10-Q


 
 
 
 
 
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
þ
 
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended September 30, 2015
OR
¨
 
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Transition Period from                      to                     .

Commission File Number: 1-12534

NEWFIELD EXPLORATION COMPANY
(Exact name of registrant as specified in its charter)
Delaware
72-1133047
(State or other jurisdiction of
(I.R.S. Employer
incorporation or organization)
Identification Number)

4 Waterway Square Place
Suite 100
The Woodlands, Texas 77380
(Address and Zip Code of principal executive offices)

(281) 210-5100
(Registrant’s telephone number, including area code)
     
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.  Yes þ No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
 
Large accelerated filer þ     
 
Accelerated filer ¨   
 
Non-accelerated filer ¨     
 
Smaller reporting company ¨
(Do not check if a smaller reporting company)
     
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes ¨ No þ

As of October 30, 2015, there were 163,412,341 shares of the registrant’s common stock, par value $0.01 per share, outstanding.
 
 
 
 
 



TABLE OF CONTENTS
 
 
Page
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 



ii




NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except share data)
(Unaudited)
 
 
September 30, 
 2015
 
December 31, 
 2014
ASSETS
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
7

 
$
14

Accounts receivable, net
 
263

 
439

Inventories
 
31

 
33

Derivative assets
 
334

 
431

Other current assets
 
28

 
23

Total current assets
 
663

 
940

Oil and gas properties, net — full cost method ($985 and $677 were excluded from amortization at September 30, 2015 and December 31, 2014, respectively)

 
4,418

 
8,232

Other property and equipment, net
 
168

 
182

Derivative assets
 
148

 
190

Long-term investments
 
20

 
26

Deferred taxes
 
49

 

Other assets
 
47

 
28

Total assets
 
$
5,513

 
$
9,598

LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
 
 

 
 

Accounts payable
 
$
62

 
$
32

Accrued liabilities
 
480

 
880

Advances from joint owners
 
53

 
34

Asset retirement obligations
 
3

 
3

Derivative liabilities
 
8

 
8

Deferred taxes
 
112

 
144

Total current liabilities
 
718

 
1,101

Other liabilities
 
47

 
45

Derivative liabilities
 
6

 

Long-term debt
 
2,498

 
2,892

Asset retirement obligations
 
192

 
183

Deferred taxes
 
21

 
1,484

Total long-term liabilities
 
2,764

 
4,604

Commitments and contingencies (Note 13)
 
 
 
 
Stockholders' equity:
 
 

 
 

Preferred stock ($0.01 par value, 5,000,000 shares authorized; no shares issued)
 

 

Common stock ($0.01 par value, 300,000,000 and 200,000,000 shares authorized at September 30, 2015 and December 31, 2014, respectively; 163,989,826 and 137,603,643 shares issued at September 30, 2015 and December 31, 2014, respectively)
 
2

 
1

Additional paid-in capital
 
2,424

 
1,576

Treasury stock (at cost, 587,135 and 275,069 shares at September 30, 2015 and December 31, 2014, respectively)
 
(21
)
 
(10
)
Accumulated other comprehensive gain (loss)
 
(2
)
 
(1
)
Retained earnings (deficit)
 
(372
)
 
2,327

Total stockholders' equity
 
2,031

 
3,893

Total liabilities and stockholders' equity
 
$
5,513

 
$
9,598


The accompanying notes to consolidated financial statements are an integral part of this statement.

1


NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF OPERATIONS
(In millions, except per share data)
(Unaudited)
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2015
 
2014
 
2015
 
2014
Oil, gas and NGL revenues
 
$
377

 
$
610

 
$
1,195

 
$
1,793

 
 
 
 
 
 
 
 
 
Operating expenses:
 
 

 
 

 
 

 
 

Lease operating
 
71

 
74

 
219

 
228

Transportation and processing
 
52

 
51

 
153

 
125

Production and other taxes
 
13

 
32

 
43

 
90

Depreciation, depletion and amortization
 
236

 
228

 
721

 
633

General and administrative
 
66

 
48

 
180

 
172

Ceiling test and other impairments
 
1,889

 

 
4,202

 

Other
 
1

 
10

 
8

 
15

Total operating expenses
 
2,328

 
443

 
5,526

 
1,263

Income (loss) from operations
 
(1,951
)
 
167

 
(4,331
)
 
530

 
 
 
 
 
 
 
 
 
Other income (expense):
 
 

 
 

 
 

 
 

Interest expense
 
(37
)
 
(51
)
 
(127
)
 
(153
)
Capitalized interest
 
8

 
13

 
23

 
39

Commodity derivative income (expense)
 
87

 
303

 
230

 
33

Other, net
 
1

 
1

 
(13
)
 
4

Total other income (expense)
 
59

 
266

 
113

 
(77
)
 
 
 
 
 
 
 
 
 
Income (loss) from continuing operations before income taxes
 
(1,892
)
 
433

 
(4,218
)
 
453

 
 
 
 
 
 
 
 
 
Income tax provision (benefit):
 
 

 
 

 
 

 
 

Current
 
7

 
1

 
25

 
3

Deferred
 
(672
)
 
154

 
(1,544
)
 
167

Total income tax provision (benefit)
 
(665
)
 
155

 
(1,519
)
 
170

Income (loss) from continuing operations
 
(1,227
)
 
278

 
(2,699
)
 
283

Income (loss) from discontinued operations, net of tax
 

 

 

 
257

Net income (loss)
 
$
(1,227
)
 
$
278

 
$
(2,699
)
 
$
540

 
 
 
 
 
 
 
 
 
Earnings (loss) per share:
 
 

 
 

 
 

 
 

Basic:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
(7.52
)
 
$
2.04

 
$
(17.17
)
 
$
2.07

Income (loss) from discontinued operations
 

 

 

 
1.89

Basic earnings (loss) per share
 
$
(7.52
)
 
$
2.04

 
$
(17.17
)
 
$
3.96

Diluted:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
(7.52
)
 
$
2.02

 
$
(17.17
)
 
$
2.05

Income (loss) from discontinued operations
 

 

 

 
1.87

Diluted earnings (loss) per share
 
$
(7.52
)
 
$
2.02

 
$
(17.17
)
 
$
3.92

Weighted-average number of shares outstanding for basic earnings (loss) per share
 
163

 
137

 
157

 
137

Weighted-average number of shares outstanding for diluted earnings (loss) per share
 
163

 
138

 
157

 
138


The accompanying notes to consolidated financial statements are an integral part of this statement.

2


NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
(In millions)
(Unaudited)

 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
Net income (loss)
 
$
(1,227
)
 
$
278

 
$
(2,699
)
 
$
540

Other comprehensive income (loss):
 
 

 
 

 
 

 
 

Unrealized gain (loss) on investments, net of tax
 
(1
)
 

 
(1
)
 

Other comprehensive income (loss), net of tax
 
(1
)
 

 
(1
)
 

Comprehensive income (loss)
 
$
(1,228
)
 
$
278

 
$
(2,700
)
 
$
540


The accompanying notes to consolidated financial statements are an integral part of this statement.


3


NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
(Unaudited)
 
 
Nine Months Ended
 
 
September 30,
 
 
2015
 
2014
Cash flows from operating activities:
 
 
Net income (loss)
 
$
(2,699
)
 
$
540

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

 
 

Depreciation, depletion and amortization
 
721

 
665

Deferred tax provision (benefit)
 
(1,544
)
 
308

Stock-based compensation
 
19

 
15

Unrealized (gain) loss on derivative contracts
 
145

 
(139
)
Ceiling test and other impairments
 
4,202

 

Gain on sale of Malaysia business
 

 
(388
)
Other, net
 
38

 
1

Changes in operating assets and liabilities:
 
 

 
 

(Increase) decrease in accounts receivable
 
80

 
89

(Increase) decrease in inventories
 

 
(1
)
(Increase) decrease in other current assets
 
(5
)
 
(2
)
(Increase) decrease in other assets
 
(5
)
 
1

Increase (decrease) in accounts payable and accrued liabilities
 
(82
)
 
(20
)
Increase (decrease) in advances from joint owners
 
19

 
(1
)
Increase (decrease) in other liabilities
 

 
2

Net cash provided by (used in) operating activities
 
889

 
1,070

Cash flows from investing activities:
 
 

 
 

Additions to oil and gas properties
 
(1,294
)
 
(1,535
)
Acquisitions of oil and gas properties
 
(125
)
 
(21
)
Proceeds from sales of oil and gas properties
 
86

 
616

Proceeds received from sale of Malaysia business, net
 

 
809

Additions to other property and equipment
 
(9
)
 
(22
)
Redemptions of investments
 

 
39

Proceeds from insurance settlement, net
 
57

 

Net cash provided by (used in) investing activities
 
(1,285
)
 
(114
)
Cash flows from financing activities:
 
 

 
 

Proceeds from borrowings under credit arrangements
 
1,442

 
2,076

Repayments of borrowings under credit arrangements
 
(1,840
)
 
(2,725
)
Proceeds from issuance of senior notes
 
691

 

Repayment of senior subordinated notes
 
(700
)
 

Debt issue costs
 
(8
)
 

Proceeds from issuances of common stock, net
 
817

 
4

Purchases of treasury stock, net
 
(11
)
 
(10
)
Other
 
(2
)
 

Net cash provided by (used in) financing activities
 
389

 
(655
)
Increase (decrease) in cash and cash equivalents
 
(7
)
 
301

Cash and cash equivalents, beginning of period
 
14

 
95

Cash and cash equivalents, end of period
 
$
7

 
$
396


The accompanying notes to consolidated financial statements are an integral part of this statement.

4


NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(In millions)
(Unaudited)
 
 
 
 
 
 
 
 
 
 
Additional
Paid-in
Capital
 
Retained Earnings
(Deficit)
 
Accumulated
Other
 Comprehensive
Gain (Loss)
 
 Total
Stockholders' Equity
 
 
Common Stock
 
Treasury Stock
 
 
 
 
 
 
Shares
 
Amount
 
Shares
 
Amount
 
Balance, December 31, 2014
 
137.6

 
$
1

 
(0.3
)
 
$
(10
)
 
$
1,576

 
$
2,327

 
$
(1
)
 
$
3,893

Issuances of common stock
 
26.4

 
1

 
 
 
 
 
816

 
 
 
 
 
817

Stock-based compensation
 
 
 
 
 
 
 
 
 
32

 
 
 
 
 
32

Treasury stock, net
 
 
 
 
 
(0.3
)
 
(11
)
 

 
 

 
 
 
(11
)
Net income (loss)
 
 
 
 
 
 
 
 
 
 
 
(2,699
)
 
 
 
(2,699
)
Other comprehensive income (loss), net of tax

 
 
 
 
 
 
 
 
 
 
 
 
 
(1
)
 
(1
)
Balance, September 30, 2015
 
164.0

 
$
2

 
(0.6
)
 
$
(21
)
 
$
2,424

 
$
(372
)
 
$
(2
)
 
$
2,031


The accompanying notes to consolidated financial statements are an integral part of this statement.

5



NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)

1.      Organization and Summary of Significant Accounting Policies
   
Organization and Principles of Consolidation
     
We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids (NGLs). We focus on U.S. resource plays, and our primary areas of operation include the Mid-Continent, the Rocky Mountains and onshore Texas. We also have offshore oil developments in China.

Our consolidated financial statements include the accounts of Newfield Exploration Company, a Delaware corporation, and its subsidiaries. We proportionately consolidate our interests in oil and natural gas exploration and production ventures and partnerships in accordance with industry practice. All significant intercompany balances and transactions have been eliminated. Unless otherwise specified or the context otherwise requires, all references in these notes to “Newfield,” “we,” “us,” “our” or the “Company” are to Newfield Exploration Company and its subsidiaries.

These unaudited consolidated financial statements reflect, in the opinion of our management, all adjustments, consisting only of normal and recurring adjustments, necessary to fairly state our financial position as of and results of operations for the periods presented. These financial statements have been prepared in accordance with the instructions to Form 10-Q and, therefore, do not include all disclosures required for financial statements prepared in conformity with accounting principles generally accepted in the United States of America. Interim period results are not necessarily indicative of results of operations or cash flows for a full year.

These consolidated financial statements and notes should be read in conjunction with our audited consolidated financial statements and the notes thereto included in our Annual Report on Form 10-K for the year ended December 31, 2014.
  
Risks and Uncertainties

As an independent oil and natural gas producer, our revenue, profitability and future rate of growth are substantially dependent on prevailing prices for oil, natural gas and NGLs. Historically, the energy markets have been very volatile, and there can be no assurance that commodity prices will not be subject to wide fluctuations in the future. A substantial or extended decline in commodity prices could have a material adverse effect on our financial position, results of operations, cash flows, access to capital and on the quantities of oil, natural gas and NGL reserves that we can economically produce.

Use of Estimates

The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America requires our management to make estimates and assumptions that affect the reported amounts of assets and liabilities; disclosure of contingent assets and liabilities at the date of the financial statements; the reported amounts of revenues and expenses during the reporting period; and the quantities and values of proved oil, natural gas and NGL reserves used in calculating depletion and assessing impairment of our oil and gas properties. Actual results could differ significantly from these estimates. Our most significant estimates are associated with the quantities of proved oil, natural gas and NGL reserves, the timing and amount of transfers of our unevaluated properties into our amortizable full cost pool and the fair value of both our derivative positions and our stock-based compensation liability awards. 

Restructuring Costs

Restructuring costs include severance and related benefit costs, costs associated with abandoned office space, employee relocation costs and other associated costs. Employee severance and related benefit costs are recognized on a straight-line basis over the required service period, if any. Employee relocation costs are expensed as incurred. On the date the leased property ceases to be used, a liability for noncancellable office-lease costs associated with restructuring is recognized and measured at fair value on our consolidated balance sheet. Fair value estimates include assumptions regarding estimated future sublease payments. These estimates could materially differ from actual results and may require revision to initial estimates of the liability. See Note 15, "Restructuring Costs," for additional disclosures.




6

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Reclassifications

Certain reclassifications have been made to prior years' reported amounts in order to conform to the current year presentation. These reclassifications did not impact our net income (loss), stockholders' equity or cash flows.

Restricted Cash

We have restricted cash of $10 million included in "Other assets" on our consolidated balance sheet at September 30, 2015 that represents amounts held in escrow accounts to satisfy future plug and abandonment obligations for our China operations. These amounts are restricted as to their current use and will be released as we plug and abandon wells and facilities in our China field. Consistent with our other plug and abandonment activities, changes in restricted cash are included in cash flows from operating activities in our consolidated statement of cash flows.

Discontinued Operations

The results of our Malaysia operations are reflected separately as discontinued operations in the consolidated statement of operations on a line immediately after "Income (loss) from continuing operations." See Note 17, "Discontinued Operations," for additional disclosures, as well as information regarding the sale of our Malaysia business, which closed in February 2014.

New Accounting Requirements

In April 2015, the Financial Accounting Standards Board (FASB) issued guidance regarding the presentation of debt issuance costs in the financial statements and requires that debt issuance costs be presented as a reduction of the carrying value of the financial liability and not as a separate asset. The guidance requires retrospective adjustment to the balance sheet presentation and disclosures applicable for a change in an accounting principle. The guidance is effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance in our 2015 annual report.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings (deficit). In July 2015, the FASB approved a deferral of the effective date by one year. As a result, the guidance is effective for interim and annual periods beginning on or after December 15, 2017. We are currently evaluating the impact of this guidance on our financial statements.

2.      Earnings Per Share
     
The following is the calculation of basic and diluted weighted-average shares outstanding and earnings per share (EPS) for the indicated periods:

7

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In millions, except per share data)
Income (numerator):
 
 
 
 
 
 
 
 
  Income (loss) from continuing operations
 
$
(1,227
)
 
$
278

 
$
(2,699
)
 
$
283

  Income (loss) from discontinued operations
 

 

 

 
257

Net income (loss)
 
$
(1,227
)
 
$
278

 
$
(2,699
)
 
$
540

 
 
 
 
 
 
 
 
 
Weighted-average shares (denominator):
 
 

 
 

 
 

 
 

Weighted-average shares — basic
 
163

 
137

 
157

 
137

Dilution effect of stock options and unvested restricted stock and restricted stock units outstanding at end of period(1)(2)
 

 
1

 

 
1

Weighted-average shares — diluted
 
163

 
138

 
157

 
138

 
 
 
 
 
 
 
 
 
Earnings (loss) per share:
 
 

 
 

 
 

 
 

Basic:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
(7.52
)
 
$
2.04

 
$
(17.17
)
 
$
2.07

Income (loss) from discontinued operations
 

 

 

 
1.89

Basic earnings (loss) per share
 
$
(7.52
)
 
$
2.04

 
$
(17.17
)
 
$
3.96

Diluted:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
(7.52
)
 
$
2.02

 
$
(17.17
)
 
$
2.05

Income (loss) from discontinued operations
 

 

 

 
1.87

Diluted earnings (loss) per share
 
$
(7.52
)
 
$
2.02

 
$
(17.17
)
 
$
3.92

_______
(1)
The effect of 2.3 million and 2.8 million unvested restricted stock or restricted stock units and stock options for the three and nine months ended September 30, 2015, respectively, have not been included in the calculation of shares outstanding for diluted EPS as their effect would have been anti-dilutive.
(2)
Excludes 0.3 million and 1.1 million shares of unvested restricted stock or restricted stock units and stock options for the three and nine months ended September 30, 2014, respectively, because including the effect would have been anti-dilutive.

3.      Stockholders' Equity Activity
     
During the first quarter of 2015, we issued 25.3 million additional shares of common stock through a public equity offering. We received net proceeds of approximately $815 million, which were used primarily to repay all borrowings under our credit facility and money market lines of credit.

In May 2015, our stockholders approved an amendment to the Company's Certificate of Incorporation that increases the total authorized shares of common stock from 200 million to 300 million shares.

4.      Inventories
     
Inventories primarily consist of tubular goods and well equipment held for use in our oil and natural gas operations and oil produced but not sold in our China operations. At September 30, 2015, the crude oil inventory from our China operations consisted of approximately 188,000 barrels of crude oil valued at cost of approximately $9 million. At December 31, 2014, the crude oil inventory from our China operations consisted of approximately 240,000 barrels of crude oil valued at cost of approximately $8 million and is included under the caption "Inventories" on our consolidated balance sheet. Cost for purposes of the carrying value of oil inventory is the sum of related production costs and depletion expense.





8

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

5.      Oil and Gas Assets

  Property and Equipment

  Property and equipment consisted of the following:
 
 
September 30, 
 2015
 
December 31, 
 2014
 
 
(In millions)
Oil and gas properties:
 
 
 
 
Proved
 
$
21,305

 
$
20,402

Unproved
 
747

 
563

Gross oil and gas properties
 
22,052

 
20,965

Accumulated depreciation, depletion and amortization
 
(8,855
)
 
(8,152
)
Accumulated impairment
 
(8,779
)
 
(4,581
)
Net oil and gas properties
 
$
4,418

 
$
8,232

Other property and equipment:
 
 

 
 

Furniture, fixtures and equipment
 
$
143

 
$
144

Gathering systems and equipment
 
116

 
114

Accumulated depreciation and amortization
 
(91
)
 
(76
)
Net other property and equipment
 
$
168

 
$
182


Oil and gas properties not subject to amortization as of September 30, 2015, consisted of the following:
 
 
Costs Incurred In
 
 
 
 
2015
 
2014
 
2013
 
2012 and Prior
 
Total
 
 
(In millions)
Acquisition costs
 
$
272

 
$
165

 
$
158

 
$
46

 
$
641

Exploration costs
 
236

 
2

 

 

 
238

Fee mineral interests
 

 

 
1

 
23

 
24

Capitalized interest
 
23

 
52

 
7

 

 
82

Total oil and gas properties not subject to amortization
 
$
531

 
$
219

 
$
166

 
$
69

 
$
985


We capitalized approximately $23 million and $38 million of interest and direct internal costs during the three months ended September 30, 2015 and 2014, respectively, and $81 million and $158 million during the nine months ended September 30, 2015 and 2014, respectively.

During the second quarter of 2015, we finalized a settlement agreement with our insurance carriers related to an August 2013 LF-7 topside incident in China and recorded a $57 million receivable (the Company's share) and associated reduction to capital expenditures. The settlement proceeds were collected in July 2015.

At September 30, 2015, the ceiling value of our reserves was calculated based upon SEC pricing of $3.06 per MMBtu for natural gas and $59.09 per barrel for oil. Using these prices, our ceiling for the U.S. did not exceed the net capitalized costs of oil and gas properties resulting in a ceiling test writedown. Our domestic ceiling test writedown was approximately $1.8 billion ($1.2 billion after tax) for the three months ended September 30, 2015. For the nine months ended September 30, 2015, we recorded U.S. ceiling test writedowns of approximately $4.1 billion ($2.6 billion after tax).

Using SEC pricing, our ceiling for China at September 30, 2015 did not exceed the net capitalized costs of oil and gas properties, resulting in a ceiling test writedown for the three and nine months of approximately $72 million ($29 million after tax).
The continued decline of SEC pricing for oil and natural gas reserves since September 30, 2015 will likely result in additional U.S. and China ceiling test writedowns in the fourth quarter of 2015.

9

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Granite Wash Asset Sale

In September 2014, we closed on the sale of our Granite Wash assets, located primarily in Texas, for approximately $588 million, subject to customary post-closing purchase price adjustments. The sale of our Granite Wash assets did not significantly alter the relationship between capitalized costs and proved reserves, and as such, all proceeds were recorded as adjustments to our domestic full cost pool with no gain or loss recognized. These consolidated financial statements include the results of our Granite Wash operations through the date of sale.

Other Asset Acquisitions and Sales

During the nine months ended September 30, 2015 and 2014, we acquired various other oil and gas properties for approximately $125 million and $21 million, respectively, and sold certain other oil and gas properties for proceeds of approximately $86 million and $56 million, respectively. The cash flows and results of operations for the assets sold were included in our consolidated financial statements up to the date of sale. Proceeds associated with our asset sales were recorded as adjustments to our domestic full cost pool.

6.      Derivative Financial Instruments
     
Commodity Derivative Instruments
     
We utilize derivative strategies that consist of either a single derivative instrument or a combination of instruments to manage the variability in cash flows associated with the forecasted sale of our future domestic oil and natural gas production. While the use of derivative instruments may limit or partially reduce the downside risk of adverse commodity price movements, their use also may limit future income from favorable commodity price movements.

In addition to the derivative strategies outlined in our Annual Report on Form 10-K for the year ended December 31, 2014, we purchased call options in 2015 that effectively lock in the value for a portion of our corresponding oil swaps with short puts as well as collars with short puts. We elected to defer the premiums related to these calls until contract settlement. At September 30, 2015, the deferred premiums totaled $14 million. Excluding the effect of the deferred premium, if the settlement price is above the call strike price, the counterparty is required to make a payment to us.

Our oil and gas derivative contracts are settled based upon reported prices on the NYMEX. The estimated fair value of these contracts is based upon various factors, including closing exchange prices on the NYMEX, over-the-counter quotations, estimated volatility, non-performance risk adjustments using credit default swaps and time to maturity. The calculation of the fair value of options requires the use of an option-pricing model. See Note 9, “Fair Value Measurements.”

At September 30, 2015, we had outstanding derivative positions as set forth in the tables below.


10

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Crude Oil
 
 
 
 
NYMEX Contract Price Per Bbl
 
 
 
 
 
 
 
 
 
 
 
 
Collars
 
Estimated Fair Value
Asset (Liability)
Period and Type of Instrument
 
Volume in MBbls
 
Swaps
(Weighted Average)
 
Purchased Calls (Weighted Average)
 
Sold Puts
(Weighted Average)
(1)
 
Floors
(Weighted Average)
 
Ceilings
(Weighted Average)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions)
2015:
 
 

 
 

 
 
 
 

 
 

 
 

 
 

  Fixed-price swaps
 
92

 
$
90.00

 
$

 
$

 
$

 
$

 
$
4

  Fixed-price swaps with sold puts:
 
4,278

 
 
 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
90.08

 

 

 

 

 
189

Sold puts
 
 
 

 

 
71.12

 

 

 
(109
)
  Collars with sold puts:
 
184

 
 
 
 
 
 
 
 
 
 
 
 
Collars
 
 
 

 

 

 
90.00

 
104.00

 
8

Sold puts
 
 
 

 

 
75.00

 

 

 
(5
)
2016:
 
 

 
 

 
 
 
 

 
 

 
 

 
 

  Fixed-price swaps with sold puts:
 
10,060

 
 
 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
89.98

 

 

 

 

 
408

Sold puts
 
 
 

 

 
74.14

 

 

 
(258
)
  Collars with sold puts:
 
6,220

 
 
 
 
 
 
 
 
 
 
 
 
Collars
 
 
 

 

 

 
90.00

 
96.15

 
252

Sold puts
 
 
 

 

 
75.00

 

 

 
(164
)
  Purchased calls
 
4,954

 

 
71.60

 

 

 

 
6

2017:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-price swaps with sold puts:
 
4,468

 
 
 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
88.37

 

 

 

 

 
155

Sold puts
 
 
 

 

 
73.28

 

 

 
(99
)
  Collars with sold puts:
 
2,080

 
 
 
 
 
 
 
 
 
 
 
 
Collars
 
 
 

 

 

 
90.00

 
95.59

 
78

Sold puts
 
 
 

 

 
75.00

 

 

 
(50
)
  Purchased calls
 
1,997

 

 
73.73

 

 

 

 
3

Total
 
$
418

_________________
(1)
If the market prices remain below our sold puts at contract settlement, we will receive the market price plus the following associated with our production:

the difference between our floors and our sold puts for collars with sold puts; or
the difference between our swaps and our sold puts for fixed-price swaps with sold puts.
For the volumes with purchased calls, we have effectively locked in a portion of the spreads noted above (less the call premium).







11

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

Natural Gas
 
 
 
 
NYMEX Contract Price Per MMBtu
 
 
 
 
 
 
 
 
 
 
Collars
 
Estimated Fair Value Asset (Liability)
Period and Type of Instrument
 
Volume in MMMBtus
 
Swaps (Weighted Average)
 
Sold Puts (Weighted Average)
 
Floors (Weighted Average)
 
Ceilings (Weighted Average)
 
 
 
 
 
 
 
 
 
 
 
 
 
(In millions)
2015:
 
 
 
 
 
 
 
 

 
 
 
 
  Fixed-price swaps
 
13,970

 
$
4.14

 
$

 
$

 
$

 
$
21

Swaptions(1)
 

 
3.50

 

 

 

 

  Collars
 
9,660

 

 

 
3.93

 
4.74

 
13

2016:
 
 

 
 

 
 

 
 

 
 

 
 

  Fixed-price swaps
 
4,550

 
3.39

 

 

 

 
3

Swaptions(1)
 

 
3.50

 

 

 

 

  Collars
 
10,980

 

 

 
4.00

 
4.54

 
13

Total
 
$
50

________
(1)
During the second quarter of 2015, we sold natural gas swaption contracts that expired unexercised in October 2015. During the third quarter of 2015, we sold natural gas swaption contracts that, if exercised on their expiration date in December 2015, would protect 9,100 MMMBtus of January 2016 through June 2016 production with $3.50 per MMBtu fixed price swaps.

Additional Disclosures about Derivative Financial Instruments

We had derivative financial instruments recorded in our consolidated balance sheet as assets (liabilities) at their respective estimated fair value, as set forth below.
 
 
Derivative Assets
 
Derivative Liabilities
 
 
Gross Fair Value
 
Offset in Balance Sheet
 
Balance Sheet Location
 
Gross Fair Value
 
Offset in Balance Sheet
 
Balance Sheet Location
 
 
 
 
Current
 
Noncurrent
 
 
 
Current
 
Noncurrent
 
 
(In millions)
 
(In millions)
September 30, 2015
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil positions
 
$
1,044

 
$
(612
)
 
$
287

 
$
145

 
$
(626
)
 
$
612

 
$
(8
)
 
$
(6
)
Natural gas positions
 
50

 

 
47

 
3

 

 

 

 

Total
 
$
1,094

 
$
(612
)
 
$
334

 
$
148

 
$
(626
)
 
$
612

 
$
(8
)
 
$
(6
)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2014
 
 

 
 

 
 

 
 

 
 

 
 

 
 

 
 

Oil positions
 
$
1,115

 
$
(597
)
 
$
332

 
$
186

 
$
(605
)
 
$
597

 
$
(8
)
 
$

Natural gas positions
 
105

 
(2
)
 
99

 
4

 
(2
)
 
2

 

 

Total
 
$
1,220

 
$
(599
)
 
$
431

 
$
190

 
$
(607
)
 
$
599

 
$
(8
)
 
$

 

12

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

The amount of gain (loss) recognized in “Commodity derivative income (expense)” in our consolidated statement of operations related to our derivative financial instruments follows:
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In millions)
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
 
Realized gain (loss) on oil positions
 
$
100

 
$
(18
)
 
$
287

 
$
(70
)
Realized gain (loss) on natural gas positions
 
31

 
(2
)
 
88

 
(36
)
Total realized gain (loss)
 
131

 
(20
)
 
375

 
(106
)
Unrealized gain (loss) on oil positions
 
(30
)
 
285

 
(92
)
 
109

Unrealized gain (loss) on natural gas positions
 
(14
)
 
38

 
(53
)
 
30

Total unrealized gain (loss)
 
(44
)
 
323

 
(145
)
 
139

Total
 
$
87

 
$
303

 
$
230

 
$
33


The use of derivative transactions involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty, and we have netting arrangements with all of our counterparties that provide for offsetting payables against receivables from separate derivative instruments with that counterparty. At September 30, 2015, ten of our 17 counterparties accounted for approximately 85% of our contracted volumes, with the largest counterparty accounting for approximately 15%.

At September 30, 2015, approximately 72% of our volumes subject to derivative instruments are with lenders under our credit facility. Our credit facility, senior notes and substantially all of our derivative instruments contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations. 

7.    Accounts Receivable

Accounts receivable consisted of the following:
 
 
September 30, 
 2015
 
December 31, 
 2014
 
 
(In millions)
Revenue
 
$
102

 
$
155

Joint interest
 
122

 
230

Other
 
55

 
70

Reserve for doubtful accounts
 
(16
)
 
(16
)
Total accounts receivable, net
 
$
263

 
$
439


Reserve for doubtful accounts includes an allowance of $15 million related to discontinued operations. See Note 17, "Discontinued Operations."

8.    Accrued Liabilities

Accrued liabilities consisted of the following:

13

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

 
 
September 30, 
 2015
 
December 31, 
 2014
 
 
(In millions)
Revenue payable
 
$
151

 
$
197

Accrued capital costs
 
141

 
441

Accrued lease operating expenses
 
40

 
47

Employee incentive expense
 
31

 
62

Accrued interest on debt
 
32

 
67

Taxes payable
 
40

 
32

Other
 
45

 
34

Total accrued liabilities
 
$
480

 
$
880


9.      Fair Value Measurements
     
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The authoritative guidance requires disclosure of the framework for measuring fair value and requires that fair value measurements be classified and disclosed in one of the following categories:

Level 1:
Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. We consider active markets as those in which transactions for the assets or liabilities occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2:
Quoted prices in markets that are not active, or inputs that are observable, either directly or indirectly, for substantially the full term of the asset or liability. This category includes those derivative instruments that we value using observable market data. Substantially all of these inputs are observable in the marketplace throughout the full term of the derivative instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange traded derivatives such as over-the-counter commodity fixed-price swaps and certain investments.
Level 3:
Measured based on prices or valuation models that require inputs that are both significant to the fair value measurement and less observable from objective sources (i.e., supported by little or no market activity). Level 3 instruments primarily include derivative instruments, such as commodity options (i.e., price collars, sold puts, purchased calls or swaptions) and other financial investments.
Our valuation models for derivative contracts are primarily industry-standard models (i.e., Black-Scholes) that consider various inputs including: (a) forward prices for commodities, (b) time value, (c) volatility factors, (d) counterparty credit risk and (e) current market and contractual prices for the underlying instruments.

Our valuation model for the Stockholder Value Appreciation Program (SVAP) is a Monte Carlo simulation that is based on a probability model and considers various inputs including: (a) the measurement date stock price, (b) time value and (c) historical and implied volatility. See Note 12, “Stock-Based Compensation,” for a description of the SVAP.

Financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy.

Recurring Fair Value Measurements

The following table summarizes the valuation of our assets and liabilities that are measured at fair value on a recurring basis.

14

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

 
 
Fair Value Measurement Classification
 
 
 
 
Quoted Prices in Active Markets for Identical Assets or Liabilities (Level 1)
 
Significant Other Observable Inputs (Level 2)
 
Significant Unobservable Inputs (Level 3)
 
Total
 
 
(In millions)
As of December 31, 2014:
 
 
 
 
 
 
 
 
Money market fund investments
 
$
1

 
$

 
$

 
$
1

Deferred compensation plan assets
 
9

 

 

 
9

Equity securities available-for-sale
 
10

 

 

 
10

Oil and gas derivative swap contracts
 

 
994

 

 
994

Oil and gas derivative option and swaption contracts
 

 

 
(381
)
 
(381
)
Stock-based compensation liability awards
 
(12
)
 

 
(3
)
 
(15
)
Total
 
$
8

 
$
994

 
$
(384
)
 
$
618

 
 
 

 
 

 
 

 
 

As of September 30, 2015:
 
 

 
 

 
 

 
 

Money market fund investments
 
$
2

 
$

 
$

 
$
2

Deferred compensation plan assets
 
5

 

 

 
5

Equity securities available-for-sale
 
15

 

 

 
15

Oil and gas derivative swap contracts
 

 
780

 

 
780

Oil and gas derivative option and swaption contracts
 

 

 
(312
)
 
(312
)
Stock-based compensation liability awards
 
(11
)
 

 

 
(11
)
Total
 
$
11

 
$
780

 
$
(312
)
 
$
479


The determination of the fair values of our derivative contracts above incorporates various factors, which include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests), if any. We utilize credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to, and receivables from, counterparties.

Level 3 Fair Value Measurements

The following table sets forth a reconciliation of changes in the fair value of financial assets and liabilities classified as Level 3 in the fair value hierarchy for the indicated periods.    

15

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

 
 
Investments
 
Derivatives
 
Stock-Based Compensation
 
Total
 
 
(In millions)
Balance at January 1, 2014
 
$
39

 
$
(8
)
 
$
(5
)
 
$
26

Realized or unrealized gains (losses) included in earnings
 

 

 
(42
)
 
(42
)
Purchases, issuances, sales and settlements:
 
 

 
 

 
 

 
 

Sales
 
(39
)
 

 

 
(39
)
Settlements
 

 
4

 
40

 
44

Transfers in to Level 3
 

 

 

 

Transfers out of Level 3
 

 
3

 

 
3

Balance at September 30, 2014
 
$

 
$
(1
)
 
$
(7
)
 
$
(8
)
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at September 30, 2014
 
$

 
$
20

 
$
(3
)
 
$
17

 
 
 
 
 
 
 
 
 
Balance at January 1, 2015
 
$

 
$
(381
)
 
$
(3
)
 
$
(384
)
Realized or unrealized gains (losses) included in earnings
 

 
(116
)
 
3

 
(113
)
Purchases, issuances, sales and settlements:
 
 

 
 

 
 

 
 

Settlements
 

 
185

 

 
185

Transfers in to Level 3
 

 

 

 

Transfers out of Level 3
 

 

 

 

Balance at September 30, 2015
 
$

 
$
(312
)
 
$

 
$
(312
)
Change in unrealized gains or losses included in earnings relating to Level 3 instruments still held at September 30, 2015
 
$

 
$
(88
)
 
$
3

 
$
(85
)

Qualitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements

Investments.   During the first quarter of 2014, all auction rate securities that we held as of January 1, 2014, were sold for $39 million.

Derivatives.  Our valuation models for Level 3 derivative contracts are primarily industry-standard models that consider various factors, including certain significant unobservable inputs such as volatility factors and counterparty credit risk. The calculation of the fair value of our option contracts requires the use of an option-pricing model. The estimated future prices are compared to the strike prices fixed by our derivative contracts, and the resulting estimated future cash inflows or outflows over the contractual life are discounted to calculate the fair value. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts, regional price differences and interest rates. Significant increases (decreases) in the quoted forward prices for commodities generally lead to corresponding decreases (increases) in the fair value measurement of our oil and gas derivative contracts. Significant changes in the volatility factors utilized in our option-pricing model can cause significant changes in the fair value measurement of our oil and gas derivative contracts. See Note 6, "Derivative Financial Instruments," for additional discussion of our derivative instruments.
 
The determination of the fair values of derivative instruments incorporates various factors that include not only the impact of our non-performance risk on our liabilities but also the credit standing of the counterparties involved and the impact of credit enhancements (such as cash deposits, letters of credit and priority interests). Historically, we have not experienced significant changes in the fair value of our derivative contracts resulting from changes in counterparty credit risk as the counterparties for all of our derivative transactions have an “investment grade” credit rating.

Stock-Based Compensation. The calculation of the fair value of the SVAP liability requires the use of a probability-based Monte Carlo simulation, which includes unobservable inputs. The simulation predicts multiple scenarios of future stock returns over the performance period, which are discounted to calculate the fair value. The fair value is recognized over a service period derived from the simulation. Future stock returns and discounting variables are sensitive to market volatility. Significant increases (decreases) in the volatility factors utilized in our option-pricing model can cause significant increases (decreases) in the fair value measurement of the SVAP liability.

16

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


Quantitative Disclosures about Unobservable Inputs for Level 3 Fair Value Measurements 
 
 
Estimated Fair Value Asset (Liability)
 
  Quantitative Information about Level 3 Fair Value Measurements
Instrument Type
 
Valuation Technique
 
Unobservable Input
 
Range
 
 
(In millions)
 
 
 
 
 
 
 
 
 
Oil option contracts
 
$
(338
)
 
Black-Scholes
 
Oil price volatility
 
23.88
%
 
 
60.75
%
 
 
 
 
 
 
Credit risk
 
0.01
%
 
 
2.89
%
Natural gas option and swaption
contracts
 
$
26

 
Black-Scholes
 
Natural gas price volatility
 
27.63
%
 
 
56.05
%
 
 
 
 
 
 
Credit risk
 
0.01
%
 
 
2.19
%
SVAP
 
$

(1) 
Monte Carlo
 
Implied volatility
 

 

 
53.2
%
_______
(1) Rounds to 0.

Fair Value of Debt
 
The estimated fair value of our notes, based on quoted prices in active markets (Level 1) as of the indicated dates, was as follows:
 
 
September 30, 
 2015
 
December 31, 
 2014
 
 
(In millions)
5¾% Senior Notes due 2022
 
$
734

 
$
772

5⅝% Senior Notes due 2024
 
953

 
989

5⅜% Senior Notes due 2026
 
646

 

6⅞% Senior Subordinated Notes due 2020
 

 
721


Any amounts outstanding under our revolving credit facility and money market lines of credit as of the indicated dates are stated at cost, which approximates fair value. Please see Note 10, “Debt.”

10.      Debt
 
Our debt consisted of the following:
 
 
September 30, 
 2015
 
December 31, 
 2014
 
 
(In millions)
Senior unsecured debt:
 
 
 
 
Revolving credit facility — LIBOR based loans (matures in 2020)
 
$

 
$
345

Money market lines of credit(1)
 
48

 
101

Total credit arrangements
 
48

 
446

5¾% Senior Notes due 2022
 
750

 
750

5⅝% Senior Notes due 2024
 
1,000

 
1,000

5⅜% Senior Notes due 2026
 
700

 

Total senior unsecured debt
 
2,498

 
2,196

6⅞% Senior Subordinated Notes due 2020
 

 
700

Discount on notes
 

 
(4
)
Total long-term debt
 
$
2,498

 
$
2,892

________
(1) Because we have the ability and intent to use our available credit facility to repay borrowings under our money market lines of credit as of the indicated dates, amounts outstanding under these obligations, if any, are classified as long-term.


17

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)


Credit Arrangements
     
In March 2015, we entered into the fourth amendment to our Credit Agreement. This amendment extended the maturity date of the revolving credit facility from June 2018 to June 2020 and increased the borrowing capacity from $1.4 billion to $1.8 billion. We incurred $7 million of deferred financing costs related to this amendment, which will be amortized through June 2020. As of September 30, 2015, the largest individual loan commitment by any lender was 12% of total commitments.

Loans under the credit facility bear interest, at our option, equal to (a) a rate per annum equal to the higher of the prime rate announced from time to time by JPMorgan Chase Bank, N.A. or the weighted average of the rates on overnight federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 50 basis points, plus a margin that is based on a grid of our debt rating (75 basis points per annum at September 30, 2015) or (b) the London Interbank Offered Rate, plus a margin that is based on a grid of our debt rating (175 basis points per annum at September 30, 2015).

Under our credit facility, we pay commitment fees on available but undrawn amounts based on a grid of our debt rating (30 basis points per annum at September 30, 2015). We incurred aggregate commitment fees under our current credit facility of approximately $2 million and $4 million for the three and nine-month periods ended September 30, 2015, respectively, which are recorded in “Interest expense” on our consolidated statement of operations. For the three- and nine-month periods ended September 30, 2014, we incurred commitment fees under our credit facility of approximately $1 million and $3 million, respectively.

Our credit facility has restrictive financial covenants that include the maintenance of a ratio of total debt to book capitalization not to exceed 0.6 to 1.0 and maintenance of a ratio of earnings before gain or loss on the disposition of assets, interest expense, income taxes and noncash items (such as depreciation, depletion and amortization expense, unrealized gains and losses on commodity derivatives, ceiling test writedowns and goodwill impairments) to interest expense of at least 3.0 to 1.0. At September 30, 2015, we were in compliance with all of our debt covenants.

As of September 30, 2015, we had no letters of credit outstanding under our credit facility. Letters of credit are subject to a fronting fee of 20 basis points and annual fees based on a grid of our debt rating (175 basis points at September 30, 2015).
     
Subject to compliance with the restrictive covenants in our credit facility, at September 30, 2015, we also had a total of $147 million of available borrowing capacity under our money market lines of credit with various financial institutions, the availability of which is at the discretion of the financial institutions.
 
The credit facility includes events of default relating to customary matters, including, among other things, nonpayment of principal, interest or other amounts; violation of covenants; inaccuracy of representations and warranties in any material respect; a change of control; or certain other material adverse changes in our business. Our senior notes also contain standard events of default. If any of the foregoing defaults were to occur, our lenders under the credit facility could terminate future lending commitments, and our lenders under both the credit facility and our notes could declare the outstanding borrowings due and payable. In addition, our credit facility, senior notes and substantially all of our derivative arrangements contain provisions that provide for cross defaults and acceleration of those debt and derivative instruments in certain situations.

Senior Notes and Senior Subordinated Notes

In March 2015, we issued $700 million of 5⅜% Senior Notes due 2026 and received net proceeds of $691 million (net of offering costs of approximately $9 million). These notes were issued at par to yield 5⅜%. In April 2015 we used the net proceeds to redeem our $700 million aggregate principal amount of 6⅞% Senior Subordinated Notes due 2020. In connection with the redemption, we paid a premium of $24 million. The premium was recorded under the caption "Other income (expense) — Other, net" on our consolidated statement of income. In addition, associated unamortized offering costs and discounts of approximately $8 million were charged to interest expense during the second quarter of 2015 as a result of the redemption.

11.      Income Taxes

The following table presents a reconciliation of the United States statutory income tax rate to our effective income tax rate.


18

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
U.S. statutory income tax rate
 
35.0
 %
 
35.0
 %
 
35.0
 %
 
35.0
%
State and local income taxes, net of federal effect
 
(0.6
)
 
1.1

 
0.9

 
2.0

Foreign tax on foreign earnings
 
1.1

 
(0.1
)
 
0.2

 
0.5

Other
 
(0.3
)
 
(0.4
)
 
(0.1
)
 

Effective income tax rate
 
35.2
 %
 
35.6
 %
 
36.0
 %
 
37.5
%

Unrealized derivative gains and losses are treated differently for income tax purposes in the various state taxing jurisdictions to which we are subject. As a result, our effective tax rate fluctuates in periods with significant commodity price volatility. These effective tax rate fluctuations are magnified when income before taxes approaches zero.

As of September 30, 2015, we did not have a liability for uncertain tax positions, and as such, we had not accrued related interest or penalties. The tax years 2011 through 2014 remain open to examination for federal income tax purposes and by the other major taxing jurisdictions to which we are subject.

12.      Stock-Based Compensation
     
Our stock-based compensation consisted of the following:
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In millions)
Equity awards
 
$
9

 
$
15

 
$
31

 
$
37

Liability awards:
 


 


 


 


Cash-settled restricted stock units
 
3

 
5

 
15

 
21

Stockholder Value Appreciation Program
 
(3
)
 
(12
)
 
(3
)
 
42

Total liability awards
 

 
(7
)
 
12

 
63

Total stock-based compensation
 
9

 
8

 
43

 
100

Capitalized in oil and gas properties
 
(2
)
 
2

 
(11
)
 
(38
)
Net stock-based compensation expense
 
$
7

 
$
10

 
$
32

 
$
62


As of September 30, 2015, we had approximately $63 million of total unrecognized stock-based compensation expense related to unvested stock-based compensation awards that vest within four years.

Equity Awards

Equity awards consist of service-based and performance- or market-based restricted stock units, stock options and stock purchase options under the Employee Stock Purchase Plan (ESPP).

Stock-based compensation classified as equity awards are currently granted under the 2011 Omnibus Stock Plan, as amended (2011 Plan), to employees and non-employee directors. The fair value of grants is determined utilizing the Black-Scholes option-pricing model for stock options and a Monte Carlo lattice-based model for our performance- and market-based restricted stock and restricted stock units. Compensation expense for equity awards is expected to be recognized on a straight-line basis over the applicable remaining vesting periods.

Shares available for grant under our 2011 Plan are reduced by 1.87 times the number of shares of restricted stock or restricted stock units awarded under the plan and are reduced by 1 times the number of shares subject to stock options awarded under the plan. In May 2015, our stockholders approved an additional 7.0 million shares available for issuance under our 2011 Plan. As a result, at September 30, 2015, we had approximately (1) 7.2 million shares available for issuance under our 2011 Plan if all future awards are stock options, or (2) 3.9 million shares available for issuance under our 2011 Plan if all future

19

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

awards are restricted stock or restricted stock units. Thus far, all awards under our 2011 Plan have been granted as restricted stock or restricted stock unit awards.

Restricted Stock. The following table provides information about restricted stock and restricted stock unit activity.
 
 
Service-Based
Shares
 
Performance/
Market-Based
Shares
 
Total
Shares
 
Weighted- Average Grant Date Fair Value per Share
 
 
(In thousands, except per share data)
Non-vested shares outstanding at January 1, 2015
 
1,902

 
945

 
2,847

 
$
30.05

Granted
 
1,008

 
414

 
1,422

 
28.63

Forfeited
 
(328
)
 
(97
)
 
(425
)
 
24.51

Vested
 
(815
)
 
(183
)
 
(998
)
 
33.32

Non-vested shares outstanding at September 30, 2015
 
1,767

 
1,079

 
2,846

 
$
27.93


On September 30, 2015, the last reported sales price of our common stock on the New York Stock Exchange was $32.90 per share.

Employee Stock Purchase Plan. During the first six months of 2015, options to purchase approximately 85,000 shares of our common stock were issued under our ESPP. The fair value of each option was $7.93 per share. The fair value of the options granted was determined using the Black-Scholes option valuation method assuming no dividends, a risk-free interest rate of 0.12%, an expected life of six months and weighted-average volatility of 52%.

On July 1, 2015, options to purchase approximately 49,000 shares of our common stock were granted under our employee stock purchase plan. The fair value of each option was $9.99 per share as determined using the Black-Scholes option valuation method assuming no dividends, a risk-free interest rate of 0.11%, an expected life of six months and weighted-average volatility of 46%.

Stock Options. As of September 30, 2015, we had approximately 200,000 stock options outstanding and exercisable. No stock options have been granted since 2008, except for ESPP options as discussed above.

Liability Awards

Liability awards consist of performance awards that are settled in cash instead of shares, as discussed below.

Cash-Settled Restricted Stock Units. We periodically grant cash-settled restricted stock units to employees that vest over three years. As of September 30, 2015, we accrued $11 million for future cash settlement upon vesting of awards. The value of the awards, and the associated stock-based compensation expense, is based on the Company’s stock price at the end of each period. As of September 30, 2015, we had unrecognized stock-based compensation expense related to cash-settled restricted stock units of approximately $10 million. The following table provides information about cash-settled restricted stock unit activity.
 
 
Cash-Settled Restricted Stock Units
 
 
(In thousands)
Non-vested units outstanding at January 1, 2015
 
1,216

Granted
 
211

Forfeited
 
(218
)
Vested
 
(462
)
Non-vested units outstanding at September 30, 2015
 
747


    Stockholder Value Appreciation Program. In September 2013, the Compensation and Management Development Committee of the Board approved the SVAP to be administered under the 2011 Plan. The SVAP pays substantially all full-time domestic, nonexecutive employees a cash payment based on a percentage of salary upon each incremental $5 increase in our

20

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

30-calendar day average share price. Each price threshold can be reached only once during the term of the program. The SVAP's performance period lasts through December 31, 2015. Each price trigger, if any, that is reached during the fourth quarter of 2015 would result in an approximately $11 million payment.

The first price threshold that triggered a payment under the SVAP was $27.50 during the fourth quarter of 2013. The second and third price thresholds for the SVAP were $32.50 and $37.50, respectively, which were reached during the second quarter of 2014. The fourth price threshold for the SVAP of $42.50 was reached in July 2014. Each of the first four SVAP payments was approximately $13 million.

Based on the valuation of the SVAP as of September 30, 2015, $0.2 million has been accrued. The total expected cost was determined using a Monte Carlo simulation assuming no dividends, a risk-free weighted-average interest rate of 0.03%, a remaining plan term of three months and an average of implied and historical stock price volatility of 47%. Future changes in our stock price could cause the total cost of the program to be different than our estimates as of September 30, 2015. In the event we do not achieve the next price threshold of $47.50 before December 31, 2015, the remaining accrued expense will be reversed.

13.    Commitments and Contingencies

On May 22, 2015, a lawsuit was filed against the Company alleging certain plugging and abandonment predecessor-in-interest liabilities related to offshore assets sold by the Company in 2010. The lawsuit alleges damages of approximately $23 million. The Company has responded to the petition, denied the allegations and is vigorously defending the case. The action is in the early stages and no discovery has been conducted. Therefore, an estimate of reasonably possible losses, if any, cannot be made at this time.

We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

14.
Segment Information

While we only have operations in the oil and gas exploration and production industry, we are organizationally structured along geographic operating segments. Our current operating segments are the United States and China. The accounting policies of each of our operating segments are the same as those described in Note 1, “Organization and Summary of Significant Accounting Policies,” in our Annual Report on Form 10-K for the year ended December 31, 2014.

The following tables provide the geographic operating segment information for our continuing operations for the three- and nine- month periods ended September 30, 2015 and 2014. Income tax allocations have been determined based on statutory rates in the applicable geographic segment. Our earnings and profits in China are taxed at the combined statutory rates for China and the U.S. for our income tax allocation of our China operations in the following tables.


21

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

 
 
Domestic
 
China
 
Total
 
 
(In millions)
Three Months Ended September 30, 2015:
 
 
 
 
 
 
Oil, gas and NGL revenues
 
$
316

 
$
61

 
$
377

Operating expenses:
 
 
 
 
 
 
Lease operating
 
57

 
14

 
71

Transportation and processing
 
52

 

 
52

Production and other taxes
 
13

 

 
13

Depreciation, depletion and amortization
 
184

 
52

 
236

General and administrative
 
64

 
2

 
66

Ceiling test and other impairments
 
1,817

 
72

 
1,889

Other
 
1

 

 
1

Allocated income tax (benefit)
 
(693
)
 
(47
)
 
 
Net income (loss) from oil and gas properties
 
$
(1,179
)
 
$
(32
)
 
 
Total operating expenses
 
 
 
 
 
2,328

Income (loss) from continuing operations
 
 
 
 
 
(1,951
)
Interest expense, net of interest income, capitalized interest and other
 
 
 
 
 
(28
)
Commodity derivative income (expense)
 
 
 
 
 
87

Income (loss) from continuing operations before income taxes
 
 
 
 
 
$
(1,892
)
Total assets
 
$
5,114

 
$
399

 
$
5,513

Additions to long-lived assets
 
$
474

 
$
(12
)
 
$
462


 
 
Domestic
 
China
 
Total
 
 
(In millions)
Three Months Ended September 30, 2014:
 
 
 
 
 
 
Oil, gas and NGL revenues
 
$
610

 
$

 
$
610

Operating expenses:
 
 
 
 
 
 
Lease operating
 
73

 
1

 
74

Transportation and processing
 
51

 

 
51

Production and other taxes
 
31

 
1

 
32

Depreciation, depletion and amortization
 
228

 

 
228

General and administrative
 
48

 

 
48

Other
 
10

 

 
10

Allocated income tax (benefit)
 
63

 
(1
)
 
 
Net income (loss) from oil and gas properties
 
$
106

 
$
(1
)
 
 
Total operating expenses
 
 
 
 
 
443

Income (loss) from continuing operations
 
 
 
 
 
167

Interest expense, net of interest income, capitalized interest and other
 
 
 
 
 
(37
)
Commodity derivative income (expense)
 
 
 
 
 
303

Income (loss) from continuing operations before income taxes
 
 
 
 
 
$
433

Total assets
 
$
8,392

 
$
676

 
$
9,068

Additions to long-lived assets
 
$
485

 
$
38

 
$
523




22

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

 
 
Domestic
 
China
 
Total
 
 
(In millions)
Nine Months Ended September 30, 2015:
 
 
 
 
 
 
Oil, gas and NGL revenues
 
$
989

 
$
206

 
$
1,195

Operating expenses:
 
 
 
 
 
 
Lease operating
 
178

 
41

 
219

Transportation and processing
 
153

 

 
153

Production and other taxes
 
43

 

 
43

Depreciation, depletion and amortization
 
603

 
118

 
721

General and administrative
 
174

 
6

 
180

Ceiling test and other impairments
 
4,130

 
72

 
4,202

Other
 
7

 
1

 
8

Allocated income tax (benefit)
 
(1,591
)
 
(19
)
 
 
Net income (loss) from oil and gas properties
 
$
(2,708
)
 
$
(13
)
 
 
Total operating expenses
 
 
 
 
 
5,526

Income (loss) from continuing operations
 
 
 
 
 
(4,331
)
Interest expense, net of interest income, capitalized interest and other
 
 
 
 
 
(117
)
Commodity derivative income (expense)
 
 
 
 
 
230

Income (loss) from continuing operations before income taxes
 
 
 
 
 
$
(4,218
)
Total assets
 
$
5,114

 
$
399

 
$
5,513

Additions to long-lived assets
 
$
1,210

 
$
15

 
$
1,225


 
 
Domestic
 
China
 
Total
 
 
(In millions)
Nine Months Ended September 30, 2014:
 
 
 
 
 
 
Oil, gas and NGL revenues
 
$
1,771

 
$
22

 
$
1,793

Operating expenses:
 
 
 
 
 
 
Lease operating
 
224

 
4

 
228

Transportation and processing
 
125

 

 
125

Production and other taxes
 
85

 
5

 
90

Depreciation, depletion and amortization
 
628

 
5

 
633

General and administrative
 
172

 

 
172

Other
 
15

 

 
15

Allocated income tax (benefit)
 
193

 
5

 
 
Net income (loss) from oil and gas properties
 
$
329

 
$
3

 
 
Total operating expenses
 
 
 
 
 
1,263

Income (loss) from continuing operations
 
 
 
 
 
530

Interest expense, net of interest income, capitalized interest and other
 
 
 
 
 
(110
)
Commodity derivative income (expense)
 
 
 
 
 
33

Income (loss) from continuing operations before income taxes
 
 
 
 
 
$
453

Total assets
 
$
8,392

 
$
676

 
$
9,068

Additions to long-lived assets
 
$
1,473

 
$
104

 
$
1,577




23

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

15.    Restructuring Costs

In April 2015, we announced plans to combine our onshore Gulf Coast and Rocky Mountain business units into our newly-created Western Region which is managed from The Woodlands, Texas. Our decision to restructure our organization, which only affects our domestic business, was primarily in response to the current oil and gas commodity price environment. These changes are expected to result in better utilization of our resources and improve cost efficiencies in operations. We expect substantially all one-time restructuring-related costs to be incurred by December 31, 2015 and do not expect these costs to materially affect our cash flows or results of operations. We abandoned our Denver, Colorado office space during the third quarter of 2015 and recorded a loss for the remaining contracted payments net of expected sublease income. We will close our North Houston (Greenspoint area) office on or before April 2016, consistent with the terms of our lease.

Restructuring costs recorded in our consolidated statement of operations are set forth below.
 
 
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
 
 
2015
 
2014
 
2015
 
2014
 
 
 
 
(In millions)
Type of Restructuring Cost
 
Location in the Consolidated Statement of Operations
 
 
Severance and related benefit costs
 
Operating expenses - General and administrative
 
$
3

 
$

 
$
6

 
$

Relocation costs
 
Operating expenses - General and administrative
 
2

 

 
3

 

Office-lease abandonment costs
 
Operating expenses - General and administrative
 
13

 

 
13

 

Other associated costs
 
Operating expenses - Depreciation, depletion and amortization
 

 

 
1

 

Total
 
 
 
$
18

 
$

 
$
23

 
$

    
The following table summarizes our restructuring costs and related accruals.
 
 
Severance and Related Benefit Costs
 
Office-lease Abandonment Costs
 
Relocation Costs
 
Other Associated Costs
 
Total
 
 
(In millions)
Restructuring liability at January 1, 2015
 
$

 
$

 
$

 
$

 
$

Additions
 
6

 
13

 
3

 
1

 
23

Settlements
 
(4
)
 

 
(3
)
 
(1
)
 
(8
)
Revisions
 

 

 

 

 

Restructuring liability at September 30, 2015
 
$
2

 
$
13

 
$

 
$

 
$
15

 
 
 
 
 
 
 
 
 
 
 
Cumulative costs as of September 30, 2015
 
$
6

 
$
13

 
$
3

 
$
1

 
$
23

Expected total costs
 
$
7

 
$
19

 
$
5

 
$
1

 
$
32


16.    Supplemental Cash Flow Information

The following table presents information about investing and financing activities that affect recognized assets and liabilities but do not result in cash receipts or payments for the indicated periods.
 
 
Nine Months Ended
 
 
September 30,
 
 
2015
 
2014
 
 
(In millions)
Non-cash investing and financing activities excluded from the statement of cash flows:
 
 
 
 
(Increase) decrease in receivables for property sales
 
$
8

 
$
(17
)
(Increase) decrease in accrued capital expenditures
 
212

 
2

(Increase) decrease in asset retirement costs
 
(4
)
 
18





24

Table of Contents
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Unaudited)

17.     Discontinued Operations

In 2013, we met the criteria to classify our Malaysia business as held for sale and discontinued operations. In February 2014, we closed the sale of our Malaysia business to SapuraKencana Petroleum Berhad (SapuraKencana), a Malaysian public company, for $898 million. As a result of the sale, we recorded a gain in the first quarter of 2014 of approximately $388 million ($252 million, after tax). In the fourth quarter of 2014, we recorded an allowance against a receivable from SapuraKencana and reduced the previously recognized gain by $15 million ($10 million, after tax) due to uncertainty associated with collectability. In April 2015, we initiated a notice of dispute related to the final post-close settlement, which was countered by SapuraKencana. We believe the dispute may result in arbitration proceedings. There are no other assets and liabilities in the consolidated balance sheet attributable to discontinued operations as of September 30, 2015 or December 31, 2014.

Results of Discontinued Operations
 
 
Nine Months Ended  September 30,
 
 
2014
 
 
(In millions)
Oil and gas revenues
 
$
90

Operating expenses
 
69

    Income (loss) from discontinued operations
 
21

    Gain on sale of Malaysia business
 
388

Income from discontinued operations before income taxes
 
409

Income tax provision (benefit):
 


    Current
 
12

    Deferred
 
140

    Total income tax provision (benefit)
 
152

Income (loss) from discontinued operations, net of tax
 
$
257



25


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Overview
     
We are an independent energy company engaged in the exploration, development and production of crude oil, natural gas and natural gas liquids. We focus on U.S. resource plays, and our primary areas of operation include the Mid-Continent, the Rocky Mountains and onshore Texas. We also have offshore oil developments in China.

Third quarter 2015 highlights include:

Increased total domestic production 4% from the second quarter of 2015 to 12.6 MMBOE, excluding approximately 1.9 Bcf of natural gas produced and consumed in operations. Year-over-year, domestic production increased 14%, excluding the effects of asset sales.

Continued trend of lower consolidated lease operating expense with a 2% decrease (4% on a per BOE basis) in the current quarter compared to the previous quarter. Year-over-year, lease operating expense decreased 20% on a per BOE basis.

Production from the Anadarko Basin of Oklahoma (SCOOP/STACK) was 6.2 MMBOE, up approximately 50% over the same period of 2014 and 25% from the second quarter of 2015. Anadarko Basin oil production increased more than 100% over the prior year.

Reduced current completed well costs in our STACK play to approximately $7.5 million gross per well.


Results of Continuing Operations            
Our continuing operations consist of exploration, development and production activities in the United States and China.

Domestic Revenues and Production. Revenues during the third quarter of 2015 were $294 million lower than the same quarter of 2014. The lower revenues were attributable to a 49% decrease in the average revenue per BOE compared to the third quarter of 2014. We increased our crude oil production for the third quarter 2015 by 9% over the same period of 2014, reducing the domestic impact of lower prices by $38 million. Oil production in the Anadarko Basin increased 109% while production in our other domestic basins declined as compared to the third quarter of 2014 due to the reduction of our development activities in those areas.

Revenues during the nine months ended September 30, 2015 were $782 million lower than the same period of 2014. The lower revenues were attributable to a 47% decrease in the average revenue per BOE, period over period. We increased our crude oil production for the nine months ended September 30, 2015 by 17% over the same period of 2014, reducing the impact of lower prices by $198 million. Oil production in the Anadarko Basin increased 111%, and our Williston Basin oil production increased 9%. Production in our other domestic basins declined year-over-year due to the reduction of our development activities in those areas.

China Revenues and Production/Liftings. During the first nine months of 2015, substantially all of our China production was from our Pearl development. Despite the approximate 50% reduction in realized crude oil prices, our revenues from China of $61 million and $206 million for the three and nine months ended September 30, 2015, respectively, were significantly higher than the comparable periods of 2014 because our Pearl development commenced production during the fourth quarter of 2014. As such, we expect that 2015 revenues and expenses in China will continue to increase compared to 2014.

The following table reflects our production/liftings from continuing operations and average realized commodity prices:


26





Three Months Ended 
 September 30,

Percentage
Increase (Decrease)

Nine Months Ended 
 September 30,

Percentage
Increase (Decrease)
 

2015

2014


2015

2014

Production/Liftings:

 

 

 

 

 

 
Domestic:(1)
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (MBbls)

5,245


4,797


9
 %

15,728


13,453


17
 %
Natural gas (Bcf)

30.2


31.7


(5
)%

85.4


90.2


(5
)%
NGLs (MBbls)

2,319


2,242


3
 %

6,144


5,945


3
 %
Total (MBOE)

12,589


12,325


2
 %

36,104


34,430


5
 %
China:(2)
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (MBbls)
 
1,428

 

 
100
 %
 
3,977

 
201

 
>100 %

Total Continuing Operations:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (MBbls)
 
6,673

 
4,797

 
39
 %
 
19,705

 
13,654

 
44
 %
Natural gas (Bcf)
 
30.2

 
31.7

 
(5
)%
 
85.4

 
90.2

 
(5
)%
NGLs (MBbls)
 
2,319

 
2,242

 
3
 %
 
6,144

 
5,945

 
3
 %
Total (MBOE)
 
14,017

 
12,325

 
14
 %
 
40,081

 
34,631

 
16
 %
Average Realized Prices:

 


 


 


 


 


 

Domestic:(3)
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (per Bbl)

$
38.41


$
85.07


(55
)%

$
41.58


$
87.22


(52
)%
Natural gas (per Mcf)

2.51


3.85


(35
)%

2.52


4.26


(41
)%
NGLs (per Bbl)

16.79


34.16


(51
)%

18.51


34.24


(46
)%
Crude oil equivalent (per BOE)

25.11


49.49


(49
)%

27.38


51.43


(47
)%
China:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (per Bbl)
 
$
42.78

 
$

 
100
 %
 
$
51.81

 
$
107.57

 
(52
)%
Total Continuing Operations:
 
 
 
 
 
 
 
 
 
 
 
 
Crude oil and condensate (per Bbl)
 
$
39.34

 
$
85.07

 
(54
)%
 
$
43.64

 
$
87.52

 
(50
)%
Natural gas (per Mcf)
 
2.51

 
3.85

 
(35
)%
 
2.52

 
4.26

 
(41
)%
NGLs (per Bbl)
 
16.79

 
34.16

 
(51
)%
 
18.51

 
34.24

 
(46
)%
Crude oil equivalent (per BOE)
 
26.91

 
49.49

 
(46
)%
 
29.81

 
51.76

 
(42
)%
________________
(1)
Excludes natural gas produced and consumed in operations of 1.9 Bcf and 2.0 Bcf during the three months ended September 30, 2015 and 2014, respectively, and 6.0 Bcf and 6.4 Bcf during the nine months ended September 30, 2015 and 2014, respectively.

(2)
Represents our net share of volumes sold regardless of when produced.

(3)
Had we included the realized effects of derivative contracts, the average realized prices for our domestic crude oil and natural gas production would have been as follows:
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
Crude oil and condensate (per Bbl)
 
$
57.45

 
$
81.41

 
$
59.84

 
$
82.03

Natural gas (per Mcf)
 
3.54

 
3.79

 
3.55

 
3.86


Operating Expenses.

Three months ended September 30, 2015 compared to September 30, 2014

The following table presents information about our operating expenses for our continuing operations:


27



 
 
Unit-of-Production
 
Total Amount
 
 
Three Months Ended 
 September 30,
 
Percentage
Increase (Decrease)
 
Three Months Ended 
 September 30,
 
Percentage
Increase (Decrease)
 
 
2015
 
2014
 
 
2015
 
2014
 
 
 
(Per BOE)
 
 
 
(In millions)
 
 
Domestic:
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating
 
$
4.55

 
$
5.92

 
(23
)%
 
$
57

 
$
73

 
(22
)%
Transportation and processing
 
4.20

 
4.09

 
3
 %
 
52

 
51

 
5
 %
Production and other taxes
 
1.01

 
2.47

 
(59
)%
 
13

 
31

 
(58
)%
Depreciation, depletion and amortization
 
14.65

 
18.50

 
(21
)%
 
184

 
228

 
(19
)%
General and administrative
 
5.09

 
3.97

 
28
 %
 
64

 
48

 
31
 %
Ceiling test and other impairments
 
144.35

 

 
100
 %
 
1,817

 

 
100
 %
Other
 
0.07

 
0.82

 
(91
)%
 
1

 
10

 
(91
)%
Total operating expenses
 
$
173.92

 
$
35.77

 
>100 %

 
$
2,188

 
$
441

 
>100 %

China:
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating
 
$
9.92

 
$

 
100
 %
 
$
14

 
$
1

 
>100 %

Production and other taxes
 

 

 

 

 
1

 
(100
)%
Depreciation, depletion and amortization
 
36.15

 

 
100
 %
 
52

 

 
100
 %
General and administrative
 
1.03

 

 
100
 %
 
2

 

 
100
 %
Ceiling test impairment
 
50.11

 

 
100
 %
 
72

 

 
100
 %
Total operating expenses
 
$
97.21

 
$

 
100
 %
 
$
140

 
$
2

 
>100 %

Total Continuing Operations:
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating
 
$
5.08

 
$
6.03

 
(16
)%
 
$
71

 
$
74

 
(4
)%
Transportation and processing
 
3.77

 
4.09

 
(8
)%
 
52

 
51

 
5
 %
Production and other taxes
 
0.92

 
2.53

 
(64
)%
 
13

 
32

 
(59
)%
Depreciation, depletion and amortization
 
16.84

 
18.50

 
(9
)%
 
236

 
228

 
4
 %
General and administrative
 
4.68

 
3.97

 
18
 %
 
66

 
48

 
34
 %
Ceiling test and other impairments
 
134.75

 

 
100
 %
 
1,889

 

 
100
 %
Other
 
0.06

 
0.82

 
(93
)%
 
1

 
10

 
(91
)%
Total operating expenses
 
$
166.10

 
$
35.94

 
>100 %

 
$
2,328

 
$
443

 
>100 %


Domestic Operations. Excluding the effect of the $1.8 billion non-cash ceiling test impairment, our operating expenses for domestic operations for the three months ended September 30, 2015 decreased 17% over the same period of 2014 stated on a per BOE basis. The primary components within our operating expenses are as follows:

Lease operating expense decreased 23% on a per BOE basis primarily due to lower service costs and higher production volumes. Service costs per BOE declined in our Anadarko, Arkoma and Uinta basins period over period due to our increased focus on cost-reduction initiatives combined with downward service cost pressures in the industry due to a lower commodity price environment.

Transportation and processing increased 3% on a per BOE basis primarily due to the increased gas and NGL volumes in our SCOOP and STACK plays, which are subject to higher fees. Third quarter 2015 gas production from these two plays increased 38% compared to the third quarter of 2014, while NGL production increased 20%.

Production and other taxes decreased 59% per BOE consistent with lower total revenues. As a percent of total revenue, production and other taxes were 4.0% and 5.0% for the three months ended September 30, 2015 and 2014, respectively. The lower rate in 2015 was due to development in areas with lower production tax rates.

Depreciation, depletion and amortization decreased 21% on a per BOE basis primarily due to the impact of the non-cash ceiling test impairments in the first and second quarters of 2015. We expect a further decrease in the fourth quarter as a result of the impairment recorded effective September 30, 2015.


28



General and administrative (G&A) expenses increased 31% during the third quarter of 2015 compared to the third quarter of 2014 primarily due to a $13 million non-cash loss related to the abandonment of our Denver office lease and $5 million of other costs associated with our domestic restructuring. For the three months ended September 30, 2015, we capitalized $15 million ($1.20 per BOE) of direct internal costs as compared to $23 million ($1.89 per BOE) during the comparable quarter of 2014. This decrease in capitalization is consistent with the reduced exploration and development activities in the Uinta and Maverick basins during the third quarter of 2015.

During the third quarter of 2015, we recorded a non-cash ceiling test impairment of $1.8 billion due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 17% decrease in crude oil SEC pricing and a 10% decrease in natural gas SEC pricing since June 30, 2015. These commodity price decreases were partially offset by the impact of current service cost reductions on our cash flow estimates.

China Operations. For the three months ended September 30, 2015, total operating expenses increased $138 million compared to the third quarter of 2014 due to our Pearl development commencing production during the fourth quarter of 2014 and the ceiling test impairment during the third quarter of 2015. As a result of the different cost structures of our Pearl development and our Bohai Bay field, the 2015 results are not comparable with 2014. We expect our China operating costs in 2015 to continue to be higher than 2014 with the exception of production and other taxes. A new regulation was implemented by the Chinese government in early 2015 resulting in no special levy taxes on production with a contract price below $65 per barrel. As such, until our contract prices exceed $65 per barrel, we will continue to experience lower production and other taxes in China.

Nine months ended September 30, 2015 compared to September 30, 2014


29



The following table presents information about our operating expenses for our continuing operations:
 
 
Unit-of-Production
 
Total Amount
 
 
Nine Months Ended 
September 30,
 
Percentage
Increase (Decrease)
 
Nine Months Ended 
 September 30,
 
Percentage
Increase (Decrease)
 
 
2015
 
2014
 
 
2015
 
2014
 
 
 
(Per BOE)
 
 
 
(In millions)
 
 
Domestic:
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating
 
$
4.94

 
$
6.50

 
(24
)%
 
$
178

 
$
224

 
(20
)%
Transportation and processing
 
4.25

 
3.63

 
17
 %
 
153

 
125

 
23
 %
Production and other taxes
 
1.18

 
2.47

 
(52
)%
 
43

 
85

 
(50
)%
Depreciation, depletion and amortization
 
16.71

 
18.23

 
(8
)%
 
603

 
628

 
(4
)%
General and administrative
 
4.82

 
5.01

 
(4
)%
 
174

 
172

 
1
 %
Ceiling test and other impairments
 
114.39

 

 
100
 %
 
4,130

 

 
100
 %
Other
 
0.18

 
0.43

 
(58
)%
 
7

 
15

 
(57
)%
Total operating expenses
 
$
146.47

 
$
36.27

 
>100 %

 
$
5,288

 
$
1,249

 
>100 %

China:
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating
 
$
10.32

 
$
23.88

 
(57
)%
 
$
41

 
$
4

 
>100 %

Production and other taxes
 

 
22.47

 
(100
)%
 

 
5

 
(100
)%
Depreciation, depletion and amortization
 
29.74

 
23.89

 
24
 %
 
118

 
5

 
>100 %

General and administrative
 
1.37

 

 
100
 %
 
6

 

 
100
 %
Ceiling test impairment
 
17.99

 

 
100
 %
 
72

 

 
100
 %
Other
 
0.29

 

 
100
 %
 
1

 

 
100
 %
Total operating expenses
 
$
59.71

 
$
70.24

 
(15
)%
 
$
238

 
$
14

 
>100 %

Total Continuing Operations:
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating
 
$
5.46

 
$
6.60

 
(17
)%
 
$
219

 
$
228

 
(4
)%
Transportation and processing
 
3.83

 
3.60

 
6
 %
 
153

 
125

 
23
 %
Production and other taxes
 
1.08

 
2.58

 
(58
)%
 
43

 
90

 
(52
)%
Depreciation, depletion and amortization
 
18.00

 
18.27

 
(1
)%
 
721

 
633

 
14
 %
General and administrative
 
4.48

 
4.99

 
(10
)%
 
180

 
172

 
4
 %
Ceiling test and other impairments
 
104.83

 

 
100
 %
 
4,202

 

 
100
 %
Other
 
0.19

 
0.43

 
(56
)%
 
8

 
15

 
(49
)%
Total operating expenses
 
$
137.87

 
$
36.47

 
>100 %

 
$
5,526

 
$
1,263

 
>100 %


Domestic Operations. Excluding the effect of the $4.1 billion non-cash ceiling test and other impairments, our domestic operating expenses per BOE decreased 12% for the nine months ended September 30, 2015 compared to the same period of 2014. The primary components within our operating expenses are as follows:

Lease operating expense decreased 20% despite a 5% increase in total domestic production. On a per BOE basis, lease operating expense was 24% lower primarily due to lower service costs and higher production volumes. Period over period, service costs per BOE declined in our Anadarko, Arkoma, Maverick and Uinta basins due to our increased focus on cost-reduction initiatives as well as the current lower commodity price environment causing downward pressure on the service industry.

Transportation and processing increased 17% on a per BOE basis primarily due to the increased gas and NGL volumes in our SCOOP and STACK plays, which are subject to higher fees. For the first nine months of 2015, gas production from these two plays increased 43% compared to the same period of 2014, while NGL production increased 27%.

Production and other taxes decreased 52% per BOE consistent with lower total revenues. As a percent of total revenue, production and other taxes were 4.3% and 4.8% for the nine months ended September 30, 2015 and 2014, respectively. The lower rate in 2015 was due to development in areas with lower production tax rates.


30



Depreciation, depletion and amortization decreased 8% on a per BOE basis primarily due to the impact of the non-cash ceiling test impairments in the first and second quarters of 2015. We expect a further decrease in the fourth quarter as a result of the impairment recorded effective September 30, 2015.

General and administrative expenses were relatively flat during the first nine months of 2015 compared to the first nine months of 2014. Decreases in G&A expenses were primarily due to a decrease in employee-related expenses associated with our stock-based compensation programs of $26 million (net of amounts capitalized) during the nine months ended September 30, 2015, compared to the same period of 2014 primarily due to a decrease in the fair value of awards under our Stockholder Value Appreciation Program as the probability of achieving the next payout decreases as the program nears conclusion and our stock price remains below the next price threshold of $47.50 per share. These decreases were offset by a $13 million non-cash loss related to the abandonment of our Denver office lease and $21 million of costs associated with the reduction of our workforce and domestic restructuring. For the nine months ended September 30, 2015, we capitalized $57 million ($1.59 per BOE) of direct internal costs as compared to $109 million ($3.17 per BOE) during the comparable period of 2014. This decrease in capitalization is consistent with the decrease in costs associated with our stock-based liability award programs. Capitalization was further decreased by reduced exploration and development activities in the Uinta and Maverick basins during 2015.

During the first nine months of 2015, we recorded a non-cash ceiling test writedown of $4.1 billion due to a net decrease in the discounted value of our proved reserves. The decrease primarily resulted from a 38% decrease in crude oil SEC pricing and a 30% decrease in natural gas SEC pricing since December 31, 2014. These commodity price decreases were partially offset by the impact of current service cost reductions on our cash flow estimates. Additionally, during the first quarter of 2015, we recorded a $4 million rig impairment associated with our decision to indefinitely lay down both of our company-owned drilling rigs in the Uinta Basin.

China Operations. For the nine months ended September 30, 2015, total operating expenses increased $224 million compared to the nine months ended September 30, 2014, primarily due to our Pearl development commencing production during the fourth quarter of 2014 and the ceiling test impairment during the third quarter of 2015. As a result of the different cost structures of our Pearl development and our Bohai Bay field, the 2015 results are not comparable with 2014. We expect our China operating costs in 2015 to continue to be higher than 2014 with the exception of production and other taxes. A new regulation was implemented by the Chinese government in early 2015 resulting in no special levy taxes on production with a contract price below $65 per barrel. As such, until our contract prices exceed $65 per barrel, we will continue to experience lower production and other taxes in China.

Interest Expense. The following table presents information about interest expense. Interest expense associated with unproved oil and gas properties is capitalized into oil and gas properties.

 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In millions)
Gross interest expense:
 
 
 
 
 
 
 
 
Credit arrangements
 
$
2

 
$
2

 
$
8

 
$
7

Senior notes
 
35

 
26

 
98

 
76

Senior subordinated notes
 

 
23

 
21

 
70

Total gross interest expense
 
37

 
51

 
127

 
153

Capitalized interest
 
(8
)
 
(13
)
 
(23
)
 
(39
)
Net interest expense
 
$
29

 
$
38

 
$
104

 
$
114


Gross interest expense decreased for the three and nine months ended September 30, 2015, as compared to the three and nine months ended September 30, 2014, primarily due to the redemption of our 7⅛% Senior Subordinated Notes due 2018 in the fourth quarter of 2014 and the redemption of our 6⅞% Senior Subordinated Notes due 2020 in April 2015. This decrease was partially offset by the additional interest expense associated with our $700 million 5⅜% Senior Notes due 2026 issued in March of 2015.

Capitalized interest decreased for the three and nine months ended September 30, 2015, as compared to the three and nine months ended September 30, 2014, due to a reduction of oil and gas properties excluded from amortization coupled with a reduced capitalization rate due to a reduction of our average borrowing rate.


31



Commodity Derivative Income (Expense). The fluctuations in commodity derivative income (expense) from period to period are due to the volatility of oil and natural gas prices and changes in our outstanding derivative instruments during these periods. The amount of gain (loss) recognized in “Commodity derivative income (expense)” in our consolidated statement of operations related to our derivative financial instruments follows:
 
 
Three Months Ended 
 September 30,
 
Nine Months Ended 
 September 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(In millions)
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
 
 
Total realized gain (loss)
 
$
131

 
$
(20
)
 
$
375

 
$
(106
)
Total unrealized gain (loss)
 
(44
)
 
323

 
(145
)
 
139

Commodity derivative income (expense)
 
$
87

 
$
303

 
$
230

 
$
33


See Note 6, "Derivative Financial Instruments," and Note 9, "Fair Value Measurements," to our consolidated financial statements in Item 1 of this report.

Taxes. The effective tax rates for continuing operations for the three months ended September 30, 2015 and 2014 were 35.2% and 35.6%, respectively. The effective tax rates for continuing operations for the nine months ended September 30, 2015 and 2014 were 36.0% and 37.5%, respectively. Our effective tax rate for both periods was different than the federal statutory rate of 35% due to non-deductible expenses, state income taxes, the differences between international and U.S. federal statutory rates, and the impact of our China earnings being taxed both in the U.S. and China. This double taxation is a byproduct of our federal net operating loss (NOL) position that limits our ability to utilize related foreign tax credits (FTC) until our remaining NOLs are utilized. As a result of our earnings being taxed in both the U.S. and China, we expect our effective tax rate for future China earnings to be approximately 60%. We expect the U.S. portion of the rate to be a 35% tax rate, all of which is expected to be deferred.

For the nine months ended September 30, 2015, our effective tax rate was 36% for continuing operations as the majority of our consolidated net loss from continuing operations resulted from our domestic business, which was only taxable in the U.S.

Discontinued Operations

As a result of the sale of our Malaysia business in February 2014, we do not have current operations classified as discontinued operations, and the period-over-period change in discontinued operations is solely related to the sale. Historical Malaysia results of operations are not indicative of our future trends or results; therefore, we have not provided detailed information of prior year results of discontinued operations in the results of operations discussion. See Note 1, “Organization and Summary of Significant Accounting Policies,” and Note 17, “Discontinued Operations,” to our consolidated financial statements appearing earlier in this report for additional information regarding the sale of our Malaysia business.

Liquidity and Capital Resources

Beginning in the fourth quarter of 2014, crude oil prices declined significantly primarily due to global supply and demand imbalances. Given the future uncertainty regarding the timing and magnitude of an eventual recovery of crude oil prices, our planned capital spending for 2015 was reduced from 2014 levels to reduce deficit spending and preserve long-term liquidity. During the first nine months of 2015, as a part of our strategy to optimize long-term liquidity we:
issued 25.3 million additional shares of common stock through a public equity offering and received net proceeds of approximately $815 million in the first quarter of 2015, which were used primarily to repay all borrowings under our credit facility and money market lines of credit;
issued $700 million 5⅜% Senior Notes due 2026 through a public debt offering and received net proceeds of $691 million in March 2015. In April 2015, we used the proceeds to redeem the $700 million aggregate principal of our 6⅞% Senior Subordinated Notes due 2020; and
amended our credit facility in March 2015 to increase the capacity from $1.4 billion to $1.8 billion and extended the maturity date until June 2020.

We expect our 2015 budget will be financed through our cash flows from operations (inclusive of realized derivative contract gains and losses) and borrowings under our credit facility, as needed. Approximately 82% of our expected remaining 2015

32



domestic oil and gas sales (excluding NGLs) supporting the 2015 capital budget are partially protected against oil and gas price volatility using derivative contracts. For further discussion of our derivative activities, see Note 6, "Derivative Financial Instruments," to our consolidated financial statements appearing earlier in this report. Our 2015 capital budget, excluding estimated capitalized interest and direct internal costs of approximately $107 million, is expected to be approximately $1.4 billion, inclusive of additional lease acquisitions in the Anadarko Basin.

Actual capital expenditure levels may vary significantly due to many factors, including drilling results; oil, natural gas and NGL prices; industry conditions; the prices and availability of goods and services; and the extent to which properties are acquired or non-strategic assets are sold. We continue to screen for attractive acquisition opportunities; however, the timing and size of acquisitions are unpredictable. We believe we have the operational flexibility to react quickly with our capital expenditures to changes in circumstances or fluctuations in our cash flows.

We continuously monitor our liquidity needs, coordinate our capital expenditure program with our expected cash flows and projected debt-repayment schedule, and evaluate our available alternative sources of liquidity, including accessing debt and equity capital markets in light of current and expected economic conditions. We believe that our liquidity position and ability to generate cash flows from our operations will be adequate to fund 2015 and 2016 operations and to meet our other obligations.

Credit Arrangements and Other Financing Activities. In March 2015, we entered into the fourth amendment to our Credit Agreement. This amendment extended the maturity date of the revolving credit facility from June 2018 to June 2020 and increased the borrowing capacity from $1.4 billion to $1.8 billion. We incurred $7 million of deferred financing costs related to this amendment, which will be amortized through June 2020. We also maintain money market lines of credit of $195 million. At September 30, 2015, we had $48 million in borrowings under our money market lines of credit, no borrowings outstanding under our revolving credit facility and no letters of credit outstanding under our credit facility.

As of October 30, 2015, we had no outstanding borrowings and available borrowing capacity of $1.8 billion under our revolving credit facility. As of October 30, 2015, we had $74 million outstanding under our money market lines of credit and available capacity of $121 million.

In April 2015, we completed the redemption of our $700 million aggregate principal of 6⅞% Senior Subordinated Notes due 2020. The transaction included a premium payment of approximately $24 million. We have no scheduled maturities of senior notes until 2022. For a more detailed description of the terms of our credit arrangements and senior notes, please see Note 10, “Debt,” to our consolidated financial statements appearing earlier in this report.

Working Capital. Our working capital balance fluctuates as a result of the timing and amount of borrowings or repayments under our credit arrangements, changes in the fair value of our outstanding commodity derivative instruments as well as the timing of receiving reimbursement of amounts paid by us for the benefit of joint venture partners. Without the effects of commodity derivative instruments, we typically have a working capital deficit or a relatively small amount of positive working capital.

At September 30, 2015, we had negative working capital of $55 million compared to negative working capital of $161 million at December 31, 2014. The change in working capital is primarily due to reduced capital spending and the impact of lower revenues on accounts receivable and related royalty and severance taxes payable. The remaining change is due to the timing of the collection of receivables; changes in the fair value of our derivative positions; the timing of crude oil liftings in our China operations; drilling activities; payments made by us to vendors and other operators; and the timing and amount of advances received from our joint operations.

Cash Flows from Operations. Our primary source of capital and liquidity is cash flows from operations, which are primarily affected by the sale of our oil, natural gas and NGLs, as well as commodity prices, net of the effects of derivative contract settlements and changes in working capital.

Our net cash flows from operations were $889 million for the nine months ended September 30, 2015, which decreased compared to net cash flows from operations of $1.1 billion (includes $18 million of cash flows from discontinued operations) for the same period in 2014. We had no cash flows from discontinued operations for the nine months ended September 30, 2015. The primary driver of lower operating cash flows was lower revenues as a result of lower commodity prices.

Cash Flows from Investing Activities. Net cash used in investing activities for the nine months ended September 30, 2015 was $1.3 billion compared to $114 million for the same period in 2014 due to proceeds of $809 million received from the sale of our Malaysia business in 2014. Cash used for capital expenditures in 2015 was approximately $241 million lower due to our planned reductions in capital spending as compared to the first nine months of 2014.


33



Cash Flows from Financing Activities. Net cash provided by financing activities for the nine months ended September 30, 2015 was $389 million compared to net cash used in financing activities of $655 million (included the repayment of $649 million of outstanding borrowings under our revolving credit facility using the proceeds received from the sale of our Malaysia business and Granite Wash assets) for the same period in 2014. During the nine months ended September 30, 2015, we:
issued 25.3 million additional shares of common stock through a public equity offering and received net proceeds of approximately $815 million, which were used primarily to repay all borrowings under our credit facility and money market lines of credit; and
issued $700 million 5⅜% Senior Notes due 2026 through a public debt offering and received net proceeds of $691 million in March 2015. In April 2015, we used the proceeds to redeem our $700 million aggregate principal of our 6⅞% Senior Subordinated Notes due 2020.

Capital Expenditures. Our capital investments for continuing operations for the first nine months of 2015 decreased 21% as compared to the same period of 2014. The table below summarizes our capital investments.
 
Nine Months Ended 
 September 30,
 
2015
 
2014
 
(In millions)
Continuing operations:
 
 
 
     Exploration, exploitation and development (exclusive of leasehold)
$
873

 
$
1,320

     Acquisitions
125

 
21

     Leasing proved and unproved property (leasehold)
137

 
75

     Pipeline spending
3

 
7

        Total continuing operations
1,138

 
1,423

Discontinued operations

 
12

         Total
$
1,138

 
$
1,435


Restructuring

In April 2015, we announced plans to restructure our organization primarily in response to the current commodity price environment, by combining our onshore Gulf Coast and Rocky Mountain business units into our newly-created Western Region which is managed from The Woodlands, Texas. These changes are expected to result in better utilization of our resources and improve cost efficiencies in operations. In September 2015 we abandoned six of seven floors in our Denver, Colorado office and began managing the new region from our existing Texas offices. We expect to abandon our North Houston (Greenspoint area) office on or before April 2016.

Restructuring costs include severance and related benefit costs, costs associated with abandoned office space, employee relocation costs and other associated costs. Restructuring costs are expected to total $32 million and will be funded through our cash flows from operations. We expect substantially all one-time restructuring-related costs to be incurred by December 31, 2015 and do not expect these costs to materially affect our cash flows or results of operations. See Note 15, "Restructuring Costs," to our consolidated financial statements in Item 1 of this report for additional details regarding our restructuring activities.

Ceiling Test Writedown

At September 30, 2015, the values of our U.S. and China cost center ceilings were calculated based upon SEC pricing of $3.06 per MMBtu for natural gas and $59.09 per barrel for oil. Using these prices, our ceiling for the U.S. did not exceed the net capitalized costs of oil and gas properties resulting in a non-cash ceiling test writedown of approximately $1.8 billion ($1.2 billion after tax). Our ceiling for China did not exceed the net capitalized costs of oil and gas properties by approximately $72 million ($29 million after tax), and as such, a ceiling test writedown was required. Holding all other factors constant, it is likely that we will experience a ceiling test writedown in both the U.S. and China in the fourth quarter of 2015. It is difficult to predict with reasonable certainty the amount of expected future impairments given the many factors impacting the ceiling test calculation including, but not limited to, future pricing, operating and development costs, upward or downward reserve revisions, reserve adds, and tax attributes. Subject to these numerous factors and inherent limitations, we believe that impairments in the fourth quarter of 2015 could exceed $1 billion. Once recorded, a ceiling test writedown is not reversible at a later date even if oil and gas prices increase. Further declines in SEC pricing could result in additional ceiling test writedowns in subsequent quarters.

34



Contractual Obligations

We have various contractual obligations in the normal course of our operations. For further information, please see “Management's Discussion and Analysis of Financial Condition and Results of Operations - Contractual Obligations” in our Annual Report on Form 10-K for the year ended December 31, 2014. There have been no material changes to the disclosure since year-end 2014, except that in March 2015, we issued $700 million of 5⅜% Senior Notes due 2026 and in April 2015, we redeemed our 6⅞% Senior Subordinated Notes due 2020. The 2026 Senior Notes were issued at par to yield 5⅜%. The semi-annual interest payments of approximately $19 million associated with these notes will be made in January and July of each year.

Commitments under Joint Operating Agreements. Most of our properties are operated through joint ventures under joint operating or similar agreements. Typically, the operator under a joint operating agreement enters into contracts, such as drilling contracts, for the benefit of all joint venture partners. Through the joint operating agreement, the non-operators reimburse, and in some cases advance, the funds necessary to meet the contractual obligations entered into by the operator. These obligations are typically shared on a “working interest” basis. The joint operating agreement provides remedies to the operator if a non-operator does not satisfy its share of the contractual obligations. Occasionally, the operator is permitted by the joint operating agreement to enter into lease obligations and other contractual commitments that are then passed on to the non-operating joint interest owners as lease operating expenses, frequently without any identification as to the long-term nature of any commitments underlying such expenses.

Oil and Gas Derivatives
     
We use derivative contracts to manage the variability in cash flows caused by commodity price fluctuations associated with our anticipated oil and gas production for the next 24 to 36 months. As of September 30, 2015, we had no outstanding derivative contracts related to our NGL production. We do not use derivative instruments for trading purposes.

For a further discussion of our derivative activities, see "Oil, Natural Gas and NGL Prices" in Item 3 of this report. See the discussion and tables in Note 6, “Derivative Financial Instruments,” and Note 9, “Fair Value Measurements,” to our consolidated financial statements appearing earlier in this report for additional information regarding the accounting applicable to our oil and gas derivative contracts, a listing of open contracts and the estimated fair market value of those positions as of September 30, 2015.

Between October 1, 2015 and October 30, 2015, we entered into additional crude oil derivative contracts. A listing of all our crude oil derivative contracts as of October 30, 2015 are as follows:


35



 
 
 
 
NYMEX Contract Price Per Bbl
 
 
 
 
 
 
 
 
 
 
Collars
Period and Type of Instrument
 
Volume in MBbls
 
Swaps
(Weighted Average)
 
Purchased Calls (Weighted Average)
 
Sold Puts
(Weighted Average)
 
Floors
(Weighted Average)
 
Ceilings
(Weighted Average)
 
 
 
 
 
 
 
 
 
 
 
 
 
2015:
 
 

 
 

 
 
 
 

 
 

 
 

  Fixed-price swaps
 
92

 
$
90.00

 
$

 
$

 
$

 
$

  Fixed-price swaps with sold puts:
 
4,278

 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
90.08

 

 

 

 

Sold puts
 
 
 

 

 
71.12

 

 

  Collars with sold puts:
 
184

 
 
 
 
 
 
 
 
 
 
Collars
 
 
 

 

 

 
90.00

 
104.00

Sold puts
 
 
 

 

 
75.00

 

 

2016:
 
 

 
 

 
 
 
 

 
 

 
 

  Fixed-price swaps with sold puts:
 
10,060

 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
89.98

 

 

 

 

Sold puts
 
 
 

 

 
74.14

 

 

  Collars with sold puts:
 
6,220

 
 
 
 
 
 
 
 
 
 
Collars
 
 
 

 

 

 
90.00

 
96.15

Sold puts
 
 
 

 

 
75.00

 

 

  Purchased calls
 
6,242

 

 
72.18

 

 

 

2017:
 
 
 
 
 
 
 
 
 
 
 
 
  Fixed-price swaps with sold puts:
 
4,468

 
 
 
 
 
 
 
 
 
 
Fixed-price swaps
 
 
 
88.37

 

 

 

 

Sold puts
 
 
 

 

 
73.28

 

 

  Collars with sold puts:
 
2,080

 
 
 
 
 
 
 
 
 
 
Collars
 
 
 

 

 

 
90.00

 
95.59

Sold puts
 
 
 

 

 
75.00

 

 

  Purchased calls
 
5,647

 

 
73.71

 

 

 


At October 30, 2015, the deferred premiums associated with our purchased calls totaled $22 million.

Accounting for Derivative Activities. As our derivative contracts are not designated for hedge accounting, they are accounted for on a mark-to-market basis. We have in the past experienced, and are likely in the future to experience non-cash volatility in our reported earnings during periods of commodity price volatility. As of September 30, 2015, we had net derivative assets of $468 million, of which 63%, based on total contracted volumes, was measured based upon a modified Black-Scholes valuation model and, as such, were classified as a Level 3 fair value measurement. The model considers various inputs including the following:

forward prices for commodities;
time value;
volatility factors;
counterparty credit risk; and
current market and contractual prices for the underlying instruments.

As a result, the value of these contracts at their respective settlement dates could be significantly different than their fair value as of September 30, 2015. We use credit default swap values to assess the impact of non-performance risk when evaluating both our liabilities to and receivables from counterparties. See “— Critical Accounting Policies and Estimates — Commodity Derivative

36



Activities” in Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2014 and Note 6, “Derivative Financial Instruments,” and Note 9, “Fair Value Measurements,” to our consolidated financial statements appearing earlier in this report for additional discussion of the accounting applicable to our oil and gas derivative contracts.

New Accounting Requirements

In April 2015, the Financial Accounting Standards Board (FASB) issued guidance regarding the presentation of debt issuance costs in the financial statements and requires that debt issuance costs be presented as a reduction of the carrying value of the financial liability and not as a separate asset. The guidance requires retrospective adjustment to the balance sheet presentation and disclosures applicable for a change in an accounting principle. The guidance is effective for interim and annual periods beginning after December 15, 2015. We expect to adopt this guidance in our 2015 annual report.

In May 2014, the FASB issued guidance regarding the accounting for revenue from contracts with customers. The guidance may be applied retrospectively or using a modified retrospective approach to adjust retained earnings (deficit). In July 2015, the FASB approved a deferral of the effective date by one year. As a result, the guidance is effective for interim and annual periods beginning on or after December 15, 2017. We are currently evaluating the impact of this guidance on our financial statements.

Forward-Looking Information

This report 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 (Exchange Act). All statements, other than statements of historical facts included in this report, are forward-looking, including information relating to anticipated future events or results, such as planned capital expenditures, the availability and sources of capital resources to fund capital expenditures and other plans and objectives for future operations. Forward-looking statements are typically identified by use of terms such as “may,” “believe,” “expect,” “anticipate,” “intend,” “estimate,” “project,” “target,” “goal,” “plan,” “should,” “will,” “predict,” “potential” and similar expressions that convey the uncertainty of future events or outcomes. Although we believe that the expectations reflected in such forward-looking statements are reasonable, this information is based upon assumptions and anticipated results that are subject to numerous uncertainties and risks. Actual results may vary significantly from those anticipated due to many factors, including:

oil, natural gas and natural gas liquids prices;
the availability and volatility of the securities, capital or credit markets and the cost of capital to fund our operations and business strategies;
accuracy and fluctuations in our reserves estimates due to sustained low commodity prices;
ability to develop existing reserves or acquire new reserves;
the timing and our success in discovering, producing and estimating reserves;
sustained decline in commodity prices resulting in writedowns of assets;
operating hazards inherent in the exploration for and production of oil and natural gas;
general economic, financial, industry or business trends or conditions;
the impact of, and changes in, legislation, law and governmental regulations, including those related to hydraulic fracturing, climate change, seismicity and over-the-counter derivatives;
land, legal, regulatory, and ownership complexities inherent in the U.S. oil and gas industry;
the impact of regulatory approvals;
the availability and volatility of the securities, capital or credit markets and the cost of capital to fund our operations and business strategies;
the ability and willingness of current or potential lenders, derivative contract counterparties, customers and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us;

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the prices and quantities of commodities reflected in our commodity derivative arrangements as compared to the actual prices or quantities of commodities we produce or use;
the volatility and liquidity in the commodity futures and commodity and financial derivatives markets;
drilling risks and results;
the prices and availability of goods and services;
the cost and availability of drilling rigs and other support services;
global events that may impact our domestic and international operating contracts, markets and prices;
labor conditions;
weather conditions;
environmental liabilities that are not covered by an effective indemnity or insurance;
competitive conditions;
terrorism or civil or political unrest in a region or country;
our ability to monetize non-strategic assets, pay debt and the impact of changes in our investment ratings;
electronic, cyber or physical security breaches;
changes in tax rates;
inflation rates;
financial counterparty risk;
the effect of worldwide energy conservation measures;
the price and availability of, and demand for, competing energy sources;
the availability (or lack thereof) of acquisition, disposition or combination opportunities; and
the other factors affecting our business described under the caption “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates” included in our 2014 Annual Report on Form 10-K.

Should one or more of the risks described above occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.

All forward-looking statements in this report, as well as all other written and oral forward-looking statements attributable to us or persons acting on our behalf, are expressly qualified in their entirety by the cautionary statements contained in this section and elsewhere in this report. These factors are not necessarily all of the important factors that could affect us. Use caution and common sense when considering these forward-looking statements. Unless securities laws require us to do so, we do not undertake any obligation to publicly correct or update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.

Commonly Used Oil and Gas Terms

Below are explanations of some commonly used terms in the oil and gas business and in this report.

Barrel or Bbl.    One stock tank barrel or 42 U.S. gallons liquid volume.

Basis risk.    The risk associated with the sales point price for oil or gas production varying from the reference (or settlement) price for a particular derivative transaction.


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Bcf.    Billion cubic feet.

BOE.    One barrel of oil equivalent determined using the ratio of six Mcf of natural gas to one barrel of crude oil or condensate or 42 gallons for NGLs.

Btu.    British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Development well.    A well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive.

Exploitation activities.    An exploration well drilled to find and produce probable reserves. Exploitation wells typically have less risk and less reserve potential and typically may be drilled at a lower cost than other exploration wells. Most of the exploitation wells we drill are located in the Mid-Continent or the Monument Butte field. For internal reporting and budgeting purposes, we combine exploitation and development activities.

Exploration well.    An exploration well is a well drilled to find a new field or new reservoir. Generally, an exploratory well is any well that is not a development well, an extension well, a service well or a stratigraphic test well. For internal reporting and budgeting purposes, we exclude exploitation activities from exploration activities.

Field.    An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

Liquids. Crude oil and NGLs.

MBbls.    One thousand barrels of crude oil or other liquid hydrocarbons.

MBOE.    One thousand barrels of oil equivalent.

Mcf.    One thousand cubic feet of natural gas.

MMBtu.    One million Btus.

MMBOE.    One million barrels of oil equivalent.

MMMBtu.    One billion Btus.

NGL.    Natural gas liquid. Hydrocarbons which can be extracted from wet natural gas and become liquid under various combinations of increasing pressure and lower temperature. NGLs consist primarily of ethane, propane, butane and natural gasolines.

NYMEX.    The New York Mercantile Exchange.

Probable reserves.    Those additional reserves that are less certain to be recovered than proved reserves but that, together with proved reserves, are as likely as not to be recovered. The SEC provides a complete definition of probable reserves in Rule 4-10(a)(18) of Regulation S-X.

Proved reserves.    Those quantities of oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations — prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

SCOOP.    South-Central Oklahoma Oil Province. A field in the Anadarko Basin of Oklahoma in which we operate.

SEC pricing.    The unweighted average first-day-of-the-month NYMEX commodity prices for crude oil or natural gas for the prior 12 months, adjusted for market differentials. The SEC provides a complete definition of prices in “Modernization of Oil and Gas Reporting” (Final Rule).

39



STACK.    Sooner Trend Anadarko Canadian Kingfisher. A play in the Anadarko Basin of Oklahoma in which we operate.

Working interest.    The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production and requires the owner to pay a share of the costs of drilling and production operations.

WTI.    West Texas Intermediate, a grade of crude oil.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to market risk from changes in oil, natural gas and NGL prices, interest rates and foreign currency exchange rates as discussed below.

Oil, Natural Gas and NGL Prices
     
Our decision on the quantity and price at which we choose to enter into derivative contracts is based in part on our view of current and future market conditions. While the use of derivative contracts can limit or reduce the downside risk of adverse price movements, their use also may limit future benefits from favorable price movements. In addition, the use of derivative contracts may involve basis risk. All of our derivative transactions have been carried out in the over-the-counter market. The use of derivative contracts also involves the risk that the counterparties, which generally are financial institutions, will be unable to meet the financial terms of such transactions. Our derivative contracts are with multiple counterparties to minimize our exposure to any individual counterparty. At September 30, 2015, ten of our 17 counterparties accounted for approximately 85% of our contracted volumes, with the largest counterparty accounting for approximately 15%. Of our remaining expected 2015 crude oil production, 86% is protected against price volatility through the use of derivative contracts. Substantially all of our crude oil collars and swaps include short puts. Short puts effectively limit our downward price protection below the weighted average of our short puts of $73.79 per barrel. If the market price remains below $73.79 per barrel, we receive the market price for our associated production plus the difference between our short puts and the associated floors or fixed-price swaps, which average $15.94 per barrel. We have effectively locked in this spread (less the call premium) for a portion of the volume through the calls purchased in 2015. We do not have any natural gas derivative contracts that include short puts. For a further discussion of our derivative activities, see the information under the caption “Oil and Gas Derivatives” in Item 2 appearing earlier in this report and the discussion and tables in Note 6, “Derivative Financial Instruments,” to our consolidated financial statements appearing earlier in this report. For further discussion of the types of derivative positions, refer to Note 5, “Derivative Financial Instruments” within Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2014.

Interest Rates

We consider our interest rate exposure to be minimal because 98% of our obligations were at fixed rates as of September 30, 2015. A 10% increase in LIBOR would not materially impact our interest cost on debt outstanding as of September 30, 2015, but would affect the fair value of our outstanding debt, as well as interest costs associated with future debt issuances or borrowings under our revolving credit facility.

Foreign Currency Exchange Rates
     
The functional currency for our foreign operations is the U.S. dollar. To the extent that business transactions in these countries are not denominated in the respective country’s functional currency, we are exposed to foreign currency exchange risk. We consider our current risk exposure to exchange rate movements, based on net cash flows, to be immaterial. We did not have any open derivative contracts related to foreign currencies at September 30, 2015.

Item 4. Controls and Procedures

Disclosure Controls and Procedures
     
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures (as defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Our disclosure controls and procedures are designed to ensure that information required to be disclosed by us in the reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC, and to ensure that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow

40



timely decisions regarding required disclosure. Based upon our evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2015.

Changes in Internal Control over Financial Reporting
     
As of the end of the period covered by this report, we carried out an evaluation, under the supervision and with the participation of our Chief Executive Officer and our Chief Financial Officer, of our internal control over financial reporting to determine whether any changes occurred during the third quarter of 2015 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. Based upon our evaluation, there were no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II

Item 1. Legal Proceedings

We have been named as a defendant in a number of lawsuits and are involved in various other disputes, all arising in the ordinary course of our business, such as (a) claims from royalty owners for disputed royalty payments, (b) commercial disputes, (c) personal injury claims and (d) property damage claims. Although the outcome of these lawsuits and disputes cannot be predicted with certainty, we do not expect these matters to have a material adverse effect on our financial position, cash flows or results of operations.

In addition, from time to time we receive notices of violation from governmental and regulatory authorities in areas in which we operate related to alleged violations of environmental statutes or rules and regulations promulgated thereunder. We cannot predict with certainty whether these notices of violation will result in fines or penalties, or if such fines or penalties are imposed, that they would individually or in the aggregate exceed $100,000. If any fines or penalties are in fact imposed that are greater than $100,000, or we expect to be greater than $100,000, then we will disclose such fact in our subsequent filings.


Item 1A. Risk Factors

The following risk factor updates, and should be considered in addition to, the risk factors previously reported in our Annual Report on Form 10-K for the year ended December 31, 2014. Other than the risk factor discussed below, there have been no material changes with respect to the risk factors previously reported in our Annual Report on Form 10-K.

Legislation or regulatory initiatives intended to address seismic activity in Oklahoma could increase our costs of compliance or lead to operational delays, which could have a material adverse effect on our business, results of operations or financial condition. We conduct oil and natural gas exploration, development and drilling activities in Oklahoma and elsewhere. In recent years, Oklahoma has experienced a significant increase in seismic activity. This increase has led the Oklahoma Corporation Commission (OCC), and other state and federal agencies, to evaluate and monitor the correlation between seismicity and oil and natural gas exploration and production activities, with the primary concern focused on injection wells used for wastewater disposal. In September 2014, the OCC adopted amended monitoring and reporting rules for disposal wells in certain seismically-active areas. The Oklahoma Geological Survey (“OGS”) then issued in April 2015 a document entitled “Statement of Oklahoma Seismicity,” in which the agency states “[t]he OGS considers it very likely that the majority of recent earthquakes, particularly those in central and north-central Oklahoma, are triggered by the injection of produced water in disposal wells.” Thereafter, in July 2015, the OCC issued an additional directive regarding its regulations targeting disposal operations in specific counties in Oklahoma. These developments may result in additional levels of regulation, or increased complexity and costs with respect to existing regulations, that could lead to operational delays or increased operating and compliance costs, which could have a material adverse effect on our business, results of operations or financial condition.


Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

The following table sets forth certain information with respect to repurchases of our common stock during the three months ended September 30, 2015.

41


Period
 
Total Number of Shares Purchased(1)
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased under the Plans or Programs
July 1 — July 31, 2015
 
11,495

 
$
35.52

 
 
August 1 — August 31, 2015
 
178,856

 
35.76

 
 
September 1 — September 30, 2015
 
15,017

 
32.65

 
 
Total
 
205,368

 
$
35.52

 
 
_______
(1)
All of the shares repurchased were surrendered by employees to pay tax withholding upon the vesting of restricted stock awards and restricted stock units. These repurchases were not part of a publicly announced program to repurchase shares of our common stock.


42



Item 6. Exhibits
Exhibit Number
 
Description
3.1
 
Fourth Amended and Restated Certificate of Incorporation of Newfield Exploration Company dated July 22, 2015 (incorporated by reference to Exhibit 3.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 27, 2015 (File No. 1-12534))
 
 
 
3.2
 
Amended and Restated Bylaws of Newfield (incorporated by reference to Exhibit 3.2 to Newfield’s Current Report on Form 8-K filed with the SEC on July 25, 2013 (File No. 1-12534))
 
 
 
*31.1
 
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
*31.2
 
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
*32.1
 
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
*32.2
 
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
*101.INS
 
XBRL Instance Document
 
 
 
*101.SCH
 
XBRL Schema Document
 
 
 
*101.CAL
 
XBRL Calculation Linkbase Document
 
 
 
*101.LAB
 
XBRL Label Linkbase Document
 
 
 
*101.PRE
 
XBRL Presentation Linkbase Document
 
 
 
*101.DEF
 
XBRL Definition Linkbase Document
_______
*      Filed or furnished herewith.

43



SIGNATURE

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 thereunto duly authorized.

 
NEWFIELD EXPLORATION COMPANY
 
 
 
Date: November 4, 2015
By:
/s/ LAWRENCE S. MASSARO
 
 
Lawrence S. Massaro
 
 
Executive Vice President and Chief Financial Officer
(Principal Financial Officer)

44


Exhibit Index
Exhibit Number
 
Description
3.1
 
Fourth Amended and Restated Certificate of Incorporation of Newfield Exploration Company dated July 22, 2015 (incorporated by reference to Exhibit 3.1 to Newfield’s Current Report on Form 8-K filed with the SEC on July 27, 2015 (File No. 1-12534))
 
 
 
3.2
 
Amended and Restated Bylaws of Newfield (incorporated by reference to Exhibit 3.2 to Newfield’s Current Report on Form 8-K filed with the SEC on July 25, 2013 (File No. 1-12534))
 
 
 
*31.1
 
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
*31.2
 
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 15 U.S.C. Section 7241, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
 
 
 
*32.1
 
Certification of Chief Executive Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
*32.2
 
Certification of Chief Financial Officer of Newfield Exploration Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
 
 
 
*101.INS
 
XBRL Instance Document
 
 
 
*101.SCH
 
XBRL Schema Document
 
 
 
*101.CAL
 
XBRL Calculation Linkbase Document
 
 
 
*101.LAB
 
XBRL Label Linkbase Document
 
 
 
*101.PRE
 
XBRL Presentation Linkbase Document
 
 
 
*101.DEF
 
XBRL Definition Linkbase Document
_______
*      Filed or furnished herewith.

45