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):  July 31, 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 July 31, 2018, Newfield Exploration Company (“Newfield”) issued a press release that announced its second quarter 2018 financial results and provided an update on operations. A copy of that press release is furnished herewith as Exhibit 99.1.

 

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

 

Item 7.01  Regulation FD Disclosure

 

On July 31, 2018, Newfield posted its @NFX publication, which provided prior quarter highlights, current quarter and remaining year outlook on Newfield’s operations and complete hedging positions. A copy of the publication is furnished herewith as Exhibit 99.2.

 

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

 

Item 9.01  Financial Statements and Exhibits

 

(d)                                      Exhibits

 

99.1

 

Second Quarter 2018 Financial Results and Update on Operations issued by Newfield on July 31, 2018

99.2

 

@ NFX Publication posted by Newfield on July 31, 2018

 

2



 

SIGNATURES

 

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

 

 

NEWFIELD EXPLORATION COMPANY

 

 

 

 

Date:  July 31, 2018

By:

/s/ Timothy D. Yang

 

 

Timothy D. Yang

 

 

General Counsel and Corporate Secretary

 

3


Exhibit 99.1

 

 

Newfield Exploration Reports Second Quarter 2018 Results

 

Domestic net production up more than 30% year-over-year; averages 186,700 BOEPD (39% oil, 62% liquids)

Anadarko Basin second quarter net production up more than 45% year-over-year; averages 131,100 BOEPD

Anadarko Basin second quarter net liquids production up more than 50% year-over-year; exceeds 80,000 BOEPD

Anadarko Basin second quarter net crude oil production up more than 40% year-over-year; exceeds 42,000 BOPD

Company achieves surplus of discretionary free cash flow over capital investment of $11 million in second quarter

Newfield raises 2018 expectations for total production and capital investments

 

The Woodlands, Texas - July 31, 2018 - Newfield Exploration Company (NYSE: NFX) today announced second quarter 2018 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 7:30 a.m. CDT on August 1, 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 1873319 at least 10 minutes prior to the scheduled start time.

 

Second Quarter 2018 Highlights

 

·                  Domestic and Anadarko Basin net production exceeded the high-end of the Company’s guidance ranges. Second quarter 2018 domestic net production was 186,700 BOEPD (39% oil and 62% liquids). Stronger than expected production results were driven primarily by the Anadarko Basin which averaged 131,100 BOEPD (mid-point of guidance was 123,000 BOEPD), an increase of 13% relative to the prior quarter and approximately 48% year-over-year.  Second quarter average net liquids production in the Anadarko Basin grew approximately 15% relative to the prior quarter to over 80,000 BOEPD.  The Company’s net crude oil production from the Anadarko Basin averaged over 42,000 BOPD (up more than 40% year-over-year), in line with guidance.

 

·                  Consolidated production for the second quarter of 2018 was approximately 195,300 BOEPD (42% oil, and 64% liquids). The Company lifted 782,000 net barrels from its offshore oil field in China.

 

·                  Second quarter 2018 capital investments were $365 million, or approximately $5 million above original guidance. For the full-year 2018, the Company increased its capital budget by approximately 4% to $1.35 billion, excluding capitalized interest and overhead costs of approximately $114 million.

 



 

·                  Realized prices for crude oil and NGLs remained stable relative to the prior quarter. Specifically, STACK realized crude oil prices during the quarter averaged 100% of NYMEX WTI. Domestic natural gas prices in the quarter averaged approximately 79% of Henry Hub pricing.

 

·                  During the second quarter, discretionary cash flow exceeded capital investments by $11 million. As a result, available liquidity expanded to $2.4 billion ($2 billion in undrawn credit facility, $125 million money market lines of credit and nearly $300 million of available cash on hand).  Additionally, the Company’s ratio of Net Debt to adjusted EBITDA decreased to 1.7x as of June 30, 2018.  This is ahead of the prior guidance of decreasing the ratio below 1.8x by year-end 2018. The Company remains focused on further improving its credit profile and reaching sustainable positive free cash flow generation.

 

·                  The Company continues to advance its Sycamore, Caney, Osage, Resource Expansion (SCORE) initiative.  Recent positive drilling results were released in Northwest STACK, located in northeast Dewey County, Oklahoma, where the Company holds approximately 24,000 net acres (>70% operated).  Results on several recent wells can be found in @NFX. By year-end, over 80% of this position is expected to be HBP.

 

·                  In the Williston Basin, Newfield’s net production in the quarter averaged 21,000 BOEPD. Importantly, the Williston Basin program is expected to deliver discretionary cash flow that exceeds capital expenditures by more than $130 million at today’s strip oil prices. Uinta Basin net production averaged approximately 21,000 BOEPD during the quarter.

 



 

Second Quarter 2018 Financial and Production Summary

 

For the second quarter, the Company recorded net income of $119 million, or $0.59 per diluted share (all per share amounts are on a diluted basis). Earnings were impacted by an unrealized derivative loss of $78 million, or $0.39 per share, and a gain from a favorable legal settlement of $8 million, or $0.04 per share. After adjusting for the effects of the unrealized derivative loss and legal settlement during the period, net income would have been $189 million, or $0.94 per share. See the “Explanation and Reconciliation of Non-GAAP Financial Measures” at the end of this press release for additional disclosures.

 

Revenues for the second quarter were $679 million. Net cash provided by operating activities was $488 million. Discretionary cash flow from operations was $376 million. See the “Explanation and Reconciliation of Non-GAAP Financial Measures” at the end of this press release for additional disclosures.

 

Newfield’s consolidated net production in the second quarter of 2018 was approximately 195,300 BOEPD, comprised of 42% oil, 22% natural gas liquids and 36% natural gas. Domestic net production in the same quarter was approximately 186,700 BOEPD, comprised of 39% oil, 23% natural gas liquids and 38% natural gas.

 

2018 Production and Capital Investment Outlook

 

Newfield today increased it’s expectations for annual production volumes and capital investments in 2018. The table below updates guidance for production by commodity and planned capital investments for the Company’s Domestic and Anadarko Basin assets. Newfield now expects to invest approximately $1.35 billion in 2018 (previous guidance was $1.3 billion), excluding capitalized interest overhead costs of about $114 million. The increase in estimated capital investments for 2018 is primarily related to greater participation in projects operated by others as well as increased working interest levels in its operated developments year-to-date.

 

In the table below, the Company provides an updated 2018 production and capital outlook for Domestic, and more specifically, the Anadarko Basin.  Cost and expense guidance for the year can be found in the Company’s @NFX presentation.

 



 

2018E Quarterly Guidance(1)

 

 

 

1Q18
Actual

 

2Q18
Guidance

 

2Q18
Actual

 

3Q18E(2)

 

4Q18E(2)

 

FY18E

 

DOMESTIC GUIDANCE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PRODUCTION

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (mbopd)

 

72

 

72

 

74

 

73-77

 

73-77

 

74

 

NGL (mbopd)

 

35

 

37

 

43

 

40-46

 

40-46

 

41

 

Gas (mmcfpd)

 

401

 

402

 

422

 

420-450

 

420-450

 

425

 

Total (mboepd)

 

174

 

172-180

 

187

 

185-195

 

185-195

 

180-190

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPEX ($MM)

 

$

345

 

$

360

 

$

365

 

$

365

 

$

275

 

$

1,350

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

ANADARKO GUIDANCE

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

PRODUCTION

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil (mbopd)

 

40

 

42

 

42

 

42-44

 

42-44

 

42

 

NGL (mbopd)

 

31

 

33

 

38

 

36-40

 

36-40

 

36

 

Gas (mmcfpd)

 

279

 

288

 

304

 

310-330

 

310-330

 

305

 

Total (mboepd)

 

117

 

120-126

 

131

 

130-140

 

130-140

 

125-135

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

CAPEX ($MM)

 

$

282

 

$

265

 

$

291

 

$

265

 

$

220

 

$

1,060

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

China Production (mboepd)

 

3

 

7-9

 

9

 

2-3

 

3-5

 

 

 

 


(1)Production and capital are expected to be within 5% of the estimates above

(2)Individual product guidance ranges do not necessarily sum to total production guidance range.

 

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 a producing oil field 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,” “prospective,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “guidance,” “potential” or other similar expressions are intended to identify forward-looking statements. Other than historical facts included in this release, all information and statements, including but not limited to information regarding planned capital expenditures, estimated reserves, estimated production targets and expected production mix, estimated future operating costs and other expenses and other financial measures, estimated future tax rates, drilling and development plans, the timing of production, planned capital expenditures, and other plans and objectives for future operations, are forward-looking statements. Although, as of the date of this release, Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks, some of which are beyond Newfield’s control and are difficult to predict.  No assurance can be given that such expectations will prove to have been correct. Actual results may vary significantly from those anticipated due to many factors, including but not limited to commodity prices, drilling results, changes in commodity mix, accessibility to economic transportation modes and processing facilities, our liquidity and the availability of capital resources, operating risks, industry conditions, U.S. and China governmental regulations, financial counterparty risks, the prices of goods and services, the availability of drilling rigs and other oilfield services, our ability to monetize assets and repay or refinance our existing indebtedness, labor conditions, severe

 



 

weather conditions, new regulations or changes in tax or environmental legislation, environmental liabilities not covered by indemnity or insurance, legislation or regulatory initiatives intended to address seismic activity, and other operating risks. Please see Newfield’s 2017 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other subsequent public filings, all filed with the U.S. Securities and Exchange Commission (SEC), for a discussion of other factors that may cause actual results to vary. Unpredictable or unknown factors not discussed in this press release or in Newfield’s SEC filings could also have material adverse effects on Newfield’s actual results as compared to its anticipated results. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this release and are not guarantees of performance. Unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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

Phone: 281-210-5182

Email: IR@newfield.com

 



 

2Q18 Actual Results

 

 

 

Domestic

 

China

 

Total

 

Production/Liftings(1)

 

 

 

 

 

 

 

Crude oil and condensate (MBbls)

 

6,696

 

782

 

7,478

 

Natural gas (Bcf)

 

38.4

 

 

38.4

 

NGLs (MBbls)

 

3,892

 

 

3,892

 

Total (MBOE)

 

16,989

 

782

 

17,771

 

 

 

 

 

 

 

 

 

Average Realized Prices(2)

 

 

 

 

 

 

 

Crude oil and condensate (per Bbl)

 

$

63.15

 

$

73.97

 

$

64.28

 

Natural gas (per Mcf)

 

2.22

 

 

2.22

 

NGLs (per Bbl)

 

28.82

 

 

28.82

 

Crude oil equivalent (per BOE)

 

$

36.50

 

$

73.97

 

$

38.15

 

 

 

 

Domestic

 

China

 

Total

 

Domestic

 

China

 

Total

 

Selected Expenses:

 

(In millions)

 

(Per BOE)

 

Lease operating

 

$

60

 

$

13

 

$

73

 

$

3.54

 

$

16.69

 

$

4.12

 

Transportation and processing

 

83

 

 

83

 

4.85

 

 

4.64

 

Production and other taxes

 

26

 

1

 

27

 

1.52

 

1.32

 

1.51

 

General and administrative, net(3)

 

50

 

1

 

51

 

2.94

 

1.83

 

2.90

 

Other operating expenses (income), net

 

(7

)

1

 

(6

)

(0.41

)

0.72

 

(0.36

)

Interest expense

 

 

 

 

 

37

 

 

 

 

 

2.10

 

Capitalized Interest

 

 

 

 

 

(15

)

 

 

 

 

(0.84

)

Other non-operating (income) expense

 

 

 

 

 

 

 

 

 

 

 

 


(1)         Represents volumes lifted and sold regardless of when produced.

 

(2)         Average realized prices including the effects of derivative contracts for our domestic and consolidated crude oil and condensate would have been $52.72 per barrel and $54.94 per barrel, respectively. The average realized price including the effects of derivative contracts for domestic natural gas would have been $2.32 per Mcf and the average realized price for domestic NGLs would have been $28.54 per barrel. We did not have any derivative contracts associated with our China production as of June 30, 2018.

 

(3)         Net general and administrative expenses excludes $13 million, or $0.75 per BOE, of capitalized direct internal costs.

 



 

CONDENSED CONSOLIDATED BALANCE SHEET

(Unaudited, in millions)

 

 

 

June 30,

 

December 31,

 

 

 

2018

 

2017

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

293

 

$

326

 

Derivative assets

 

2

 

15

 

Other current assets

 

461

 

405

 

Total current assets

 

756

 

746

 

 

 

 

 

 

 

Oil and gas properties, net (full cost method)

 

4,416

 

3,931

 

Restricted cash

 

46

 

40

 

Other assets

 

243

 

244

 

Total assets

 

$

5,461

 

$

4,961

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Derivative liabilities

 

$

228

 

$

98

 

Other current liabilities

 

822

 

720

 

Total current liabilities

 

1,050

 

818

 

 

 

 

 

 

 

Other liabilities

 

66

 

69

 

Derivative liabilities

 

39

 

26

 

Long-term debt

 

2,435

 

2,434

 

Asset retirement obligations

 

134

 

130

 

Deferred taxes

 

97

 

76

 

Total long-term liabilities

 

2,771

 

2,735

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Common stock, treasury stock and additional paid-in capital

 

3,274

 

3,246

 

Accumulated other comprehensive income (loss)

 

(1

)

 

Retained earnings (deficit)

 

(1,633

)

(1,838

)

Total stockholders’ equity

 

1,640

 

1,408

 

Total liabilities and stockholders’ equity

 

$

5,461

 

$

4,961

 

 



 

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited, in millions, except per share data)

 

 

 

Three Months Ended

 

Six Months Ended

 

 

 

June 30,

 

June 30,

 

 

 

2018

 

2017

 

2018

 

2017

 

 

 

 

 

 

 

 

 

 

 

Oil, gas and NGL revenues

 

$

679

 

$

402

 

$

1,259

 

$

819

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating

 

73

 

58

 

131

 

114

 

Transportation and processing

 

83

 

71

 

161

 

143

 

Production and other taxes

 

27

 

13

 

51

 

27

 

Depreciation, depletion and amortization

 

151

 

110

 

284

 

216

 

General and administrative

 

51

 

51

 

105

 

98

 

Other

 

(6

)

 

(5

)

1

 

Total operating expenses

 

379

 

303

 

727

 

599

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from operations

 

300

 

99

 

532

 

220

 

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest expense

 

(37

)

(37

)

(75

)

(75

)

Capitalized interest

 

15

 

15

 

30

 

31

 

Commodity derivative income (expense)

 

(145

)

28

 

(256

)

81

 

Other, net

 

 

2

 

1

 

4

 

Total other income (expense)

 

(167

)

8

 

(300

)

41

 

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes

 

133

 

107

 

232

 

261

 

 

 

 

 

 

 

 

 

 

 

Income tax provision (benefit)

 

14

 

9

 

27

 

16

 

Net income (loss)

 

$

119

 

$

98

 

$

205

 

$

245

 

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

$

0.60

 

$

0.49

 

$

1.03

 

$

1.23

 

Diluted

 

$

0.59

 

$

0.49

 

$

1.02

 

$

1.22

 

 

 

 

 

 

 

 

 

 

 

Weighted-average number of shares outstanding for basic earnings (loss) per share

 

200

 

199

 

200

 

199

 

 

 

 

 

 

 

 

 

 

 

Weighted-average number of shares outstanding for diluted earnings (loss) per share

 

201

 

200

 

200

 

200

 

 



 

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited, in millions)

 

 

 

Six Months Ended

 

 

 

June 30,

 

 

 

2018

 

2017

 

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

 

$

205

 

$

245

 

Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:

 

 

 

 

 

Depreciation, depletion and amortization

 

284

 

216

 

Deferred tax provision (benefit)

 

21

 

16

 

Stock-based compensation

 

25

 

20

 

Unrealized (gain) loss on derivative contracts

 

157

 

(46

)

Other, net

 

5

 

7

 

 

 

697

 

458

 

Changes in operating assets and liabilities

 

51

 

16

 

Net cash provided by (used in) operating activities

 

748

 

474

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Additions to and acquisitions of oil and gas properties and other

 

(789

)

(521

)

Proceeds from sales of oil and gas properties

 

23

 

28

 

Net cash provided by (used in) investing activities

 

(766

)

(493

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Debt issue costs

 

(8

)

 

Other, net

 

(1

)

(7

)

Net cash provided by (used in) financing activities

 

(9

)

(7

)

 

 

 

 

 

 

Net increase (decrease) in cash, cash equivalents and restricted cash

 

(27

)

(26

)

Cash, cash equivalents and restricted cash, beginning of period

 

$

366

 

$

580

 

Cash, cash equivalents and restricted cash, end of period

 

$

339

 

$

554

 

 



 

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 (GAAP). A reconciliation of earnings for the second quarter of 2018 stated without the effect of certain items to net income (loss) is shown below (in millions, except per share data):

 

 

 

2Q18

 

 

 

(In millions)

 

(Per diluted share)

 

Net Income (loss)

 

$

119

 

$

0.59

 

Unrealized (gain) loss on derivative contracts

 

78

 

0.39

 

Legal settlement

 

(8

)

(0.04

)

Earnings stated without the effect of the above items

 

$

189

 

$

0.94

 

Weighted-average number of shares outstanding for per diluted share

 

 

 

201

 

 

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

 

 

 

2Q18

 

 

 

(In millions)

 

Net cash provided by operating activities

 

$

488

 

Net changes in operating assets and liabilities

 

(112

)

Discretionary cash flow from operations

 

$

376

 

 

Net Debt to Earnings Before Interest, Taxes, Depreciation, and Amortization (EBITDA)

 

EBITDA is determined by subtracting from net income, interest, income tax provision, and DD&A. Adjusted EBITDA, a non-GAAP measure, further subtracts out non-cash items related to impairments, stock based compensation, derivative gain or loss, and other permitted adjustments. Adjusted EBITDA should not be considered an alternative to net income, as defined by GAAP. A reconciliation of net income to EBITDA, and to adjusted EBITDA, is shown below. Net debt is defined as principal amount of debt less cash and cash equivalents.

 



 

 

 

QTD

 

Twelve Months Ended

 

 

 

3Q17

 

4Q17

 

1Q18

 

2Q18

 

June 30, 2018

 

 

 

 

 

 

 

(In millions)

 

 

 

 

 

Net Income

 

$

87

 

$

95

 

$

86

 

$

119

 

$

387

 

Adjustments to derive EBITDA:

 

 

 

 

 

 

 

 

 

 

 

Interest expense, net of capitalized interest

 

22

 

23

 

23

 

22

 

90

 

Income tax provision (benefit)

 

(19

)

(38

)

13

 

14

 

(30

)

Depreciation, depletion and amortization (DD&A)

 

124

 

127

 

133

 

151

 

535

 

EBITDA

 

$

214

 

$

207

 

$

255

 

$

306

 

982

 

 

 

 

 

 

 

 

 

 

 

 

 

Adjustments to EBITDA:

 

 

 

 

 

 

 

 

 

 

 

Ceiling test and other impairment

 

$

 

$

 

$

 

$

 

$

 

Non-cash stock based compensation

 

5

 

9

 

9

 

16

 

39

 

Unrealized (gain) loss on commodity derivatives

 

34

 

95

 

79

 

78

 

286

 

Other permitted adjustments

 

1

 

3

 

1

 

(6

)

(1

)

Adjusted EBITDA

 

$

254

 

$

314

 

$

344

 

$

394

 

$

1,306

 

 

 

 

 

 

 

 

 

 

 

 

 

Long-term debt

 

 

 

 

 

 

 

 

 

$

2,450

 

Less: Cash

 

 

 

 

 

 

 

 

 

293

 

Net debt

 

 

 

 

 

 

 

 

 

$

2,157

 

Net debt / Adjusted EBITDA

 

 

 

 

 

 

 

 

 

1.7

 

 


Exhibit 99.2

2Q18 UPDATE Exhibit 99.2

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Forward Looking Statements and Related Matters This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The words “may,” “forecast,” “outlook,” “could,” “budget,” “objectives,” “strategy,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “prospective,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “guidance,” “potential” or other similar expressions are intended to identify forward-looking statements. Other than historical facts included in this presentation, all information and statements, including but not limited to information regarding planned capital expenditures, estimated reserves, estimated production targets and commodity mix, estimated pre-tax wellhead rates of return, estimated future operating costs and other expenses and other financial measures, estimated future tax rates, drilling and development plans, the timing of production, and other plans and objectives for future operations, are forward-looking statements. Although, as of the date of this presentation, Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks, some of which are beyond Newfield’s control and are difficult to predict. No assurance can be given that such expectations will prove to have been correct. Actual results may vary significantly from those anticipated due to many factors, including but not limited to commodity prices and our ability to hedge commodity prices, drilling results, changes in commodity mix, accessibility to economic transportation modes and processing facilities, our liquidity and the availability of capital resources, operating risks, failures and hazards, industry conditions, governmental regulations in the areas in which we operate, including water regulations, financial counterparty risks, the prices of goods and services, the availability of drilling rigs and other oilfield services, our ability to monetize assets and repay or refinance our existing indebtedness, labor conditions, severe weather conditions, new regulations or changes in tax or environmental legislation, environmental liabilities not covered by indemnity or insurance, legislation or regulatory initiatives intended to address seismic activity or induced seismicity, and other operating risks. Please see Newfield’s 2017 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other subsequent public filings, all filed with the U.S. Securities and Exchange Commission (SEC), for a discussion of other factors that may cause actual results to vary. Unpredictable or unknown factors not discussed herein or in Newfield’s SEC filings could also have material adverse effects on Newfield’s actual results as compared to its anticipated results. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this presentation and are not guarantees of performance. Unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. 2

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Forward Looking Statements and Related Matters (continued) This presentation has been prepared by Newfield and includes market data and other statistical information from sources believed by Newfield to be reliable, including independent industry publications, government publications or other published independent sources. Some data are also based on Newfield’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although Newfield believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. Actual quantities that may be ultimately recovered from Newfield’s assets may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Newfield’s ongoing drilling program, which will be directly affected by commodity prices (including our ability to hedge commodity prices) and our pre-tax wellhead rates of return, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation and processing constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates and commodity mix. Newfield may use terms in this presentation, such as “EURs,” “unrisked locations,” “risked locations,” “net effective reservoir acreage,” “upside potential,” “net unrisked resource,” “gross EURs,” and similar terms that the SEC’s guidelines strictly prohibit in SEC filings. These terms include reserves with substantially less certainty than proved reserves, and no discount or other adjustment is included in the presentation of such reserve numbers. Investors are urged to consider closely the oil and gas disclosures in Newfield’s 2017 Annual Report on Form 10-K and subsequent public filings, available at www.newfield.com, www.sec.gov or by writing Newfield at 4 Waterway Square Place, Suite 100, The Woodlands, Texas 77380 Attn: Investor Relations. In addition, this presentation contains non-GAAP financial measures, which include, but are not limited to, Adjusted EBITDA. Newfield defines EBITDA as net income/loss before income tax expense/benefit, interest expense and depreciation, depletion and amortization. Adjusted EBITDA, as presented herein, is EBITDA before ceiling test impairments, gains/losses on asset sales, non-cash compensation expense, net unrealized (gains) / losses on commodity derivatives and other permitted adjustments. Adjusted EBITDA is not a recognized term under GAAP and does not represent net income as defined under GAAP, and should not be considered an alternative to net income as an indicator of operating performance or to cash flows as a measure of liquidity. Adjusted EBITDA is a supplemental financial measure used by Newfield’s management and by securities analysts, lenders, ratings agencies and others who follow the industry as an indicator of Newfield’s ability to internally fund exploration and development activities. NOTE: All numbered references throughout document are defined in Endnotes beginning on page 28 of this presentation. 3

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2Q18 Highlights: Anadarko Basin Drives Outperformance 2Q18 reached new heights for the Company Domestic net production up >30% Y-o-Y: 186,700 BOEPD (39% oil, 62% liquids) Anadarko Basin net production up >45% Y-o-Y: 131,100 BOEPD (32% oil, 61% liquids) Anadarko Basin liquids production up >50% Y-o-Y: >80,000 barrels per day (7% above guidance) Anadarko Basin oil production up >40% Y-o-Y: >42,000 BOPD (in-line with guidance) Discretionary cash flow exceeded capital investment by $11 million Raising full-year production and capital guidance 2018E Domestic production outlook of 180-190 MBOEPD (up from 175-185 MBOEPD) 2018E Anadarko Basin production outlook of 125-135 MBOEPD (up from 120-130 MBOEPD) 2018E Capital budget increased 4% to approximately $1,350 million to reflect increased working interest and non-operated activity in high-return projects Successful Meramec assessments in NW STACK providing inventory confidence Newfield holds approximately 24,000 net acres in this region Expect to operate over 70% of the development Approximately 80% HBP by year-end 2018 4

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Raising 2018 Guidance Based on Strong Anadarko Results 5 “NEW” “NEW” Domestic Production Guidance (mboepd) Anadarko Basin Production Guidance (mboepd) Raising 2018E domestic and Anadarko Basin production expectations (on BOE basis) based on strong 1H18 results and reiterating total oil volumes 2018E Domestic and Anadarko Basin production now expected to grow 18-25% and 25-35%, respectively DOMESTIC

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1H18 Anadarko Basin Adjustments From Partner Activity 6 Avg. 1H18: >124,000 BOEPD Gas: 39% / NGL: 28% / Oil: 33% $515 $573 ~ $25 ~ $35 Orig. Guidance Higher Op. WI & Operated Outspend Incremental OBO 1H18 Actual $mm Anadarko Basin CAPEX 69% 8% 23% OBO Production Oil 34% 31% 35% Operated Production Gas NGLs

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Unlocking Resource Expansion in NW STACK SCORE Program NW STACK Assessment Successes STACK Walters 1H-22X Avg. GPI: 9,662’ IP30: 1,274 boepd (68% Oil) CHARLES 1H-19 Avg. GPI: 4,892’ IP30: 931 boepd (49% Oil) Hyden 1H-17x Avg. GPI: 9.755’ IP30: 1,555 boepd (40% Oil) GOSS 1H-8X Avg. GPI: 9,772’ IP30: 1,125 boepd (47% Oil) Recent Newfield operated wells demonstrate prolific nature of NW STACK Recent well highlights (IP30s): CHARLES 1H-19: ~900 boepd (49% oil) JAKE 1H-21X: >1,500 boepd (73% oil) WALTERS 1H-22X: >1,250 boepd (68% oil) HYDEN 1H-17X: >1,500 boepd (40% oil) GOSS 1H-8X: >1,100 boepd (47% oil) Newfield controls approximately 24,000 net acres (>70% operated3) in key area of interest 7 Jake 1H-21X Avg. GPI: 10,056’ IP30: 1,533 boepd (73% Oil) * Average cumulative performance normalized to 10,000’ lateral length. 0 1 2 3 4 5 6 0 50 100 150 200 250 300 350 400 0 2 4 6 8 10 12 WELL COUNT AVG. CUMULATIVE MBOE Months Online 3YR Plan Recent NW STACK Wells (5)* Well Count

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Newfield Has Led Development of Water Solutions in STACK 8 Since 2015, NFX has invested >$80 MM on permanent water pipelines and infrastructure ~75 miles of permanent “dual” pipe (effectively ~150 miles) 30,000 Bbl/d Barton water recycling and treatment facility >13 million barrels of water storage in STACK Operational benefits of infrastructure across STACK Reduced operating cost and improved efficiencies Reduced reliance on trucking and related services No history of operational integrity issues on existing pipeline infrastructure Existing Permanent Water Pipelines Future Permanent Water Pipelines Barton Water Treatment Facility 8

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Net debt / adj EBITDA4 Long-Term Debt Maturities $ millions No maturities until 1/30/2022 Leverage Profile Improvement Ahead of Schedule FCF generation in 2Q18 has placed Net debt / adj. EBITDA at 1.7x (Ahead of FY18 guidance) Expanding liquidity to over $2.4 billion $2.0 billion undrawn unsecured credit facility $293 million cash $125 million undrawn line of credit 9 Improving Debt Profile 2018E Guidance 2Q18 Actual “Ahead of Schedule” 1.7x 1.8x 2018E 2019E 2020E $750 $1,000 $700 2018 2018 2019 2020 2021 2022 2023 2024 2025 2026

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2Q18 Results

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2Q18 Domestic Results 1Q18 ACTUAL 2Q18 GUIDANCE 2Q18 ACTUAL PRODUCTION Oil (mbopd) 72 72 74 NGL (mbopd) 35 37 43 Gas (mmcfpd) 401 402 422 Total (mboepd) 174 172-180 187 EXPENSES ($/BOE)* LOE $3.43 $3.43 $3.13 Transportation** $5.01 $4.95 $4.85 Production & other taxes $1.53 4.7% $1.52 General & administrative, net $3.35 $3.44 $2.95 CAPEX ($MM)*** $345 $360 $365 OPERATIONS Operated rigs 11 - 13 Op. wells placed on production (WI%/NRI%) 54 (54% / 44%) - 49 (85% / 68%) Op. wells placed on production (Average GPI) 8,312‘ - 7,925’ *Guidance numbers for Expenses shown on annual basis. **Actual transportation fees include $12 million associated with firm gas transportation in the Arkoma Basin in each of 1Q18A and 2Q18A, as well as $4 million of shortfall fees in the Uinta Basin in 1Q18A. *** CAPEX excludes ~$28 million of capitalized interest and direct internal cost in each of 1Q18A and 2Q18A. 11

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2Q18 Basin Results ANADARKO WILLISTON UINTA ARKOMA PRODUCTION Oil (mbopd) 42.1 14.3 17.6 0.0 NGL (mbopd) 38.3 3.4 0.6 0.4 Gas (mmcfpd) 304.4 19.9 14.7 81.0 Total (mboepd) 131.1 21.0 20.7 13.9 EXPENSES ($/BOE) LOE $2.29 $5.59 $9.87 $3.24 Transportation* $4.37 $5.66 $1.13 $4.44 Production & other taxes $0.95 $4.26 $2.69 $0.72 Total Expenses $7.61 $15.51 $13.69 $8.40 CAPEX ($MM) Drilling & Completion $284 $41 $25 ($2) Other $7 $1 $2 $1 Total CAPEX** $291 $42 $27 ($1) OPERATIONS Operated rigs 11 1 1 0 Op. wells placed on production (WI%/NRI%) 40 (89% / 70%) 6 (70% / 57%) 3 (74% / 59%) NA Op. wells placed on production (Average GPI) 7,513’ 10,052’ 9,173’ NA 12 * Transportation fees exclude $12 million of firm gas transportation in the Arkoma. ** CAPEX excludes $6 million associated with Corporate FF&E.

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2018 Annual Guidance DOMESTIC GUIDANCE 2017 ACTUAL 2018 ESTIMATES* PRODUCTION Oil (mbopd) 61.2 74 NGL (mbopd) 31.7 41 Gas (mmcfpd) 356.5 425 Total (mboepd) 152.2 180 - 190 EXPENSES ($/BOE) LOE $3.47 $3.47 Transportation** $5.40 $4.93 Production & other taxes 3.5% 4.6% General & administrative, net $3.49 $3.10 Interest expense, net $1.62 $1.36 CAPEX ($MM) Drilling & Completion $992 $1,210 Other $161 $140 Total CAPEX*** $1,153 $1,350 CHINA GUIDANCE Production (mbopd) 4.7 3 - 5 13 * Individual product guidance ranges do not necessarily sum to total production guidance range. ** 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 approximately $36 million and $13 million of firm gas transportation in the Arkoma Basin and shortfall fees in the Uinta Basin, respectively. *** 2017A and 2018E exclude ~$124 million and ~$114 million of capitalized interest and direct internal costs, respectively. Includes ~$31 million of Corporate FF&E for 2018E.

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2018 Quarterly Guidance DOMESTIC GUIDANCE 1Q18 Actual 2Q18 Guidance 2Q18 Actual 3Q18E* 4Q18E* PRODUCTION Oil (mbopd) 72 72 74 73 – 77 73 – 77 NGL (mbopd) 35 37 43 40 – 46 40 – 46 Gas (mmcfpd) 401 402 422 420 – 450 420 – 450 Total (mboepd) 174 172-180 187 185 – 195 185 – 195 CAPEX ($MM) $345 $360 $365 $365 $275 14 *Individual product guidance ranges do not necessarily sum to total production guidance range. ANADARKO GUIDANCE 1Q18 Actual 2Q18 GUIDANCE 2Q18 Actual 3Q18E* 4Q18E* PRODUCTION Oil (mbopd) 40 42 42 42 – 44 42 – 44 NGL (mbopd) 31 33 38 36 – 40 36 –40 Gas (mmcfpd) 279 288 304 310 – 330 310 – 330 Total (mboepd) 117 120-126 131 130 – 140 130 – 140 CAPEX ($MM) $282 $265 $291 $265 $220 China Production (mboepd) 3 7-9 9 2 – 3

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APPENDIX

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STACK 3YR Plan Assumptions: EUR Range: 1.1 – 1.7 MMBOE1 Well Cost Range (incl. facilities): $7.6 – $8.7 million 3YR Plan Average: 1.3 MMBOE1 EUR @ $7.9 million well cost (incl. facilities) STACK 3YR Plan Modeling Assumptions MODELING ASSUMPTIONS STACK PRODUCTION Avg. IP30 (BOEPD) 1,300 Avg. IP30 (% oil / % liquids) 59% / 79% Avg. EUR (mboe) 1,300 Avg. EUR (oil mbo / liquids mboe) 455 / 860 First Five Year Cum (mboe) 675 First Five Year Cum (mbo) 275 EXPENSES ($/BOE) LOE $1.80 Oil transportation $1.73 Gas/NGL transportation/processing $4.70 Production & other taxes 5% (3 years) / 7% (thereafter)* REALIZATIONS** Oil (%WTI) 100% NGLs (%WTI) 43% Gas (%HH) 84% CAPEX ($MM) Avg. gross completed well cost (incl. facilities) $7.9 OPERATIONS Avg. operated rigs/year 6 – 8 Est. op. wells placed on production (WI%/NRI%) 414 (77% / 62%) Op. wells avg. GPI 8,907’ 16 1 2 3 4 5 6 7 8 9 10 11 12 0 *Reflects recent Oklahoma Regulatory Changes to Gross Production Tax Rate. **Approximate realizations relative to NYMEX STRIP pricing as of July 2018. 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) LOE $1.65 $1.65 Oil transporation $0.00 $0.00 Gas/NGL transportation/processing $6.10 $6.02 Production & other taxes 5% (3 years) / 7% (thereafter)* REALIZATIONS** Oil (%WTI) 96% 96% NGLs (%WTI) 46% 46% Gas (%HH) 86% 86% CAPEX ($MM) Avg. gross completed well cost (incl. facilities) $8.6 $9.2 OPERATIONS Avg. operated rigs/year 1-2 1-2 Est. op. wells placed on production (WI%/NRI%) 104 (57% / 46%) 30 (67% / 56%) Op. wells avg. GPI 9,438’ 9,423’ SCOOP 3YR Plan Modeling Assumptions 17 *Reflects recent Oklahoma Regulatory Changes to Gross Production Tax Rate **Approximate realizations relative to NYMEX STRIP pricing as of July 2018. 0 100 200 300 400 500 600 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) LOE $4.70 Oil transportation $1.90 Gas/NGL transportation/processing $15.67 Production & other taxes 10% for oil / $0.0555 per MCF gas REALIZATIONS* Oil (%WTI) 95% NGLs (%WTI) 51% Gas (%HH) 74% CAPEX ($MM) Avg. gross completed well cost (incl. facilities) $6.0 OPERATIONS Avg. operated rigs/year 1 Est. op. wells placed on production (WI%/NRI%) 67 (57% / 47%) Op. wells avg. GPI 9,552’ Williston Basin 3YR Plan Modeling Assumptions 18 *Approximate realizations relative to NYMEX STRIP pricing as of July 2018. 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

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Oil Hedging Details as of 07/16/18 Denotes update 19 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts5 Collars Collars w/ Short Puts6 3Q 2018 60,000 3,500 -- -- $56.58 -- -- -- -- $44.00/$56.78 -- -- -- -- -- -- -- -- -- -- 4Q 2018 28,000 3,500 -- 21,000 $55.81 -- -- -- -- $44.00/$56.78 -- -- -- -- -- -- -- -- -- $39.47/$48.34-$56.60

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Oil Hedging Details as of 07/16/18 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts Collars Collars w/ Short Puts8 1Q 2019 -- -- -- 36,500 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $40.47/$50.53-$57.02 2Q 2019 -- -- -- 33,500 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $40.48/$50.51-$57.04 3Q 2019 -- -- -- 27,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $40.80/$50.69-$57.26 4Q 2019 -- -- -- 19,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $40.82/$50.71-$57.32 20

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Oil Hedging Details as of 07/16/18 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. 21 Oil Prices Period $20 $30 $40 $50 $60 $70 $80 3Q 2018 $206 $151 $93 $41 ($20) ($78) ($137) 4Q 2018 $113 $88 $59 $20 ($18) ($67) ($115) 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) Denotes update

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Gas Hedging Details as of 07/16/18 22 Weighted-Average Price Period Volume (mmbtu/d) Swaps Swaps w/ Short Puts8 Collars Collars w/ Short Puts9 3Q 2018 180,000 40,000 10,000 30,000 $2.97 -- -- -- -- $2.60/$2.97 -- -- -- -- $2.90-$3.15 -- -- -- -- $2.30/$2.87-$3.32 4Q 2018 150,000 66,500 39,900 10,100 $2.97 -- -- -- -- $2.66/$3.03 -- -- -- -- $2.88-$3.28 -- -- -- -- $2.30/$2.87-$3.32 Denotes update

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Gas Hedging Details as of 07/16/18 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 1Q 2019 10,000 100,000 $2.91 -- -- $3.00-$3.47 2Q 2019 10,000 -- $2.91 -- -- -- 3Q 2019 10,000 -- $2.91 -- -- -- 4Q 2019 10,000 -- $2.91 -- -- -- 23

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Gas Hedging Details as of 07/16/18 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. 24 Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 3Q 2018 $20 $11 ($1) ($12) ($23) ($35) ($47) 4Q 2018 $19 $11 $0 ($11) ($23) ($36) ($48) 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) Denotes update

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Propane Hedging Details as of 07/16/18 25 Weighted-Average Price Period Volume (bbl/d) Swaps ($/gal) 3Q 2018 5,000 $.830 4Q 2018 3,000 $.807 Denotes update

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Propane Hedging Details as of 07/16/18 The following table details the expected impact to pre-tax income (in millions, except prices) from the settlement of our derivative contracts, outlined on the previous slide, at various Mont Belvieu non-tet prices. 26 Propane Prices Period $.50 $.60 $.70 $.80 $.90 $1.00 $1.10 3Q 2018 $6.4 $4.5 $2.5 $0.6 ($1.3) ($3.3) ($5.2) 4Q 2018 $3.6 $2.4 $1.2 $0.1 ($1.1) ($2.2) ($3.4) Denotes update

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Non-GAAP reconciliation of Adjusted EBITDA 27 ($ in millions) QTD Twelve Months Ended 3Q17 4Q17 1Q18 2Q18 June 30, 2018 Net Income $87 $95 $86 $119 $387 Adjustments to derive EBITDA: Interest expense, net of capitalized interest 22 23 23 22 90 Income tax provision (benefit) (19) (38) 13 14 (30) Depreciation, depletion and amortization 124 127 133 151 535 EBITDA $214 $207 $255 $306 $982 Adjustments to EBITDA: Ceiling test and other impairment - - - - - Non-cash stock based compensation 5 9 9 16 39 Unrealized (gain) loss on commodity derivatives 34 95 79 78 286 Other permitted adjustments* 1 3 1 (6) (1) Adjusted EBITDA** $254 $314 $344 $394 $1,306 Long-term debt $2,450 Less: Cash 293 Net debt $2,157 Net debt / Adjusted EBITDA 1.7 *Other permitted adjustments per Company’s credit agreement include, but are not limited to, inventory write-downs, office-lease abandonment, severance and relocation costs. ** Adjusted EBITDA calculated per Company’s credit agreement definition.

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Endnotes 3YR Plan type curve indicative of anticipated results of wells to be drilled in play during the 3YR Plan and is representative of estimated ultimate recovery from the well and are not indicative of cumulative historical results in play. Estimated ultimate recovery (EUR) refers to potential recoverable oil and natural gas hydrocarbon quantities with ethane processing and depends on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Such amounts do not meet SEC rules and guidelines, may not be reflective of SEC proved reserves and do not equate to or predict any level of reserves or production. Realizations do not factor in transportation fees associated with selling crude in-field. YTD Differentials through June 30, 2018. Gulf Coast based on HSC pricing. Haynesville based on Perryville pricing. Bakken based on 84% of NNG Ventura. Marcellus based on DOM SOUTH pricing. Anadarko based on MC R-AVG pricing. DJ Basin based on CIG pricing. Permian based on WAHA pricing. Percent operated defined as number of government defined sections that Newfield believes it has appropriate working interest to operate development as of June 30, 2018. Net debt represents principal balance of debt less cash on balance sheet. Adjusted EBITDA calculated per Company’s credit agreement definition; The Amended and Restated Credit Agreement dated March 23, 2018. A full reconciliation begins on page 27. 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. Below $39.47 for 4Q18 these contracts effectively result in realized prices that are $8.87 per Bbl higher than the cash price that otherwise would have been realized. We have converted several of our 3-way structures into swaps by buying short puts, selling long puts, and buying calls, then embedding the option cost into the swap price. Below $40.47 for 1Q19, $40.48 for 2Q19, $40.80 for 3Q19, and $40.82 for 4Q19 these contracts effectively result in realized prices that are $10.06, $10.03, $9.89, and $9.89 per Bbl higher, respectively by quarter, than the cash price that otherwise would have been realized. Below $2.60 for 3Q18 and below $2.66 for 4Q18, these contracts effectively result in realized prices that are on average $.37 per MMBtu higher, than the cash price that otherwise would have been realized. Below $2.30 for 3Q18-4Q18 these contracts effectively result in realized prices that are $.57 per MMBtu higher than the cash price that otherwise would have been realized. These 3-way structures were created by selling a $2.30 put to enhance collars already in place. 28

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Key Definitions 3YR Plan Assumptions – Estimated production, costs, expenses (inclusive of CAPEX) shown are expected to be within +/- 5% of the values illustrated. Commodity prices based on NYMEX STRIP pricing as of June 30, 2018. Adjusted EBITDA / Net Debt – See reconciliation beginning on page 27. Discretionary Cash Flow – Cash flow from operations before changes in operating assets and liabilities. Controllable Capital / Capital Investment (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, excluding capitalized interest and overhead costs1. Free Cash / Free Cash Flow – Determined by subtracting Controllable Capital from Cash Flow. GPI – Gross Perforated Interval, which reflects the total feet completed in each horizontal wellbore. IP30 – Average production rate over the peak 30-day period of time following first production. Operated by Others / Non-Operated (“OBO” / “Non-Op”) – Well costs and associated production from projects operated by others Operational Integrity Issues – Issues from normal use of equipment and excludes any issues as a result of third party vandalism or natural disasters. Well Cost – Includes capital associated with drilling, completions, facilities and artificial lift. 29

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