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):   October 31, 2017

 


 

NEWFIELD EXPLORATION COMPANY

(Exact name of registrant as specified in its charter)

 


 

Delaware

 

1-12534

 

72-1133047

(State or other jurisdiction

 

(Commission File Number)

 

(I.R.S. Employer

of incorporation)

 

 

 

Identification No.)

 

4 Waterway Square Place, Suite 100

The Woodlands, Texas 77380

(Address of principal executive offices)

 

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

 

Not Applicable

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

 

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

 

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 October 31, 2017, Newfield Exploration Company (“Newfield”) issued a press release that announced its prior quarter financial results and provided an update on operations. A copy of that press release is furnished herewith as Exhibit 99.1.

 

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

 

Item 7.01  Regulation FD Disclosure

 

On October 31, 2017, Newfield posted its @NFX publication, which provided prior quarter highlights and year and current quarter outlook of Newfield’s operations and complete hedging positions. A copy of the publication is furnished herewith as Exhibit 99.2.

 

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

 

Item 9.01  Financial Statements and Exhibits

 

(d)

 

Exhibits

 

 

 

99.1

Third Quarter 2017 Financial Results and Update on Operations issued by Newfield on October 31, 2017

 

 

99.2

@ NFX Publication posted by Newfield on October 31, 2017

 

2



 

Exhibit Index

 

Exhibit No.

 

 Description

99.1

 

Third Quarter 2017 Financial Results and Update on Operations issued by Newfield on October 31, 2017

 

 

 

99.2

 

@ NFX Publication posted by Newfield on October 31, 2017

 

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:   October 31, 2017

By:

/s/ Timothy D. Yang

 

 

Timothy D. Yang

 

 

General Counsel and Corporate Secretary

 

4


Exhibit 99.1

 

Newfield Exploration Reports Third Quarter 2017 Results

 

Anadarko Basin net oil production grows more than 25% quarter-over-quarter and averages 37,000 BOPD

Anadarko Basin total net production attains new high of 105,000 BOEPD, growing 20% quarter-over-quarter

 

The Woodlands, Texas - October 31, 2017 - Newfield Exploration Company (NYSE: NFX) today announced third quarter 2017 unaudited financial and operating results. Additional details can be found in the Company’s @NFX publication, located on its website.

 

Newfield plans to host a conference call at 10 a.m. CDT on November 1, 2017. To listen to the call, please visit Newfield’s website at http://www.newfield.com. To participate in the call, dial 719-457-2641 and provide conference code 7914344 at least 10 minutes prior to the scheduled start time.

 

Highlights

 

·                  Third quarter 2017 net production significantly exceeded guidance expectations.

 

·                  Domestic net production was 159,000 BOEPD (41% oil and 64% liquids), exceeding the mid-point guidance by approximately 4,650 BOEPD. The better than expected results during the quarter were primarily related to higher volumes in STACK.

 

·                  Consolidated net production was approximately 161,700 BOEPD (42% oil and 64% liquids). In China, the Company lifted approximately 239,000 barrels of remaining oil from the damaged storage vessel during the quarter. Oil liftings in China are expected to resume in the first half of 2018 following repairs to the third-party storage vessel.

 

·                  Newfield’s Anadarko Basin production increased approximately 20% quarter-over-quarter (3Q17 vs 2Q17), averaging approximately 105,000 BOEPD during the third quarter. The Anadarko Basin now comprises approximately two-thirds of total domestic production.

 

·                  Anadarko Basin net oil production grew more than 25% quarter-over-quarter (3Q17 vs 2Q17) to achieve a record average quarterly output of 37,000 BOPD.

 

·                  Based on state records, Newfield is now the largest gross oil producer in the State of Oklahoma.

 

·                  Realized oil prices in STACK continue to improve, averaging $48.04 per barrel, or approximately 99% of NYMEX WTI during the quarter.

 

·                  Anadarko Basin lease operating expenses averaged $1.69 per BOE during the quarter, the lowest LOE within the Company’s operating regions.

 



 

·                  Newfield’s production in the Williston Basin increased during the third quarter, averaging nearly 22,000 BOEPD. Approximately 65% of the production was oil and the average sales price during the quarter was $45.21 per barrel.

 

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

 

·                  For the fourth quarter of 2017, Newfield expects its net domestic production to average approximately 168,000 BOEPD.

 

·                  The mid-point for 2017 domestic guidance was raised to approximately 152,000 BOEPD (previous guidance: 149,600 BOEPD). The Company now estimates that its year-over-year domestic production growth, adjusted for prior-year asset sales, will be approximately 9 - 10%.

 

·                  The mid-point estimate for 2017 total company production was increased to approximately 156,700 BOEPD (previous guidance was 153,600 BOEPD).

 

·                  At the end of the third quarter, the Company had approximately $428 million of cash on hand.

 

·                  Recent Anadarko Basin operational highlights include:

 

·                  In STACK, Newfield has now completed the Company’s fourth operated pilot on increased density spacing. The Freeman development pad initiated production early in the third quarter from nine SXL infill wells in the Meramec. The wells were completed with Newfield’s GEN17 completion design of 2,100 pounds of proppant per foot and 2,100 gallons of liquid per foot. Although early, cumulative average production, both oil and barrels of oil equivalent, after 60 days is outperforming the Company’s 1.1 MMBOE gross type curve.

 

·                  After more than 120 days, production from nine Meramec infill wells (both oil and barrels of oil equivalent) on the Stark pad continues to exceed the Company’s 1.1 MMBOE gross type curve. Newfield estimates that this development is generating a before tax internal rate of return of more than 50% at a flat price of $50 per barrel (NYMEX WTI).

 

·                  Newfield today provided data on eight recent HBP wells in STACK, including the play’s “record setting” Hoile well, which had the play’s highest oil production per 1,000’ of lateral over a 24-hour period. The Hoile recently commenced production with a 24-hr initial production rate of 5,100 BOEPD (67% oil) from 7,140’ lateral. Thirty-day production data is not yet available.  A comprehensive list of recent STACK completions can be found in @NFX.

 

·                  In SCOOP, two developments were brought on-line during the third quarter. The McClelland pad was our first development with eight infill wells drilled in the Woodford. The average 30-day rate for the eight infill wells was 1,966 BOEPD (36% oil). The McClelland infill wells are performing in-line with Newfield’s recent Tina development (2Q17 completions), where production per well has averaged 1,465 BOEPD (41% oil) over the first 120 days. Complete details on both pads referenced above can be found in @NFX.

 

·                  The Holinsworth development pad, also located in SCOOP, commenced production late in the third quarter from seven infill wells drilled in the Woodford. Initial 24-hour production per well averaged 3,193 BOEPD (33% oil). Thirty day production data is not yet available. In addition, a non-operated SCOOP development was recently completed and is currently producing at high rates from the condensate window of the play. Newfield’s net share is more than 10,000 BOEPD, of which only 11% is black oil. The company expects that the rich gas will lead to higher natural gas volumes in the fourth quarter — see fourth quarter guidance in this news release.

 



 

Third Quarter 2017 Financial and Production Summary

 

For the third quarter, the Company recorded net income of $87 million, or $0.44 per diluted share (all per share amounts are on a diluted basis). Earnings were impacted by one time tax benefits of $17 million, or $0.09 per share, due to the carryback of net operating losses, and an unrealized derivative loss of $34 million, or $0.17 per share. After adjusting for the effect of the tax benefit and unrealized derivative loss during the period, net income would have been $104 million, or $0.52 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 third quarter were $439 million. Net cash provided by operating activities was $173 million. Discretionary cash flow from operations was $262 million.

 

Newfield’s total net production in the third quarter of 2017 was approximately 161,700 BOEPD, comprised of 42% oil, 22% natural gas liquids and 36% natural gas. Domestic production in the third quarter was approximately 159,000 BOEPD, comprised of 41% oil, 23% natural gas liquids and 36% natural gas.

 

2017e Production, Cost and Expense Guidance

 

 

 

Domestic

 

China

 

Total

 

Production

 

 

 

 

 

 

 

Oil %

 

40

%

100

%

42

%

NGLs %

 

21

%

 

20

%

Natural Gas %

 

39

%

 

38

%

Total (MBOEPD)(1)

 

150.0 - 154.0

 

4.7

 

154.7 - 158.7

 

 

 

 

 

 

 

 

 

Expenses ($/BOE)(2)

 

 

 

 

 

 

 

LOE(3),(5)

 

$

3.48

 

$

15.65

 

$

3.84

 

Transportation(4)

 

5.58

 

 

5.41

 

Production & other taxes

 

1.07

 

0.18

 

1.04

 

 

 

 

 

 

 

 

 

General & administrative (G&A), net(5)

 

$

3.58

 

$

3.88

 

$

3.59

 

Interest expense, gross

 

 

 

2.62

 

 

 

 

 

 

 

 

 

Capitalized interest and direct internal costs

 

$

 

$

 

$

(2.21

)

Effective Tax rate

 

0 - 5

%

0 - 5

%

0 - 5

%

 


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

 

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

 

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

 

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

 

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

 

4Q17e Production, Cost and Expense Guidance

 

 

 

Domestic

 

China

 

Total

 

Production

 

 

 

 

 

 

 

Oil %

 

39

%

 

39

%

NGLs %

 

22

%

 

22

%

Natural Gas %

 

39

%

 

39

%

Total (MBOEPD)

 

162.0 - 174.0

 

 

162.0 - 174.0

 

 

 

 

 

 

 

 

 

Expenses ($/BOE)(1)

 

 

 

 

 

 

 

LOE(2),(4)

 

$

3.20

 

$

 

$

3.30

 

Transportation(3)

 

5.58

 

 

5.58

 

Production & other taxes

 

1.07

 

 

1.07

 

 

 

 

 

 

 

 

 

General & administrative (G&A), net(4)

 

$

3.31

 

$

 

$

3.44

 

Interest expense, gross

 

 

 

2.41

 

 

 

 

 

 

 

 

 

Capitalized interest and direct internal costs

 

$

 

$

 

$

(1.89

)

Effective Tax rate

 

0 - 5

%

 

0 - 5

%

 



 


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

 

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

 

(3)4Q17e transportation / processing fees include ~$13 million of Arkoma unused firm gas transportation and ~$9 million of Uinta oil and gas delivery shortfall fees

 

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

 

Newfield Exploration Company is an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. Our U.S. operations are onshore and focus primarily on large scale, liquids-rich resource plays 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 assets offshore China.

 

**This release contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The words “may,” “forecast,” “outlook,” “could,” “budget,” “objectives,” “strategy,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “guidance,” “potential” or other similar expressions are intended to identify forward-looking statements. Other than historical facts included in this release, all information and statements, including but not limited to information regarding planned capital expenditures, estimated reserves, estimated production targets, estimated future operating costs 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 and no assurance can be given that such expectations will prove to have been correct. Actual results may vary significantly from those anticipated due to many factors, including but not limited to commodity prices, drilling results, our liquidity and the availability of capital resources, operating risks, industry conditions, U.S. and China governmental regulations, financial counterparty risks, the prices of goods and services, the availability of drilling rigs and other support services, our ability to monetize assets and repay or refinance our existing indebtedness, labor conditions, severe weather conditions, new regulations or changes in tax or environmental legislation, environmental liabilities not covered by indemnity or insurance, legislation or regulatory initiatives intended to address seismic activity, and other operating risks. Please see Newfield’s 2016 Annual Report on Form 10-K,  Quarterly Reports on Form 10-Q and other subsequent public filings, all filed with the U.S. Securities and Exchange Commission (SEC), for a discussion of other factors that may cause actual results to vary. Unpredictable or unknown factors not discussed in this press release or in Newfield’s SEC filings could also have material adverse effects on Newfield’s actual results as compared to its anticipated results. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this release. Unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

 

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

Phone: 281-210-5321

Email: IR@newfield.com

 



 

 

 

3Q17 Actual

 

3Q17 Actual Results

 

Domestic

 

China

 

Total

 

 

 

 

 

 

 

 

 

Production/Liftings(1)

 

 

 

 

 

 

 

Crude oil and condensate (MBbls)

 

6,028

 

239

 

6,267

 

Natural gas (Bcf)

 

32.0

 

 

32.0

 

NGLs (MBbls)

 

3,279

 

 

3,279

 

Total (MBOE)

 

14,635

 

239

 

14,874

 

 

 

 

 

 

 

 

 

Average Realized Prices(2)(3)

 

 

 

 

 

 

 

Crude oil and condensate (per Bbl)

 

$

45.70

 

$

48.22

 

$

45.80

 

Natural gas (per Mcf)

 

2.52

 

 

2.52

 

NGLs (per Bbl)

 

25.72

 

 

25.72

 

Crude oil equivalent (per BOE)

 

$

30.32

 

$

48.22

 

$

30.61

 

 

 

 

 

 

 

 

 

Operating Expenses:(3)

 

 

 

 

 

 

 

Lease operating (in millions)

 

 

 

 

 

 

 

Recurring

 

$

41

 

$

4

 

$

45

 

Major (workovers, etc.)

 

$

8

 

$

 

$

8

 

 

 

 

 

 

 

 

 

Lease operating (per BOE)

 

 

 

 

 

 

 

Recurring

 

$

2.79

 

$

19.11

 

$

3.06

 

Major (workovers, etc.)

 

$

0.55

 

$

0.07

 

$

0.54

 

 

 

 

 

 

 

 

 

Transportation and processing (in millions)

 

$

80

 

$

 

$

80

 

per BOE

 

$

5.55

 

$

 

$

5.46

 

 

 

 

 

 

 

 

 

Production and other taxes (in millions)

 

$

16

 

$

 

$

16

 

per BOE

 

$

1.12

 

$

 

$

1.11

 

 

 

 

 

 

 

 

 

General and administrative (G&A), net (in millions)

 

$

51

 

$

2

 

$

53

 

per BOE

 

$

3.63

 

$

6.11

 

$

3.67

 

 

 

 

 

 

 

 

 

Capitalized direct internal costs (in millions)

 

 

 

 

 

$

(18

)

per BOE

 

 

 

 

 

$

(1.20

)

 

 

 

 

 

 

 

 

Other operating expenses (income), net (in millions)

 

 

 

 

 

$

1

 

per BOE

 

 

 

 

 

$

0.05

 

 

 

 

 

 

 

 

 

Interest expense (in millions)

 

 

 

 

 

$

37

 

per BOE

 

 

 

 

 

$

2.56

 

 

 

 

 

 

 

 

 

Capitalized interest (in millions)

 

 

 

 

 

$

(15

)

per BOE

 

 

 

 

 

$

(1.02

)

 

 

 

 

 

 

 

 

Other non-operating (income) expense (in millions)

 

 

 

 

 

$

(1

)

per BOE

 

 

 

 

 

$

(0.13

)

 


(1)         Represents volumes lifted and sold regardless of when produced. Includes natural gas produced and consumed in operations of 1.3 Bcf during the three months ended September 30, 2017.

 

(2)         Average realized prices include the effects of derivative contracts. Excluding these effects, the average realized price for domestic and total natural gas would have been $2.58 per Mcf and the average realized price for our domestic and total crude oil and condensate would have been $43.79 per barrel and $43.96 per barrel, respectively. We did not have any derivative contracts associated with our NGL or China production as of September 30, 2017.

 

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

 



 

CONDENSED CONSOLIDATED BALANCE SHEET

(Unaudited, in millions)

 

 

 

September 30,

 

December 31,

 

 

 

2017

 

2016

 

ASSETS

 

 

 

 

 

Current assets:

 

 

 

 

 

Cash and cash equivalents

 

$

428

 

$

555

 

Short-term investments

 

 

25

 

Derivative assets

 

10

 

75

 

Other current assets

 

398

 

294

 

Total current assets

 

836

 

949

 

 

 

 

 

 

 

Oil and gas properties, net (full cost method)

 

3,670

 

3,140

 

Other assets

 

238

 

223

 

Total assets

 

$

4,744

 

$

4,312

 

 

 

 

 

 

 

LIABILITIES AND STOCKHOLDERS’ EQUITY

 

 

 

 

 

Current liabilities:

 

 

 

 

 

Derivative liabilities

 

$

18

 

$

97

 

Other current liabilities

 

694

 

587

 

Total current liabilities

 

712

 

684

 

 

 

 

 

 

 

Other liabilities

 

71

 

63

 

Derivative liabilities

 

5

 

3

 

Long-term debt

 

2,433

 

2,431

 

Asset retirement obligations

 

158

 

154

 

Deferred taxes

 

64

 

39

 

Total long-term liabilities

 

2,731

 

2,690

 

 

 

 

 

 

 

Stockholders’ equity:

 

 

 

 

 

Common stock, treasury stock and additional paid-in capital

 

3,235

 

3,205

 

Accumulated other comprehensive income (loss)

 

(1

)

(2

)

Retained earnings (deficit)

 

(1,933

)

(2,265

)

Total stockholders’ equity

 

1,301

 

938

 

Total liabilities and stockholders’ equity

 

$

4,744

 

$

4,312

 

 



 

CONSOLIDATED STATEMENT OF OPERATIONS

(Unaudited, in millions, except per share data)

 

 

 

Three Months Ended

 

Nine Months Ended

 

 

 

September 30,

 

September 30,

 

 

 

2017

 

2016

 

2017

 

2016

 

 

 

 

 

 

 

 

 

 

 

Oil, gas and NGL revenues

 

$

439

 

$

392

 

$

1,258

 

$

1,057

 

 

 

 

 

 

 

 

 

 

 

Operating expenses:

 

 

 

 

 

 

 

 

 

Lease operating

 

53

 

60

 

167

 

183

 

Transportation and processing

 

80

 

71

 

223

 

200

 

Production and other taxes

 

16

 

13

 

43

 

34

 

Depreciation, depletion and amortization

 

124

 

120

 

340

 

457

 

General and administrative

 

53

 

65

 

151

 

167

 

Ceiling test and other impairments

 

 

 

 

1,028

 

Other

 

1

 

18

 

2

 

19

 

Total operating expenses

 

327

 

347

 

926

 

2,088

 

 

 

 

 

 

 

 

 

 

 

Income (loss) from operations

 

112

 

45

 

332

 

(1,031

)

 

 

 

 

 

 

 

 

 

 

Other income (expense):

 

 

 

 

 

 

 

 

 

Interest expense

 

(37

)

(37

)

(112

)

(116

)

Capitalized interest

 

15

 

15

 

46

 

35

 

Commodity derivative income (expense)

 

(23

)

28

 

58

 

(122

)

Other, net

 

1

 

1

 

5

 

2

 

Total other income (expense)

 

(44

)

7

 

(3

)

(201

)

 

 

 

 

 

 

 

 

 

 

Income (loss) before income taxes

 

68

 

52

 

329

 

(1,232

)

 

 

 

 

 

 

 

 

 

 

Income tax provision (benefit)

 

(19

)

4

 

(3

)

11

 

Net income (loss)

 

$

87

 

$

48

 

$

332

 

$

(1,243

)

 

 

 

 

 

 

 

 

 

 

Earnings (loss) per share:

 

 

 

 

 

 

 

 

 

Basic

 

$

0.44

 

$

0.24

 

$

1.67

 

$

(6.50

)

Diluted

 

$

0.44

 

$

0.24

 

$

1.66

 

$

(6.50

)

 

 

 

 

 

 

 

 

 

 

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

 

199

 

199

 

199

 

191

 

 

 

 

 

 

 

 

 

 

 

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

 

200

 

200

 

200

 

191

 

 



 

CONDENSED CONSOLIDATED STATEMENT OF CASH FLOWS

(Unaudited, in millions)

 

 

 

Nine Months Ended

 

 

 

September 30,

 

 

 

2017

 

2016

 

Cash flows from operating activities:

 

 

 

 

 

Net income (loss)

 

$

332

 

$

(1,243

)

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

 

 

 

 

 

Depreciation, depletion and amortization

 

340

 

457

 

Deferred tax provision (benefit)

 

25

 

8

 

Stock-based compensation

 

25

 

14

 

Unrealized (gain) loss on derivative contracts

 

(12

)

307

 

Ceiling test and other impairments

 

 

1,028

 

Other, net

 

10

 

10

 

 

 

720

 

581

 

Changes in operating assets and liabilities

 

(80

)

6

 

Net cash provided by (used in) operating activities

 

640

 

587

 

 

 

 

 

 

 

Cash flows from investing activities:

 

 

 

 

 

Additions to and acquisitions of oil and gas properties and other

 

(828

)

(1,228

)

Proceeds from sales of oil and gas properties

 

74

 

399

 

Net cash provided by (used in) investing activities

 

(754

)

(829

)

 

 

 

 

 

 

Cash flows from financing activities:

 

 

 

 

 

Net proceeds (repayments) of borrowings under credit arrangements

 

 

(39

)

Proceeds from issuances of common stock, net

 

2

 

777

 

Other, net

 

(15

)

(23

)

Net cash provided by (used in) financing activities

 

(13

)

715

 

 

 

 

 

 

 

Increase (decrease) in cash and cash equivalents

 

(127

)

473

 

Cash and cash equivalents, beginning of period

 

555

 

5

 

Cash and cash equivalents, end of period

 

$

428

 

$

478

 

 



 

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 third quarter of 2017 stated without the effect of certain items to net income (loss) is shown below (in millions, except per share data):

 

 

 

3Q17

 

 

 

In millions

 

Per diluted
share

 

Net Income (loss)

 

$

87

 

$

0.44

 

Unrealized (gain) loss on derivative contracts

 

34

 

0.17

 

Carryback of net operating losses

 

(17

)

(0.09

)

Earnings stated without the effect of the above items

 

104

 

0.52

 

 

 

 

 

 

 

Weighted-average number of shares outstanding for per diluted share

 

 

 

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:

 

 

 

3Q17

 

 

 

(In millions)

 

Net cash provided by operating activities

 

$

173

 

Net changes in operating assets and liabilities

 

89

 

Discretionary cash flow from operations

 

262

 

 


Exhibit 99.2

@NFX – 3Q17 Update

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3Q17 Key Messages – What You Need to Know We exceeded the mid-point of our 3Q17 net domestic production guidance by 4,650 BOEPD and again raised our 2017 outlook Total Company net production was ~161,700 BOEPD (42% oil and 64% liquids) Anadarko Basin production increased 20% & Anadarko Basin oil production increased more than 25% (3Q17 vs. 2Q17) 3-year plan to deliver double-digit CAGR in production and improving returns We have $428MM of cash on hand Recent STACK pilots are projecting above our 1.1 MMBOE EUR1 TC Recent STACK HBP wells deliver strong results Hoile well sets record STACK IP24 oil rate per 1,000’ SCOOP results show continual improvement through enhanced completions and tighter well density spacing Williston Basin averaged nearly 22,000 BOEPD in 3Q17 2 1Estimated ultimate recovery (EUR) refers to potential recoverable oil and natural gas hydrocarbon quantities with ethane processing and depends on the availability of capital, regulatory approvals, commodity prices, costs, actual drilling results and other factors. Such amounts do not meet SEC rules and guidelines, may not be reflective of SEC proved reserves and do not equate to or predict any level of reserves or production.

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Newfield is Focused on Value Creation Tomorrow’s Winners Sustainable Value Creation Proven Execution Increase Bottom-Line Returns High-Grade Drilling Inventory 40% + IRR Oil & Liquids Focused Margin Expansion Development Synergies Data Analytics Profitable Growth Premium Inventory Returns Execution Vast, High Quality Resource Combination of Returns and Growth NAV expansion Premier Capital Structure 3

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STACK Freeman & Stark Infill Wells vs. Type Curve “NEW” Freeman pilot (9 infill wells in the Meramec) Average IP30: 1,278 BOEPD (70% oil, 84% liquids) Average IP60: 1,156 BOEPD (67% oil, 83% liquids) Stark pilot (9 infill wells in the Meramec) Average IP30: 1,211 BOEPD (65% oil, 82% liquids) Average IP60: 1,202 BOEPD (65% oil, 82% liquids) “NEW” Average IP90: 1,156 BOEPD (66% oil, 83% liquids) “NEW” Average IP120: 1,121 BOEPD (66% oil, 82% liquids) Freeman & Stark Infill Wells vs. 440 MBO Oil TC 4 Freeman & Stark Infill Wells vs. 1,100 MBOE TC Stark Pilot Freeman Pilot “NEW” Freeman Infills Stark Infills 440 MBO Oil TC “NEW” Freeman Infills Stark Infills 1,100 MBOE TC 0 50 100 150 0 1 2 3 4 5 Cumulative Production (MBOE) Months 0 50 100 0 1 2 3 4 5 Cumulative Production (MBO) Months

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Recent Strong STACK HBP Results and Record Setting Oil Well HOILE 1H-25X IP24hr: 5,100 BOEPD 67% Oil GPI: 7,140’ M&M 1H-29 IP24: 1,810 BOEPD 50% Oil GPI: 4,719’ CHANNEL 1H-30X IP30: 1,175 BOEPD 74% Oil GPI: 9,969’ NANCY 1809 1H-32 IP30: 1,233 BOEPD 76% Oil GPI: 4,479’ JOLEE 1H-5 IP30: 1,303 BOEPD 55% Oil GPI: 4,192’ EVELYN 1508 1H-17 IP30: 1,188 BOEPD 53% Oil GPI: 4,842’ KIERA 1506 1H-3X IP60: 928 BOEPD 82% Oil GPI: 10,092’ H&W 1H-28X IP30: 1,852 BOEPD 63% Oil GPI: 9,618’ “NEW” Hoile Well** “NEW” HBP Wells** 440 MBO Oil TC *Utilizes internal and IHS data ** Normalized to 10,000’ lateral length Hoile Peer Well Peer Well Peer Well Burgess NFX has two of the TOP 5 STACK IP24 Oil Wells (oil production per 1,000’) 5 NFX NFX “NEW” Hoile & HBP Wells vs. 440 MBO Oil TC BURGESS 1H-18 - 50 100 0 1 2 3 4 5 Cumulative Production (MBO) Months 0 100 200 300 400 500 IP24 BOPD per 1,000’ TOP 5 STACK IP24 Oil Wells (oil production per 1,000’)*

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SCOOP McClelland & Tina Comparison vs. Type Curve 6 “NEW” McClelland & Tina Infill Wells* vs. 1,200 MBOE TC “NEW” McClelland & Tina Infill Wells* vs. 430 MBO Oil TC Tina Wells IP120: 1,465 BOEPD Holinsworth Wells IP24: 3,193 BOEPD McClelland Wells IP30: 1,966 BOEPD “NEW” McClelland Infills Tina Infills 1,200 MBOE TC “NEW” McClelland Infills Tina Infills 430 MBO Oil TC “NEW” McClelland development (8 infill wells in the Woodford) Average IP30: 1,966 BOEPD (36% oil, 70% liquids) Tina development (7 infill wells in the Woodford) “NEW” Average IP90: 1,539 BOEPD (41% oil, 72% liquids) “NEW” Average IP120: 1,465 BOEPD (41% oil, 72% liquids) “NEW” Holinsworth development (7 infill wells in the Woodford) Average IP24: 3,193 BOEPD (33% oil, 69% liquids) *Note: GPI for McClelland/Tina ~ 7,500’ & Holinsworth ~10,000’ 0 50 100 150 200 0 1 2 3 4 5 6 Cumulative Production (MBOE) Months 0 50 100 0 1 2 3 4 5 6 Cumulative Production (MBO) Months

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NFX is the “Best-in-Class” Driller 7 NFX NFX NFX NFX Williston Avg. Ft/Day vs. Peers NFX SCOOP Avg. Ft/Day vs. Peers NFX STACK Avg. Ft/Day vs. Peers Active drilling programs in several basins allows rapid transfer of lessons learned Constant benchmarking against peers encourages continual improvement Consistent, active drilling levels creates “manufacturing mindset,” advances efficiency gains 7 *Total depth average feet per day based on 2017 public data from government database

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Data Analytics Is Changing The Game For Newfield & Industry Initiated in 2013 Thousands of Oklahoma wells catalogued in database dating back to 2010 > 6 billion usable data points impacting decisions Realized learnings enhance our workforce efficiency Dedicated team uses machine learning algorithms on terabytes of data daily Workforce focuses on new ideas, concepts and optimization instead of data mining Predictive modeling drives operational enhancements, geologic understanding and high grades portfolio Autonomous partner data extraction accelerates learnings on most relevant data State of the art data security protects our data Multivariate analysis translates into industry leading wells, better forecasting, faster decisions & mitigates risk 8

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Appendix

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2017 Capital investments YTD Total Company ($ in millions) Capital Expenditures: Q1 Q2 Q3 Q4 YTD Exploration & development $186 $271 $304 -- $761 Leasehold $30 $24 $12 -- $66 Pipeline -- $1 -- -- $1 Total Capital Expenditures1 $216 $296 $316 -- $828 1 Excludes ~$97 million in capitalized interest and direct internal costs and ~$20 million in FF&E 10

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3Q17 Average Production by Area Production Anadarko Basin Williston Basin Uinta Basin China (Liftings) 1 Oil (bopd) 36,910 14,068 14,458 2,598 NGL (boepd) 31,209 3,768 434 -- Gas (boepd) 36,689 4,072 3,110 -- Total (boepd) 104,808 21,908 18,002 2,598 1 Includes lifted volumes in the quarter. Not reflective of daily rate. 11

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2017e Production, Cost and Expense Guidance 12 Domestic China Total Production Oil % 40% 100% 42% NGLs % 21% -- 20% Natural Gas % 39% -- 38% Total (mboepd)1 150.0 – 154.0 4.7 154.7 – 158.7 Expenses ($/boe)2 LOE3,5 $3.48 $15.65 $3.84 Transportation4 $5.58 -- $5.41 Production & other taxes $1.07 $0.18 $1.04 General & administrative (G&A), net5 $3.58 $3.88 $3.59 Interest expense, gross -- -- $2.62 Capitalized interest and direct internal costs -- -- ($2.21) Effective Tax rate 0 – 5% 0 – 5% 0 – 5% 1 Total Company and China volumes include impact of Bohai Bay divestiture 2 Cost and expenses are expected to be within 5% of the estimates above 3 Total LOE includes recurring, major expense and non E&P operating expenses 4 2017e transportation / processing fees include ~$52 million of Arkoma unused firm gas transportation and ~$33 million of Uinta oil and gas delivery shortfall fees 5 Total LOE and G&A includes $2 million and $2 million, respectively, associated with remainder of 2017 activity in China

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4Q17e Production, Cost and Expense Guidance 13 Domestic China Total Production Oil % 39% -- 39% NGLs % 22% -- 22% Natural Gas % 39% -- 39% Total (mboepd) 162.0 – 174.0 -- 162.0 – 174.0 Expenses ($/boe)1 LOE2,4 $3.20 -- $3.30 Transportation3 $5.58 -- $5.58 Production & other taxes $1.07 -- $1.07 General & administrative (G&A), net4 $3.31 -- $3.44 Interest expense, gross -- -- $2.41 Capitalized interest and direct internal costs -- -- ($1.89) Effective Tax rate 0 – 5% 0% 0 – 5% 1 Cost and expenses are expected to be within 5% of the estimates above 2 Total LOE includes recurring, major expense and non E&P operating expenses 3 4Q17e transportation / processing fees include ~$13 million of Arkoma unused firm gas transportation and ~$9 million of Uinta oil and gas delivery shortfall fees 4 Total LOE and G&A includes $2 million and $2 million, respectively, associated with Q4 2017 activity in China

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Solid capital structure $1.8 bn unsecured credit facility maturing 2020 ~$2.3 bn of total liquidity No fixed debt maturities until 2022 Weighted average fixed debt maturity of ~6 years at 4.3% YTM1 1 Sourced from Bloomberg as of September 30, 2017. 2 Net debt represents principal balance of debt less cash on balance sheet. Adjusted EBITDA calculated per Company’s credit agreement definition; YE 2016 reflects 5th amendment executed 3/18/2016. See next slide. Net debt / adj EBITDA2 Fixed debt maturity schedule $ millions No maturities until 1/30/2022 14 $750 $1,000 $700 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026 1.9x 2.0x 2.0x YE 2015 YE 2016 Q3 2017

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Non-GAAP reconciliation of Adjusted EBITDA 15 Twelve Months Ended December 31, September 30, ($ in millions) 2015 2016 2017 Net Income ($3,362) ($1,230) $345 Adjustments to derive EBITDA: Interest expense, net of capitalized interest $131 $103 $88 Income tax provision (benefit) (1,585) 22 8 Depreciation, depletion and amortization 917 572 455 EBITDA ($3,899) ($533) $896 Adjustments to EBITDA: Ceiling test and other impairment $4,904 $1,028 $0 Non-cash stock-based compensation 25 22 33 Unrealized (gain) loss on commodity derivatives 246 392 73 Other permitted adjustments1 19 59 10 Adjusted EBITDA per credit agreement2 $1,295 $968 $1,012 1 Other permitted adjustments per Company’s credit agreement include but are not limited to inventory write-downs, office-lease abandonment, severance and relocation costs 2 Adjusted EBITDA calculated per Company’s credit agreement definition; December 31, 2016 reflects 5th amendment executed 3/18/2016

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Oil Hedging Details as of 10/30/17 16 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 4Q 2017 31,000 11,000 11,000 -- $47.52 -- -- -- -- $73.09/$88.01 -- -- -- -- $73.09 -- -- -- -- -- 1Q 2018 6,000 -- -- 44,000 $50.04 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.18/$48.05-$55.98 2Q 2018 6,000 -- -- 42,000 $50.04 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.10/$47.98-$56.04 3Q 2018 6,000 -- -- 36,000 $50.04 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38.88/$47.64-$56.13 4Q 2018 6,000 -- -- 29,000 $50.04 -- -- -- -- -- -- -- -- -- -- -- -- -- -- $38.52/$47.00-$56.13 1 Below $73.09 for 4Q17, these contracts effectively result in realized prices that are on average $14.92 per Bbl higher, respectively, than the cash price that otherwise would have been realized. 2 Above $73.09 plus the call premium of $2.05 for 4Q 2017, these contracts effectively lock in the spread between the average short put and swap. 3 Below $38.18 for 1Q18, $39.10 for 2Q18, $38.88 for 3Q18, and $38.52 for 4Q18 these contracts effectively result in realized prices that are $8.87, $8.88, $8.76, and $8.48 per Bbl higher, respectively by quarter, than the cash price that otherwise would have been realized. Denotes update

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Oil Hedging Details as of 10/30/17 17 Weighted-Average Price Period Volume (bbl/d) Swaps Swaps w/ Short Puts1 Purchased Calls2 Collars w/ Short Puts3 1Q 2019 -- -- -- 28,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.71/$50.00-$56.46 2Q 2019 -- -- -- 26,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.73/$50.00-$56.48 3Q 2019 -- -- -- 19,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.82/$50.00-$56.60 4Q 2019 -- -- -- 13,000 -- -- -- -- -- -- -- -- -- -- -- -- -- -- -- $39.73/$50.00-$56.56 3 Below $39.71 for 1Q19, $39.73 for 2Q19, $39.82 for 3Q19, and $39.73 for 4Q19 these contracts effectively result in realized prices that are $10.29, $10.27, $10.18, and $10.27 per Bbl higher, respectively by quarter, than the cash price that otherwise would have been realized.

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Oil Hedging Details as of 10/30/17 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 4Q 2017 $92 $63 $34 $6 ($23) ($51) ($80) 1Q 2018 $51 $46 $36 $0 ($21) ($66) ($111) 2Q 2018 $50 $45 $35 $0 ($21) ($64) ($108) 3Q 2018 $46 $40 $30 $0 ($18) ($57) ($96) 4Q 2018 $39 $34 $24 $0 ($16) ($48) ($80)

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Oil Hedging Details as of 10/30/17 19 The following table details the expected impact to pre-tax income (in millions, except prices) from the settlement of our derivative contracts, outlined on the previous slide, at various NYMEX oil prices. Oil Prices Period $20 $30 $40 $50 $60 $70 $80 1Q 2019 $26 $26 $25 $0 ($9) ($34) ($59) 2Q 2019 $24 $24 $23 $0 ($8) ($32) ($56) 3Q 2019 $18 $18 $17 $0 ($6) ($23) ($41) 4Q 2019 $12 $12 $12 $0 ($4) ($16) ($28)

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Gas Hedging Details as of 10/30/17 20 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 4Q 2017 75,000 170,000 $2.73 -- -- $2.87-$3.28 1Q 2018 30,000 190,000 $3.01 -- -- $3.14-$3.73 2Q 2018 150,000 40,000 $2.99 -- -- $2.83-$3.28 3Q 2018 140,000 40,000 $2.99 -- -- $2.83-$3.28 4Q 2018 120,000 40,000 $2.99 -- -- $2.83-$3.28

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Gas Hedging Details as of 10/30/17 21 Weighted-Average Price Period Volume (mmbtu/d) Swaps Collars 1Q 2019 10,000 90,000 $2.91 -- -- $3.00-$3.48 2Q 2019 10,000 -- $2.91 -- -- -- 3Q 2019 10,000 -- $2.91 -- -- -- 4Q 2019 10,000 -- $2.91 -- -- --

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Gas Hedging Details as of 10/30/17 22 Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 4Q 2017 $19 $7 ($1) ($10) ($20) ($31) ($43) 1Q 2018 $22 $12 $3 ($2) ($7) ($17) ($27) 2Q 2018 $16 $8 $0 ($8) ($16) ($25) ($34) 3Q 2018 $16 $7 $0 ($7) ($16) ($24) ($32) 4Q 2018 $14 $7 $0 ($6) ($14) ($21) ($29) 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.

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Gas Hedging Details as of 10/30/17 23 Gas Prices Period $2.00 $2.50 $3.00 $3.50 $4.00 $4.50 $5.00 1Q 2019 $9 $4 $0 ($1) ($5) ($10) ($14) 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) 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.

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This presentation contains forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. The words ““may,” “forecast,” “outlook,” “could,” “budget,” “objectives,” “strategy,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “guidance,” “potential” or other similar expressions are intended to identify forward-looking statements. Other than historical facts included in this presentation, all information and statements, including but not limited to information regarding planned capital expenditures, estimated reserves, estimated production targets, estimated future operating costs, 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 presentation, Newfield believes that these expectations are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks and no assurance can be given that such expectations will prove to have been correct. Actual results may vary significantly from those anticipated due to many factors, including but not limited to commodity prices, drilling results, our liquidity and the availability of capital resources, operating risks, industry conditions, U.S. and China governmental regulations, financial counterparty risks, the prices of goods and services, the availability of drilling rigs and other support services, our ability to monetize assets and repay or refinance our existing indebtedness, labor conditions, severe weather conditions, new regulations or changes in tax or environmental legislation, environmental liabilities not covered by indemnity or insurance, legislation or regulatory initiatives intended to address seismic activity, and other operating risks. Please see Newfield’s 2016 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q and other subsequent public filings, all filed with the U.S. Securities and Exchange Commission (SEC), for a discussion of other factors that may cause actual results to vary. Unpredictable or unknown factors not discussed herein or in Newfield’s SEC filings could also have material adverse effects on Newfield’s actual results as compared to its anticipated results. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date of this presentation. Unless legally required, Newfield undertakes no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. This presentation has been prepared by Newfield and includes market data and other statistical information from sources believed by Newfield to be reliable, including independent industry publications, government publications or other published independent sources. Some data are also based on Newfield’s good faith estimates, which are derived from its review of internal sources as well as the independent sources described above. Although Newfield believes these sources are reliable, it has not independently verified the information and cannot guarantee its accuracy and completeness. Actual quantities that may be ultimately recovered from Newfield’s interests may differ substantially from the estimates in this presentation. Factors affecting ultimate recovery include the scope of Newfield’s ongoing drilling program, which will be directly affected by commodity prices, the availability of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, transportation constraints, regulatory approvals and other factors, and actual drilling results, including geological and mechanical factors affecting recovery rates. Newfield may use terms in this presentation, such as “EURs”, “upside potential”, “net unrisked resource”, “gross EURs”, and similar terms that the SEC’s guidelines strictly prohibit in SEC filings. These terms include reserves with substantially less certainty than proved reserves, and no discount or other adjustment is included in the presentation of such reserve numbers. Investors are urged to consider closely the oil and gas disclosures in Newfield’s 2016 Annual Report on Form 10-K, its Quarterly Reports on Form 10-Q and subsequent public filings, available at www.newfield.com, www.sec.gov or by writing Newfield at 4 Waterway Square Place, Suite 100, The Woodlands, Texas 77380 Attn: Investor Relations. In addition, this presentation contains non-GAAP financial measures, which include, but are not limited to, Adjusted EBITDA. Newfield defines EBITDA as net income/loss before income tax expense/benefit, interest expense and depreciation, depletion and amortization. Adjusted EBITDA, as presented herein, is EBITDA before ceiling test impairments, gains/losses on asset sales, non-cash compensation expense, net unrealized (gains) / losses on commodity derivatives and other permitted adjustments. Adjusted EBITDA is not a recognized term under GAAP and does not represent net income as defined under GAAP, and should not be considered an alternative to net income as an indicator of operating performance or to cash flows as a measure of liquidity. Adjusted EBITDA is a supplemental financial measure used by Newfield’s management and by securities analysts, lenders, ratings agencies and others who follow the industry as an indicator of Newfield’s ability to internally fund exploration and development activities. Forward Looking Statements & Related Matters 24

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