e10vq
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
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þ |
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QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934 |
For the Quarterly Period Ended March 31, 2008
OR
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o |
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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)
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Delaware
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72-1133047 |
(State or other jurisdiction of
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(I.R.S. Employer |
incorporation or organization)
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Identification Number) |
363 North Sam Houston Parkway East
Suite 2020
Houston, Texas 77060
(Address and Zip Code of principal executive offices)
(281) 847-6000
(Registrants 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 o
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):
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Large accelerated filer þ
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Accelerated filer o
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Non-accelerated filer o
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Smaller reporting company o |
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(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 o No þ
As of April 23, 2008, there were 131,748,494 shares of the registrants common stock, par
value $0.01 per share, outstanding.
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED BALANCE SHEET
(In millions, except share data)
(Unaudited)
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March 31, |
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December 31, |
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2008 |
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2007 |
|
ASSETS |
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|
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Current assets: |
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|
|
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Cash and cash equivalents |
|
$ |
80 |
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|
$ |
250 |
|
Short-term investments |
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77 |
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120 |
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Accounts receivable |
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416 |
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332 |
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Inventories |
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73 |
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|
82 |
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Derivative assets |
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41 |
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72 |
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Deferred taxes |
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131 |
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|
35 |
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Other current assets |
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39 |
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36 |
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Total current assets |
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857 |
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927 |
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Oil and gas properties (full cost method, of which $1,362 at March 31, 2008
and $1,189 at December 31, 2007 were excluded from amortization) |
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10,307 |
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9,791 |
|
Lessaccumulated depreciation, depletion and amortization |
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(4,017 |
) |
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(3,868 |
) |
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6,290 |
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|
5,923 |
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Furniture, fixtures and equipment, net |
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35 |
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35 |
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Derivative assets |
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24 |
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17 |
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Other assets |
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21 |
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22 |
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Goodwill |
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62 |
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62 |
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Total assets |
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$ |
7,289 |
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$ |
6,986 |
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LIABILITIES AND STOCKHOLDERS EQUITY |
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Current liabilities: |
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Accounts payable |
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$ |
62 |
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$ |
52 |
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Accrued liabilities |
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683 |
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671 |
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Advances from joint owners |
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70 |
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44 |
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Asset retirement obligation |
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6 |
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6 |
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Derivative liabilities |
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395 |
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156 |
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Total current liabilities |
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1,216 |
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929 |
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Other liabilities |
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34 |
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18 |
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Derivative liabilities |
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254 |
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248 |
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Long-term debt |
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1,052 |
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1,050 |
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Asset retirement obligation |
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59 |
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56 |
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Deferred taxes |
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1,137 |
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1,104 |
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Total long-term liabilities |
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2,536 |
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2,476 |
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Commitments and contingencies (Note 5) |
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Stockholders equity: |
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Preferred stock ($0.01 par value; 5,000,000 shares authorized; no shares issued) |
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Common stock ($0.01 par value; 200,000,000 shares authorized at March 31, 2008
and December 31, 2007; 133,621,288 and 133,232,197 shares issued
at March 31, 2008 and December 31, 2007, respectively) |
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|
1 |
|
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|
1 |
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Additional paid-in capital |
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|
1,298 |
|
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1,278 |
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Treasury stock (at cost; 1,898,917 and 1,896,286 shares at March 31, 2008 and
December 31, 2007, respectively) |
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(32 |
) |
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|
(32 |
) |
Accumulated other comprehensive income (loss): |
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Minimum pension liability |
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(3 |
) |
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|
(3 |
) |
Retained earnings |
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2,273 |
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|
2,337 |
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Total stockholders equity |
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3,537 |
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3,581 |
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Total liabilities and stockholders equity |
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$ |
7,289 |
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$ |
6,986 |
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The accompanying notes to consolidated financial statements are an integral part of this statement.
1
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF INCOME
(In millions, except per share data)
(Unaudited)
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Three Months Ended |
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March 31, |
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2008 |
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2007 |
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|
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Oil and gas revenues |
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$ |
515 |
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$ |
440 |
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Operating expenses: |
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Lease operating |
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59 |
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111 |
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Production and other taxes |
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51 |
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17 |
|
Depreciation, depletion and amortization |
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157 |
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|
180 |
|
General and administrative |
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32 |
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|
39 |
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Total operating expenses |
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299 |
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347 |
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Income from operations |
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216 |
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93 |
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Other income (expenses): |
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Interest expense |
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(19 |
) |
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(23 |
) |
Capitalized interest |
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13 |
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|
11 |
|
Commodity derivative expense |
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(321 |
) |
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|
(158 |
) |
Other |
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3 |
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|
1 |
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(324 |
) |
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(169 |
) |
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Loss from continuing operations before income taxes |
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(108 |
) |
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|
(76 |
) |
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Income tax provision (benefit): |
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Current |
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19 |
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|
9 |
|
Deferred |
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(63 |
) |
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|
(38 |
) |
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|
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|
(44 |
) |
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(29 |
) |
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Loss from continuing operations |
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|
(64 |
) |
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|
(47 |
) |
Loss from discontinued operations, net of tax |
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|
|
|
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|
(49 |
) |
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Net loss |
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$ |
(64 |
) |
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$ |
(96 |
) |
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Earnings (loss) per share: |
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Basic |
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Loss from continuing operations |
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$ |
(0.50 |
) |
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$ |
(0.37 |
) |
Loss from discontinued operations |
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|
|
|
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|
(0.38 |
) |
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|
|
|
|
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|
Net loss |
|
$ |
(0.50 |
) |
|
$ |
(0.75 |
) |
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Diluted |
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Loss from continuing operations |
|
$ |
(0.50 |
) |
|
$ |
(0.37 |
) |
Loss from discontinued operations |
|
|
|
|
|
|
(0.38 |
) |
|
|
|
|
|
|
|
Net loss |
|
$ |
(0.50 |
) |
|
$ |
(0.75 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding for basic
earnings (loss) per share |
|
|
129 |
|
|
|
127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of shares outstanding for diluted
earnings (loss) per share |
|
|
129 |
|
|
|
127 |
|
|
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|
The accompanying notes to consolidated financial statements are an integral part of this statement.
2
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF CASH FLOWS
(In millions)
(Unaudited)
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Three Months Ended |
|
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March 31, |
|
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2008 |
|
|
2007 |
|
Cash flows from operating activities: |
|
|
|
|
|
|
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|
Net loss |
|
$ |
(64 |
) |
|
$ |
(96 |
) |
|
|
|
|
|
|
|
|
|
Adjustments to reconcile net loss to net cash provided by
operating activities: |
|
|
|
|
|
|
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|
Loss from discontinued operations, net of tax |
|
|
|
|
|
|
49 |
|
Depreciation, depletion and amortization |
|
|
157 |
|
|
|
180 |
|
Stock-based compensation |
|
|
5 |
|
|
|
4 |
|
Commodity
derivative expense |
|
|
321 |
|
|
|
158 |
|
Cash
(payments) receipts on derivative settlements |
|
|
(40 |
) |
|
|
91 |
|
Deferred taxes |
|
|
(63 |
) |
|
|
(38 |
) |
|
|
|
|
|
|
|
|
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
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|
Decrease (increase) in accounts receivable |
|
|
(91 |
) |
|
|
25 |
|
Decrease (increase) in inventories |
|
|
5 |
|
|
|
(14 |
) |
Decrease (increase) in other current assets |
|
|
(3 |
) |
|
|
22 |
|
Increase in commodity derivative assets |
|
|
(8 |
) |
|
|
(1 |
) |
Increase (decrease) in accounts payable and accrued liabilities |
|
|
13 |
|
|
|
(31 |
) |
Increase (decrease) in advances from joint owners |
|
|
26 |
|
|
|
(30 |
) |
Increase in other liabilities |
|
|
14 |
|
|
|
20 |
|
|
|
|
|
|
|
|
Net cash provided by continuing activities |
|
|
272 |
|
|
|
339 |
|
Net cash used in discontinued activities |
|
|
|
|
|
|
(4 |
) |
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
|
272 |
|
|
|
335 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from investing activities: |
|
|
|
|
|
|
|
|
Additions to oil and gas properties |
|
|
(501 |
) |
|
|
(502 |
) |
Proceeds from sale of oil and gas properties |
|
|
2 |
|
|
|
1 |
|
Additions to furniture, fixtures and equipment |
|
|
(2 |
) |
|
|
(5 |
) |
Purchases of short-term investments |
|
|
(22 |
) |
|
|
|
|
Redemption of short-term investments |
|
|
68 |
|
|
|
24 |
|
|
|
|
|
|
|
|
Net cash used in continuing activities |
|
|
(455 |
) |
|
|
(482 |
) |
Net cash used in discontinued activities |
|
|
|
|
|
|
(38 |
) |
|
|
|
|
|
|
|
Net cash used in investing activities |
|
|
(455 |
) |
|
|
(520 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flows from financing activities: |
|
|
|
|
|
|
|
|
Proceeds from borrowings under credit arrangements |
|
|
64 |
|
|
|
453 |
|
Repayments of borrowings under credit arrangements |
|
|
(64 |
) |
|
|
(326 |
) |
Payments to discontinued operations |
|
|
|
|
|
|
(15 |
) |
Proceeds from issuances of common stock |
|
|
9 |
|
|
|
3 |
|
Stock-based compensation excess tax benefit |
|
|
4 |
|
|
|
1 |
|
|
|
|
|
|
|
|
Net cash provided by continuing activities |
|
|
13 |
|
|
|
116 |
|
Net cash provided by discontinued activities |
|
|
|
|
|
|
15 |
|
|
|
|
|
|
|
|
Net cash provided by financing activities |
|
|
13 |
|
|
|
131 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in cash and cash equivalents |
|
|
(170 |
) |
|
|
(54 |
) |
Cash and cash equivalents, beginning of period |
|
|
250 |
|
|
|
52 |
|
Cash and cash equivalents from discontinued operations, beginning of period |
|
|
|
|
|
|
28 |
|
|
|
|
|
|
|
|
Cash and cash equivalents, end of period |
|
$ |
80 |
|
|
$ |
26 |
|
|
|
|
|
|
|
|
The accompanying notes to consolidated financial statements are an integral part of this statement.
3
NEWFIELD EXPLORATION COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS EQUITY
(In millions)
(Unaudited)
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additional |
|
|
|
|
|
|
Other |
|
|
Total |
|
|
|
Common Stock |
|
|
Treasury Stock |
|
|
Paid-in |
|
|
Retained |
|
|
Comprehensive |
|
|
Stockholders |
|
|
|
Shares |
|
|
Amount |
|
|
Shares |
|
|
Amount |
|
|
Capital |
|
|
Earnings |
|
|
Income (Loss) |
|
|
Equity |
|
Balance, December 31, 2007 |
|
|
133.2 |
|
|
$ |
1 |
|
|
|
(1.9 |
) |
|
$ |
(32 |
) |
|
$ |
1,278 |
|
|
$ |
2,337 |
|
|
$ |
(3 |
) |
|
$ |
3,581 |
|
Issuance of common and restricted stock |
|
|
0.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
9 |
|
Stock-based compensation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
7 |
|
Stock-based compensation excess tax benefit |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
4 |
|
Comprehensive income (loss): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(64 |
) |
|
|
|
|
|
|
(64 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total comprehensive income (loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(64 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance, March 31, 2008 |
|
|
133.6 |
|
|
$ |
1 |
|
|
|
(1.9 |
) |
|
$ |
(32 |
) |
|
$ |
1,298 |
|
|
$ |
2,273 |
|
|
$ |
(3 |
) |
|
$ |
3,537 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes to consolidated financial statements are an integral part of this statement.
4
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Organization and Summary of Significant Accounting Policies:
Organization and Principles of Consolidation
We are an independent oil and gas company engaged in the exploration, development and
acquisition of natural gas and crude oil properties. Our domestic areas of operation include the
Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains, onshore Texas and the Gulf of
Mexico. Internationally, we are active in Malaysia and China.
Our financial statements include the accounts of Newfield Exploration Company, a Delaware
corporation, and its subsidiaries. We proportionately consolidate our interests in oil and 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 or our
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 state fairly 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 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, 2007.
In September 2007, we entered into an agreement to sell all of our interests in the U.K. North
Sea for $511 million in cash. As a result of this agreement, the historical results of operations
and financial position of our U.K. North Sea operations are reflected in our financial statements
as discontinued operations. This reclassification affects the presentation of our prior period
financial statements. In October 2007, we closed and recorded a gain of $341 million. See Note
13, Discontinued Operations. Except where noted, discussions in these notes relate to our
continuing operations only.
Dependence on Oil and Gas Prices
As an independent oil and gas producer, our revenue, profitability and future rate of growth
are substantially dependent on prevailing prices for natural gas and oil. Historically, the energy
markets have been very volatile, and there can be no assurance that oil and gas prices will not be
subject to wide fluctuations in the future. A substantial or extended decline in oil or gas prices
could have a material adverse effect on our financial position, results of operations, cash flows
and access to capital and on the quantities of oil and gas 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 reported amounts of proved oil and gas reserves. Actual results
could differ from these estimates. Our most significant financial estimates are based on our proved
oil and gas reserves.
Investments
Investments consist of auction rate securities classified as available-for-sale.
Accordingly, unrealized gains and losses and the related deferred income tax effects are excluded
from earnings and reported as a separate component of stockholders equity. Although our auction
rate securities generally have contractual maturities of more than 25 years, the underlying
interest rates on such securities are scheduled to reset every 7-28 days. Therefore, these auction
rate securities are generally priced and subsequently trade as short-term investments because of
the interest rate reset feature. As a result, we have classified our auction rate securities as
short-term investments in the accompanying balance sheet. Realized gains or losses are computed
based on specific identification of the securities sold. We realized interest income on our
investment securities for the three months ended March 31, 2008 of $2 million.
5
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Foreign Currency
The functional currency for all of our foreign operations is the U.S. dollar. Gains and losses
incurred on currency transactions in other than a countrys functional currency are recorded under
the caption Other income (expense) Other on our consolidated statement of income.
Inventories
Inventories primarily consist of tubular goods and well equipment held for use in our oil and
gas operations and oil produced in our operations offshore Malaysia and China but not sold.
Inventories are carried at the lower of cost or market. Crude oil from our operations offshore
Malaysia and China is produced into floating production, storage and off-loading vessels and sold
periodically as barge quantities are accumulated. The product inventory consisted of approximately
242,000 barrels and 480,000 barrels of crude oil valued at cost of $8 million and $17 million at
March 31, 2008 and December 31, 2007, respectively. Cost for purposes of the carrying value of oil
inventory is the sum of production costs and depreciation, depletion and amortization expense.
Accounting for Asset Retirement Obligations
If a reasonable estimate of the fair value of an obligation to perform site reclamation,
dismantle facilities or plug and abandon wells can be made, we record a liability (an asset
retirement obligation or ARO) on our consolidated balance sheet and capitalize the present value of
the asset retirement cost in oil and gas properties in the period in which the retirement
obligation is incurred. In general, the amount of an ARO and the costs capitalized will be equal to
the estimated future cost to satisfy the abandonment obligation assuming the normal operation of
the asset, using current prices that are escalated by an assumed inflation factor up to the
estimated settlement date, which is then discounted back to the date that the abandonment
obligation was incurred using an assumed cost of funds for our company. After recording these
amounts, the ARO is accreted to its future estimated value using the same assumed cost of funds and
the additional capitalized costs are depreciated on a unit-of-production basis within the related
full cost pool. Both the accretion and the depreciation are included in depreciation, depletion and
amortization on our consolidated statement of income.
The changes to our ARO for the three months ended March 31, 2008 are set forth below (in
millions):
|
|
|
|
|
Balance as of January 1, 2008 |
|
$ |
62 |
|
Accretion expense |
|
|
1 |
|
Additions |
|
|
2 |
|
|
|
|
|
Balance at March 31, 2008 |
|
|
65 |
|
Current portion of ARO |
|
|
(6 |
) |
|
|
|
|
Total long-term ARO at March 31, 2008 |
|
$ |
59 |
|
|
|
|
|
6
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Taxes
We use the liability method of accounting for income taxes. Under this method, deferred tax
assets and liabilities are determined by applying tax regulations existing at the end of a
reporting period to the cumulative temporary differences between the tax bases of assets and
liabilities and their reported amounts in our financial statements. A valuation allowance is
established to reduce deferred tax assets if it is more likely than not that the related tax
benefits will not be realized.
We adopted the provisions of Financial Accounting Standards Board (FASB) Interpretation No. 48
(FIN 48), Accounting for Uncertainty in Income Taxes, an interpretation of FASB Statement No. 109,
on January 1, 2007. The adoption did not result in a material adjustment to our tax liability for
unrecognized income tax benefits. During the first quarter of 2008, there was no change to our FIN
48 liability. If applicable, we would recognize interest and penalties related to uncertain tax
positions in interest expense. As of March 31, 2008, we had not accrued interest or penalties
related to uncertain tax positions. The tax years 2004-2007 remain open to examination for federal
income tax purposes and by the other major taxing jurisdictions to which we are subject.
New Accounting Standards
In March 2008, the FASB issued FASB Statement (SFAS) No. 161, Disclosures about Derivative
Instruments and Hedging Activities-an amendment of FASB Statement
No.133 (SFAS No. 161). This Statement requires
enhanced disclosures about our derivative and hedging activities. This statement is effective for
financial statements issued for fiscal years and interim periods beginning after November 15, 2008.
We will adopt SFAS No. 161 beginning January 1, 2009. We are currently evaluating the impact, if
any, the standard will have on our consolidated financial statements.
2. Earnings Per Share:
Basic earnings per share (EPS) is calculated by dividing net income (the numerator) by the
weighted average number of shares of common stock (other than unvested restricted stock and
restricted stock units) outstanding during the period (the denominator). Diluted earnings per share
incorporates the dilutive impact of outstanding stock options and unvested restricted shares and
restricted stock units (using the treasury stock method). Under the treasury stock method, the
amount the employee must pay for exercising stock options, the amount of unrecognized compensation
expense related to unvested stock-based compensation grants and the amount of excess tax benefits
that would be recorded when the award becomes deductible are assumed to be used to repurchase
shares. See Note 11, Stock-Based Compensation.
7
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following is the calculation of basic and diluted weighted average shares outstanding and
EPS for the indicated periods:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions, except per |
|
|
|
share data) |
|
Income (numerator): |
|
|
|
|
|
|
|
|
Loss from continuing operations |
|
$ |
(64 |
) |
|
$ |
(47 |
) |
Loss from discontinued operations, net of tax |
|
|
|
|
|
|
(49 |
) |
|
|
|
|
|
|
|
Net loss basic and diluted |
|
$ |
(64 |
) |
|
$ |
(96 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares (denominator): |
|
|
|
|
|
|
|
|
Weighted average shares basic |
|
|
129 |
|
|
|
127 |
|
Dilution effect of stock options and unvested
restricted stock outstanding at end of period |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average shares diluted |
|
|
129 |
|
|
|
127 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share: |
|
|
|
|
|
|
|
|
Basic |
|
|
|
|
|
|
|
|
Loss from continuing operations |
|
$ |
(0.50 |
) |
|
$ |
(0.37 |
) |
Loss from discontinued operations |
|
|
|
|
|
|
(0.38 |
) |
|
|
|
|
|
|
|
Basic earnings (loss) per share |
|
$ |
(0.50 |
) |
|
$ |
(0.75 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
|
|
|
|
|
|
|
Loss from continuing operations |
|
$ |
(0.50 |
) |
|
$ |
(0.37 |
) |
Loss from discontinued operations |
|
|
|
|
|
|
(0.38 |
) |
|
|
|
|
|
|
|
Diluted earnings (loss) per share |
|
$ |
(0.50 |
) |
|
$ |
(0.75 |
) |
|
|
|
|
|
|
|
The calculation of shares outstanding for diluted EPS for the three months periods ended March 31,
2008 and 2007 does not include the effect of 701,000 and 642,000 outstanding stock options and
unvested restricted shares or restricted share units, respectively, because to do so would be
antidilutive.
8
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
3. Oil and Gas Assets:
Oil and Gas Properties
Oil and gas properties consisted of the following at:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Subject to amortization |
|
$ |
8,945 |
|
|
$ |
8,602 |
|
Not subject to amortization: |
|
|
|
|
|
|
|
|
Exploration in progress |
|
|
366 |
|
|
|
250 |
|
Development in progress |
|
|
56 |
|
|
|
30 |
|
Capitalized interest |
|
|
112 |
|
|
|
103 |
|
Fee mineral interests |
|
|
23 |
|
|
|
23 |
|
Other capital costs: |
|
|
|
|
|
|
|
|
Incurred in 2008 |
|
|
37 |
|
|
|
|
|
Incurred in 2007 |
|
|
340 |
|
|
|
342 |
|
Incurred in 2006 |
|
|
74 |
|
|
|
77 |
|
Incurred in 2005 and prior |
|
|
354 |
|
|
|
364 |
|
|
|
|
|
|
|
|
Total not subject to amortization |
|
|
1,362 |
|
|
|
1,189 |
|
|
|
|
|
|
|
|
Gross oil and gas properties |
|
|
10,307 |
|
|
|
9,791 |
|
Accumulated depreciation, depletion and amortization |
|
|
(4,017 |
) |
|
|
(3,868 |
) |
|
|
|
|
|
|
|
Net oil and gas properties |
|
$ |
6,290 |
|
|
$ |
5,923 |
|
|
|
|
|
|
|
|
We use the full cost method of accounting for our oil and gas producing activities. Under this
method, all costs incurred in the acquisition, exploration and development of oil and gas
properties, including salaries, benefits and other internal costs directly attributable to these
activities, are capitalized into cost centers that are established on a country-by-country basis.
Capitalized costs and estimated future development and abandonment costs are amortized on a
unit-of-production method based on proved reserves associated with the applicable cost center. For
each cost center, the net capitalized costs of oil and gas properties are limited to the lower of
the unamortized cost or the cost center ceiling. A particular cost center ceiling is equal to the
sum of:
|
|
|
the present value (10% per annum discount rate) of estimated future net revenues from
proved reserves using end of period oil and gas prices applicable to our reserves
(including the effects of hedging contracts that are designated for hedge accounting); plus |
|
|
|
|
the lower of cost or estimated fair value of properties not included in the costs being
amortized, if any; less |
|
|
|
|
related income tax effects. |
Proceeds from the sale of oil and gas properties are applied to reduce the costs in the
applicable cost center unless the reduction would significantly alter the relationship between
capitalized costs and proved reserves, in which case a gain or loss is recognized.
If net capitalized costs of oil and gas properties exceed the cost center ceiling, we are
subject to a ceiling test writedown to the extent of such excess. If required, a ceiling test
writedown reduces earnings and stockholders equity
in the period of occurrence and, holding other factors constant, results in lower
depreciation, depletion and amortization expense in future periods.
9
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The risk that we will be required to writedown the carrying value of our oil and gas
properties increases when oil and gas prices decrease significantly or if we have substantial
downward revisions in our estimated proved reserves. Application of the full cost accounting rules
did not result in a ceiling test writedown at March 31, 2008.
Pro Forma Results Rocky Mountain Asset Acquisition
The unaudited pro forma results presented below for the three months ended March 31, 2007 have
been prepared to give effect to our June 2007 Rocky Mountain asset acquisition on our results of
operations as if it had been consummated at the beginning of the period. The unaudited pro forma
results do not purport to represent what our actual results of operations would have been if this
acquisition had been completed on such date or to project our results of operations for any future
date or period.
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, 2007 |
|
|
(In millions, except per share data) |
Pro forma: |
|
|
|
|
Revenue |
|
$ |
465 |
|
Income from operations |
|
|
100 |
|
Net loss |
|
|
(40 |
) |
Basic loss per share |
|
$ |
(0.32 |
) |
Diluted loss per share |
|
$ |
(0.32 |
) |
4. Debt:
As of the indicated dates, our debt consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
Senior unsecured debt: |
|
|
|
|
|
|
|
|
Revolving credit facility: |
|
|
|
|
|
|
|
|
Prime rate based loans |
|
$ |
|
|
|
$ |
|
|
LIBOR based loans |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revolving credit facility |
|
|
|
|
|
|
|
|
Money market line of credit (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total credit arrangements |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 5/8% Senior Notes due 2011 |
|
|
175 |
|
|
|
175 |
|
Fair value of interest rate swaps (2) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
Total senior unsecured notes |
|
|
177 |
|
|
|
175 |
|
|
|
|
|
|
|
|
Total senior unsecured debt |
|
|
177 |
|
|
|
175 |
|
6 5/8% Senior Subordinated Notes due 2014 |
|
|
325 |
|
|
|
325 |
|
6 5/8% Senior Subordinated Notes due 2016 |
|
|
550 |
|
|
|
550 |
|
|
|
|
|
|
|
|
Total debt |
|
$ |
1,052 |
|
|
$ |
1,050 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Because capacity under our credit facility was available 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. |
|
(2) |
|
We have hedged $50 million principal amount of our $175 million 7 5/8% Senior Notes due 2011.
The hedge provides for us to pay variable and receive fixed interest payments. |
10
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Credit Arrangements
In June 2007, we entered into a new revolving credit facility to replace our previous
facility. The credit facility matures in June 2012 and provides for initial loan commitments of
$1.25 billion from a syndicate of financial institutions, led by JPMorgan Chase Bank, as agent.
The loan commitments may be increased to a maximum of $1.65 billion if the existing lenders
increase their loan commitments or new financial institutions are added to the facility. Loans
under the credit facility bear interest, at our option, based on (a) a rate per annum equal to the
higher of the prime rate announced from time to time by JPMorgan Chase Bank 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 or (b) a base Eurodollar rate
substantially equal to the London Interbank Offered Rate, plus a margin that is based on a grid of
our debt rating (87.5 basis points per annum at March 31, 2008). At March 31, 2008, we had no
borrowings outstanding under our credit facility.
Under our current credit facility and our previous credit facilities, we pay or paid
commitment fees on available but undrawn amounts based on a grid of our debt rating (0.175% per
annum at March 31, 2008). We incurred fees under these arrangements of approximately $0.5 million
for the three months ended March 31, 2008 and 2007, respectively, which are recorded in interest expense on our
consolidated statement of income.
Our credit facility has restrictive covenants that include the maintenance of a ratio of total
debt to book capitalization not to exceed 0.6 to 1.0; maintenance of a ratio of total debt to
earnings before gain or loss on the disposition of assets, interest expense, income taxes and
noncash items (such as depreciation, depletion and amortization expense and unrealized gains and
losses on commodity derivatives) of at least 3.5 to 1.0. In addition, for as long as our debt
rating is below investment grade, we must maintain a ratio of the calculated net present value of
our oil and gas properties to total debt of at least 1.75 to 1.00. For purposes of this ratio,
total debt includes only 50% of the principal amount of our senior subordinated notes.
As of March 31, 2008, we had $11 million of undrawn letters of credit outstanding under our
credit facility. Letters of credit are subject to an issuance fee of 12.5 basis points and annual
fees based on a grid of our debt rating (87.5 basis points at March 31, 2008).
Subject to compliance with the restrictive covenants in our credit facility, we also have a
total of $135 million of borrowing capacity under money market lines of credit with various
financial institutions. At March 31, 2008, we had no borrowings outstanding under our money market
lines.
5. Commitments and Contingencies:
We have been named as a defendant in a number of lawsuits arising in the ordinary course of
our business. While the outcome of these lawsuits 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.
6. 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, Malaysia, China and Other International. 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.
The following tables provide the geographic operating segment information required by SFAS No.
131, Disclosures about Segments of an Enterprise and Related Information, as well as results of
operations of oil and gas producing activities required by SFAS No. 69, Disclosures about Oil and
Gas Producing Activities, as of and for the three months ended March 31, 2008 and 2007 for our
continuing operations. Income tax allocations have been determined based on statutory rates in the
applicable geographic segment.
11
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United |
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
States |
|
|
Malaysia |
|
|
China |
|
|
International |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2008: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues |
|
$ |
426 |
|
|
$ |
75 |
|
|
$ |
14 |
|
|
$ |
|
|
|
$ |
515 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
46 |
|
|
|
12 |
|
|
|
1 |
|
|
|
|
|
|
|
59 |
|
Production and other taxes |
|
|
22 |
|
|
|
27 |
|
|
|
2 |
|
|
|
|
|
|
|
51 |
|
Depreciation, depletion and amortization |
|
|
135 |
|
|
|
19 |
|
|
|
3 |
|
|
|
|
|
|
|
157 |
|
General and administrative |
|
|
31 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
32 |
|
Allocated income taxes |
|
|
73 |
|
|
|
7 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from oil and
gas properties |
|
$ |
119 |
|
|
$ |
10 |
|
|
$ |
5 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
299 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
216 |
|
Interest expense, net of interest income,
capitalized interest and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3 |
) |
Commodity derivative expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(321 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss before income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(108 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-lived assets |
|
$ |
5,789 |
|
|
$ |
398 |
|
|
$ |
101 |
|
|
$ |
2 |
|
|
$ |
6,290 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to long-lived assets |
|
$ |
440 |
|
|
$ |
47 |
|
|
$ |
27 |
|
|
$ |
|
|
|
$ |
514 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United |
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
States |
|
|
Malaysia |
|
|
China |
|
|
International |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
Three Months Ended March 31, 2007: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas revenues |
|
$ |
419 |
|
|
$ |
12 |
|
|
$ |
9 |
|
|
$ |
|
|
|
$ |
440 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating expenses: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
|
106 |
|
|
|
4 |
|
|
|
1 |
|
|
|
|
|
|
|
111 |
|
Production and other taxes |
|
|
14 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
17 |
|
Depreciation, depletion and amortization |
|
|
174 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
180 |
|
General and administrative |
|
|
38 |
|
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
39 |
|
Allocated income taxes |
|
|
31 |
|
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income from oil and
gas properties |
|
$ |
56 |
|
|
$ |
1 |
|
|
$ |
2 |
|
|
$ |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
347 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income from operations |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
93 |
|
Interest expense, net of interest income,
capitalized interest and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(11 |
) |
Commodity derivative expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(158 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss from continuing operations before income taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(76 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-lived assets |
|
$ |
5,480 |
|
|
$ |
204 |
|
|
$ |
65 |
|
|
$ |
|
|
|
$ |
5,749 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to long-lived assets |
|
$ |
462 |
|
|
$ |
25 |
|
|
$ |
4 |
|
|
$ |
|
|
|
$ |
491 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
12
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
7. Commodity Derivative Instruments:
We utilize swap, floor, collar and three-way collar derivative contracts to hedge against the
variability in cash flows associated with the forecasted sale of our future oil and gas production.
While the use of these derivative instruments limits the downside risk of adverse price movements,
their use also may limit future revenues from favorable price movements.
With respect to a swap contract, the counterparty is required to make a payment to us if the
settlement price for any settlement period is less than the swap price, and we are required to make
payment to the counterparty if the settlement price for any settlement period is greater than the
swap price. For a floor contract, the counterparty is required to make a payment to us if the
settlement price for any settlement period is below the floor price. We are not required to make
any payment in connection with the settlement of a floor contract. For a collar contract, the
counterparty is required to make a payment to us if the settlement price for any settlement period
is below the floor price, we are required to make payment to the counterparty if the settlement
price for any settlement period is above the ceiling price and neither party is required to make a
payment to the other party if the settlement price for any settlement period is equal to or greater
than the floor price and equal to or less than the ceiling price. A three-way collar contract
consists of a standard collar contract plus a put sold by us with a price below the floor price of
the collar. This additional put requires us to make a payment to the counterparty if the settlement
price for any settlement period is below the put price. Combining the collar contract with the
additional put results in us being entitled to a net payment equal to the difference between the
floor price of the standard collar and the additional put price if the settlement price is equal to
or less than the additional put price. If the settlement price is greater than the additional put
price, the result is the same as it would have been with a standard collar contract only. This
strategy enables us to increase the floor and the ceiling price of the collar beyond the range of a
traditional no cost collar while defraying the associated cost with the sale of the additional put.
All of our derivative contracts are carried at their fair value on our consolidated balance
sheet under the captions Derivative assets and Derivative liabilities.
Substantially all of 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, volatility and, in the
case of collars and floors, the time value of options. The calculation of the fair value of collars
and floors requires the use of an option-pricing model. See Note 14, Fair Value
Measurements. We recognize all unrealized and realized gains and losses related to these
contracts on a mark-to-market basis in our consolidated statement of income under the caption
Commodity derivative income (expense). Settlements of derivative contracts are included in
operating cash flows on our consolidated statement of cash flows.
13
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
At March 31, 2008, we had outstanding contracts with respect to our future production as set
forth in the tables below.
Natural Gas
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Contract Price Per MMBtu |
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars |
|
|
|
|
|
|
|
|
|
|
Fair Value |
|
|
|
|
|
|
|
Swaps |
|
|
Additional Put |
|
|
Floors |
|
|
Ceilings |
|
|
Floors |
|
|
Asset |
|
|
|
Volume in |
|
|
(Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
(Liability) |
|
Period and Type of Contract |
|
MMMBtus |
|
|
Average) |
|
|
Range |
|
|
Average |
|
|
Range |
|
|
Average |
|
|
Range |
|
|
Average |
|
|
Range |
|
|
Average |
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2008 June 2008
Price swap contracts |
|
|
25,325 |
|
|
$ |
7.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(50 |
) |
Collar contracts |
|
|
5,715 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
7.00 - $8.00 |
|
|
$ |
7.64 |
|
|
$ |
9.00 - $9.70 |
|
|
$ |
9.34 |
|
|
|
|
|
|
|
|
|
|
|
(4 |
) |
Floor Contracts |
|
|
5,460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
8.58 - $8.70 |
|
|
$ |
8.64 |
|
|
|
|
|
July 2008 September 2008
Price swap contracts |
|
|
26,220 |
|
|
|
7.97 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(60 |
) |
Collar contracts |
|
|
5,760 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.00 - 8.00 |
|
|
|
7.64 |
|
|
|
9.00 - 9.70 |
|
|
|
9.34 |
|
|
|
|
|
|
|
|
|
|
|
(8 |
) |
Floor Contracts |
|
|
5,520 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.58 - 8.70 |
|
|
|
8.64 |
|
|
|
1 |
|
October 2008 December
2008
Price swap contracts |
|
|
9,445 |
|
|
|
8.04 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(22 |
) |
Collar contracts |
|
|
14,745 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7.00 - 8.00 |
|
|
|
7.95 |
|
|
|
9.00 - 11.16 |
|
|
|
10.13 |
|
|
|
|
|
|
|
|
|
|
|
(24 |
) |
Floor Contracts |
|
|
1,860 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.58 - 8.70 |
|
|
|
8.64 |
|
|
|
1 |
|
3-Way collar contracts |
|
|
5,490 |
|
|
|
|
|
|
$ |
7.00 - $7.5 |
|
|
|
$7.22 |
|
|
|
8.00 - 9.00 |
|
|
|
8.67 |
|
|
|
11.72 - 15.50 |
|
|
|
13.23 |
|
|
|
|
|
|
|
|
|
|
|
(3 |
) |
January 2009 March 2009
Price swap contracts |
|
|
900 |
|
|
|
9.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Collar contracts |
|
|
19,350 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.00 |
|
|
|
8.00 |
|
|
|
9.67 - 11.16 |
|
|
|
10.25 |
|
|
|
|
|
|
|
|
|
|
|
(38 |
) |
3-Way collar contracts |
|
|
8,100 |
|
|
|
|
|
|
|
7.00 - 7.50 |
|
|
|
7.22 |
|
|
|
8.00 - 9.00 |
|
|
|
8.67 |
|
|
|
11.72 - 15.50 |
|
|
|
13.23 |
|
|
|
|
|
|
|
|
|
|
|
(8 |
) |
April 2009 June 2009
Price swap contracts |
|
|
3,185 |
|
|
|
8.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Collar contracts |
|
|
3,185 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.00 |
|
|
|
8.00 |
|
|
|
8.97 - 10.15 |
|
|
|
9.79 |
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
July 2009 September 2009
Price swap contracts |
|
|
3,220 |
|
|
|
8.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2 |
) |
Collar contracts |
|
|
3,220 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.00 |
|
|
|
8.00 |
|
|
|
8.97 - 10.15 |
|
|
|
9.79 |
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
October 2009
Price swap contracts |
|
|
1,085 |
|
|
|
8.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
Collar contracts |
|
|
1,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8.00 |
|
|
|
8.00 |
|
|
|
8.97 - 10.15 |
|
|
|
9.79 |
|
|
|
|
|
|
|
|
|
|
|
(1 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(225 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Contract Price Per Bbl |
|
|
Estimated |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collars |
|
|
Fair Value |
|
|
|
|
|
|
|
Swaps |
|
|
Additional Put |
|
|
Floors |
|
|
Ceilings |
|
|
Asset |
|
|
|
Volume in |
|
|
(Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
(Liability) |
|
Period and Type of Contract |
|
MBbls |
|
|
Average) |
|
|
Range |
|
|
Average |
|
|
Range |
|
|
Average |
|
|
Range |
|
|
Average |
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2008 June 2008
3-Way collar contracts |
|
|
819 |
|
|
|
|
|
|
$ |
25.00 - $29.00 |
|
|
$ |
26.56 |
|
|
$ |
32.00 - $35.00 |
|
|
$ |
33.00 |
|
|
$ |
49.50 - $52.90 |
|
|
$ |
50.29 |
|
|
$ |
(41 |
) |
July 2008 September 2008
3-Way collar contracts |
|
|
828 |
|
|
|
|
|
|
|
25.00 - 29.00 |
|
|
|
26.56 |
|
|
|
32.00 - 35.00 |
|
|
|
33.00 |
|
|
|
49.50 - 52.90 |
|
|
|
50.29 |
|
|
|
(40 |
) |
October 2008 December 2008
3-Way collar contracts |
|
|
828 |
|
|
|
|
|
|
|
25.00 - 29.00 |
|
|
|
26.56 |
|
|
|
32.00 - 35.00 |
|
|
|
33.00 |
|
|
|
49.50 - 52.90 |
|
|
|
50.29 |
|
|
|
(39 |
) |
January 2009 December 2009
3-Way collar contract |
|
|
3,285 |
|
|
|
|
|
|
|
25.00 - 30.00 |
|
|
|
27.00 |
|
|
|
32.00 - 36.00 |
|
|
|
33.33 |
|
|
|
50.00 - 54.55 |
|
|
|
50.62 |
|
|
|
(144 |
) |
January 2010 December 2010 (1)
Price swap contracts . |
|
|
360 |
|
|
$ |
93.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3-Way collar contracts |
|
|
3,285 |
|
|
|
|
|
|
|
25.00 - 32.00 |
|
|
|
29.00 |
|
|
|
32.00 - 38.00 |
|
|
|
35.22 |
|
|
|
50.00 - 53.50 |
|
|
|
51.59 |
|
|
|
(133 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(397 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
In February 2008, we paid $15 million and reset hedges on 360 MBbls of our oil contracts
for January 2010 through December 2010. We unwound three-way collar contracts that had
weighted average prices of $32.00 and $50.88 per barrel for the floor and ceiling prices,
respectively, and an additional put with a weighted average price of $25.00 per barrel. In
conjunction with this unwind, we entered into new swap contracts for the same notional volume
at a weighted average swap price of $93.40 per barrel. |
14
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Basis Contracts
At March 31, 2008, we had natural gas basis hedges as set forth in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Estimated |
|
|
|
Onshore Gulf Coast |
|
|
Rocky Mountains |
|
|
Fair Value |
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Weighted |
|
|
Asset |
|
|
|
Volume in |
|
|
Average |
|
|
Volume in |
|
|
Average |
|
|
(Liability) |
|
|
|
MMBtus |
|
|
Differential |
|
|
MMBtus |
|
|
Differential |
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
April 2008 June 2008 |
|
|
|
|
|
|
|
|
|
|
1,200 |
|
|
|
($1.62 |
) |
|
$ |
|
|
July 2008 September 2008 |
|
|
4,880 |
|
|
|
($0.28 |
) |
|
|
1,200 |
|
|
|
(1.62 |
) |
|
|
7 |
|
October 2008 December 2008 |
|
|
7,360 |
|
|
|
(0.28 |
) |
|
|
1,200 |
|
|
|
(1.62 |
) |
|
|
11 |
|
January 2009 December 2009 |
|
|
|
|
|
|
|
|
|
|
5,520 |
|
|
|
(1.05 |
) |
|
|
6 |
|
January 2010 December 2010 |
|
|
|
|
|
|
|
|
|
|
5,520 |
|
|
|
(0.99 |
) |
|
|
7 |
|
January 2011 December 2011 |
|
|
|
|
|
|
|
|
|
|
5,280 |
|
|
|
(0.95 |
) |
|
|
3 |
|
January 2012 December 2012 |
|
|
|
|
|
|
|
|
|
|
4,920 |
|
|
|
(0.91 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
36 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8. Accounts Receivable:
As of the indicated dates, our accounts receivable consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
Revenue |
|
$ |
210 |
|
|
$ |
142 |
|
Joint interest |
|
|
195 |
|
|
|
175 |
|
Other |
|
|
11 |
|
|
|
15 |
|
|
|
|
|
|
|
|
Total accounts receivable |
|
$ |
416 |
|
|
$ |
332 |
|
|
|
|
|
|
|
|
15
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
9. Accrued Liabilities:
As of the indicated dates, our accrued liabilities consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
March 31, |
|
|
December 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
Revenue payable |
|
$ |
110 |
|
|
$ |
95 |
|
Accrued capital costs |
|
|
359 |
|
|
|
361 |
|
Accrued lease operating expenses |
|
|
35 |
|
|
|
38 |
|
Employee incentive expense |
|
|
48 |
|
|
|
80 |
|
Accrued interest on notes |
|
|
20 |
|
|
|
19 |
|
Taxes payable |
|
|
49 |
|
|
|
31 |
|
Other |
|
|
62 |
|
|
|
47 |
|
|
|
|
|
|
|
|
Total accrued liabilities |
|
$ |
683 |
|
|
$ |
671 |
|
|
|
|
|
|
|
|
10. Comprehensive Income:
For the periods indicated, our comprehensive income (loss) consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(64 |
) |
|
$ |
(96 |
) |
Foreign currency translation adjustment, net of tax of ($0) |
|
|
|
|
|
|
1 |
|
Reclassification adjustments for settled hedging positions, net of tax of $0 |
|
|
|
|
|
|
(1 |
) |
Changes in fair value of outstanding hedging positions, net of tax of ($1) |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
Total comprehensive loss |
|
$ |
(64 |
) |
|
$ |
(94 |
) |
|
|
|
|
|
|
|
11. Stock-Based Compensation:
On
January 1, 2006, we adopted SFAS No. 123(R), Share-Based Payment, to account for
stock-based compensation. We utilize the Black-Scholes option pricing model to measure the fair
value of stock options and a lattice-based model for our performance and market-based restricted
shares and restricted share units.
Historically, we have used, and we anticipate continuing to use, unissued shares of stock when
stock options are exercised. At March 31, 2008, we had approximately 1.7 million additional shares
available for issuance pursuant to our existing employee and director
plans. Of these shares, 1.2
million could be granted as restricted shares. Grants of restricted shares under our 2004 Omnibus
Stock Plan reduce the total number of shares available under that plan by two times the number of
restricted shares issued. Of the 1.2 million shares that can be granted as restricted shares, 0.4
million of such shares can be issued under our 2004 Omnibus Stock Plan.
16
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
For the three months ended March 31, 2008, we recorded stock-based compensation expense of $7
million (pre-tax) for all plans. Of that amount, $2 million was capitalized in oil and gas
properties. For the same period, we reported $4 million of excess tax benefits from stock-based
compensation as cash provided by financing activities on our statement of cash flows.
For the three months ended March 31, 2007, we recorded stock-based compensation expense of $7
million (pre-tax) for all plans. Of that amount, $2 million was capitalized in oil and gas
properties. For the same period, we reported $1 million of excess tax benefits from stock-based
compensation as cash provided by financing activities on our statement of cash flows.
As of March 31, 2008, we had approximately $88 million of total unrecognized compensation
expense related to unvested stock-based compensation awards. This compensation expense is expected
to be recognized on a straight-line basis over the remaining vesting period of approximately five
years.
Stock Options. We have granted stock options under several plans. Options generally expire ten
years from the date of grant and become exercisable at the rate of 20% per year. The exercise price
of options cannot be less than the fair market value per share of our common stock on the date of
grant.
The following table provides information about stock option activity for the three months
ended March 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Weighted |
|
Weighted |
|
|
|
|
Number of |
|
Average |
|
Average |
|
Average |
|
|
|
|
Shares |
|
Exercise |
|
Grant Date |
|
Remaining |
|
Aggregate |
|
|
Underlying |
|
Price |
|
Fair Value |
|
Contractual |
|
Intrinsic |
|
|
Options |
|
per Share |
|
per Share |
|
Life |
|
Value(1) |
|
|
(In millions) |
|
|
|
|
|
(In years) |
|
(In millions) |
Outstanding at December 31, 2007 |
|
|
3.8 |
|
|
$ |
24.21 |
|
|
$ |
10.95 |
|
|
|
5.6 |
|
|
$ |
108 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
0.7 |
|
|
|
48.45 |
|
|
|
16.29 |
|
|
|
|
|
|
|
|
|
Exercised |
|
|
(0.4 |
) |
|
|
23.03 |
|
|
|
10.38 |
|
|
|
|
|
|
|
12 |
|
Forfeited |
|
|
(0.1 |
) |
|
|
34.42 |
|
|
|
14.31 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Outstanding at March 31, 2008 |
|
|
4.0 |
|
|
$ |
28.14 |
|
|
$ |
11.86 |
|
|
|
6.1 |
|
|
$ |
98 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exercisable at March 31, 2008 |
|
|
2.4 |
|
|
$ |
21.83 |
|
|
$ |
9.83 |
|
|
|
4.8 |
|
|
$ |
73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The intrinsic value of a stock option is the amount by which the market value of our common
stock at the indicated date, or at the time of grant, exercise or forfeiture, as applicable,
exceeds the exercise price of the option. |
The fair value of each stock option granted is estimated as of the date of grant using the
Black-Scholes option valuation method, assuming no dividends, a risk-free weighted-average interest
rate of 2.83%, an expected life of 5.2 years and weighted-average volatility of 31.7%.
The following table summarizes information about stock options outstanding and exercisable at March
31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Options Outstanding |
|
Options Exercisable |
|
|
Number of |
|
Weighted |
|
Weighted |
|
Number of |
|
Weighted |
|
|
Shares |
|
Average |
|
Average |
|
Shares |
|
Average |
Range of |
|
Underlying |
|
Remaining |
|
Exercise Price |
|
Underlying |
|
Exercise Price |
Exercise
Prices |
|
Options |
|
Contractual Life |
|
per Share |
|
Options |
|
per Share |
|
|
(In thousands) |
|
(In years) |
|
|
|
|
|
(In thousands) |
|
|
|
|
$ 7.97 to $10.00 |
|
|
10 |
|
|
|
0.4 |
|
|
$ |
7.97 |
|
|
|
10 |
|
|
$ |
7.97 |
|
10.01 to 12.50 |
|
|
|
|
|
|
1.7 |
|
|
|
12.22 |
|
|
|
|
|
|
|
12.22 |
|
12.51 to 15.00 |
|
|
240 |
|
|
|
1.8 |
|
|
|
14.62 |
|
|
|
240 |
|
|
|
14.62 |
|
15.01 to 17.50 |
|
|
721 |
|
|
|
4.3 |
|
|
|
16.64 |
|
|
|
720 |
|
|
|
16.64 |
|
17.51 to 22.50 |
|
|
507 |
|
|
|
4.0 |
|
|
|
19.01 |
|
|
|
454 |
|
|
|
18.96 |
|
22.51 to 27.50 |
|
|
601 |
|
|
|
5.9 |
|
|
|
24.77 |
|
|
|
398 |
|
|
|
24.62 |
|
27.51 to 35.00 |
|
|
1,088 |
|
|
|
6.8 |
|
|
|
31.16 |
|
|
|
513 |
|
|
|
31.33 |
|
35.01 to 41.72 |
|
|
211 |
|
|
|
7.1 |
|
|
|
37.98 |
|
|
|
59 |
|
|
|
37.45 |
|
41.73 to 48.45 |
|
|
642 |
|
|
|
9.9 |
|
|
|
48.45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,020 |
|
|
|
6.1 |
|
|
$ |
28.14 |
|
|
|
2,394 |
|
|
$ |
21.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
On March 31, 2008, the last reported sales price of our common stock on the New York Stock
Exchange was $52.85 per share.
17
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Restricted Shares. At March 31, 2008, our employees held 1.6 million restricted shares or
restricted share units that primarily vest over the service period of four to five years. The
vesting of these shares and units is dependant upon the employees continued service with our
company.
In addition, at March 31, 2008, our employees held 1.6 million restricted shares subject to
performance-based vesting criteria (substantially all of which are considered market-based
restricted shares under SFAS No. 123(R)).
Under our non-employee director restricted stock plan as in effect on March 31, 2008,
immediately after each annual meeting of our stockholders, each of our non-employee directors then
in office receives a number of restricted shares determined by dividing $100,000 by the fair market
value of one share of our common stock on the date of the annual meeting. In addition, new
non-employee directors elected other than at an annual meeting receive a number of restricted
shares determined by dividing $100,000 by the fair market value of one share of our common stock on
the date of their election. The forfeiture restrictions lapse on the day before the first annual
meeting of stockholders following the date of issuance of the shares if the holder remains a
director until that time. At March 31, 2008, 85,592 shares remained available for grants under the
plan.
The following table provides information about restricted share and restricted share unit
activity for the three months ended March 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average |
|
|
|
|
|
|
Performance/ |
|
|
|
|
|
Grant Date |
|
|
Service-Based |
|
Market-Based |
|
|
|
|
|
Fair Value |
|
|
Shares |
|
Shares |
|
Total Shares |
|
Per Share |
|
|
(In thousands, except per share data) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares outstanding at December 31, 2007 |
|
|
1,161 |
|
|
|
1,614 |
|
|
|
2,775 |
|
|
$ |
29.77 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted |
|
|
424 |
|
|
|
|
|
|
|
424 |
|
|
|
48.94 |
|
Forfeited |
|
|
(23 |
) |
|
|
(36 |
) |
|
|
(59 |
) |
|
|
32.19 |
|
Vested |
|
|
(10 |
) |
|
|
(1 |
) |
|
|
(11 |
) |
|
|
28.25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Non-vested shares outstanding at March 31, 2008 |
|
|
1,552 |
|
|
|
1,577 |
|
|
|
3,129 |
|
|
$ |
32.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The total fair value of restricted shares vested during the three months ended March 31, 2008
was $301 thousand.
Employee Stock Purchase Plan. Pursuant to our employee stock purchase plan, for each six month
period beginning on January 1 or July 1 during the term of the plan, each eligible employee has the
opportunity to purchase our common stock for a purchase price equal to 85% of the lesser of the
fair market value of our common stock on the first day of the period or the last day of the period.
No employee may purchase common stock under the plan valued at more than $25,000 in any calendar
year. Employees of our foreign subsidiaries are not eligible to participate in the plan.
During the first quarter of 2008, options to purchase 27,720 shares of our common stock at a
weighted average fair value of $12.93 per share were issued under the plan. The fair value of the
options granted was determined using the Black-Scholes option valuation method assuming no
dividends, a risk-free weighted-average interest rate of 3.49%, an expected life of six months and
weighted-average volatility of 31.9%. At March 31, 2008, 602,185 shares of our common stock
remained available for issuance under this plan.
18
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
12. Income Taxes:
The provision (benefit) for income taxes for the indicated periods was different than the
amount computed using the federal statutory rate (35%) for the following reasons:
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
|
March 31, |
|
|
|
2008 |
|
|
2007 |
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
Amount computed using the statutory rate |
|
$ |
(38 |
) |
|
$ |
(27 |
) |
Increase (decrease) in taxes resulting from: |
|
|
|
|
|
|
|
|
State and local income taxes, net of federal effect |
|
|
2 |
|
|
|
1 |
|
Net effect of different tax rates in non-U.S. jurisdictions |
|
|
|
|
|
|
(1 |
) |
Tax credits and other |
|
|
(8 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
Total provision (benefit) for income taxes |
|
$ |
(44 |
) |
|
$ |
(29 |
) |
|
|
|
|
|
|
|
As of March 31, 2008, we had NOL carryforwards for international income tax purposes of
approximately $17 million that may be used in future years to offset taxable income. We currently
estimate that we will not be able to utilize these international NOLs, therefore a valuation
allowance was established for them. Utilization of NOL carryforwards is dependent upon generating
sufficient taxable income in the appropriate jurisdictions within the carryforward period.
Estimates of future taxable income can be significantly affected by changes in natural gas and oil
prices, estimates of the timing and amount of future production and estimates of future operating
and capital costs.
13. Discontinued Operations:
In September 2007, we entered into an agreement to sell all of our interests in the U.K. North
Sea for $511 million in cash. As a result of this agreement, the historical results of operations
and financial position of our U.K. North Sea operations are reflected in our financial statements
as discontinued operations. In October 2007, we closed the sale and recorded a gain of $341
million.
The summarized financial results of the discontinued operations are as follows:
|
|
|
|
|
|
|
Three Months Ended |
|
|
March 31, 2007 |
|
|
(In millions) |
Revenues |
|
$ |
|
|
Operating expenses (1) |
|
|
(49 |
) |
|
|
|
|
|
Loss from discontinued operations, net of tax |
|
$ |
(49 |
) |
|
|
|
|
|
|
|
|
(1) |
|
Includes a ceiling test writedown of $47 million. |
19
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
14. Fair Value Measurements:
We adopted SFAS No. 157, Fair Value Measurements, effective January 1, 2008 for financial
assets and liabilities measured on a recurring basis. SFAS No. 157 applies to all financial assets
and financial liabilities that are being measured and reported on a fair value basis. In February
2008, the FASB issued FSP No. 157-2, which delayed the effective date of SFAS No. 157 by one year for
nonfinancial assets and liabilities. As defined in SFAS No. 157, 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). SFAS No. 157 requires disclosure that
establishes a framework for measuring fair value and expands disclosure about fair value
measurements. The statement requires 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 in
sufficient frequency and volume to provide pricing information on an ongoing basis. |
|
|
|
|
|
|
|
Level 2:
|
|
Quoted prices in markets that are not active, or inputs which 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 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 price swaps,
investments and interest rate
swaps. |
|
|
|
|
|
|
|
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). Our valuation models are
primarily industry-standard models that consider various inputs including: (a) quoted
forward prices for commodities, (b) time value, (c) volatility factors and (d) current
market and contractual prices for the underlying instruments, as well as other relevant
economic measures. Level 3 instruments primarily include derivative instruments, such
as basis swaps, commodity price collars and floors, as well as investments. Although we utilize
third party broker quotes to assess the reasonableness of our prices and valuation
techniques, we do not have sufficient corroborating market evidence to support
classifying these assets and liabilities as Level 2. |
As required by SFAS No. 157, 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 levels. The following table summarizes the valuation of our investments and
financial instruments by SFAS No. 157 pricing levels as of March 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using |
|
|
|
Quoted |
|
|
|
|
|
|
|
|
|
|
|
|
Prices in |
|
|
|
|
|
|
|
|
|
|
|
|
Active |
|
|
|
|
|
|
|
|
|
|
|
|
Markets for |
|
|
Significant |
|
|
|
|
|
|
|
|
|
Identical |
|
|
Other |
|
|
Significant |
|
|
|
|
|
|
Assets or |
|
|
Observable |
|
|
Unobservable |
|
|
|
|
|
|
Liabilities |
|
|
Inputs |
|
|
Inputs |
|
|
|
|
Description |
|
(Level 1) |
|
|
(Level 2) |
|
|
(Level 3) |
|
|
Total |
|
|
|
(In millions) |
|
Assets (Liabilities): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investments(1) |
|
$ |
5 |
|
|
$ |
5 |
|
|
$ |
77 |
|
|
$ |
87 |
|
Oil and gas derivative swap contracts |
|
|
|
|
|
|
(139 |
) |
|
|
36 |
|
|
|
(103 |
) |
Oil and gas derivative option contracts |
|
|
|
|
|
|
|
|
|
|
(483 |
) |
|
|
(483 |
) |
Interest rate swaps |
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
5 |
|
|
$ |
(132 |
) |
|
$ |
(370 |
) |
|
$ |
(497 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Level 1 and level 2 investments are included under the caption Other assets
on our consolidated balance sheet. |
20
NEWFIELD EXPLORATION COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The
determination of the fair values above incorporates various factors
required under SFAS No.
157. These factors include not only the impact of our nonperformance 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).
Our short-term investments as of March 31, 2008 consisted of $77 million
of auction rate securities. All such securities are AAA rated and guaranteed by the United States
government. During the first quarter of 2008, we experienced difficulty selling these securities
due to the failure of the auction mechanism that provides liquidity to these securities because the
parties wishing to sell securities could not do so. As a result, the interest rate on these
securities has increased from 1.1% to 5.5%. We will attempt to sell these securities every 7-28
days until the auction succeeds, the issuer calls the securities or the securities mature.
Accordingly, there may be no effective mechanism for selling these securities, and the securities
we own may become long-term investments. At this time, we do not believe our auction rate
securities are impaired.
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 (in millions):
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-Term |
|
|
|
|
|
|
|
|
|
Investments |
|
|
Derivatives |
|
|
Total |
|
Balance as of January 1, 2008 |
|
$ |
120 |
|
|
$ |
(341 |
) |
|
$ |
(221 |
) |
Total gains
or losses (realized or unrealized): |
|
|
|
|
|
|
|
|
|
|
|
|
Included in earnings |
|
|
|
|
|
|
(161 |
) |
|
|
(161 |
) |
Included in other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
Purchases, issuances and settlements (1) |
|
|
(43 |
) |
|
|
55 |
|
|
|
12 |
|
Transfers in and out of level 3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance as of March 31, 2008 |
|
$ |
77 |
|
|
$ |
(447 |
) |
|
$ |
(370 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in unrealized gains (losses) relating to
investments still held as of March 31, 2008 |
|
$ |
|
|
|
$ |
(146 |
) |
|
$ |
(146 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Derivative settlements includes the $15 million we paid to unwind a portion of our oil
contracts for 2010. |
21
Item 2. Managements Discussion and Analysis of Financial Condition and Results of Operations
We are an independent oil and gas company engaged in the exploration, development and
acquisition of natural gas and crude oil properties. Our domestic areas of operation include the
Anadarko and Arkoma Basins of the Mid-Continent, the Rocky Mountains, onshore Texas and the Gulf of
Mexico. Internationally, we are active in Malaysia and China.
Our revenues, profitability and future growth depend substantially on prevailing prices for
oil and gas and on our ability to find, develop and acquire oil and gas reserves that are
economically recoverable. The preparation of our financial statements in conformity with generally
accepted accounting principles requires us to make estimates and assumptions that affect our
reported results of operations and the amount of our reported assets, liabilities and proved oil
and gas reserves. We use the full cost method of accounting for our oil and gas activities.
Oil and Gas Prices. Prices for oil and gas fluctuate widely. Oil and gas prices affect:
|
|
|
the amount of cash flow available for capital expenditures; |
|
|
|
|
our ability to borrow and raise additional capital; |
|
|
|
|
the quantity of oil and gas that we can economically produce; and |
|
|
|
|
the accounting for our oil and gas activities. |
As part of our risk management program, we generally hedge a substantial, but varying, portion
of our anticipated future oil and gas production. Reducing our exposure to price volatility helps
ensure that we have adequate funds available for our capital programs and helps us manage returns
on some of our acquisitions and more price sensitive drilling programs.
Reserve Replacement. To maintain and grow our production and cash flow, we must continue to
develop existing reserves and locate or acquire new oil and gas reserves to replace those being
depleted by production. Substantial capital expenditures are required to find, develop and acquire
oil and gas reserves.
Significant Estimates. We believe the most difficult, subjective or complex judgments and
estimates we
must make in connection with the preparation of our financial statements are:
|
|
|
the quantity of our proved oil and gas reserves; |
|
|
|
|
the timing of future drilling, development and abandonment activities; |
|
|
|
|
the cost of these activities in the future; |
|
|
|
|
the fair value of the assets and liabilities of acquired companies; |
|
|
|
|
the value of our derivative positions; and |
|
|
|
|
the fair value of stock-based compensation. |
Accounting for Hedging Activities. Beginning October 1, 2005, we elected not to designate any
future price risk management activities as accounting hedges. Because hedges not designated for
hedge accounting are accounted for on a mark-to-market basis, we are likely to experience
significant non-cash volatility in our reported earnings during periods of commodity price
volatility. As of March 31, 2008, we had a net derivative
liability of $586 million, of which 76%
was measured based upon our valuation model and, as such, is
classified as a Level 3 fair value
measurement. We value these contracts using a model that considers various inputs including (a)
quoted forward prices for commodities, (b) time value, (c) volatility factors and (d) current
market and contractual prices for the underlying instruments. Please see Note 7, Commodity
Derivative Instruments and Hedging Activities, and Note 14,
Fair Value Measurements, to our
consolidated financial statements appearing earlier in this report for a discussion of the
accounting applicable to our oil and gas derivative contracts.
Other factors. Please see Risk Factors in Item 1A of our annual report on Form 10-K for the
year ended December 31, 2007 for a more detailed discussion of a number of other factors that
affect our business, financial condition and results of operations. This report should be read
together with those discussions.
22
Results of Operations
Significant Transactions. We completed several significant transactions during 2007 that
affect the comparability of our results of operations and cash flows from period to period.
|
|
|
In June 2007, we acquired Stone Energy Corporations Rocky Mountain assets for $578
million in cash. Initially, we financed this acquisition through borrowings under our
revolving credit agreement. |
|
|
|
|
In August 2007, we sold our shallow water Gulf of Mexico assets for $1.1 billion in
cash and the purchasers assumption of liabilities associated with future abandonment of
wells and platforms. |
|
|
|
|
In September 2007, we sold our coal bed methane assets in the Cherokee Basin of
northeastern Oklahoma for $128 million in cash. |
|
|
|
|
In October 2007, we sold
all of our interests in the U.K. North Sea for $511 million in
cash. The historical results of operations of our U.K. North Sea
operations are
reflected in our financial statements as discontinued operations. Except where noted,
discussions in this report relate to continuing operations only. |
Revenues. All of our revenues are derived from the sale of our oil and gas production. The
effects of the settlement of hedges designated for hedge accounting are included in revenues, but
those not so designated have no effect on our reported revenues. None of our outstanding hedges
are designated for hedge accounting. Please see Note 7, Commodity Derivative Instruments, to our
consolidated financial statements appearing earlier in this report for a discussion of the
accounting applicable to our oil and gas derivative contracts.
Our revenues may vary significantly from period to period as a result of changes in commodity
prices or volumes of production sold. In addition, crude oil from our operations offshore Malaysia
and China is produced into FPSOs and lifted and sold periodically as barge quantities are
accumulated. Revenues are recorded when oil is lifted and sold, not when it is produced into the
FPSO. As a result, the timing of liftings may impact period to period results.
Revenues of $0.5 billion for the first quarter of 2008 were 17% higher than the comparable
period of 2007 due to higher oil and gas average realized prices and higher oil production offset
by lower gas production.
23
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended |
|
|
Percentage |
|
|
|
March 31, |
|
|
Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
Production (1): |
|
|
|
|
|
|
|
|
|
|
|
|
United States: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf) |
|
|
40.4 |
|
|
|
51.8 |
|
|
|
(22 |
)% |
Oil and condensate (MBbls) |
|
|
1,422 |
|
|
|
1,740 |
|
|
|
(18 |
)% |
Total (Bcfe) |
|
|
48.9 |
|
|
|
62.3 |
|
|
|
(21 |
)% |
International: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf) |
|
|
|
|
|
|
|
|
|
|
|
|
Oil and condensate (MBbls) |
|
|
1,037 |
|
|
|
404 |
|
|
|
157 |
% |
Total (Bcfe) |
|
|
6.2 |
|
|
|
2.4 |
|
|
|
157 |
% |
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (Bcf) |
|
|
40.4 |
|
|
|
51.8 |
|
|
|
(22 |
)% |
Oil and condensate (MBbls) |
|
|
2,459 |
|
|
|
2,144 |
|
|
|
15 |
% |
Total (Bcfe) |
|
|
55.1 |
|
|
|
64.7 |
|
|
|
(15 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Realized Prices (2): |
|
|
|
|
|
|
|
|
|
|
|
|
United States: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
7.54 |
|
|
$ |
6.37 |
|
|
|
18 |
% |
Oil and condensate (per Bbl) |
|
|
85.04 |
|
|
|
49.62 |
|
|
|
71 |
% |
Natural gas equivalent (per Mcfe) |
|
|
8.70 |
|
|
|
6.69 |
|
|
|
30 |
% |
International: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
|
|
|
$ |
|
|
|
|
|
|
Oil and condensate (per Bbl) |
|
|
85.38 |
|
|
|
51.86 |
|
|
|
65 |
% |
Natural gas equivalent (per Mcfe) |
|
|
14.23 |
|
|
|
8.64 |
|
|
|
65 |
% |
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
Natural gas (per Mcf) |
|
$ |
7.54 |
|
|
$ |
6.37 |
|
|
|
18 |
% |
Oil and condensate (per Bbl) |
|
|
85.18 |
|
|
|
50.04 |
|
|
|
70 |
% |
Natural gas equivalent (per Mcfe) |
|
|
9.32 |
|
|
|
6.76 |
|
|
|
38 |
% |
|
|
|
(1) |
|
Represents volumes lifted and sold regardless of when produced. |
|
(2) |
|
Average realized prices only include the effects of hedging contracts that are designated for
hedge accounting. Had we included the effects of contracts not so designated, our average
realized price for total gas would have been $7.89 and $8.18 per Mcf for the first quarter of
2008 and 2007, respectively. Our total oil and condensate average realized price would have
been $63.28 (includes a negative impact of $5.92 per Bbl due to a $15 million payment made in
February 2008 to reset a portion of our 2010 oil three-way contracts) and $47.49 per Bbl for
the first quarter of 2008 and 2007, respectively. Without the effects of any hedging
contracts, our average realized price for the first quarter of 2007 would have been
$51.18 per Bbl
for oil. |
Domestic Production. Our first quarter of 2008 domestic gas and oil production (stated on a
natural gas equivalent basis) decreased 21% over the comparable period of 2007. Our first quarter
of 2008 natural gas production decreased 22% and our oil and condensate production decreased 18% as
a result of the sale of our shallow water Gulf of Mexico assets in August 2007. This decrease was
partially offset by an increase in production in the Mid-Continent as a result of successful
drilling efforts and in the Rocky Mountains as a result of our acquisition there in June 2007.
International Production. Our first quarter of 2008 international oil and gas production
(stated on a natural gas equivalent basis) increased 157% over the comparable period of 2007
primarily due to the timing of liftings in Malaysia.
24
Operating Expenses. We believe the most informative way to analyze changes in our operating
expenses from period to period is on a unit-of-production, or per Mcfe, basis. However, because of the several significant transactions we completed in 2007 (see above), period to period comparisons are difficult. For example, offshore Gulf of Mexico properties typically have significantly higher lease operating costs relative to onshore properties and offshore production is not subject to production taxes but onshore production is subject to production taxes.
The following table presents information about our operating expenses for the first quarter of
2008 and 2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unit-of-Production |
|
|
Amount |
|
|
|
Three Months Ended |
|
|
Percentage |
|
|
Three Months Ended |
|
|
Percentage |
|
|
|
March 31, |
|
|
Increase |
|
|
March 31, |
|
|
Increase |
|
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
2008 |
|
|
2007 |
|
|
(Decrease) |
|
|
|
(Per Mcfe) |
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
United States: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
$ |
0.95 |
|
|
$ |
1.70 |
|
|
|
(44 |
)% |
|
$ |
47 |
|
|
$ |
106 |
|
|
|
(56 |
)% |
Production and other taxes |
|
|
0.44 |
|
|
|
0.23 |
|
|
|
91 |
% |
|
|
22 |
|
|
|
15 |
|
|
|
51 |
% |
Depreciation, depletion and amortization |
|
|
2.78 |
|
|
|
2.79 |
|
|
|
|
|
|
|
136 |
|
|
|
174 |
|
|
|
(22 |
)% |
General and administrative |
|
|
0.63 |
|
|
|
0.61 |
|
|
|
3 |
% |
|
|
31 |
|
|
|
38 |
|
|
|
(19 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
$ |
4.80 |
|
|
$ |
5.34 |
|
|
|
(10 |
)% |
|
$ |
236 |
|
|
$ |
333 |
|
|
|
(29 |
)% |
International: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
$ |
2.01 |
|
|
$ |
1.97 |
|
|
|
2 |
% |
|
$ |
12 |
|
|
$ |
5 |
|
|
|
161 |
% |
Production and other taxes |
|
|
4.71 |
|
|
|
1.26 |
|
|
|
274 |
% |
|
|
29 |
|
|
|
2 |
|
|
|
861 |
% |
Depreciation, depletion and amortization |
|
|
3.43 |
|
|
|
2.43 |
|
|
|
41 |
% |
|
|
21 |
|
|
|
6 |
|
|
|
263 |
% |
General and administrative |
|
|
0.13 |
|
|
|
0.33 |
|
|
|
(61 |
)% |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
$ |
10.28 |
|
|
$ |
5.99 |
|
|
|
72 |
% |
|
$ |
63 |
|
|
$ |
14 |
|
|
|
340 |
% |
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Lease operating |
|
$ |
1.07 |
|
|
$ |
1.71 |
|
|
|
(37 |
)% |
|
$ |
59 |
|
|
$ |
111 |
|
|
|
(47 |
)% |
Production and other taxes |
|
|
0.93 |
|
|
|
0.27 |
|
|
|
244 |
% |
|
|
51 |
|
|
|
17 |
|
|
|
192 |
% |
Depreciation, depletion and amortization |
|
|
2.85 |
|
|
|
2.78 |
|
|
|
3 |
% |
|
|
157 |
|
|
|
180 |
|
|
|
(12 |
)% |
General and administrative |
|
|
0.57 |
|
|
|
0.60 |
|
|
|
(5 |
)% |
|
|
32 |
|
|
|
39 |
|
|
|
(19 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating expenses |
|
$ |
5.42 |
|
|
$ |
5.36 |
|
|
|
1 |
% |
|
$ |
299 |
|
|
$ |
347 |
|
|
|
(14 |
)% |
Domestic Operations. Our domestic operating expenses for the first quarter of 2008, stated on
an Mcfe basis, decreased 10% over the same period of 2007. The period to period change was
primarily related to the following items:
|
|
|
Lease operating expense (LOE) decreased due to the sale of all of our producing
properties in the shallow water Gulf of Mexico in August 2007, which properties have
relatively high LOE per Mcfe. In addition, our first quarter of 2007 LOE was adversely
impacted by repair expenditures of $36 million ($0.58 per Mcfe)
related to Hurricanes Katrina and Rita in 2005.
Without the impact of the repair expenditures related to these storms, our first
quarter of 2007 LOE would have been $1.12 per Mcfe. |
|
|
|
|
Production and other taxes increased $0.21 per Mcfe because of an increase in the
proportion of our production subject to taxes as a result of increased production from our
Mid-Continent and Rocky Mountain operations, the sale of our Gulf of Mexico properties and
increased commodity prices. |
|
|
|
|
Our depreciation, depletion and amortization (DD&A) rate per Mcfe remained relatively
flat period over period. The slight increase in our depletion rate (less than 1%) was
offset by a significant decrease in our accretion rate (65%) due to the significant
reduction in our asset retirement obligation resulting from the sale of our Gulf of Mexico properties
in August 2007. Actual DD&A expense decreased 22% period over period primarily
because of the sale of the Gulf of Mexico properties. |
|
|
|
|
General and administrative (G&A) expense increased 3% per Mcfe while total G&A
expense decreased 19% over the comparable period of 2007. The decrease in total G&A
expense was primarily due to recording a litigation settlement reserve associated with a
statewide royalty owner class action lawsuit in Oklahoma in the first quarter of 2007.
During the first quarter of 2008, we capitalized $11 million of direct internal costs as
compared to $9 million in 2007. |
25
International Operations. Our international operating expenses for the first quarter of
2008, stated on an Mcfe basis, increased 72% over the same period of 2007. The period to period
change was primarily related to the following items:
|
|
|
Total LOE increased due to increased liftings and higher operating costs in Malaysia. |
|
|
|
|
Production and other taxes increased significantly due to an increase in the tax rate
per unit for our oil in Malaysia as a result of substantially higher oil prices. |
|
|
|
|
The DD&A rate increased as a result of higher costs for drilling goods and services in
Malaysia and China. |
|
|
|
|
G&A expense decreased $0.20 per Mcfe primarily due to increased liftings of production in
Malaysia. |
Interest Expense. The decrease in interest expense for the first quarter of 2008 resulted
primarily from lower average debt levels outstanding under our credit arrangements and the redemption of $125 million principal amount of our 7.45% Senior Notes
in October 2007.
Taxes. The effective tax rates for the first quarter of 2008 and 2007 were 40.4% and 37.6%,
respectively. Our effective tax rates are greater than our federal statutory tax rate due to state
income taxes associated with income from various states in which we have operations. The increase
in the first quarter of 2008 effective tax rate over the first quarter of 2007 effective tax rate
is primarily due to the sale of our Gulf of Mexico properties in
August 2007, which significantly
increased the portion of our consolidated income subject to state income taxes. Estimates of
future taxable income can be significantly affected by changes in oil and natural gas prices, the
timing and amount of future production and future operating expenses and capital costs.
26
Liquidity and Capital Resources
We must find new and develop existing reserves to maintain and grow production and cash flow.
We accomplish this through successful drilling programs and the acquisition of properties. These
activities require substantial capital expenditures. We establish a capital budget at the beginning
of each calendar year. Our revised 2008 capital budget exceeds expected cash flow from
operations and cash and short-term investments on hand by
approximately $350
million. We have adequate capacity under our credit
arrangements to fund the shortfall. In the past, we often have increased our
capital budget during the year as a result of acquisitions or successful drilling. To the extent
that we further increase our capital budget during 2008, we anticipate funding these amounts with
borrowings under our credit arrangements.
Our $77 million of short-term investments as of March 31, 2008 consisted entirely of auction
rate securities that are classified as a Level 3 fair value measurement. All such securities are
AAA rated and guaranteed by the United States government. Beginning in February 2008, we
experienced difficulty selling additional securities due to the failure of the auction mechanism
that provides liquidity to these securities. As a result, the interest rate on these securities
has increased from 1.1% to 5.5%. We will attempt to sell these securities every 7-28 days until the
auction succeeds, the issuer calls the securities or the securities
mature. However, there may
be no effective mechanism for selling these securities, and the securities we own may become
long-term investments. Currently, we do not believe such securities are impaired or that the
failure of the auction mechanism will have a material impact on our liquidity given the amount of
our available borrowing capacity under our credit arrangements.
Credit Arrangements. In June 2007, we entered into a new revolving credit facility that
matures in June 2012 and provides for initial loan commitments of $1.25 billion from a syndicate of
financial institutions, led by JPMorgan Chase Bank, as agent. The loan commitments may be increased to a
maximum of $1.65 billion if the existing lenders increase their loan commitments or new financial
institutions are added to the facility. Subject to compliance with covenants in our credit
facility that restrict our ability to incur additional debt, we also have a total of $135 million
borrowing capacity under money market lines of credit with various financial institutions. For a
more detailed description of the terms of our credit arrangements, please see Note 4, Debt, to
our consolidated financial statements appearing earlier in this report.
At April 23, 2008, we had outstanding borrowings of $47 million under our money market lines
of credit and we had approximately $1.3 billion of available borrowing capacity under our credit
arrangements.
Working Capital. Our working capital balance fluctuates as a result of the timing and amount
of borrowings or repayments under our credit arrangements and changes in the fair value of our
outstanding commodity derivative instruments. Without the effects of commodity derivative
instruments, we typically have a working capital deficit or a relatively small amount of positive
working capital because our capital spending generally has exceeded our cash flows from operations
and we generally use excess cash to pay down borrowings under our credit arrangements.
At March 31, 2008, we had a working capital deficit of $359 million compared to a deficit of
$2 million at December 31, 2007. The $359 million deficit at March 31, 2008 is primarily due to
our short-term derivative liability increasing to $354 million at March 31, 2008 from $84 million
at December 31, 2007 as a result of higher oil and gas prices. In addition, our cash and
short-term investments decreased $213 million during the first
quarter of 2008 as we continued to
fund of our capital program. The working capital deficit at March 31, 2008 was slightly offset by
an increase in accounts receivable of $84 million primarily resulting from higher oil and gas
prices and increased production.
Cash Flows from Operations. Cash flows from operations (both continuing and discontinued) are
primarily affected by production and commodity prices, net of the effects of settlements of our
derivative contracts and changes in working capital.
We also have experienced fluctuations in operating cash flows as a result of volatile oil and
natural gas commodity markets and higher operating costs for all of our operations. We sell
substantially all of our natural gas and oil production under floating market contracts. However,
we generally hedge a substantial, but varying, portion of our anticipated future oil and natural
gas production for the next 12-24 months. See Oil and Gas Hedging below. We typically receive
the cash associated with accrued oil and gas sales within 45-60 days of production. As a result,
cash flows from operations and income from operations generally correlate, but cash flows from
operations is impacted by changes in working capital and is not affected by DD&A, writedowns or
other non-cash charges or credits.
27
Our net cash flow from operations was $272 million for the first quarter of 2008, a decrease
of 19% compared to net cash flow from operations of $335 million for the same period in 2007.
Although our first quarter of 2008 production volumes were impacted
by our 2007 property sales, this impact was somewhat offset by
higher commodity prices, increased production from our Mid-Continent and Rocky Mountain divisions,
increased liftings in Malaysia and lower lease operating and interest
expense. In addition, our working capital requirements during
the first quarter of 2008 increased compared to the same period in 2007 as a result of the timing
of receivable collections from purchasers, the timing of payments made by us to vendors and other
operators, and the timing and amount of advances received from our joint operators.
Cash Flows from Investing Activities. Net cash used in investing activities (both continuing
and discontinued) for the first quarter of 2008 was $455 million compared to $520 million for the
same period in 2007.
During the first quarter of 2008, we:
|
|
|
spent $501 million on capital expenditures; |
|
|
|
|
purchased investments of $22 million and redeemed investments of $68 million. |
During the first quarter of 2007, we:
|
|
|
spent $502 million on capital expenditures. |
Capital Expenditures. Our capital spending for the first quarter of 2008 was $513 million, a
7% increase from first quarter 2007 capital spending of $479 million. These amounts exclude
recorded asset retirement costs of $1 million in 2008 and $12 million in 2007. Of the $513 million
spent in 2008, we invested $318 million in domestic exploitation and development, $92 million in
domestic exploration (exclusive of exploitation and leasehold activity), $28 million in domestic
leasehold activity and $75 million internationally. Of the $479 million spent in the first quarter
of 2007, we invested $401 million in domestic exploitation and development, $35 million in domestic
exploration (exclusive of exploitation and leasehold activity), $14 million in domestic leasehold
activity and $29 million internationally.
We
increased our 2008 capital budget to $2 billion from an initial
budget of
$1.6 billion. The budget excludes $115 million of capitalized interest and overhead. The increase
reflects our recent agreement to acquire $227 million of properties in South Texas and subsequent
development drilling activities, bidding success at the most recent Gulf of Mexico lease sale,
development capital for our recent Anduin and Gladden deepwater Gulf of Mexico discoveries, an
additional drilling rig in the Woodford Shale Play and an additional rig in the Monument Butte
field.
Approximately 35% of the $2 billion is allocated to the Mid-Continent, 15% to the Rocky
Mountains, 40% to the Gulf Coast and 10% to international
projects. Since our 2008 capital budget currently exceeds forecasted net cash flow from
operations, we plan to make up the shortfall with cash and short-term investments on hand and
borrowings under our credit arrangements. Actual levels of capital expenditures may vary
significantly due to many factors, including the extent to which properties are acquired, drilling
results, oil and gas prices, industry conditions and the prices and availability of goods and
services. We continue to pursue attractive acquisition opportunities; however, the timing and size
of acquisitions are unpredictable. Depending on the timing of an acquisition we may spend
additional capital during the year of the acquisition for drilling and development activities on
the acquired properties.
Cash Flows from Financing Activities. Net cash flow provided by financing activities (both
continuing and discontinued) for the first quarter of 2008 was $13 million compared to $131 million
of net cash flow provided by financing activities for the same period in 2007.
During the first quarter of 2008, we:
|
|
|
borrowed and repaid $64 million under our credit arrangements; |
|
|
|
|
received proceeds of $9 million from the issuance of shares of our common stock upon
the exercise of stock options; and |
|
|
|
|
received a $4 million tax benefit from the exercise of stock options. |
During the first quarter of 2007, we:
|
|
|
borrowed $453 million and repaid $326 million under our credit arrangements; |
|
|
|
|
received proceeds of $3 million from the issuance of shares of our common stock upon the
exercise of stock options; and |
|
|
|
|
received a $1 million tax benefit from the exercise of stock options. |
28
Contractual Obligations
The table below summarizes our significant contractual obligations by maturity as of March 31,
2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Less than |
|
|
|
|
|
|
|
|
|
|
More than |
|
|
|
Total |
|
|
1 Year |
|
|
1-3 Years |
|
|
4-5 Years |
|
|
5 Years |
|
|
|
(In millions) |
|
Debt: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
7 5/8% Senior Notes due 2011 |
|
$ |
175 |
|
|
$ |
|
|
|
$ |
175 |
|
|
$ |
|
|
|
$ |
|
|
6 5/8% Senior Subordinated Notes due 2014 |
|
|
325 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
325 |
|
6 5/8% Senior Subordinated Notes due 2016 |
|
|
550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total debt |
|
|
1,050 |
|
|
|
|
|
|
|
175 |
|
|
|
|
|
|
|
875 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other obligations: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest payments |
|
|
489 |
|
|
|
71 |
|
|
|
143 |
|
|
|
116 |
|
|
|
159 |
|
Net derivative liabilities (assets) |
|
|
586 |
|
|
|
354 |
|
|
|
236 |
|
|
|
(4 |
) |
|
|
|
|
Asset retirement obligations |
|
|
65 |
|
|
|
6 |
|
|
|
4 |
|
|
|
9 |
|
|
|
46 |
|
Operating leases |
|
|
225 |
|
|
|
116 |
|
|
|
69 |
|
|
|
14 |
|
|
|
26 |
|
Deferred acquisition payments |
|
|
9 |
|
|
|
3 |
|
|
|
4 |
|
|
|
2 |
|
|
|
|
|
Oil and gas activities (1) |
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total other obligations |
|
|
1,394 |
|
|
|
550 |
|
|
|
456 |
|
|
|
137 |
|
|
|
231 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total contractual obligations |
|
$ |
2,444 |
|
|
$ |
550 |
|
|
$ |
631 |
|
|
$ |
137 |
|
|
$ |
1,106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
As is common in the oil and gas industry, we have various contractual commitments pertaining
to exploration, development and production activities. We have work related commitments for,
among other things, drilling wells, obtaining and processing seismic data and fulfilling other
cash commitments. At March 31, 2008, these work related commitments totaled $20 million and
were comprised of $17 million in the United States and $3 million internationally. These
amounts are not included by maturity because their timing cannot be accurately predicted. |
Oil and Gas Hedging
As part of our risk management program, we generally hedge a substantial, but varying, portion
of our anticipated future oil and natural gas production for the next 12-24 months to reduce our
exposure to fluctuations in natural gas and oil prices. In the case of acquisitions, we may hedge
acquired production for a longer period. In addition, we may utilize basis contracts to hedge the
differential between the NYMEX Henry Hub posted prices and those of our physical pricing points.
Reducing our exposure to price volatility helps ensure that we have adequate funds available for
our capital programs and helps us manage returns on some of our
acquisitions and more price sensitive drilling programs.
Our decision on the quantity and price at which we choose to hedge our future production is based
in part on our view of current and future market conditions.
While the use of these hedging arrangements limits the downside risk of adverse price
movements, their use also may limit future revenues from favorable price movements. In addition,
the use of hedging transactions may involve basis risk. Substantially all of our hedging
transactions are settled based upon reported settlement prices on the NYMEX. Historically, a
majority of our hedged natural gas and crude oil production has been sold at market prices that
have had a high positive correlation to the settlement price for such
hedges. With the sale of our
Gulf of Mexico shelf production and the corresponding shift in the geographic distribution of our
natural gas production, we have begun to utilize basis hedges to a greater extent.
The price that we receive for natural gas production from the Gulf of Mexico and onshore Gulf
Coast, after basis differentials, transportation and handling charges, typically averages
$0.40-$0.60 less per MMBtu than the Henry Hub Index. Realized gas prices for our Mid-Continent
properties, after basis differentials, transportation and handling charges, typically average
75-85% of the Henry Hub Index. In light of potential basis risk with respect to our newly acquired
Rocky Mountain assets, we have hedged the basis differential for about 50% of our estimated
production from proved producing fields acquired from Stone Energy through 2012 to lock in the
differential at a weighted average of $1.18 per MMBtu less than the Henry Hub Index. The price we
receive for our Gulf Coast oil production typically averages about $5 per barrel below the NYMEX
West Texas Intermediate (WTI) price. The price we receive for our oil production in the Rocky
Mountains is currently averaging about $13-$15 per barrel below the WTI price. Oil production from
the Mid-Continent typically sells at a $1.00-$1.50 per barrel discount to WTI. Oil sales from our
operations in Malaysia typically sell at Tapis, or about 95% of WTI. Oil sales from our operations
in China typically sell at $10-$15 per barrel less than WTI.
29
Between March 31, 2008 and April 23, 2008, we entered into additional natural gas price
derivative contracts set forth in the table below.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NYMEX Contract Price Per MMBtu |
|
|
Volume in |
|
Additional |
|
Collars |
Period and Type of Contract |
|
MMMBtus |
|
Put |
|
Floors |
|
Ceilings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
October 2008 December
2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts |
|
|
1,220 |
|
|
|
|
|
|
$ |
9.00 |
|
|
$ |
17.60 |
|
3-Way collar contracts |
|
|
610 |
|
|
$ |
7.00 |
|
|
|
9.00 |
|
|
|
20.10 |
|
January 2009 March 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts |
|
|
1,800 |
|
|
|
|
|
|
|
9.00 |
|
|
|
17.60 |
|
3-Way collar contracts |
|
|
900 |
|
|
|
7.00 |
|
|
|
9.00 |
|
|
|
20.10 |
|
April 2009 June 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts |
|
|
910 |
|
|
|
|
|
|
|
8.00 |
|
|
|
13.00 |
|
July 2009 September 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts |
|
|
920 |
|
|
|
|
|
|
|
8.00 |
|
|
|
13.00 |
|
October 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Collar contracts |
|
|
310 |
|
|
|
|
|
|
|
8.00 |
|
|
|
13.00 |
|
New Accounting Standards
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities-an amendment of FASB Statement No. 133. This statement requires enhanced
disclosures about our derivative and hedging activities. This statement is effective for financial statements issued for fiscal years
and interim periods beginning after November 15, 2008. We will adopt SFAS
No. 161 beginning January 1, 2009. We are currently evaluating the impact, if any, the standard
will have on our consolidated financial statements.
General Information
General information about us can be found at www.newfield.com. In conjunction with our web
page, we also maintain an electronic publication entitled @NFX. @NFX is periodically published to
provide updates on our operating activities and our latest publicly announced estimates of expected
production volumes, costs and expenses for the then current quarter. Recent editions of @NFX are
available on our web page. To receive @NFX directly by email, please forward your email address to
info@newfield.com or visit our web page and sign up. Unless specifically incorporated, the
information about us at www.newfield.com or in any edition of @NFX is not part of this report.
Our annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form
8-K, as well as any amendments and exhibits to those reports, are available free of charge through
our website as soon as reasonably practicable after we file or furnish them to the Securities and
Exchange Commission.
30
Forward-Looking Information
This report contains information that is forward-looking or relates to anticipated future
events or results such as planned capital expenditures, the availability and source of capital resources to fund capital
expenditures and other plans and objectives for future operations.
Although we believe that these expectations are reasonable, this information is based upon
assumptions and anticipated results that are subject to numerous uncertainties. Actual results may
vary significantly from those anticipated due to many factors, including:
|
|
|
drilling results; |
|
|
|
|
oil and gas prices; |
|
|
|
|
the prices of goods and services; |
|
|
|
|
the availability of drilling rigs and other support services; |
|
|
|
|
availability of refining capacity for crude oil we produce from our Monument Butte
field; |
|
|
|
|
the availability of capital resources; |
|
|
|
|
labor conditions; |
|
|
|
|
severe weather conditions (such as hurricanes); and |
|
|
|
|
the other factors affecting our business described under the caption Risk Factors in
Item 1A of our annual report on Form 10-K for the year ended December 31, 2007. |
All written and oral forward-looking statements attributable to us or persons acting on our
behalf are expressly qualified in their entirety by such factors.
Commonly Used Oil and Gas Terms
Below are explanations of some commonly used terms in the oil and gas business.
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 hedging transaction.
Barrel or Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume.
Bcf. Billion cubic feet.
Bcfe. Billion cubic feet equivalent, determined using the ratio of six Mcf of natural gas to
one barrel of crude oil or condensate.
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 natural gas field to the
depth of a stratigraphic horizon known to be productive.
Exploitation well. An exploration well drilled to find and produce probable reserves. Most
of the exploitation wells we drill are located in the Mid-Continent or the Monument Butte field.
Exploitation wells in those areas have less risk and less reserve potential and typically may be
drilled at a lower cost than other exploration wells. For internal reporting and budgeting
purposes, we combine exploitation and development activities.
Exploration well. A well drilled to find and produce oil or natural gas reserves that is not
a development 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.
MBbls. One thousand barrels of crude oil or other liquid hydrocarbons.
31
Mcf. One thousand cubic feet.
Mcfe. One thousand cubic feet equivalent, determined using the ratio of six Mcf of natural
gas to one barrel of crude oil or condensate.
MMBbls. One million barrels of crude oil or other liquid hydrocarbons.
MMBtu. One million Btus.
MMMBtu. One billion Btus.
MMcf. One million cubic feet.
MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural
gas to one barrel of crude oil or condensate.
NYMEX. The New York Mercantile Exchange.
Probable reserves. Reserves which analysis of drilling, geological, geophysical and
engineering data does not demonstrate to be proved under current technology and existing economic
conditions, but where such analysis suggests the likelihood of their existence and future recovery.
Proved reserves. In general, the estimated quantities of crude oil, natural gas and natural
gas liquids that geological and engineering data demonstrate with reasonable certainty to be
recoverable in future years from known reservoirs under existing economic and operating conditions.
The SEC provides a complete definition of proved reserves in Rule 4-10(a)(2) of Regulation S-X.
32
Item 3. Quantitative and Qualitative Disclosures About Market Risk
We are exposed to market risk from changes in oil and gas prices, interest rates and foreign
currency exchange rates as discussed below.
Oil and Gas Prices
We generally hedge a substantial, but varying, portion of our anticipated oil and gas
production for the next 12-24 months as part of our risk management program. In the case of
acquisitions, we may hedge acquired production for a longer period. In addition, we may utilize
basis contracts to hedge the differential between NYMEX Henry Hub posted prices and those of our
physical pricing points. We use hedging to reduce our exposure to fluctuations in natural gas and
oil prices. Reducing our exposure to price volatility helps ensure that we have adequate funds
available for our capital programs and helps us manage return on some of our acquisitions and more
price sensitive drilling programs. Our decision on the quantity and price at which we choose to
hedge our production is based in part on our view of current and future market conditions. While
hedging limits the downside risk of adverse price movements, it also may limit future revenues from
favorable price movements. The use of hedging transactions also involves the risk that the
counterparties will be unable to meet the financial terms of such transactions. For a further
discussion of our hedging activities, see the information under the caption Oil and Gas Hedging
in Item 2 of this report and the discussion and tables in Note 7, Commodity Derivative
Instruments, to our financial statements appearing earlier in this report.
Interest Rates
At March 31, 2008, our debt was comprised of:
|
|
|
|
|
|
|
|
|
|
|
Fixed |
|
|
Variable |
|
|
|
Rate Debt |
|
|
Rate Debt |
|
|
|
(In millions) |
|
Bank revolving credit facility |
|
$ |
|
|
|
$ |
|
|
Money market line of credit |
|
|
|
|
|
|
|
|
7 5/8% Senior Notes due 2011(1) |
|
|
125 |
|
|
|
50 |
|
6 5/8% Senior Subordinated Notes due 2014 |
|
|
325 |
|
|
|
|
|
6 5/8% Senior Subordinated Notes due 2016 |
|
|
550 |
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt |
|
$ |
1,000 |
|
|
$ |
50 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
$50 million principal amount of our 7 5/8% Senior Notes due 2011 are subject to interest rate
swaps. These swaps provide for us to pay variable and receive fixed interest payments, and are
designated as fair value hedges of a portion of our outstanding senior notes. |
We consider our interest rate exposure to be minimal because about 95%
of our long-term debt, after taking into account our interest rate swap agreements,
is at fixed rates.
Foreign Currency Exchange Rates
The functional currency for all of our foreign operations is the U.S. dollar. To the extent
that business transactions in these countries are not denominated in the respective countrys
functional currency, we are exposed to foreign currency exchange risk. We consider our current risk
exposure to exchange rate movements, based on net cash flow, to be immaterial. We did not have any
open derivative contracts relating to foreign currencies at March 31, 2008.
33
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 Chief Financial Officer,
of the effectiveness of the design and operation of our disclosure controls and procedures (as
defined in Rule 13a-15(e) of the Securities Exchange Act of 1934). Based upon that evaluation, our
Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and
procedures were effective as of March 31, 2008 in ensuring that material information was
accumulated and communicated to management, and made known to our Chief Executive Officer and Chief
Financial Officer, on a timely basis to allow disclosure as required in this report.
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 Chief Financial Officer,
of our internal control over financial reporting to determine whether any changes occurred during
the first quarter of 2008 that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting. Based on that evaluation, there were no
changes in our internal control over financial reporting or in other factors 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 arising in the ordinary course of
our business. While the outcome of these lawsuits 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.
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 March 31, 2008.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maximum Number |
|
|
|
|
|
|
|
|
|
|
Total Number |
|
(or Approximate |
|
|
|
|
|
|
|
|
of Shares Purchased |
|
Dollar Value) of |
|
|
Total Number |
|
|
|
|
|
as Part of Publicly |
|
Shares that May Yet |
|
|
of Shares |
|
Average Price |
|
Announced Plans |
|
Be Purchased Under |
Period |
|
Purchased (1) |
|
Paid per Share |
|
or Programs |
|
the Plans or Programs |
|
|
January 1 January 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
February 1 February 29, 2008 |
|
|
2,631 |
|
|
$ |
52.65 |
|
|
|
|
|
|
|
|
|
March 1 March 31, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
All of the shares repurchased were surrendered by employees to pay tax withholding upon the
vesting of restricted stock awards. These repurchases were not part of a publicly announced
program to repurchase shares of our common stock. |
34
Item 6. Exhibits
(a) Exhibits:
|
|
|
Exhibit Number |
|
Description |
|
|
|
*31.1
|
|
Certification of Chief Executive Officer of
Newfield 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 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 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 pursuant to 18 U.S.C. Section 1350, as
adopted pursuant to Section 906 of the
Sarbanes-Oxley Act of 2002 |
|
|
|
* |
|
Filed or furnished herewith. |
35
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: April 25, 2008 |
By: |
/s/ TERRY W. RATHERT
|
|
|
|
Terry W. Rathert |
|
|
|
Senior Vice President and Chief Financial Officer |
|
36
EXHIBIT INDEX
|
|
|
Exhibit Number |
|
Description |
|
|
|
*31.1
|
|
Certification of Chief Executive Officer of Newfield
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
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
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
pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 |
|
|
|
* |
|
Filed or furnished herewith. |