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):   February 20, 2018

 


 

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:

 

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

 

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

 

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

 

o                                    Pre-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 February 20, 2018, Newfield Exploration Company (“Newfield”) issued a press release that announced its fourth quarter and full-year 2017 financial results and provided an update on operations. A copy of that press release is furnished herewith as Exhibit 99.1.

 

Also on February 20, 2018, Newfield issued a separate press release that provided its 2018 capital investment plan and outlook. A copy of that press release is furnished herewith as Exhibit 99.2.

 

The information in Item 2.02 of this Current Report, including the exhibits attached hereto as Exhibit 99.1 and 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 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 February 20, 2018, Newfield posted its @NFX publication, which provided a year end 2017 update, outlook on Newfield’s operations and complete hedging positions. A copy of the publication is furnished herewith as Exhibit 99.3.

 

The information in Item 7.01 of this Current Report, including the exhibit attached hereto as Exhibit 99.3, 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

 

Fourth Quarter and Full-Year 2017 Financial Results and Update on Operations issued by Newfield on February 20, 2018

 

99.2

 

2018 Capital Investment Plan and Growth Outlook issued by Newfield on February 20, 2018

 

99.3

 

@ NFX Publication posted by Newfield on February 20, 2018

 

2



 

Exhibit Index

 

Exhibit No.

 

 Description

99.1

 

Fourth Quarter and Full-Year 2017 Financial Results and Update on Operations issued by Newfield on February 20, 2018

 

 

 

99.2

 

2018 Capital Investment Plan and Growth Outlook issued by Newfield on February 20, 2018

 

 

 

99.3

 

@ NFX Publication posted by Newfield on February 20, 2018

 

3



 

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:   February 20, 2018

 

By:

/s/ Timothy D. Yang

 

 

 

Timothy D. Yang

 

 

 

General Counsel and Corporate Secretary

 

4


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

 

 


Exhibit 99.2

 

 

Newfield Exploration Discloses Three-Year Outlook; Driving Double-Digit Growth Within Expected Cash Flow From Operations (2018-20)

 

The Woodlands, Texas -  February 20, 2018 - Newfield Exploration Company (NYSE: NFX) today provided a detailed overview of the Company’s business plan, including annual guidance expectations for capital investments and key operating and financial metrics for 2018 - 20. In addition, quarterly specific guidance was provided for 2018. Additional information is provided through the @NFX publication, located on its website at www.newfield.com.

 

Newfield plans to host a conference call with analysts and investors at 10 a.m. CST, February 21.

 

“Newfield is in an excellent place today and our three-year outlook has been strategically crafted to maximize our returns and grow our cash flow from operations,” said Lee K. Boothby, Newfield Chairman, President and CEO. “Now that our Anadarko Basin assets are substantially held by production and we have a better understanding of infill well spacing and completion optimizations throughout the company, we are better able to construct a plan that delivers an improving growth outlook with strong returns. Our oil growth is being driven by the Anadarko and Williston basins. We have high levels of confidence in these areas and, at current commodity prices, expect the Company to generate free cash beginning in the second half of 2018 and well into the future.”

 

The key takeaways from our 2018 strategic plan and three-year plan (3YR Plan) are summarized below. Additional slides can be found in @NFX:

 

·                  Newfield expects 2018 domestic production will increase by 14 - 18% over 2017. Domestic oil production growth is expected to be 20 - 25% year-over-year. Importantly, the 3YR Plan is expected to deliver a compound annual growth rate (CAGR) in debt-adjusted production per share of 15 - 20% over the plan period.

 

·                  Internal rates of return (IRRs), on a pre-tax basis, in the Company’s 3YR plan are expected to average in excess of 50%, assuming a NYMEX WTI oil price of $55 per barrel and natural gas price of $2.85 per thousand cubic feet. With these price assumptions, the Company expects that its 2018 deficit to cash flow will be less than $100 million and neutrality will be achieved in the second half of the year. At current STRIP commodity prices (Feb. 19, 2018), forecasted operating cash flow is expected to be more than $1.2 billion. The 2018 capital program is estimated to be cash flow “breakeven” at an estimated NYMEX WTI oil price of approximately $58 per barrel, including the impact of in-place derivative contracts.

 

·                  Our 2018 capital investment budget is $1.3 billion, excluding about $120 million in capitalized interest and internal costs. Of the total, more than 85% is earmarked for drilling and completion (D&C) investments, with approximately 80% allocated to SCOOP and STACK. Substantially all of the remaining D&C investments will be allocated to the Rocky Mountains (Williston and Uinta basins). Modest levels of service cost inflation (predominately back half 2018-weighted) have been included in the outlook. Capital spending for 2018 is expected to be funded from cash flows from operations and cash on hand. For 2019 and 2020, Newfield expects to invest approximately $1.4 billion and $1.5 billion, respectively. For 2019-20,

 



 

cumulative cash flow of approximately $3.3 billion (at $55 NYMEX WTI and $2.85 Mcf) is expected to more than offset combined capital investments of just under $3 billion.

 

·                  For 2018, Newfield expects to run 10-11 rigs in the Anadarko Basin, with activity heavily weighted to multi-well pad developments in SCOOP and STACK. With continuing gains in operational efficiencies in the Anadarko Basin, Newfield expects to place about 150 wells on line during 2018. Of the total wells, approximately 70% are expected to be drilled and completed in STACK. As the assets mature and investments migrate to development, investments in 2018 regional infrastructure and land are estimated to decrease about 25% year-over-year to approximately $85 million.

 

·                  The cornerstone of the Company’s multi-year growth outlook is the Anadarko Basin, which is expected to deliver a CAGR in production of 20 - 25% over the 3YR Plan. For 2018, growth in oil in the Anadarko Basin is estimated at 25 - 30%.

 

·                  In 2018, approximately $245 million is being allocated to ongoing drilling programs in the Rocky Mountains. In the Williston Basin, the Company intends to invest $130 million to drill 20 - 25 high-return oil wells. The Williston program is expected to generate $90 - $100 million of free cash flow in 2018 at current STRIP commodity prices. Following recent encouraging results from a 20-well joint venture program and subsequent drilling, Newfield plans to maintain a single-rig drilling program in the Central Basin region of the Uinta Basin to drill an additional 10 - 15 wells in 2018. The program is focused on HBP drilling as the Company secures the vast majority of its more than 225,000 net acres. For 2018, crude oil production from the Williston and Uinta basins is expected to grow 10% and 19% over the prior year, respectively.

 

·                  To mitigate commodity price risks, Newfield has added to its near-term derivatives positions. For 2018, a daily average of approximately 56,000 barrels of oil per day and approximately 237,500 mmbtu of natural gas per day has been hedged. Complete details can be found in @NFX.

 

·                  Throughout its 3YR Plan, Newfield’s net debt/EBITDA ratio is estimated to improve and average well within the Company’s previously stated target range of 1.5x - 2.5x. At year-end 2017, the ratio was 2.0x.

 

·                  No additional capital is planned for investment in the Pearl field offshore China. Production from the field was restored in early 2018 and a lifting of approximately 250,000 net barrels is expected in the first quarter. Daily net production is expected to average approximately 3,000 - 5,000 BOEPD in 2018.

 

·                  Newfield will amend its annual incentive pay metrics to include debt-adjusted production growth and cash flow per share metrics, a cash on cash return metric for 2018 and a heightened focus on corporate responsibility. Additional details can be found in @NFX.

 



 

2018e Production, Cost and Expense Guidance

 

 

 

2017 ACTUAL

 

2018 ESTIMATES

 

DOMESTIC GUIDANCE

 

 

 

 

 

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(1)

 

$

5.40

 

$

5.09

 

Production & other taxes

 

3.8

%

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(2)

 

$

1,153

 

$

1,300

 

CHINA GUIDANCE

 

 

 

 

 

PRODUCTION

 

 

 

 

 

Oil (mbopd)(3)

 

4.7

 

3 - 5

 

 


(1) 2017A Transportation fee include $52 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.

(2) 2017A and 2018E exclude ~$120 million and ~$100 million of capitalized interest and direct internal cost, respectively.

(3) 2017A China volumes include impact of Bohai Bay divestiture.

 

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 oil producing 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 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 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 in the areas we operate in, 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 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

 


Exhibit 99.3

3YR OUTLOOK & 2017 RESULTS

GRAPHIC

 


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, 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, 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 in, 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

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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 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. 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.

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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

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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

GRAPHIC

 


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)

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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

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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 8 $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

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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 9 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

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10 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” ~

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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 11 ~ 90% Drilling & Completions

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Asset Overview

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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 13 SPRINGER OSWEGO SCORE Hydrocarbon Saturated Column NORTH STACK STACK MERGE NORTH SCOOP SCOOP 150 MILES 1,150 FT

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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 14 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)

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Well Density Tests Helping Unlock Upside (Velta June) 15 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

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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 16 Annuschat / Bernard HBP wells Avg. Lateral Length: 10,126’ Avg. Cum: 359 MBOE (63% Oil)

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CHARLES 1H-19 (MRMC) GPI: 4,892’ IP30: 931 BOEPD (49% Oil) Significant Activity Progressing SCORE Program 17 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

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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 18 ~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

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Driving STACK Efficiencies Through Operational Leadership NFX has a proven track record of improving margins by lowering costs and driving operational efficiencies 19 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

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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 20 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)

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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.) 21 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

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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) 22 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.

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2017 Results

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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 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 24

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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 25 181 269 330 477 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

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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. 26

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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‘ 27 * 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.

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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‘ 28

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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‘ 29 * 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.

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APPENDIX

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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 31 * 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.

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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 32 * 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.

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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 $305 33 ANADARKO GUIDANCE 4Q’17A 1Q’18E 2Q’18E 3Q’18E 4Q’18E PRODUCTION Oil (mbopd) 39.2 40 42 44 42 NGL (mbopd) 32.4 29 30 32 34 Gas (mmcfpd) 274.3 272 288 296 310 Total (mboepd) 117.3 112 – 116 116 – 124 121 – 131 122 – 134 CAPEX ($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.

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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)1 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’ 34 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

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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)1 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 Basin 3YR Plan Modeling Assumptions 35 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

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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)1 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 36 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

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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 37

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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 38

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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) 39

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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 40

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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 -- -- -- 41

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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) 42

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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 43

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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) 44

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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. 45

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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. 46

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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. 47

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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. 48

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