 per MMbtu (up 20%), respectively. As a result, our standardized measure of discounted future net cash flows is $4.4 billion and our pre-tax present value of reserves (discounted at 10%) at year-end 2017 was approximately $4.9 billion, up 84% over the prior year-end.

During 2017, proved reserves increased 167 MMBOE primarily as a result of positive performance revisions of 139 MMBOE and revisions of 14 MMBOE resulting from commodity price increases. During 2017, Newfield added proved reserves of 76 MMBOE, which included 2 MMBOE of reserves purchased and 74 MMBOE added through extensions, discoveries and other additions. We also sold non-strategic assets of 4 MMBOE and produced 58 MMBOE.

Approximately 58% of proved reserves are liquids and 59% are proved developed. The largest source of reserve additions during 2017 came from the Anadarko Basin, which now total 477 MMBOE and comprise more than over two-thirds of Newfield’s total proved reserves. The proved reserve life index for the Company is approximately 12 years. Newfield engaged the consulting firms DeGolyer and MacNaughton and Ryder Scott Company to perform an audit of the internally prepared reserve estimates on certain fields covering 97% of year-end 2017 proved reserve quantities on a barrel of oil equivalent basis. The purpose of these audits was to provide additional assurance on the reasonableness of internally prepared reserve estimates. Newfield’s proved reserves are, in aggregate, reasonable and within the established audit tolerance guidelines of 10 percent.

Newfield invested approximately $1.3 billion in 2017, which includes approximately $202 million in acquisitions, land and leasehold expenditures and approximately $120 million of capitalized interest and internal costs. The tables below provide additional information on reserves and costs incurred during 2017.

	Crude Oil and Condensate (MMBbls)		Natural Gas (Bcf)		Natural Gas Liquids (MMBbls)		Total (MMBOE)
Total Company Reserves
December 31, 2016	190		1,366		95		513
Revisions of previous estimates	52		318		49		153
Extensions, discoveries and other additions	35		151		14		74
Purchases of properties	1		2		—		2
Sales of properties	(4	)	(3	)	—		(4	)
Production	(24	)	(130	)	(12	)	(58	)
December 31, 2017	250		1,704		146		680

The following table presents costs incurred for oil and gas property acquisition, exploration and development for 2017:

	Domestic		China		Total
Property acquisitions:
Unproved	$	98	$	—	$	98
Proved	104		—		104
Exploration	704		—		704
Development(1)	430		5		435
Total costs incurred(2)	$	1,336	$	5	$	1,341

(1)Includes net change in asset retirement costs of $(20) million

(2)Total costs incurred includes approximately $124 million of capitalized interest and internal costs

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 in the Anadarko and Arkoma basins of Oklahoma, the Williston Basin of North Dakota and the Uinta Basin of Utah. In addition, we have producing 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 wellhead rates of return, estimated future operating costs and other expenses and other financial measures, estimated pre-tax 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 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 and our ability to hedge commodity prices, drilling results, 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, including water regulations, in the areas we operate in 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 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

	4Q17 Actual
4Q17 Actual Results	Domestic		China		Total
Production/Liftings(1)
Crude oil and condensate (MBbls)	6,175		—		6,175
Natural gas (Bcf)	36.6		—		36.6
NGLs (MBbls)	3,338		—		3,338
Total (MBOE)	15,622		—		15,622
Average Realized Prices(2)(3)
Crude oil and condensate (per Bbl)	$	49.60	$	—	$	49.60
Natural gas (per Mcf)	2.58		—		2.58
NGLs (per Bbl)	30.15		—		30.15
Crude oil equivalent (per BOE)	$	32.29	$	—	$	32.29
Operating Expenses:(3)
Lease operating (in millions)
Recurring	$	43	$	2	$	45
Major (workovers, etc.)	$	3	$	—	$	3
Lease operating (per BOE)
Recurring	$	2.78	$	—	$	2.90
Major (workovers, etc.)	$	0.23	$	—	$	0.23
Transportation and processing (in millions)	$	77	$	—	$	77
per BOE	$	4.98	$	—	$	4.98
Production and other taxes (in millions)	$	21	$	—	$	21
per BOE	$	1.35	$	—	$	1.35
General and administrative (G&A), net (in millions)	$	47	$	2	$	49
per BOE	$	3.01	$	—	$	3.14
Capitalized direct internal costs (in millions)					$	(13	)
per BOE					$	(0.85	)
Other operating expenses (income), net (in millions)					$	4
per BOE					$	0.23
Interest expense (in millions)					$	38
per BOE					$	2.44
Capitalized interest (in millions)					$	(15	)
per BOE					$	(0.94	)
Other non-operating (income) expense (in millions)					$	(2	)
per BOE					$	(0.05	)

(1)Represents volumes lifted and sold regardless of when produced. Includes natural gas produced and consumed in operations of 1.1 Bcf during the three months ended December 31, 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 $2.57 per Mcf and the average realized price for our total crude oil and condensate would have been $51.13 per barrel.

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

CONDENSED CONSOLIDATED BALANCE SHEET

(Unaudited, in millions)

	December 31,
	2017			2016
ASSETS
Current assets:
Cash and cash equivalents	$	326		$	555
Short-term investments	—			25
Derivative assets	15			75
Other current assets	405			294
Total current assets	746			949
Oil and gas properties, net (full cost method)	3,931			3,140
Derivative assets	1			—
Other assets	283			223
Total assets	$	4,961		$	4,312
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Derivative liabilities	98			97
Other current liabilities	720			587
Total current liabilities	818			684
Other liabilities	69			63
Derivative liabilities	26			3
Long-term debt	2,434			2,431
Asset retirement obligations	130			154
Deferred taxes	76			39
Total long-term liabilities	2,735			2,690
Stockholders’ equity:
Common stock, treasury stock and additional paid-in capital	3,246			3,205
Accumulated other comprehensive income (loss)	—			(2		)
Retained earnings (deficit)	(1,838		)	(2,265		)
Total stockholders’ equity	1,408			938
Total liabilities and stockholders’ equity	$	4,961		$	4,312

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited, in millions, except per share data)

	Three Months Ended						Year Ended
	December 31,						December 31,
	2017			2016			2017			2016
Oil, gas and NGL revenues	$	509		$	415		$	1,767		$	1,472
Operating expenses:
Lease operating	48			61			215			244
Transportation and processing	77			72			300			272
Production and other taxes	21			8			64			42
Depreciation, depletion and amortization	127			115			467			572
General and administrative	49			46			200			213
Ceiling test and other impairments	—			—			—			1,028
Other	4			1			6			20
Total operating expenses	326			303			1,252			2,391
Income (loss) from operations	183			112			515			(919		)
Other income (expense):
Interest expense	(38		)	(38		)	(150		)	(154		)
Capitalized interest	15			16			61			51
Commodity derivative income (expense)	(105		)	(69		)	(47		)	(191		)
Other, net	2			3			7			5
Total other income (expense)	(126		)	(88		)	(129		)	(289		)
Income (loss) before income taxes	57			24			386			(1,208		)
Income tax provision (benefit)	(38		)	11			(41		)	22
Net income (loss)	$	95		$	13		$	427		$	(1,230	)
Earnings (loss) per share:
Basic	$	0.47		$	0.07		$	2.14		$	(6.36	)
Diluted	$	0.47		$	0.07		$	2.13		$	(6.36	)
Weighted-average number of shares outstanding for basic earnings (loss) per share	200			199			199			193
Weighted-average number of shares outstanding for diluted earnings (loss) per share	201			200			200			193

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited, in millions)

	Year Ended
	December 31,
	2017			2016
Cash flows from operating activities:
Net income (loss)	$	427		$	(1,230	)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation, depletion and amortization	467			572
Deferred tax provision (benefit)	37			13
Stock-based compensation	34			22
Unrealized (gain) loss on derivative contracts	83			392
Ceiling test and other impairments	—			1,028
Other, net	14			13
	1,062			810
Changes in operating assets and liabilities	(110		)	16
Net cash provided by (used in) operating activities	952			826
Cash flows from investing activities:
Additions to and acquisitions of oil and gas properties and other	(1,289		)	(1,371		)
Proceeds from sales of oil and gas properties	96			405
Redemptions of investments	50			—
Purchases of investments	(25		)	(25		)
Net cash provided by (used in) investing activities	(1,168		)	(991		)
Cash flows from financing activities:
Net proceeds (repayments) of borrowings under credit arrangements	—			(39		)
Proceeds from issuances of common stock, net	3			779
Other, net	(16		)	(25		)
Net cash provided by (used in) financing activities	(13		)	715
Increase (decrease) in cash and cash equivalents	(229		)	550
Cash and cash equivalents, beginning of period	555			5
Cash and cash equivalents, end of period	$	326		$	555

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 fourth quarter and full year of 2017 stated without the effect of certain items to net income (loss) is shown below:

	4Q17						2017
	In millions			Per diluted share			In millions			Per diluted share
Net Income (loss)	$	95		$	0.47		$	427		$	2.13
Carryback of net operating losses	—			—			(17		)	(0.09		)
Tax Reform Act repeal of AMT and refundable AMT tax credits	(47		)	(0.24		)	(61		)	(0.30		)
Unrealized (gain) loss on derivative contracts	95			0.48			83			0.41
Earnings stated without the effect of the above items	143			0.71			432			2.15
Weighted-average number of shares outstanding for per diluted share				201						200

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:

	4Q17		2017
	(In millions)
Net cash provided by operating activities	$	311	$	952
Net changes in operating assets and liabilities	31		110
Discretionary cash flow from operations	$	342	$	1,062

PV-10

PV-10 is a non-GAAP financial measure and generally differs from the standardized measure of discounted future net cash flows (the most directly comparable measure calculated and presented under U.S. generally accepted accounting principles) because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor the standardized measure represents an estimate of the fair market value of our crude oil and natural gas properties. PV-10 is used in the oil and natural gas industry as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities.

The following table shows a reconciliation of the standardized measure to PV-10:

	Domestic		China		Total
	(In millions)
December 31, 2017:
Standardized measure of discounted future net cash flows	$	4,354	$	47	$	4,401
Present value of future income tax expense	545		—		545
Proved reserve PV-10 value (before tax)	$	4,899	$	47	$	4,946