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 June 30, 2009
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: 1-4300
APACHE CORPORATION
(Exact name of registrant as specified in its charter)
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Delaware
(State or other jurisdiction of
incorporation or organization)
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41-0747868
(I.R.S. Employer
Identification Number) |
One Post Oak Central, 2000 Post Oak Boulevard, Suite 100, Houston, Texas 77056-4400
(Address of principal executive offices)
Registrants telephone number, including area code: (713) 296-6000
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 has submitted electronically and posted on
its corporate Web site, if any, every Interactive Data File required to be submitted and posted
pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months
(or for such shorter period that the registrant was required to submit and post such files).
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) |
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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
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Number of
shares of registrants common stock outstanding as of June 30, 2009 |
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335,747,077 |
TABLE OF CONTENTS
PART I FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)
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For the Quarter |
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For the Six Months |
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Ended June 30, |
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Ended June 30, |
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2009 |
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2008 |
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2009 |
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2008 |
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(In thousands, except per common share data) |
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REVENUES AND OTHER: |
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Oil and gas production revenues |
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$ |
2,074,344 |
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$ |
3,904,118 |
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$ |
3,677,958 |
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$ |
7,082,067 |
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Other |
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19,034 |
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(3,927 |
) |
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49,245 |
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5,865 |
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2,093,378 |
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3,900,191 |
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3,727,203 |
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7,087,932 |
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OPERATING EXPENSES: |
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Depreciation, depletion and amortization |
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Recurring |
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573,359 |
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627,668 |
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1,153,976 |
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1,248,157 |
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Additional |
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2,818,161 |
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Asset retirement obligation accretion |
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26,483 |
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25,679 |
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53,221 |
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52,176 |
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Lease operating expenses |
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405,273 |
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446,738 |
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802,762 |
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901,376 |
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Gathering and transportation |
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33,479 |
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39,767 |
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66,818 |
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80,743 |
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Taxes other than income |
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115,941 |
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298,548 |
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203,280 |
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541,126 |
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General and administrative |
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90,905 |
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78,872 |
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175,951 |
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161,295 |
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Financing costs, net |
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61,155 |
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39,050 |
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119,742 |
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83,303 |
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1,306,595 |
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1,556,322 |
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5,393,911 |
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3,068,176 |
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INCOME (LOSS) BEFORE INCOME TAXES |
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786,783 |
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2,343,869 |
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(1,666,708 |
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4,019,756 |
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Current income tax provision |
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218,247 |
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702,106 |
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220,741 |
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1,189,906 |
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Deferred income tax provision (benefit) |
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123,816 |
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196,534 |
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(575,229 |
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363,108 |
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NET INCOME (LOSS) |
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444,720 |
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1,445,229 |
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(1,312,220 |
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2,466,742 |
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Preferred stock dividends |
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1,420 |
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1,420 |
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2,840 |
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2,840 |
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INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK |
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$ |
443,300 |
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$ |
1,443,809 |
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$ |
(1,315,060 |
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$ |
2,463,902 |
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NET INCOME (LOSS) PER COMMON SHARE: |
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Basic |
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$ |
1.32 |
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$ |
4.32 |
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$ |
(3.92 |
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$ |
7.38 |
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Diluted |
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$ |
1.31 |
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$ |
4.28 |
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$ |
(3.92 |
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$ |
7.32 |
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The accompanying notes to consolidated financial statements
are an integral part of this statement.
1
APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Unaudited)
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For the Six Months Ended June 30, |
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2009 |
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2008 |
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(In thousands) |
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CASH FLOWS FROM OPERATING ACTIVITIES: |
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Net income (loss) |
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$ |
(1,312,220 |
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$ |
2,466,742 |
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Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
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Depreciation, depletion and amortization |
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3,972,137 |
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1,248,157 |
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Asset retirement obligation accretion |
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53,221 |
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52,176 |
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Provision for (benefit from) deferred income taxes |
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(575,229 |
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363,108 |
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Other |
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104,734 |
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34,250 |
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Changes in operating assets and liabilities: |
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Receivables |
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(173,502 |
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(332,836 |
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Inventories |
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(4,049 |
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(1,720 |
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Advances and other |
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(89,751 |
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(92,352 |
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Deferred charges and other |
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5,871 |
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(133,128 |
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Accounts payable |
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(176,572 |
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246,449 |
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Accrued expenses |
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(376,981 |
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(84,237 |
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Deferred credits and noncurrent liabilities |
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(60,930 |
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(28,696 |
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NET CASH PROVIDED BY OPERATING ACTIVITIES |
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1,366,729 |
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3,737,913 |
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CASH FLOWS FROM INVESTING ACTIVITIES: |
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Additions to oil and gas property |
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(2,117,415 |
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(2,543,077 |
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Additions to gas gathering, transmission and processing facilities |
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(164,723 |
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(245,627 |
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Acquisition of Marathon properties |
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(181,133 |
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Short-term investments |
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791,999 |
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Restricted cash |
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13,880 |
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(94,357 |
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Proceeds from sale of oil and gas properties |
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127 |
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299,937 |
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Other, net |
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(85,526 |
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(25,438 |
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NET CASH USED IN INVESTING ACTIVITIES |
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(1,742,791 |
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(2,608,562 |
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CASH FLOWS FROM FINANCING ACTIVITIES: |
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Commercial paper, credit facility and bank notes, net |
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147,666 |
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(182,351 |
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Payments on fixed-rate notes |
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(100,000 |
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(353 |
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Dividends paid |
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(103,331 |
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(136,145 |
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Common stock activity |
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9,971 |
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28,526 |
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Treasury stock activity, net |
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2,669 |
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3,416 |
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Cost of debt and equity transactions |
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(403 |
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(964 |
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Other |
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9,597 |
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41,139 |
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NET CASH USED IN FINANCING ACTIVITIES |
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(33,831 |
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(246,732 |
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NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS |
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(409,893 |
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882,619 |
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CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR |
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1,181,450 |
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125,823 |
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CASH AND CASH EQUIVALENTS AT END OF PERIOD |
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$ |
771,557 |
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$ |
1,008,442 |
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SUPPLEMENTARY CASH FLOW DATA: |
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Interest paid, net of capitalized interest |
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$ |
122,120 |
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$ |
90,316 |
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Income taxes paid, net of refunds |
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188,251 |
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1,093,752 |
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The accompanying notes to consolidated financial statements
are an integral part of this statement.
2
APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
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June 30, |
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December 31, |
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2009 |
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2008 |
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(In thousands) |
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ASSETS |
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CURRENT ASSETS: |
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Cash and cash equivalents |
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$ |
771,557 |
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$ |
1,181,450 |
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Short-term investments |
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791,999 |
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Receivables, net of allowance |
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1,536,649 |
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1,356,979 |
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Inventories |
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571,612 |
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498,567 |
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Drilling advances |
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176,791 |
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93,377 |
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Derivative instruments |
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67,915 |
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154,280 |
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Prepaid taxes |
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308,516 |
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303,414 |
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Prepaid assets and other |
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52,045 |
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70,908 |
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3,485,085 |
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4,450,974 |
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PROPERTY AND EQUIPMENT: |
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Oil and gas, on the basis of full-cost accounting: |
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Proved properties |
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42,752,798 |
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40,639,281 |
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Unproved properties and properties under
development, not being amortized |
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1,310,031 |
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1,300,347 |
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Gas gathering, transmission and processing facilities |
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3,048,513 |
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2,883,789 |
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Other |
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467,221 |
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452,989 |
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47,578,563 |
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45,276,406 |
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Less: Accumulated depreciation, depletion and amortization |
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(25,288,255 |
) |
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(21,317,889 |
) |
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22,290,308 |
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23,958,517 |
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OTHER ASSETS: |
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Restricted cash |
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13,880 |
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Goodwill, net |
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189,252 |
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|
189,252 |
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Deferred charges and other |
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437,282 |
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573,862 |
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$ |
26,401,927 |
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$ |
29,186,485 |
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The accompanying notes to consolidated financial statements
are an integral part of this statement.
3
APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
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June 30, |
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December 31, |
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2009 |
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2008 |
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(In thousands) |
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LIABILITIES AND SHAREHOLDERS EQUITY |
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CURRENT LIABILITIES: |
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Accounts payable |
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$ |
389,347 |
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$ |
548,945 |
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Accrued operating expense |
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94,804 |
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|
168,531 |
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Accrued exploration and development |
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687,959 |
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|
964,859 |
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Accrued compensation and benefits |
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92,428 |
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|
111,907 |
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Accrued interest |
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89,749 |
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|
91,456 |
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Accrued income taxes |
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|
78,089 |
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|
48,028 |
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Current debt |
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12,656 |
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|
112,598 |
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Asset retirement obligation |
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|
267,929 |
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|
339,155 |
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Other |
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|
95,394 |
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|
134,956 |
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1,808,355 |
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2,520,435 |
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LONG-TERM DEBT |
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4,954,667 |
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4,808,975 |
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DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: |
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Income taxes |
|
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2,502,554 |
|
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3,166,657 |
|
Asset retirement obligation |
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1,585,116 |
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1,555,529 |
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Other |
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|
592,540 |
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|
626,168 |
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4,680,210 |
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|
5,348,354 |
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COMMITMENTS AND CONTINGENCIES (Note 7) |
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SHAREHOLDERS EQUITY: |
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|
Preferred stock, no par value, 5,000,000 shares authorized
Series B, 5.68% Cumulative, $100 million aggregate
liquidation value, 100,000 shares issued and
outstanding |
|
|
98,387 |
|
|
|
98,387 |
|
Common stock, $0.625 par, 430,000,000 shares authorized,
343,613,544 and 342,754,114 shares issued, respectively |
|
|
214,758 |
|
|
|
214,221 |
|
Paid-in capital |
|
|
4,527,358 |
|
|
|
4,472,826 |
|
Retained earnings |
|
|
10,514,200 |
|
|
|
11,929,827 |
|
Treasury stock, at cost, 7,866,467 and 8,044,050 shares,
respectively |
|
|
(223,264 |
) |
|
|
(228,304 |
) |
Accumulated other comprehensive income (loss) |
|
|
(172,744 |
) |
|
|
21,764 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,958,695 |
|
|
|
16,508,721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,401,927 |
|
|
$ |
29,186,485 |
|
|
|
|
|
|
|
|
The accompanying notes to consolidated financial statements
are an integral part of this statement.
4
APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED SHAREHOLDERS EQUITY
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated |
|
|
|
|
|
|
|
|
|
|
|
Series B |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
Total |
|
|
|
Comprehensive |
|
|
|
Preferred |
|
|
Common |
|
|
Paid-In |
|
|
Retained |
|
|
Treasury |
|
|
Comprehensive |
|
|
Shareholders |
|
|
|
Income (Loss) |
|
|
|
Stock |
|
|
Stock |
|
|
Capital |
|
|
Earnings |
|
|
Stock |
|
|
Income (Loss) |
|
|
Equity |
|
|
|
| |
|
|
|
| |
|
|
| |
|
|
(In thousands) |
|
|
| |
|
|
| |
|
|
| |
|
BALANCE AT DECEMBER 31, 2007 |
|
|
|
|
|
|
$ |
98,387 |
|
|
$ |
213,326 |
|
|
$ |
4,367,149 |
|
|
$ |
11,457,592 |
|
|
$ |
(238,264 |
) |
|
$ |
(520,211 |
) |
|
$ |
15,377,979 |
|
Comprehensive income: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
$ |
2,466,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,466,742 |
|
|
|
|
|
|
|
|
|
|
|
2,466,742 |
|
Commodity hedges, net of income tax
benefit of $667,072 |
|
|
(1,256,329 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,256,329 |
) |
|
|
(1,256,329 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
1,210,413 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,840 |
) |
|
|
|
|
|
|
|
|
|
|
(2,840 |
) |
Common ($.40 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(133,435 |
) |
|
|
|
|
|
|
|
|
|
|
(133,435 |
) |
Common shares issued |
|
|
|
|
|
|
|
|
|
|
|
764 |
|
|
|
34,858 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
35,622 |
|
Treasury shares issued, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(270 |
) |
|
|
|
|
|
|
8,590 |
|
|
|
|
|
|
|
8,320 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,453 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
37,453 |
|
FIN 48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19,142 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(19,142 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
85 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
99 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT JUNE 30, 2008 |
|
|
|
|
|
|
$ |
98,387 |
|
|
$ |
214,090 |
|
|
$ |
4,420,133 |
|
|
$ |
13,788,073 |
|
|
$ |
(229,674 |
) |
|
$ |
(1,776,540 |
) |
|
$ |
16,514,469 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT DECEMBER 31, 2008 |
|
|
|
|
|
|
$ |
98,387 |
|
|
$ |
214,221 |
|
|
$ |
4,472,826 |
|
|
$ |
11,929,827 |
|
|
$ |
(228,304 |
) |
|
$ |
21,764 |
|
|
$ |
16,508,721 |
|
Comprehensive loss: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net loss |
|
$ |
(1,312,220 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,312,220 |
) |
|
|
|
|
|
|
|
|
|
|
(1,312,220 |
) |
Commodity hedges, net of income tax
benefit of $108,393 |
|
|
(194,508 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(194,508 |
) |
|
|
(194,508 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss |
|
$ |
(1,506,728 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,840 |
) |
|
|
|
|
|
|
|
|
|
|
(2,840 |
) |
Common ($.30 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(100,567 |
) |
|
|
|
|
|
|
|
|
|
|
(100,567 |
) |
Common shares issued |
|
|
|
|
|
|
|
|
|
|
|
537 |
|
|
|
(3,886 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,349 |
) |
Treasury shares issued, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,840 |
) |
|
|
|
|
|
|
5,040 |
|
|
|
|
|
|
|
200 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63,356 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
63,356 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(98 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(98 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT JUNE 30, 2009 |
|
|
|
|
|
|
$ |
98,387 |
|
|
$ |
214,758 |
|
|
$ |
4,527,358 |
|
|
$ |
10,514,200 |
|
|
$ |
(223,264 |
) |
|
$ |
(172,744 |
) |
|
$ |
14,958,695 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The accompanying notes to consolidated financial statements
are an integral part of this statement.
5
APACHE CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Unaudited)
0. GENERAL ACCOUNTING DESCRIPTION
These
financial statements have been prepared by Apache Corporation (Apache or the Company)
without audit, pursuant to the rules and regulations of the Securities and Exchange Commission
(SEC). They reflect all adjustments that are, in the opinion of management, necessary for a fair
statement of the results for the interim periods, on a basis consistent with the annual audited
financial statements. All such adjustments are of a normal recurring nature. Certain information,
accounting policies and footnote disclosures normally included in financial statements prepared in
accordance with GAAP have been omitted pursuant to such rules and regulations, although the Company
believes that the disclosures are adequate to make the information presented not misleading. This
Quarterly Report on Form 10-Q should be read along with the Annual Report on Form 10-K for the
fiscal year ended December 31, 2008, which contains a summary of the Companys significant
accounting policies and other disclosures. Additionally, the Companys financial statements for
prior periods include reclassifications that were made to conform to the current period
presentation.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
As of June 30, 2009, Apaches significant accounting policies are consistent with those
discussed in Note 1 of its consolidated financial statements contained in the Annual Report on Form
10-K for the fiscal year ended December 31, 2008.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make
estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure
of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period.
Significant estimates with regard to these financial statements
include the estimate of proved oil and gas reserves and related
present value estimates of future net cash flows there from, asset
retirement obligations, income taxes, valuation of derivative
instruments and contingency obligations including legal and
environmental risks and exposures. Actual results could differ from those estimates.
Recently Adopted Accounting Pronouncements
In December 2007, the Financial Accounting Standards Board (FASB) issued Statement of
Financial Accounting Standards (SFAS) No. 141 (Revised), Business Combinations (SFAS No. 141
(R)), which was amended by FASB Staff Position (FSP) FAS No. 141 (R)-1 in April 2009. The
statement broadens the definition of a business combination to include all transactions or other
events in which control of one or more businesses is obtained. Further, the statement establishes
principles and requirements for how an acquirer recognizes and measures in its financial statements
the identifiable assets acquired, the liabilities assumed, any non-controlling interests in the
acquiree and the goodwill acquired. Primarily, the statement requires the acquiring entity in a
business combination to recognize the fair value of all the assets acquired and liabilities assumed
in the transaction. It also modifies disclosure requirements. Apache adopted SFAS No. 141 (R) and
FSP FAS No. 141 (R)-1 effective January 1, 2009. However, since the Company did not close any
material business combinations during the six months ended June 30, 2009, the adoption had a
minimal impact on the Companys consolidated financial statements.
Also in December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements. This statement amends Accounting Research Bulletin No. 51, Consolidated
Financial Statements. SFAS No. 160 establishes accounting and reporting standards for the
noncontrolling interests in a subsidiary and for the deconsolidation of a subsidiary. It clarifies
that a noncontrolling interest in a subsidiary, sometimes called a minority interest, is an
ownership interest in the consolidated entity that should be reported as equity in the consolidated
financial statements. Additionally, the amounts of consolidated net income attributable to both
the parent and the noncontrolling interest must be reported separately on the face of the income
statement. Apache adopted SFAS No. 160 as of January 1, 2009. There were no noncontrolling
interests at the adoption date. Adoption did not impact the Companys financial position or
results of operations.
6
In March 2008, the FASB issued SFAS No. 161, Disclosures about Derivative Instruments and
Hedging Activities. SFAS No. 161 amends and expands the disclosure requirements of SFAS No. 133,
Accounting for Derivative Instruments and Hedging Activities, and requires qualitative
disclosures about objectives and strategies for using derivative instruments, quantitative
disclosures about fair value of amounts of derivative instruments and related gains and losses, and
disclosures about credit risk-related contingent features in derivative agreements. SFAS No. 161
is effective for financial statements issued for fiscal years and interim periods beginning after
November 15, 2008. Apache adopted SFAS No. 161 as of January 1, 2009. The statement provides only
for enhanced disclosures. Therefore, adoption of this standard had no impact on the Companys
financial position or results of operations.
In June 2008, the FASB issued FSP Emerging Issues Task Force (EITF) Issue No. 03-6-1,
Determining Whether Instruments Granted in Share-Based Payment Transactions Are Participating
Securities. FSP EITF Issue No. 03-6-1 addresses whether instruments granted in share-based payment
transactions should be considered participating securities for the purposes of applying the
two-class method of calculating earnings per share (EPS) pursuant to FASB Statement No. 128,
Earnings Per Share. This FSP concludes that unvested share-based payment awards that contain
rights to receive nonforfeitable dividends or dividend equivalents are participating securities
prior to vesting and, therefore, should be included in the earnings allocations in computing basic
EPS under the two-class method. Apache adopted FSP EITF Issue No. 03-6-1 effective January 1,
2009. The number of unvested shares subject to the two-class method had a negligible impact on
Apaches earnings per share.
In April 2009, the FASB issued FSP FAS No. 107-1 and APB Opinion No. 28-1, Interim
Disclosures About Fair Value of Financial Instruments, which requires quarterly fair value
disclosures for financial instruments that are not reflected on the Companys Consolidated Balance
Sheet at fair value in interim financial statements effective for interim periods ending after June
15, 2009. Apache adopted the new standard for the quarter ended June 30, 2009. Adoption had no
impact on the Companys financial position or results of operations. See Note
9 Fair Value Measurements of this Form 10-Q for interim disclosures required by FSP SFAS 107-1 and APB 28-1.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events, which establishes general
standards of accounting for and disclosure of events that occur after the balance sheet date but
before financial statements are issued. In particular, SFAS No. 165 sets forth:
|
|
|
The period after the balance sheet date during which management of a reporting entity
should evaluate events or transactions that may occur for potential recognition or
disclosure in the financial statements; and |
|
|
|
The circumstances under which an entity should recognize events or transactions
occurring after the balance sheet date in its financial statements; and |
|
|
|
The disclosures that an entity should make about events or transactions that occurred
after the balance sheet date. |
SFAS No. 165 is effective for interim or annual periods ending after June 15, 2009, and is to
be applied prospectively. Apache adopted SFAS No. 165 as of June 30, 2009. For evaluation of
subsequent events, see Note 8 Subsequent Events of this Form 10-Q.
New Pronouncements Issued But Not Yet Adopted
In December 2008, the FASB issued FSP FAS No. 132(R)-1, Employers Disclosures about
Postretirement Benefit Plan Assets. This FSP requires additional disclosures about plan assets of
a defined benefit pension or other postretirement plan, including investment strategies, major
categories of plan assets, concentrations of risk within plan assets, inputs and valuation
techniques used to measure the fair value of plan assets and the effect of fair value measurements
using significant unobservable inputs on changes in plan assets for the period. FSP FAS No.
132(R)-1 is effective for fiscal years ending after December 15, 2009, with earlier application
permitted. The statement provides only for enhanced disclosures and does not require additional
interim disclosures. Adoption will have no impact on the Companys financial position or results
of operations.
7
In January 2009, the Securities and Exchange Commission (SEC) issued Release No. 33-8995,
Modernization of Oil and Gas Reporting, amending oil and gas reporting requirements under Rule
4-10 of Regulation S-X and Industry Guide 2 in Regulation S-K and bringing full-cost accounting
rules into alignment with the revised disclosure requirements. The new rules include changes to
the pricing used to estimate reserves, the ability to include nontraditional resources in reserves,
the use of new technology for determining reserves and permitting disclosure of probable and
possible reserves. The final rules are effective for registration statements filed on or after
January 1, 2010, and for annual reports for fiscal years ending on or after December 31, 2009. The
Company is continuing to evaluate the impact of this release.
In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards
CodificationTM and the Hierarchy of Generally Accepted Accounting Principles. SFAS No.
168 establishes the FASB Accounting Standards CodificationTM (Codification), which
officially commenced July 1, 2009, to become the single source of authoritative U.S. GAAP
recognized by the FASB to be applied by nongovernmental entities. Rules and interpretive releases
of the SEC under authority of federal securities laws are also sources of authoritative GAAP for
SEC registrants. All other accounting literature excluded from the Codification will be considered
nonauthoritative. The subsequent issuances of new standards will be in the form of Accounting
Standards Updates that will be included in the Codification. Generally, the Codification is not
expected to change U.S. GAAP. SFAS No. 168 is effective for financial statements issued for
interim and annual periods ending after September 15, 2009. Apache will adopt SFAS No. 168 for the
quarter ending September 30, 2009. The Company is currently evaluating the effect of the standard
on its financial statement disclosures, as all future references to authoritative accounting
literature will be referenced in accordance with the Codification.
2. DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES
Objectives and Strategies for Using Derivative Instruments
The Company is exposed to fluctuations in crude oil and natural gas prices on the majority of
its worldwide production. Management believes it is prudent to manage the variability in cash
flows on a portion of its crude oil and natural gas production. The Company utilizes various types
of derivative financial instruments to manage fluctuations in cash flows resulting from changes in
commodity prices. Derivative instruments typically entered into by the Company and designated as
cash flow hedges are swaps and options.
Fair Value of Derivatives
All of the Companys derivative instruments are reflected as either assets or liabilities at
fair value in the Consolidated Balance Sheet. Note 9 Fair Value Measurements of this Form 10-Q
discusses the methods and assumptions used to estimate the fair values of the Companys commodity
derivative instruments and gross amounts of commodity derivative assets and liabilities.
Counterparty Risk
The use of derivative transactions exposes the Company to counterparty credit risk, or the
risk that a counterparty will be unable to meet its commitments. Apaches commodity derivative
instruments are with a diversified group of counterparties, primarily financial institutions. To
reduce the concentration of exposure to any individual counterparty,
Apache had positions with 13
counterparties as of June 30, 2009. Apache enters into derivative transactions with counterparties
rated A- or higher by Standard & Poors and A3 or higher by Moodys. The Company monitors
counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in
counterparties creditworthiness. In addition, even if such changes are not sudden, the Company
may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of
these counterparties not perform, Apache may not realize the benefit of some of its derivative
instruments under lower commodity prices and/or may incur a loss.
The Company executes commodity derivative transactions under master agreements that have
netting provisions that provide for offsetting payables against receivables. In general, if a
party to a derivative transaction incurs a material deterioration, as defined in the applicable
agreement, in its credit ratings, the other party will have the right to demand the posting of
collateral, demand a transfer or terminate the arrangement.
8
Commodity Derivative Instruments
Approximately eight percent of the Companys worldwide oil and natural gas production was
subject to financial derivative hedges for the second quarter and six-month period of 2009. As of
June 30, 2009, Apache had the following open crude oil
derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Weighted |
Production |
|
|
|
|
|
Average |
|
Average |
Period |
|
Mbbls |
|
Floor Price (1) |
|
Ceiling Price (1) |
2009 |
|
|
6,072 |
|
|
$ |
63.24 |
|
|
$ |
78.13 |
|
2010 |
|
|
8,399 |
|
|
|
63.98 |
|
|
|
74.96 |
|
2011 |
|
|
8,027 |
|
|
|
67.78 |
|
|
|
77.91 |
|
2012 |
|
|
4,748 |
|
|
|
69.73 |
|
|
|
75.44 |
|
2013 |
|
|
1,451 |
|
|
|
72.01 |
|
|
|
72.01 |
|
2014 |
|
|
76 |
|
|
|
74.50 |
|
|
|
74.50 |
|
|
|
|
(1) |
|
Crude oil prices represent a weighted average of all
fixed-price swap
contracts and collars. |
As of June 30, 2009, Apache had the following open natural gas derivative positions:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
Weighted |
Production |
|
MMBtu (1) |
|
Average |
|
Average |
Period |
|
(in 000s) |
|
Floor Price (1) |
|
Ceiling Price (1) |
2009 |
|
|
30,513 |
|
|
$ |
5.99 |
|
|
$ |
8.35 |
|
2010 |
|
|
22,299 |
|
|
|
5.62 |
|
|
|
5.82 |
|
2011 |
|
|
28,685 |
|
|
|
6.12 |
|
|
|
6.18 |
|
2012 |
|
|
37,437 |
|
|
|
6.26 |
|
|
|
6.39 |
|
2013 |
|
|
1,825 |
|
|
|
7.05 |
|
|
|
7.05 |
|
2014 |
|
|
755 |
|
|
|
7.23 |
|
|
|
7.23 |
|
|
|
|
(1) |
|
Natural gas prices and volumes represent a weighted average of all
fixed-price swap contracts and collars for U.S. and Canadian denominated contracts entered
into on a per million British thermal units (MMBtu) basis and on a per gigajoule (GJ)
basis, respectively. Canadian gas contracts are converted to U.S. dollars utilizing a
period-end exchange rate and are converted to an MMBtu equivalent for purposes of this
table. Natural gas contracts are settled primarily against NYMEX Henry Hub, various Inside
FERC indices and the AECO Index. |
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
The Company accounts for derivative instruments and hedging activity in accordance with SFAS
No. 133, Accounting for Derivative Instruments and Hedging Activities, as amended, and all
derivative instruments are reflected as either assets or liabilities at fair value in the
Consolidated Balance Sheet. These fair values are recorded by netting asset and liability
positions where counterparty master netting arrangements contain provisions for net settlement.
The fair market value of the Companys derivative assets and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Current Assets: Derivative instruments |
|
$ |
68 |
|
|
$ |
154 |
|
Other Assets: Deferred charges and other |
|
|
7 |
|
|
|
65 |
|
|
|
|
|
|
|
|
Total Assets |
|
|
75 |
|
|
|
219 |
|
|
|
|
|
|
|
|
Current Liabilities: Other |
|
|
37 |
|
|
|
|
|
Noncurrent Liabilities: Other |
|
|
131 |
|
|
|
7 |
|
|
|
|
|
|
|
|
Total Liabilities |
|
$ |
168 |
|
|
$ |
7 |
|
|
|
|
|
|
|
|
9
Commodity Derivative Activity Recorded in Statement of Consolidated Operations
The following table summarizes the effect of derivative instruments on the Companys Statement
of Consolidated Operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended |
|
|
For the Six Months Ended |
|
|
|
Gain (Loss) on Derivatives |
|
|
June 30, |
|
|
June 30, |
|
|
|
Recognized in Operations |
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(In millions) |
|
Gain (loss)
reclassified from
accumulated other
comprehensive
income (loss) into
operations (effective portion) |
|
Oil and Gas Production Revenues |
|
$ |
50 |
|
|
$ |
(220 |
) |
|
$ |
106 |
|
|
$ |
(313 |
) |
Gain (loss) on
derivatives
recognized in
operations
(ineffective
portion and basis) |
|
Revenues and Other: Other |
|
$ |
1 |
|
|
$ |
5 |
|
|
$ |
(2 |
) |
|
$ |
5 |
|
Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)
As of June 30, 2009, substantially all of the Companys derivative instruments were designated
as cash flow hedges in accordance with SFAS No. 133. A reconciliation of the components of
accumulated other comprehensive income (loss) in the Statement of Consolidated Shareholders Equity
related to Apaches cash flow hedges is presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
Before tax |
|
|
After tax |
|
|
|
(In millions) |
|
Unrealized gain on derivatives at December 31, 2008 |
|
$ |
212 |
|
|
$ |
138 |
|
Realized amounts reclassified into earnings |
|
|
(106 |
) |
|
|
(72 |
) |
Net change in derivative fair value |
|
|
(199 |
) |
|
|
(124 |
) |
Ineffectiveness and basis swaps reclassified into earnings |
|
|
2 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on derivatives at June 30, 2009 |
|
$ |
(91 |
) |
|
$ |
(57 |
) |
|
|
|
|
|
|
|
Based on market prices as of June 30, 2009, the Companys net unrealized earnings in
accumulated other comprehensive income (loss) for commodity derivatives designated as cash flow
hedges totaled a loss of $91 million ($57 million after tax). Gains and losses on hedges are
realized in future earnings through mid-2014, contemporaneously with the related sales of natural
gas and crude oil production applicable to specific hedges. Included in accumulated other
comprehensive income (loss) at June 30, 2009 is a net gain of approximately $34 million ($26
million after tax) that applies to the next 12 months; however, estimated and actual amounts are
likely to vary materially as a result of changes in market conditions.
3. DEBT
As of June 30, 2009, the Company had unsecured committed revolving syndicated bank credit
facilities totaling $2.3 billion. The facilities consist of a $1.5 billion facility and a $450
million facility in the U.S., a $200 million facility in Australia and a $150 million facility in
Canada. There are no outstanding borrowings or commercial paper at quarter-end, and the full $2.3
billion of unsecured credit facilities are available to the Company.
The Company has available a $1.95 billion commercial paper program, which generally enables
Apache to borrow funds for up to 270 days at competitive interest rates. The commercial paper
program is fully supported by available borrowing capacity under U.S. committed credit facilities,
which expire in 2013.
One of the Companys Australian subsidiaries has a secured revolving syndicated credit
facility for its Van Gogh and Pyrenees oil developments, offshore Western Australia. The facility
provides for total commitments of $350 million, with availability determined by a borrowing base
formula. The borrowing base was set at $350 million and will be redetermined after the fields
commence production and certain tests have been met, and semi-annually thereafter. The outstanding
balance under the facility as of June 30, 2009 and December 31, 2008, respectively, was $245
million and $100 million.
10
At June 30, 2009 and December 31, 2008, there was $12.2 million and $12.6 million,
respectively, borrowed on uncommitted overdraft lines in Argentina.
On March 15, 2009, $100 million of Apache Finance Pty Ltd (Apache Finance Australia) 7.0%
notes matured and were repaid using existing cash balances.
Financing Costs, Net
Financing costs incurred during the periods noted are composed of the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended |
|
|
For the Six Months Ended |
|
|
|
June 30, |
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Interest expense |
|
$ |
77,363 |
|
|
$ |
66,328 |
|
|
$ |
156,277 |
|
|
$ |
135,635 |
|
Amortization of deferred loan costs |
|
|
1,365 |
|
|
|
829 |
|
|
|
2,773 |
|
|
|
1,680 |
|
Capitalized interest |
|
|
(14,972 |
) |
|
|
(22,810 |
) |
|
|
(30,981 |
) |
|
|
(44,387 |
) |
Interest income |
|
|
(2,601 |
) |
|
|
(5,297 |
) |
|
|
(8,327 |
) |
|
|
(9,625 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing costs, net |
|
$ |
61,155 |
|
|
$ |
39,050 |
|
|
$ |
119,742 |
|
|
$ |
83,303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4. INCOME TAXES
The Company estimates its annual effective income tax rate in recording its quarterly
provision for income taxes in the various jurisdictions in which the Company operates. Statutory
tax rate changes and other significant or unusual items are recognized as discrete items in the
quarter in which they occur. No significant discrete tax events occurred during the second quarter
of 2009. The year-to-date tax provision includes the tax impact of the non-cash write-down of
proved oil and gas properties recorded as a discrete item in the first quarter of 2009.
Apache and its subsidiaries are subject to U.S. federal income tax as well as income tax in
various state and foreign jurisdictions. The Companys tax reserves are related to tax years that
may be subject to examination by the relevant taxing authority.
The Company is in Administrative Appeals with the United States Internal Revenue Service (IRS)
regarding the 2004 and 2005 tax years and under IRS audit for the 2006 and 2007 tax years. The
Company is also under audit in various states and in most of the Companys foreign jurisdictions as
part of its normal course of business.
11
5. CAPITAL STOCK
Net Income (Loss) per Common Share
A reconciliation of the components of basic and diluted net income (loss) per common share is
presented in the table below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
Income |
|
|
Shares |
|
|
Per Share |
|
|
Income |
|
|
Shares |
|
|
Per Share |
|
|
|
|
|
|
|
(In thousands, except per share amounts) |
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income attributable to common stock |
|
$ |
443,300 |
|
|
|
335,637 |
|
|
$ |
1.32 |
|
|
$ |
1,443,809 |
|
|
|
334,208 |
|
|
$ |
4.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Dilutive Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and other |
|
|
|
|
|
|
1,728 |
|
|
|
|
|
|
|
|
|
|
|
3,468 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income attributable to common
stock, including assumed
conversions |
|
$ |
443,300 |
|
|
|
337,365 |
|
|
$ |
1.31 |
|
|
$ |
1,443,809 |
|
|
|
337,676 |
|
|
$ |
4.28 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
Loss |
|
|
Shares |
|
|
Per Share |
|
|
Income |
|
|
Shares |
|
|
Per Share |
|
|
|
|
|
|
|
(In thousands, except per share amounts) |
|
|
|
|
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) attributable
to common stock |
|
$ |
(1,315,060 |
) |
|
|
335,372 |
|
|
$ |
(3.92 |
) |
|
$ |
2,463,902 |
|
|
|
333,801 |
|
|
$ |
7.38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Dilutive Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) attributable
to common stock, including
assumed conversions |
|
$ |
(1,315,060 |
) |
|
|
335,372 |
|
|
$ |
(3.92 |
) |
|
$ |
2,463,902 |
|
|
|
336,802 |
|
|
$ |
7.32 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The diluted earnings per share calculation excludes options and restricted stock that
were anti-dilutive totaling 4.1 million and 3.9 million for the quarter and six months ending June
30, 2009, respectively, and 380,000 for the quarter and six months ending June 30, 2008. As more
fully described in Note 1 Summary of Significant Accounting Policies of this Form 10-Q, the
Company adopted the provisions of FSP EITF Issue No. 03-6-1, Determining Whether Instruments
Granted in Share-Based Payment Transactions Are Participating Securities, effective January 1,
2009. The adoption of FSP EITF Issue No. 03-6-1 had a negligible impact on Apaches earnings per
share.
Common and Preferred Stock Dividends
For each quarter ending June 30, 2009 and 2008, Apache paid $50 million in dividends on its
common stock. For the six-month periods ended June 30, 2009 and 2008, the Company paid $100
million and $133 million, respectively. The higher common stock dividends for the first six months
of 2008 were attributable to a special cash dividend of 10 cents per common share paid March 18,
2008. In addition, for each of the three- and six-month periods ended June 30, 2009 and 2008,
Apache paid a total of $1.4 million and $2.8 million, respectively, in dividends on its Series B
Preferred Stock.
Stock-Based Compensation
Share Appreciation Plans The Company utilizes share appreciation plans from time to time to
provide incentives for substantially all full-time employees to increase Apaches share price
within a stated measurement period. To achieve the payout, the Companys stock price must close at
or above a stated threshold for 10 out of any 30 consecutive trading days before the end of the
stated period. Since 2005, two separate share appreciation plans have been approved. A summary of
these plans follows:
12
|
|
|
On May 7, 2008, the Stock Option Plan Committee of the Companys Board of Directors,
pursuant to the Companys 2007 Omnibus Equity Compensation Plan, approved the 2008 Share
Appreciation Program, with a target to increase Apaches share price to $216 by the end of
2012 and an interim goal of $162 to be achieved by the end of 2010. Any awards under the
plan would be payable in five equal annual installments. As of June 30, 2009, neither
share price threshold had been met. |
|
|
|
On May 5, 2005, the Companys stockholders approved the 2005 Share Appreciation Plan,
with a target to increase Apaches share price to $108 by the end of 2008 and an interim
goal of $81 to be achieved by the end of 2007. Awards under the plan are payable in four
equal annual installments to eligible employees remaining with the Company. Apaches share
price exceeded the interim $81 threshold for the 10-day requirement as of June 14, 2007,
and the first and second installments were awarded in July 2007 and 2008. The third
installment was awarded in June 2009. Apaches share price exceeded the $108 threshold for
the 10-day requirement as of February 29, 2008, and the first and second installments were
awarded in March of 2008 and 2009. |
6. ASSET RETIREMENT OBLIGATION
The following table describes changes to the Companys asset retirement obligation (ARO)
liability for the six months ended June 30, 2009:
|
|
|
|
|
|
|
(In thousands) |
|
Asset retirement obligation at December 31, 2008 |
|
$ |
1,894,684 |
|
Liabilities incurred |
|
|
93,706 |
|
Liabilities settled |
|
|
(188,566 |
) |
Accretion expense |
|
|
53,221 |
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation at June 30, 2009 |
|
|
1,853,045 |
|
|
|
|
|
|
Less current portion |
|
|
267,929 |
|
|
|
|
|
Asset retirement obligation, long-term |
|
$ |
1,585,116 |
|
|
|
|
|
The ARO reflects the estimated present value of the amount of dismantlement, removal, site
reclamation and similar activities associated with Apaches oil and gas properties. The Company
utilizes current retirement costs to estimate the expected cash outflows for retirement
obligations. To determine the current present value of this obligation, some key assumptions the
Company must estimate include the ultimate productive life of the properties, a risk-adjusted
discount rate and an inflation factor. To the extent future revisions to these assumptions impact
the present value of the existing ARO liability, a corresponding adjustment is made to the oil and
gas property balance.
Liabilities settled primarily relate to individual properties plugged and abandoned during the
period. Most of the activity was in the Gulf of Mexico, a portion of which relates to the
continued abandonment activity on platforms toppled in 2005 during Hurricanes Katrina and Rita and
in 2008 during Hurricane Ike.
7. COMMITMENTS AND CONTINGENCIES
Apache is party to various legal actions arising in the ordinary course of business, including
litigation and governmental and regulatory controls. The Company has an accrued liability of
approximately $19 million for all legal contingencies that are deemed to be probable of occurring
and can be reasonably estimated. Apaches estimates are based on information known about the
matters and its experience in contesting, litigating and settling similar matters. Although actual
amounts could differ from managements estimate, none of the actions are believed by management to
involve future amounts that would be material to Apaches financial position or results of
operations after consideration of recorded accruals. It is managements opinion that the loss for
any other litigation matters and claims that are reasonably possible to occur will not have a
material adverse affect on the Companys financial position or results of operations.
13
Legal Matters
Grynberg As more fully described in Note 9 of the financial statements in our Annual Report
on Form 10-K for our 2008 fiscal year, in 1997, Jack J. Grynberg began filing lawsuits against
other natural gas producers, gatherers and pipelines claiming that the defendants have underpaid
royalty to the federal government and Indian tribes by mismeasurement of the volume and heating
content of natural gas and are responsible for acts of others who mis-measured natural gas. The
claims filed against Apache in 2005 were dismissed, though Mr. Grynberg appealed the dismissal. On
March 17, 2009, the United States Court of Appeals for the Tenth Circuit affirmed the dismissal,
and on May 4, 2009, the Tenth Circuit denied Mr. Grynbergs petition for rehearing. No other
material changes in this matter have occurred since the filing of our most recent Annual Report on
Form 10-K.
Argentine Environmental Claims As more fully described in Note 9 of the financial statements
in our annual report on Form 10-K for our 2008 fiscal year, in connection with the Pioneer
acquisition in 2006, the Company acquired a subsidiary of Pioneer in Argentina (PNRA) that is
involved in various administrative proceedings with environmental authorities in the Neuquén
Province relating to permits for and discharges from operations in that province. In addition,
PNRA was named in a suit initiated against oil companies operating in the Neuquén basin entitled
Asociación de Superficiarios de la Patagonia v. YPF S.A., et. al., originally filed on August 21,
2003, in the Argentine National Supreme Court of Justice relating to various environmental and
remediation claims. No material change in the status of these matters has occurred since the
filing of our most recent Annual Report on Form 10-K.
Louisiana Restoration As more fully described in Note 9 of the financial statements in our
annual report on Form 10-K for our 2008 fiscal year, numerous surface owners have filed claims or
sent demand letters to various oil and gas companies, including Apache, claiming that, under either
expressed or implied lease terms or Louisiana law, they are liable for damage measured by the cost
of restoration of leased premises to their original condition as well as damages for contamination
and cleanup. No material change in the status of these matters has occurred since the filing of
our most recent Annual Report on Form 10-K.
Australia Gas Pipeline Force Majeure As more fully described in Note 9 of the financial
statements in our annual report on Form 10-K for our 2008 fiscal year, Company subsidiaries
reported a pipeline explosion that interrupted deliveries of natural gas in Australia to customers
under various long-term contracts. On May 27, 2009, the Department of Mines and Petroleum of
Western Australia filed a prosecution notice in the Magistrates Court of Western Australia,
charging Apache Northwest Pty Ltd and its co-licensees with failure to maintain a pipeline in good
condition and repair under the Petroleum Pipelines Act 1969, Section 38(b). The maximum fine
associated with the alleged offense is AUD$50,000. The Company subsidiary does not believe that
the charge has merit and plans to vigorously pursue its defenses. No material change in the status
of these matters has occurred since the filing of our most recent Annual Report on Form 10-K.
Environmental Matters
As of June 30, 2009, the Company had an undiscounted reserve for environmental remediation of
approximately $28 million. The Company is not aware of any environmental claims existing as of
June 30, 2009 that have not been provided for or would otherwise have a material impact on its
financial position or results of operations. There can be no assurance, however, that current
regulatory requirements will not change or past non-compliance with environmental laws will not be
discovered on the Companys properties.
8. SUBSEQUENT EVENTS
Subsequent events have been evaluated for recognition and disclosure through August 7, 2009,
the date these financial statements were filed with the SEC. No significant subsequent events have
been identified.
9. FAIR VALUE MEASUREMENTS
SFAS No. 157, Fair Value Measurements, provides a hierarchy that prioritizes and defines the
types of inputs used to measure fair value. The fair value hierarchy gives the highest priority to
Level 1 inputs, which consist of unadjusted quoted prices for identical instruments in active
markets. Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are
derived from inputs that are significant and unobservable, and these valuations have the lowest
priority.
14
Assets and Liabilities Measured at Fair Value on a Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis in Apaches
Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair
values:
Cash, Cash Equivalents, Short-Term Investments, Accounts Receivable and Accounts Payable The
carrying amounts approximate fair value due to the short-term nature or maturity of the
instruments.
Commodity Derivative Instruments Apaches commodity derivative instruments consist of
variable-to-fixed price commodity swaps and options. The Company estimates the fair values of
derivative instruments using published commodity futures price strips for the underlying
commodities as of the date of the estimate. The fair values of the Companys derivative
instruments are not actively quoted in the open market and are valued using forward commodity price
curves provided by a third-party, which are Level 2 inputs (see Note 2 Derivative Instruments and
Hedging Activities of this Form 10-Q).
The following table presents the Companys material assets and liabilities measured at fair
value on a recurring basis for each hierarchy level:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
|
Fair Value Measurements Using |
|
|
|
|
|
|
|
|
Quoted Price |
|
Significant |
|
Significant |
|
|
|
|
|
|
|
|
in Active |
|
Other |
|
Unobservable |
|
|
|
|
|
|
|
|
Markets |
|
Inputs |
|
Inputs |
|
Total Fair |
|
|
|
Carrying |
|
|
(Level 1) |
|
(Level 2) |
|
(Level 3) |
|
Value |
|
Netting (1) |
|
Amount |
|
|
|
|
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
Assets: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative
Instruments |
|
$ |
|
|
|
$ |
88 |
|
|
$ |
|
|
|
$ |
88 |
|
|
$ |
(13 |
) |
|
$ |
75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative
Instruments |
|
|
|
|
|
|
181 |
|
|
|
|
|
|
|
181 |
|
|
|
(13 |
) |
|
|
168 |
|
|
|
|
(1) |
|
The derivative fair values above are based on analysis of each contract as
required by SFAS No. 157. Derivative assets and liabilities with the same counterparty are
presented here on a gross basis, even where the legal right of offset exists. See Note 2
Derivative Instruments and Hedging Activities of this Form 10-Q for a discussion of net
amounts recorded on the Consolidated Balance Sheet at June 30, 2009. |
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Certain assets and liabilities are reported at fair value on a nonrecurring basis in Apaches
Consolidated Balance Sheet. The following methods and assumptions were used to estimate the fair
values:
Asset Retirement Obligations Incurred in Current Period Apache estimates the fair value of
asset retirement obligations (AROs) based on discounted cash flow projections using numerous
estimates, assumptions and judgments regarding such factors as the existence of a legal obligation
for an ARO; estimated probabilities, amounts and timing of settlements; the credit-adjusted
risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the
current period were Level 3 fair value measurements. Note 6 Asset Retirement Obligation of this
Form 10-Q provides a summary of changes in the ARO liability.
Debt The Companys debt is recorded at the carrying amount on its Consolidated Balance Sheet.
In accordance with FSP FAS No. 107-1 and APB Opinion No. 28-1, certain disclosures about the fair
value of debt are required for interim reporting. The fair value of
Apaches fixed-rate debt
is based upon estimates provided by an independent investment banking
firm, which is a Level 2 fair value measurement. The carrying amount
of floating-rate debt approximates fair
value because the interest rates are variable and reflective of market rates. The following table
presents the carrying amounts and estimated fair values of the Companys debt at June 30, 2009 and
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
June 30, 2009 |
|
December 31, 2008 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Amount |
|
Value |
|
Amount |
|
Value |
|
|
|
|
|
|
(In millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Debt, Net of Unamortized Discount |
|
$ |
4,967 |
|
|
$ |
5,505 |
|
|
$ |
4,922 |
|
|
$ |
5,092 |
|
15
10. BUSINESS SEGMENT INFORMATION
Apache has production in six countries: the United States (Gulf Coast and Central regions),
Canada, Egypt, offshore Australia, offshore the United Kingdom (U.K.) in the North Sea and
Argentina. We also have exploration interest on the Chilean side of the island of Tierra del
Fuego. Financial information by country is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.K. |
|
|
|
|
|
|
Other |
|
|
|
|
|
|
States |
|
|
Canada |
|
|
Egypt |
|
|
Australia |
|
|
North Sea |
|
|
Argentina |
|
|
International |
|
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended
June 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Revenues |
|
$ |
707,081 |
|
|
$ |
215,476 |
|
|
$ |
655,063 |
|
|
$ |
86,726 |
|
|
$ |
322,181 |
|
|
$ |
87,817 |
|
|
$ |
|
|
|
$ |
2,074,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (1) |
|
$ |
242,962 |
|
|
$ |
62,934 |
|
|
$ |
441,175 |
|
|
$ |
12,482 |
|
|
$ |
140,149 |
|
|
$ |
20,107 |
|
|
$ |
|
|
|
$ |
919,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,034 |
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(90,905 |
) |
Financing costs, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(61,155 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
786,783 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended
June 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Revenues |
|
$ |
1,302,939 |
|
|
$ |
425,394 |
|
|
$ |
1,075,291 |
|
|
$ |
129,561 |
|
|
$ |
564,954 |
|
|
$ |
179,819 |
|
|
$ |
|
|
|
$ |
3,677,958 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss) (1) |
|
$ |
(856,576 |
) |
|
$ |
(1,495,033 |
) |
|
$ |
663,935 |
|
|
$ |
(107 |
) |
|
$ |
227,804 |
|
|
$ |
39,717 |
|
|
$ |
|
|
|
$ |
(1,420,260 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,245 |
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(175,951 |
) |
Financing costs, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(119,742 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Before Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(1,666,708 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
10,438,404 |
|
|
$ |
4,435,413 |
|
|
$ |
5,102,967 |
|
|
$ |
3,004,809 |
|
|
$ |
2,024,529 |
|
|
$ |
1,395,704 |
|
|
$ |
101 |
|
|
$ |
26,401,927 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended
June 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Revenues |
|
$ |
1,665,167 |
|
|
$ |
516,058 |
|
|
$ |
878,418 |
|
|
$ |
127,499 |
|
|
$ |
628,428 |
|
|
$ |
88,548 |
|
|
$ |
|
|
|
$ |
3,904,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (1) |
|
$ |
1,069,688 |
|
|
$ |
295,585 |
|
|
$ |
731,592 |
|
|
$ |
69,182 |
|
|
$ |
287,706 |
|
|
$ |
11,965 |
|
|
$ |
|
|
|
$ |
2,465,718 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,927 |
) |
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(78,872 |
) |
Financing costs, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(39,050 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
2,343,869 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Revenues |
|
$ |
3,034,635 |
|
|
$ |
922,320 |
|
|
$ |
1,550,316 |
|
|
$ |
251,598 |
|
|
$ |
1,144,804 |
|
|
$ |
178,394 |
|
|
$ |
|
|
|
$ |
7,082,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (1) |
|
$ |
1,852,807 |
|
|
$ |
476,309 |
|
|
$ |
1,264,220 |
|
|
$ |
114,101 |
|
|
$ |
519,535 |
|
|
$ |
31,517 |
|
|
$ |
|
|
|
$ |
4,258,489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,865 |
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(161,295 |
) |
Financing costs, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(83,303 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
4,019,756 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
13,191,709 |
|
|
$ |
7,542,245 |
|
|
$ |
4,258,260 |
|
|
$ |
2,308,963 |
|
|
$ |
2,816,537 |
|
|
$ |
1,745,382 |
|
|
$ |
14,063 |
|
|
$ |
31,877,159 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Operating Income (Loss) consists of oil and gas production revenues less
depreciation, depletion and amortization, asset retirement obligation accretion, lease
operating expenses, gathering and transportation costs, and taxes other than income. The U.S.
and Canada operating losses for the six-
month period of 2009 include additional depletion of $1.2 billion and $1.6 billion, respectively,
to write-down the carrying value of oil and gas properties. |
16
11. SUPPLEMENTAL GUARANTOR INFORMATION
Apache Finance Canada Corporation (Apache Finance Canada) is a subsidiary of Apache and has
approximately $650 million of publicly traded notes outstanding that are fully and unconditionally
guaranteed by Apache. The following condensed consolidating financial statements are provided as
an alternative to filing separate financial statements.
Apache Finance Pty Ltd. (Apache Finance Australia), a subsidiary of Apache, had $100 million
of publicly traded securities, which matured on March 15, 2009. The notes were repaid using
existing cash balances.
Each of these companies has been fully consolidated in Apaches consolidated financial
statements. As such, these condensed consolidating financial statements should be read in
conjunction with the financial statements of Apache Corporation and subsidiaries and notes thereto,
of which this note is an integral part.
17
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache |
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
Apache |
|
|
Finance |
|
|
of Apache |
|
|
Reclassifications |
|
|
|
|
|
|
Corporation |
|
|
Canada |
|
|
Corporation |
|
|
& Eliminations |
|
|
Consolidated |
|
|
|
|
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
|
|
|
|
REVENUES AND OTHER: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues |
|
$ |
640,421 |
|
|
$ |
|
|
|
$ |
1,433,923 |
|
|
$ |
|
|
|
$ |
2,074,344 |
|
Equity in net income of affiliates |
|
|
306,956 |
|
|
|
7,393 |
|
|
|
3,911 |
|
|
|
(318,260 |
) |
|
|
|
|
Other |
|
|
(1,184 |
) |
|
|
14,630 |
|
|
|
6,625 |
|
|
|
(1,037 |
) |
|
|
19,034 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
946,193 |
|
|
|
22,023 |
|
|
|
1,444,459 |
|
|
|
(319,297 |
) |
|
|
2,093,378 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
201,542 |
|
|
|
|
|
|
|
371,817 |
|
|
|
|
|
|
|
573,359 |
|
Asset retirement obligation accretion |
|
|
16,166 |
|
|
|
|
|
|
|
10,317 |
|
|
|
|
|
|
|
26,483 |
|
Lease operating expenses |
|
|
173,639 |
|
|
|
|
|
|
|
231,634 |
|
|
|
|
|
|
|
405,273 |
|
Gathering and transportation costs |
|
|
7,217 |
|
|
|
|
|
|
|
26,262 |
|
|
|
|
|
|
|
33,479 |
|
Taxes other than income |
|
|
20,861 |
|
|
|
|
|
|
|
95,080 |
|
|
|
|
|
|
|
115,941 |
|
General and administrative |
|
|
73,286 |
|
|
|
|
|
|
|
18,656 |
|
|
|
(1,037 |
) |
|
|
90,905 |
|
Financing costs, net |
|
|
57,959 |
|
|
|
14,115 |
|
|
|
(10,919 |
) |
|
|
|
|
|
|
61,155 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
550,670 |
|
|
|
14,115 |
|
|
|
742,847 |
|
|
|
(1,037 |
) |
|
|
1,306,595 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES |
|
|
395,523 |
|
|
|
7,908 |
|
|
|
701,612 |
|
|
|
(318,260 |
) |
|
|
786,783 |
|
Provision (benefit) for income taxes |
|
|
(49,197 |
) |
|
|
(3,396 |
) |
|
|
394,656 |
|
|
|
|
|
|
|
342,063 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
444,720 |
|
|
|
11,304 |
|
|
|
306,956 |
|
|
|
(318,260 |
) |
|
|
444,720 |
|
Preferred stock dividends |
|
|
1,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK |
|
$ |
443,300 |
|
|
$ |
11,304 |
|
|
$ |
306,956 |
|
|
$ |
(318,260 |
) |
|
$ |
443,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
18
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache |
|
|
Apache |
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
Apache |
|
|
Apache |
|
|
Finance |
|
|
Finance |
|
|
of Apache |
|
|
Reclassifications |
|
|
|
|
|
|
Corporation |
|
|
North America |
|
|
Australia |
|
|
Canada |
|
|
Corporation |
|
|
& Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
REVENUES AND OTHER: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues |
|
$ |
1,623,565 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,301,447 |
|
|
$ |
(20,894 |
) |
|
$ |
3,904,118 |
|
Equity in net income (loss) of affiliates |
|
|
782,543 |
|
|
|
6,742 |
|
|
|
14,166 |
|
|
|
92,918 |
|
|
|
(55,375 |
) |
|
|
(840,994 |
) |
|
|
|
|
Other |
|
|
9,889 |
|
|
|
|
|
|
|
(7,459 |
) |
|
|
14,657 |
|
|
|
(20,091 |
) |
|
|
(923 |
) |
|
|
(3,927 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,415,997 |
|
|
|
6,742 |
|
|
|
6,707 |
|
|
|
107,575 |
|
|
|
2,225,981 |
|
|
|
(862,811 |
) |
|
|
3,900,191 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
299,879 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
327,789 |
|
|
|
|
|
|
|
627,668 |
|
Asset retirement obligation accretion |
|
|
16,931 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,748 |
|
|
|
|
|
|
|
25,679 |
|
Lease operating expenses |
|
|
202,001 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
244,737 |
|
|
|
|
|
|
|
446,738 |
|
Gathering and transportation costs |
|
|
10,849 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
49,812 |
|
|
|
(20,894 |
) |
|
|
39,767 |
|
Taxes other than income |
|
|
61,617 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
236,931 |
|
|
|
|
|
|
|
298,548 |
|
General and administrative |
|
|
65,829 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,966 |
|
|
|
(923 |
) |
|
|
78,872 |
|
Financing costs, net |
|
|
32,629 |
|
|
|
|
|
|
|
4,498 |
|
|
|
14,113 |
|
|
|
(12,190 |
) |
|
|
|
|
|
|
39,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
689,735 |
|
|
|
|
|
|
|
4,498 |
|
|
|
14,113 |
|
|
|
869,793 |
|
|
|
(21,817 |
) |
|
|
1,556,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES |
|
|
1,726,262 |
|
|
|
6,742 |
|
|
|
2,209 |
|
|
|
93,462 |
|
|
|
1,356,188 |
|
|
|
(840,994 |
) |
|
|
2,343,869 |
|
Provision (benefit) for income taxes |
|
|
281,033 |
|
|
|
|
|
|
|
(4,533 |
) |
|
|
48,495 |
|
|
|
573,645 |
|
|
|
|
|
|
|
898,640 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
1,445,229 |
|
|
|
6,742 |
|
|
|
6,742 |
|
|
|
44,967 |
|
|
|
782,543 |
|
|
|
(840,994 |
) |
|
|
1,445,229 |
|
Preferred stock dividends |
|
|
1,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK |
|
$ |
1,443,809 |
|
|
$ |
6,742 |
|
|
$ |
6,742 |
|
|
$ |
44,967 |
|
|
$ |
782,543 |
|
|
$ |
(840,994 |
) |
|
$ |
1,443,809 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache |
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
Apache |
|
|
Finance |
|
|
of Apache |
|
|
Reclassifications |
|
|
|
|
|
|
Corporation |
|
|
Canada |
|
|
Corporation |
|
|
& Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
REVENUES AND OTHER: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues |
|
$ |
1,185,151 |
|
|
$ |
|
|
|
$ |
2,492,807 |
|
|
$ |
|
|
|
$ |
3,677,958 |
|
Equity in net income (loss) of affiliates |
|
|
(638,787 |
) |
|
|
(534,943 |
) |
|
|
141,223 |
|
|
|
1,032,507 |
|
|
|
|
|
Other |
|
|
392 |
|
|
|
29,314 |
|
|
|
21,574 |
|
|
|
(2,035 |
) |
|
|
49,245 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
546,756 |
|
|
|
(505,629 |
) |
|
|
2,655,604 |
|
|
|
1,030,472 |
|
|
|
3,727,203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
1,643,031 |
|
|
|
|
|
|
|
2,329,106 |
|
|
|
|
|
|
|
3,972,137 |
|
Asset retirement obligation accretion |
|
|
32,475 |
|
|
|
|
|
|
|
20,746 |
|
|
|
|
|
|
|
53,221 |
|
Lease operating expenses |
|
|
346,807 |
|
|
|
|
|
|
|
455,955 |
|
|
|
|
|
|
|
802,762 |
|
Gathering and transportation costs |
|
|
15,696 |
|
|
|
|
|
|
|
51,122 |
|
|
|
|
|
|
|
66,818 |
|
Taxes other than income |
|
|
42,288 |
|
|
|
|
|
|
|
160,992 |
|
|
|
|
|
|
|
203,280 |
|
General and administrative |
|
|
146,177 |
|
|
|
|
|
|
|
31,809 |
|
|
|
(2,035 |
) |
|
|
175,951 |
|
Financing costs, net |
|
|
111,411 |
|
|
|
28,228 |
|
|
|
(19,897 |
) |
|
|
|
|
|
|
119,742 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,337,885 |
|
|
|
28,228 |
|
|
|
3,029,833 |
|
|
|
(2,035 |
) |
|
|
5,393,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS BEFORE INCOME TAXES |
|
|
(1,791,129 |
) |
|
|
(533,857 |
) |
|
|
(374,229 |
) |
|
|
1,032,507 |
|
|
|
(1,666,708 |
) |
Provision (benefit) for income taxes |
|
|
(478,909 |
) |
|
|
(140,137 |
) |
|
|
264,558 |
|
|
|
|
|
|
|
(354,488 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS |
|
|
(1,312,220 |
) |
|
|
(393,720 |
) |
|
|
(638,787 |
) |
|
|
1,032,507 |
|
|
|
(1,312,220 |
) |
Preferred stock dividends |
|
|
2,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS ATTRIBUTABLE TO COMMON STOCK |
|
$ |
(1,315,060 |
) |
|
$ |
(393,720 |
) |
|
$ |
(638,787 |
) |
|
$ |
1,032,507 |
|
|
$ |
(1,315,060 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Six Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache |
|
|
Apache |
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
Apache |
|
|
Apache |
|
|
Finance |
|
|
Finance |
|
|
of Apache |
|
|
Reclassifications |
|
|
|
|
|
|
Corporation |
|
|
North America |
|
|
Australia |
|
|
Canada |
|
|
Corporation |
|
|
& Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
REVENUES AND OTHER: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues |
|
$ |
2,976,970 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
4,143,766 |
|
|
$ |
(38,669 |
) |
|
$ |
7,082,067 |
|
Equity in net income (loss) of affiliates |
|
|
1,425,632 |
|
|
|
14,792 |
|
|
|
25,092 |
|
|
|
182,511 |
|
|
|
(57,866 |
) |
|
|
(1,590,161 |
) |
|
|
|
|
Other |
|
|
9,855 |
|
|
|
|
|
|
|
(7,459 |
) |
|
|
29,314 |
|
|
|
(24,000 |
) |
|
|
(1,845 |
) |
|
|
5,865 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,412,457 |
|
|
|
14,792 |
|
|
|
17,633 |
|
|
|
211,825 |
|
|
|
4,061,900 |
|
|
|
(1,630,675 |
) |
|
|
7,087,932 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
588,395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
659,762 |
|
|
|
|
|
|
|
1,248,157 |
|
Asset retirement obligation accretion |
|
|
34,708 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
17,468 |
|
|
|
|
|
|
|
52,176 |
|
Lease operating expenses |
|
|
415,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
486,050 |
|
|
|
|
|
|
|
901,376 |
|
Gathering and transportation costs |
|
|
20,976 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
98,436 |
|
|
|
(38,669 |
) |
|
|
80,743 |
|
Taxes other than income |
|
|
115,826 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
425,300 |
|
|
|
|
|
|
|
541,126 |
|
General and administrative |
|
|
132,712 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
30,428 |
|
|
|
(1,845 |
) |
|
|
161,295 |
|
Financing costs, net |
|
|
70,102 |
|
|
|
|
|
|
|
8,995 |
|
|
|
28,226 |
|
|
|
(24,020 |
) |
|
|
|
|
|
|
83,303 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,378,045 |
|
|
|
|
|
|
|
8,995 |
|
|
|
28,226 |
|
|
|
1,693,424 |
|
|
|
(40,514 |
) |
|
|
3,068,176 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES |
|
|
3,034,412 |
|
|
|
14,792 |
|
|
|
8,638 |
|
|
|
183,599 |
|
|
|
2,368,476 |
|
|
|
(1,590,161 |
) |
|
|
4,019,756 |
|
Provision (benefit) for income taxes |
|
|
567,670 |
|
|
|
|
|
|
|
(6,154 |
) |
|
|
48,654 |
|
|
|
942,844 |
|
|
|
|
|
|
|
1,553,014 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
2,466,742 |
|
|
|
14,792 |
|
|
|
14,792 |
|
|
|
134,945 |
|
|
|
1,425,632 |
|
|
|
(1,590,161 |
) |
|
|
2,466,742 |
|
Preferred stock dividends |
|
|
2,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,840 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK |
|
$ |
2,463,902 |
|
|
$ |
14,792 |
|
|
$ |
14,792 |
|
|
$ |
134,945 |
|
|
$ |
1,425,632 |
|
|
$ |
(1,590,161 |
) |
|
$ |
2,463,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache |
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
Apache |
|
|
Finance |
|
|
of Apache |
|
|
Reclassifications |
|
|
|
|
|
|
Corporation |
|
|
Canada |
|
|
Corporation |
|
|
& Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
CASH PROVIDED BY (USED IN) OPERATING
ACTIVITIES |
|
$ |
659,679 |
|
|
$ |
(22,357 |
) |
|
$ |
729,407 |
|
|
$ |
|
|
|
$ |
1,366,729 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas property |
|
|
(666,421 |
) |
|
|
|
|
|
|
(1,450,994 |
) |
|
|
|
|
|
|
(2,117,415 |
) |
Additions to gas gathering, transmission
and processing facilities |
|
|
|
|
|
|
|
|
|
|
(164,723 |
) |
|
|
|
|
|
|
(164,723 |
) |
Acquisition of Marathon properties |
|
|
(181,133 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(181,333 |
) |
Short-term investments |
|
|
791,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
791,999 |
|
Restricted cash for acquisition settlement |
|
|
13,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,880 |
|
Proceeds from sale of oil & gas properties |
|
|
144 |
|
|
|
|
|
|
|
(17 |
) |
|
|
|
|
|
|
127 |
|
Investment in subsidiaries, net |
|
|
(300,472 |
) |
|
|
|
|
|
|
|
|
|
|
300,472 |
|
|
|
|
|
Other, net |
|
|
(26,903 |
) |
|
|
|
|
|
|
(58,623 |
) |
|
|
|
|
|
|
(85,526 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES |
|
|
(368,906 |
) |
|
|
|
|
|
|
(1,674,357 |
) |
|
|
300,472 |
|
|
|
(1,742,791 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt borrowings |
|
|
652 |
|
|
|
40 |
|
|
|
448,985 |
|
|
|
(302,011 |
) |
|
|
147,666 |
|
Payments on debt |
|
|
|
|
|
|
|
|
|
|
(100,000 |
) |
|
|
|
|
|
|
(100,000 |
) |
Dividends paid |
|
|
(103,331 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(103,331 |
) |
Common stock activity |
|
|
9,971 |
|
|
|
20,606 |
|
|
|
(22,145 |
) |
|
|
1,539 |
|
|
|
9,971 |
|
Treasury stock activity, net |
|
|
2,669 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,669 |
|
Cost of debt and equity transactions |
|
|
(403 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(403 |
) |
Other |
|
|
9,597 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,597 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING
ACTIVITIES |
|
|
(80,845 |
) |
|
|
20,646 |
|
|
|
326,840 |
|
|
|
(300,472 |
) |
|
|
(33,831 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS |
|
|
209,928 |
|
|
|
(1,711 |
) |
|
|
(618,110 |
) |
|
|
|
|
|
|
(409,893 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF
YEAR |
|
|
142,026 |
|
|
|
1,714 |
|
|
|
1,037,710 |
|
|
|
|
|
|
|
1,181,450 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
|
$ |
351,954 |
|
|
$ |
3 |
|
|
$ |
419,600 |
|
|
$ |
|
|
|
$ |
771,557 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache |
|
|
Apache |
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
Apache |
|
|
Apache |
|
|
Finance |
|
|
Finance |
|
|
of Apache |
|
|
Reclassifications |
|
|
|
|
|
|
Corporation |
|
|
North America |
|
|
Australia |
|
|
Canada |
|
|
Corporation |
|
|
& Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
CASH PROVIDED BY (USED IN) OPERATING
ACTIVITIES |
|
$ |
1,168,611 |
|
|
$ |
|
|
|
$ |
(3,194 |
) |
|
$ |
(22,652 |
) |
|
$ |
2,595,148 |
|
|
$ |
|
|
|
$ |
3,737,913 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas property |
|
|
(765,114 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,777,963 |
) |
|
|
|
|
|
|
(2,543,077 |
) |
Additions to gas gathering, transmission and
processing facilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(245,627 |
) |
|
|
|
|
|
|
(245,627 |
) |
Restricted cash |
|
|
(94,357 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(94,357 |
) |
Proceeds from sale of oil & gas properties |
|
|
198,842 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
101,095 |
|
|
|
|
|
|
|
299,937 |
|
Investment in subsidiaries, net |
|
|
(175,241 |
) |
|
|
(5,974 |
) |
|
|
|
|
|
|
|
|
|
|
(23,974 |
) |
|
|
205,189 |
|
|
|
|
|
Other, net |
|
|
(11,242 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(14,196 |
) |
|
|
|
|
|
|
(25,438 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES |
|
|
(847,112 |
) |
|
|
(5,974 |
) |
|
|
|
|
|
|
|
|
|
|
(1,960,665 |
) |
|
|
205,189 |
|
|
|
(2,608,562 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial paper and money market borrowings, net |
|
|
(140,670 |
) |
|
|
|
|
|
|
(2,781 |
) |
|
|
(2,091 |
) |
|
|
90,189 |
|
|
|
(126,998 |
) |
|
|
(182,351 |
) |
Payments on fixed-rate debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(353 |
) |
|
|
|
|
|
|
(353 |
) |
Dividends paid |
|
|
(136,145 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(136,145 |
) |
Common stock activity |
|
|
28,526 |
|
|
|
5,974 |
|
|
|
5,974 |
|
|
|
22,993 |
|
|
|
43,250 |
|
|
|
(78,191 |
) |
|
|
28,526 |
|
Treasury stock activity, net |
|
|
3,416 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,416 |
|
Cost of debt and equity transactions |
|
|
(964 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(964 |
) |
Other |
|
|
41,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
41,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES |
|
|
(204,698 |
) |
|
|
5,974 |
|
|
|
3,193 |
|
|
|
20,902 |
|
|
|
133,086 |
|
|
|
(205,189 |
) |
|
|
(246,732 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND CASH
EQUIVALENTS |
|
|
116,801 |
|
|
|
|
|
|
|
(1 |
) |
|
|
(1,750 |
) |
|
|
767,569 |
|
|
|
|
|
|
|
882,619 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR |
|
|
3,626 |
|
|
|
|
|
|
|
1 |
|
|
|
1,751 |
|
|
|
120,445 |
|
|
|
|
|
|
|
125,823 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
|
$ |
120,427 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
888,014 |
|
|
$ |
|
|
|
$ |
1,008,442 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of June 30, 2009
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache |
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
Apache |
|
|
Finance |
|
|
of Apache |
|
|
Reclassifications |
|
|
|
|
|
|
Corporation |
|
|
Canada |
|
|
Corporation |
|
|
& Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
351,954 |
|
|
$ |
3 |
|
|
$ |
419,600 |
|
|
$ |
|
|
|
$ |
771,557 |
|
Receivables, net of allowance |
|
|
517,886 |
|
|
|
|
|
|
|
1,018,763 |
|
|
|
|
|
|
|
1,536,649 |
|
Inventories |
|
|
63,714 |
|
|
|
|
|
|
|
507,898 |
|
|
|
|
|
|
|
571,612 |
|
Drilling advances and other |
|
|
299,406 |
|
|
|
1,576 |
|
|
|
236,370 |
|
|
|
|
|
|
|
537,352 |
|
Derivative instruments |
|
|
30,379 |
|
|
|
|
|
|
|
37,536 |
|
|
|
|
|
|
|
67,915 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,263,339 |
|
|
|
1,579 |
|
|
|
2,220,167 |
|
|
|
|
|
|
|
3,485,085 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT, NET |
|
|
9,161,874 |
|
|
|
|
|
|
|
13,128,434 |
|
|
|
|
|
|
|
22,290,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany receivable, net |
|
|
1,487,782 |
|
|
|
|
|
|
|
254,595 |
|
|
|
(1,742,377 |
) |
|
|
|
|
Restricted cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill, net |
|
|
|
|
|
|
|
|
|
|
189,252 |
|
|
|
|
|
|
|
189,252 |
|
Equity in affiliates |
|
|
10,594,021 |
|
|
|
1,072,461 |
|
|
|
57,202 |
|
|
|
(11,723,684 |
) |
|
|
|
|
Deferred charges and other |
|
|
156,228 |
|
|
|
1,003,195 |
|
|
|
270,159 |
|
|
|
(1,000,000 |
) |
|
|
429,582 |
|
Derivative instruments |
|
|
6,740 |
|
|
|
|
|
|
|
690 |
|
|
|
|
|
|
|
7,430 |
|
Long-term investments |
|
|
|
|
|
|
|
|
|
|
270 |
|
|
|
|
|
|
|
270 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
22,669,984 |
|
|
$ |
2,077,235 |
|
|
$ |
16,120,769 |
|
|
$ |
(14,466,061 |
) |
|
$ |
26,401,927 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term debt |
|
$ |
|
|
|
$ |
|
|
|
$ |
12,656 |
|
|
$ |
|
|
|
$ |
12,656 |
|
Accounts payable |
|
|
250,868 |
|
|
|
250,009 |
|
|
|
1,630,847 |
|
|
|
(1,742,377 |
) |
|
|
389,347 |
|
Accrued exploration and development |
|
|
165,692 |
|
|
|
|
|
|
|
522,267 |
|
|
|
|
|
|
|
687,959 |
|
Other accrued expenses |
|
|
507,960 |
|
|
|
46,633 |
|
|
|
163,800 |
|
|
|
|
|
|
|
718,393 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
924,520 |
|
|
|
296,642 |
|
|
|
2,329,570 |
|
|
|
(1,742,377 |
) |
|
|
1,808,355 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT |
|
|
4,061,657 |
|
|
|
647,111 |
|
|
|
245,899 |
|
|
|
|
|
|
|
4,954,667 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
|
1,220,617 |
|
|
|
3,819 |
|
|
|
1,278,118 |
|
|
|
|
|
|
|
2,502,554 |
|
Advances from gas purchasers |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation |
|
|
873,118 |
|
|
|
|
|
|
|
711,998 |
|
|
|
|
|
|
|
1,585,116 |
|
Derivative instruments |
|
|
100,386 |
|
|
|
|
|
|
|
30,565 |
|
|
|
|
|
|
|
130,951 |
|
Other |
|
|
530,991 |
|
|
|
|
|
|
|
930,598 |
|
|
|
(1,000,000 |
) |
|
|
461,589 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,725,112 |
|
|
|
3,819 |
|
|
|
2,951,279 |
|
|
|
(1,000,000 |
) |
|
|
4,680,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS EQUITY |
|
|
14,958,695 |
|
|
|
1,129,663 |
|
|
|
10,594,021 |
|
|
|
(11,723,684 |
) |
|
|
14,958,695 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
22,669,984 |
|
|
$ |
2,077,235 |
|
|
$ |
16,120,769 |
|
|
$ |
(14,466,061 |
) |
|
$ |
26,401,927 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of December 31, 2008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
All Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Apache |
|
|
|
|
|
|
Subsidiaries |
|
|
|
|
|
|
|
|
|
Apache |
|
|
Apache |
|
|
Finance |
|
|
Apache |
|
|
of Apache |
|
|
Reclassifications |
|
|
|
|
|
|
Corporation |
|
|
North America |
|
|
Australia |
|
|
Finance Canada |
|
|
Corporation |
|
|
& Eliminations |
|
|
Consolidated |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
142,026 |
|
|
$ |
|
|
|
$ |
2 |
|
|
$ |
1,714 |
|
|
$ |
1,037,708 |
|
|
$ |
|
|
|
$ |
1,181,450 |
|
Short-term investments |
|
|
791,899 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100 |
|
|
|
|
|
|
|
791,999 |
|
Receivables, net of allowance |
|
|
514,174 |
|
|
|
|
|
|
|
|
|
|
|
1,095 |
|
|
|
841,710 |
|
|
|
|
|
|
|
1,356,979 |
|
Inventories |
|
|
59,106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
439,461 |
|
|
|
|
|
|
|
498,567 |
|
Drilling advances and other |
|
|
456,956 |
|
|
|
|
|
|
|
|
|
|
|
1,786 |
|
|
|
163,237 |
|
|
|
|
|
|
|
621,979 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,964,161 |
|
|
|
|
|
|
|
2 |
|
|
|
4,595 |
|
|
|
2,482,216 |
|
|
|
|
|
|
|
4,450,974 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT, NET |
|
|
9,970,619 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,987,898 |
|
|
|
|
|
|
|
23,958,517 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany receivable, net |
|
|
1,185,771 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,185,771 |
) |
|
|
|
|
Restricted cash |
|
|
13,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,880 |
|
Goodwill, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
189,252 |
|
|
|
|
|
|
|
189,252 |
|
Equity in affiliates |
|
|
12,919,395 |
|
|
|
510,620 |
|
|
|
714,092 |
|
|
|
1,556,673 |
|
|
|
(157,276 |
) |
|
|
(15,543,504 |
) |
|
|
|
|
Deferred charges and other |
|
|
212,635 |
|
|
|
|
|
|
|
|
|
|
|
1,003,353 |
|
|
|
357,874 |
|
|
|
(1,000,000 |
) |
|
|
573,862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,266,461 |
|
|
$ |
510,620 |
|
|
$ |
714,094 |
|
|
$ |
2,564,621 |
|
|
$ |
16,859,964 |
|
|
$ |
(17,729,275 |
) |
|
$ |
29,186,485 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term debt |
|
$ |
|
|
|
$ |
|
|
|
$ |
99,977 |
|
|
$ |
|
|
|
$ |
12,621 |
|
|
$ |
|
|
|
$ |
112,598 |
|
Accounts payable |
|
|
2,038,266 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,489,321 |
) |
|
|
|
|
|
|
548,945 |
|
Other accrued expenses |
|
|
855,197 |
|
|
|
(10,097 |
) |
|
|
165,432 |
|
|
|
290,587 |
|
|
|
1,743,544 |
|
|
|
(1,185,771 |
) |
|
|
1,858,892 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,893,463 |
|
|
|
(10,097 |
) |
|
|
265,409 |
|
|
|
290,587 |
|
|
|
266,844 |
|
|
|
(1,185,771 |
) |
|
|
2,520,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT |
|
|
4,061,005 |
|
|
|
|
|
|
|
|
|
|
|
647,071 |
|
|
|
100,899 |
|
|
|
|
|
|
|
4,808,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NONCURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
|
1,599,539 |
|
|
|
|
|
|
|
(31,292 |
) |
|
|
3,548 |
|
|
|
1,594,862 |
|
|
|
|
|
|
|
3,166,657 |
|
Asset retirement obligation |
|
|
844,126 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
711,403 |
|
|
|
|
|
|
|
1,555,529 |
|
Derivative instruments |
|
|
|
|
|
|
30,643 |
|
|
|
(30,643 |
) |
|
|
|
|
|
|
7,713 |
|
|
|
|
|
|
|
7,713 |
|
Other |
|
|
359,607 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,258,848 |
|
|
|
(1,000,000 |
) |
|
|
618,455 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,803,272 |
|
|
|
30,643 |
|
|
|
(61,935 |
) |
|
|
3,548 |
|
|
|
3,572,826 |
|
|
|
(1,000,000 |
) |
|
|
5,348,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS EQUITY |
|
|
16,508,721 |
|
|
|
490,074 |
|
|
|
510,620 |
|
|
|
1,623,415 |
|
|
|
12,919,395 |
|
|
|
(15,543,504 |
) |
|
|
16,508,721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
26,266,461 |
|
|
$ |
510,620 |
|
|
$ |
714,094 |
|
|
$ |
2,564,621 |
|
|
$ |
16,859,964 |
|
|
$ |
(17,729,275 |
) |
|
$ |
29,186,485 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
ITEM 2 MANAGEMENTS DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Apache Corporation, a Delaware corporation formed in 1954, together with its subsidiaries
(collectively, Apache) is one of the worlds largest independent oil and gas companies. We have
exploration and production interests in the United States, Canada, Egypt, offshore Australia,
offshore the United Kingdom (U.K.) in the North Sea (North Sea) and Argentina. We also have
exploration interests on the Chilean side of the island of Tierra del Fuego.
This discussion relates to Apache Corporation and its consolidated subsidiaries and should be
read in conjunction with our consolidated financial statements and accompanying notes included
under Part I, Item 1, of this Quarterly Report on Form 10-Q, as well as our consolidated financial
statements, accompanying notes, Managements Discussion and Analysis of Financial Condition and
Results of Operations included in our most recent Annual Report on Form 10-K.
OVERVIEW
Apaches
performance during the quarter reflects the benefts of our geological and geographical diversity
as well as our balanced product mix. Initial development from projects in the Gulf of Mexico
and the Western Desert of Egypt contributed to record second-quarter 2009 production, which
increased six percent from the second quarter of 2008 and seven percent from the first quarter
of 2009. Both increases reflect production growth in four of the six countries in which we
operate.
Our
balanced product mix served us well during the year, as the benefit from the rebound in oil
prices more than offset continuing deterioration of North American natural gas prices.
Oil production contributed 48 percent of Apaches worldwide second-quarter production,
but 72 percent of oil and gas revenues. Prices for both oil and gas were substantially
below year-earlier quarter and six-month levels, which were at historically high levels.
We
continue to make progress reducing per unit operating costs. Lease operating costs are down
nine percent from the second quarter and 11 percent from the first half of 2008.
Absent nonrecurring costs related to staff reductions and the retirement of our founder
and former chairman, our general and administrative costs for the first six months of
2009 would have been $23 million lower than the first half of 2008. Apache employees
united in cost-reduction efforts and, in addition to other cost-cutting initiatives,
company-wide salary increases were deferred for a six-month period, and the four
members of the Office of the Chief Executive reduced their salaries by 10 percent.
We continue to push for even greater efficiencies.
We
remain steadfast to the business principles that have guided Apaches progress since our
inception. We set the objective of continuing to live within our means and are on target
to keep 2009 exploration and development capital spending within cash flow. We also
remain strategically positioned to take advantage of potential acquisition opportunities
that may materialize. We ended the quarter with $772 million in cash, $2.4 billion of
available committed borrowing capacity, a debt-to-capitalization ratio of 25 percent
and single-A credit ratings. In the current economic and political climate, it is
imperative that we keep a long-term perspective and continue to demand operational excellence.
EARNINGS AND CASH FLOW
Our second-quarter earnings of $1.31 per diluted common share were negatively impacted by
significantly lower crude oil and natural gas price realizations relative to the second quarter of
2008, which saw record earnings of $4.28 per share. Our six-month period earnings in 2009,
relative to 2008, were also negatively impacted by lower crude oil and natural gas price
realizations and our $1.98 billion non-cash after-tax write-down of the carrying value of our U.S.
and Canadian proved oil and gas properties in the first quarter of 2009. This write-down
contributed to a
26
loss of $3.92 per share for the 2009 six-month period compared to earnings of $7.32 per share
in the year-ago period. Cash provided by operating activities for the 2009 six-month period
totaled $1.4 billion compared to $3.7 billion in the comparable prior-year period. For additional
discussion on prices, refer to Pricing Trends under this Item 2. We believe weak commodity
prices are likely to be a challenge for the remainder of 2009.
Second-quarter 2009 oil and gas revenues were 47 percent, or $1.8 billion, lower than the
second quarter of 2008, driven by a 47 percent drop in average crude oil realizations and a 57
percent drop in natural gas realizations. On a unit basis, daily production was six percent above
the year-ago period, with gains in Egypt, Australia and the North Sea offsetting the continuing
impact of the 2008 U.S. hurricanes. Total operating expenses were 16 percent lower than the second
quarter of 2008. Reductions in service costs continue to lag behind the sharp decline in commodity
prices and are not presently at levels we believe are in line with todays lower commodity prices.
We continue to monitor service cost trends very closely and make appropriate adjustments to
drilling and development schedules while actively pursuing further cost reductions.
OPERATING HIGHLIGHTS
Egypt
Exploration Activity
|
|
|
On July 30, 2009, we announced that the Falcon 1-X wildcat in the Matruh Concession,
drilled in May 2009, tested 4,400 barrels of oil per day (b/d) from the Alam El Buieb
(AEB-3D) formation. The well will be initially completed in the AEB-3D oil zone, and first
production from the well should commence in the third quarter of 2009. The well also
encountered hydrocarbon pay zones in the AEB-6 and Jurassic Safa formation that will not be
produced until additional processing and transportation capacity is developed. The
Jurassic Safa tested at a rate of 11 million cubic feet of natural gas per day (MMcf/d) and
415 b/d. The AEB-6 tested at 35 MMcf/d and 1,953 b/d. An appraisal well is planned before
year-end. |
|
|
|
|
On July 30, 2009, we also announced that the Hydra-5X appraisal well in the Shushan
Concession tested 21 MMcf/d and 3,744 barrels of condensate per day from the Jurassic Upper
Safa formation. This well follows Apaches Hydra-1X discovery drilled in 2008. The field
will be developed upon completion of a gas sales agreement with the Egyptian General
Petroleum Corporation. |
|
|
|
|
On April 30, 2009, Apache announced discovery of the Phiops field, the largest of five
fields discovered since 2006 by Apache through its joint venture partner, Khalda Petroleum
Company, in the Faghur Basin of the Western Desert. The Phiops-1X well in the South
Umbarka Concession was completed earlier this year as an oil producer and test-flowed 2,278
b/d and 5 MMcf/d from the Safa formation. The Phiops field was subsequently appraised by
the Phiops-5 well discussed below. |
|
|
|
|
On April 30, we also announced that the WKAL-A-1X well, located five miles west of
Phiops-1X in the West Kalabsha Concession, tested at 770 b/d and 4 MMcf/d from the Jurassic
Zahra formation and 2,906 b/d and 16 MMcf/d from the Cretaceous AEB-3 formation. Apache
plans to apply for a development lease on this discovery. |
|
|
|
|
On April 30, we also announced the NTRK-C-1X well, our first new field discovery in the
North Tarek Concession along the Mediterranean coast, tested at a rate of 3,489 b/d and 5
MMcf/d. Additional drilling is planned for this new concession. |
Development and Appraisal Activity
|
|
|
On June 9, 2009, we announced that the Phiops-5 appraisal well in the Faghur Basin in
Egypts Western Desert test-flowed 8,279 b/d and 0.4 MMcf/d. A new pipeline from Phiops to
the Khepri-Sethos facilities is expected to be completed during the third quarter of 2009.
The new pipeline and additional storage capacity at Kalabsha and Khepri-Sethos are
estimated to increase gross production capacity in the Kalabsha area from 4,000 b/d to
20,000 b/d in early 2010. We plan to continue an exploration, appraisal and development
program in the second half of 2009 to capitalize on these successes, including the
acquisition of 740 square kilometers of three-dimensional seismic data in the area. |
|
|
|
|
During the second quarter, we completed performance tests at the new Salam Gas Plant
Trains 3 and 4, and the Northern Pipeline Compression project is now fully operational.
These two new trains add 200 MMcf/d and 10,000 b/d of gross processing capacity and are
currently operating at design capacity throughput. |
27
|
|
|
Amendments to extend our Siwa, Sallum, and West Ghazalat exploration concessions for an
additional three years (to July 27, 2013) were approved by the Egyptian Parliament in June
2009. These concessions encompass 3.8 million gross acres, which Apache operates with a
50-percent contractor interest. Apaches first well in West Ghazalat should spud in
October 2009. |
Australia
Varanus Island
|
|
|
Early in the third quarter, Apache subsidiaries completed final repairs to the Varanus
Island gas processing and transportation hub offshore Western Australia, which sustained
damage from a gas pipeline explosion in June 2008. The subsidiaries are also installing a
compressor at Varanus Island to expand gross compression capacity to 460 terajoules per day
(TJ/d). Installation is expected to be completed during the third quarter of this year. |
Exploration Activity
|
|
|
We drilled two new wells in the Julimar-Brunello complex during the second quarter. We
are presently evaluating all options to commercialize this large gas resource, and the
process is expected to be completed by year-end. |
Development Activity
|
|
|
At our Van Gogh oil project, the Van Gogh-6H development well and Van Gogh-12 water
injector were completed. Repairs of the floating production, storage and offloading (FPSO)
vessel, a result of Aprils control room fire, are well underway, and we estimate first
production at Van Gogh around year-end. The fire delayed first production, initially
scheduled for the second quarter of this year. The FPSO is owned and operated by a third
party and will be leased by Apache when it is delivered to the Van Gogh field. |
North Sea
Development Activity
|
|
|
Apache completed four successful oil development wells during the quarter, bringing the
2009 total to seven. Of note is the Forties Charlie 6-3 well, which encountered 34 meters
of pay and was brought on production in mid-June at 10,500 b/d, the highest initial rate
in the field since 1994. Apache owns a 97.14-percent interest in the Forties field. |
|
|
|
|
The Forties Field is currently producing at sustained rates in excess of 70,000 gross
b/d. We are in the process of drilling one development well and completing an additional
successful oil development well, which is scheduled to be on production in August 2009. |
U.S. Central Region
Development Activity
|
|
|
Region rig activity was deliberately slowed in the first two quarters of 2009 in an
effort to better align service costs with the current lower oil and gas price environment.
With the reduced activity levels, the region concentrated on building their inventory of
drillable prospects and proceeded with lower cost projects, such as water-flood expansions
to target oil. |
|
|
|
|
We also began a rigorous evaluation of our emerging horizontal tight-gas play in the
Anadarko Basin. We are presently drilling our first operated horizontal granite wash well
following recent industry successes. Apache has identified a number of horizontal oil and
gas plays on our acreage and will be testing these over the remainder of 2009 and into
2010. |
|
|
|
|
We believe we can drill and complete a well today for roughly two-thirds of 2008 costs
as service costs continue to fall. With costs down and over 60 percent of the regions
annual budget unspent at the end of the second quarter, we plan to accelerate our drilling
and workover programs in the second half of 2009. |
28
Acquisitions
|
|
|
On June 3, 2009, we completed the acquisition of nine Permian Basin oil and gas fields
from Marathon Oil Corporation. Apache has indentified numerous attractive oil drilling
targets, especially in southeastern New Mexico, where we recently sanctioned a 10-well
program for the second half of 2009. |
U.S. Gulf Coast Region
Development Activity
|
|
|
Our much anticipated, 40-percent owned, Geauxpher (Garden Banks 462) development came on
line May 15, 2009. Through July 31, 2009, the two-well field had already produced 7.5
billion cubic feet (Bcf) and was continuing to flow at 105 MMcf/d. |
|
|
|
|
We also made considerable progress restoring Gulf Coast region production previously
shut-in because of hurricane damage. The region restored an average of 5,100 barrels of
oil equivalent per day (boe/d) in the second quarter. The last 8,800 boe/d is projected to
be restored in the third quarter of 2009. The timing of the remaining restoration in many
instances is beyond our control since we are awaiting repairs to third-party pipelines and
facilities. |
|
|
|
|
On April 20, 2009, Apache reported that its Ewing Banks 998 #1 discovery test-flowed
4,254 b/d and 5.4 MMcf/d. The well will be connected to existing facilities, with first
production projected for the first quarter of 2010. Apache owns a 50-percent interest in
the property. |
|
|
|
|
The Gulf Coast Region continues to see further reductions in rig rates. For example,
jack-up rig activity has fallen to fewer than 20 rigs, down from the more traditional
100-rig level. As a result, quotes are now below 2008 rates. We are also seeing
significant cost reductions for support vessels. |
Canada
Development Activity
|
|
|
Continued weak gas prices and a high-cost environment slowed our development drilling
activity in Canada. Although we drilled 118 development wells during the first half of
2009, very little activity occurred after the winter drilling campaign concluded in the
first quarter. We plan to drill another 53 wells in the second half of the year,
predominately for oil targets. The province of Alberta implemented a royalty incentive
limiting royalties to five percent for the first year if the well is completed before April
1, 2011, as well as a $200-per-meter drilled royalty credit. We continue to evaluate our
substantial prospect inventory with these incentives in mind but will generally need more
cost relief and/or higher gas prices to increase activity substantially. |
|
|
|
|
Activity at our Horn River (Ootla) shale play remained high during the quarter. We
currently have six horizontal Muskwa wells from the 2008 drilling program
producing an aggregate gross 14 MMcf/d after more than a year, on
average. Also,
the first three wells from the Encana-operated 2009 program are on
production
and together produced a gross 26 MMcf/d after three weeks, on average. A fourth
well is expected to be on production in early August 2009.
Encana will finish drilling another 11 wells while Apache completes
its 16-well program on the 70-K pad by the end of the third quarter of
2009. Completion operations for these wells will commence late this year,
and we anticipate first production by the end of the first quarter of 2010. We are quite
pleased with the improved efficiencies that we have been able to achieve, as drilling times
have improved to as little as 16 days from our original estimation of 30 days. |
|
|
|
|
In the second quarter, the partners commissioned a new dehydration and compressor facility
and a new 42-mile, 24-inch sales line, with capacity of over 700 MMcf/d, that will allow us
to flow gas to a third-partys interconnect point. |
|
|
|
|
Given soft gas prices, the partners will need to continue to look for ways to reduce costs.
We believe combining our results to date with our acreage position will enable us to drill
up to 3,000 gross wells in the Ootla shale play over the next several decades. |
29
RESULTS OF OPERATIONS
Revenues
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Oil and Gas Production Revenues Quarter |
|
|
|
Crude Oil |
|
|
Natural Gas |
|
|
NGLs |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Revenues for the quarter ended June 30, 2007 |
|
$ |
1,473,621 |
|
|
$ |
922,736 |
|
|
$ |
47,674 |
|
|
$ |
2,444,031 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume increase (decrease) |
|
|
89,708 |
|
|
|
(119,798 |
) |
|
|
(5,056 |
) |
|
|
(35,146 |
) |
Price increase |
|
|
1,243,800 |
|
|
|
444,557 |
|
|
|
18,948 |
|
|
|
1,707,305 |
|
Impact of hedges decrease |
|
|
(200,225 |
) |
|
|
(11,847 |
) |
|
|
|
|
|
|
(212,072 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in 2008 |
|
$ |
1,133,283 |
|
|
$ |
312,912 |
|
|
$ |
13,892 |
|
|
$ |
1,460,087 |
|
|
Revenues for the quarter ended June 30, 2008 |
|
$ |
2,606,904 |
|
|
$ |
1,235,648 |
|
|
$ |
61,566 |
|
|
$ |
3,904,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution to total year-to-date 2008 revenues |
|
|
67 |
% |
|
|
31 |
% |
|
|
2 |
% |
|
|
100 |
% |
|
Volume increase (decrease) |
|
|
118,948 |
|
|
|
31,342 |
|
|
|
(2,936 |
) |
|
|
147,354 |
|
Price decrease |
|
|
(1,453,720 |
) |
|
|
(760,451 |
) |
|
|
(35,981 |
) |
|
|
(2,250,152 |
) |
Impact of hedges increase |
|
|
219,264 |
|
|
|
53,760 |
|
|
|
|
|
|
|
273,024 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in 2009 |
|
$ |
(1,115,508 |
) |
|
$ |
(675,349 |
) |
|
$ |
(38,917 |
) |
|
$ |
(1,829,774 |
) |
|
Revenues for the quarter ended June 30, 2009 |
|
$ |
1,491,396 |
|
|
$ |
560,299 |
|
|
$ |
22,649 |
|
|
$ |
2,074,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution to total year-to-date 2009 revenues |
|
|
72 |
% |
|
|
27 |
% |
|
|
1 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Oil and Gas Production Revenues Six Months |
|
|
|
Crude Oil |
|
|
Natural Gas |
|
|
NGLs |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Revenues for the six months ended June 30, 2007 |
|
$ |
2,633,550 |
|
|
$ |
1,749,497 |
|
|
$ |
84,051 |
|
|
$ |
4,467,098 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume increase (decrease) |
|
|
416,323 |
|
|
|
(129,932 |
) |
|
|
(3,637 |
) |
|
|
282,754 |
|
Price increase |
|
|
1,989,824 |
|
|
|
631,233 |
|
|
|
41,727 |
|
|
|
2,662,784 |
|
Impact of hedges decrease |
|
|
(313,073 |
) |
|
|
(17,496 |
) |
|
|
|
|
|
|
(330,569 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in 2008 |
|
$ |
2,093,074 |
|
|
$ |
483,805 |
|
|
$ |
38,090 |
|
|
$ |
2,614,969 |
|
|
Revenues for the six months ended June 30, 2008 |
|
$ |
4,726,624 |
|
|
$ |
2,233,302 |
|
|
$ |
122,141 |
|
|
$ |
7,082,067 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution to total year-to-date 2008 revenues |
|
|
67 |
% |
|
|
31 |
% |
|
|
2 |
% |
|
|
100 |
% |
Volume increase (decrease) |
|
|
125,669 |
|
|
|
2,387 |
|
|
|
(7,180 |
) |
|
|
120,876 |
|
Price decrease |
|
|
(2,693,106 |
) |
|
|
(1,180,396 |
) |
|
|
(72,845 |
) |
|
|
(3,946,347 |
) |
Impact of hedges increase |
|
|
354,842 |
|
|
|
66,520 |
|
|
|
|
|
|
|
421,362 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in 2009 |
|
$ |
(2,212,595 |
) |
|
$ |
(1,111,489 |
) |
|
$ |
(80,025 |
) |
|
$ |
(3,404,109 |
) |
|
Revenues for the six months ended June 30, 2009 |
|
$ |
2,514,029 |
|
|
$ |
1,121,813 |
|
|
$ |
42,116 |
|
|
$ |
3,677,958 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution to total 2009 year-to-date revenues |
|
|
68 |
% |
|
|
31 |
% |
|
|
1 |
% |
|
|
100 |
% |
30
Production and Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended June 30, |
|
|
For the Six Months Ended June 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
Oil Volume b/d: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
88,530 |
|
|
|
100,049 |
|
|
|
(12 |
)% |
|
|
87,642 |
|
|
|
100,364 |
|
|
|
(13 |
)% |
Canada |
|
|
15,833 |
|
|
|
17,746 |
|
|
|
(11 |
)% |
|
|
16,090 |
|
|
|
17,547 |
|
|
|
(8 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
|
104,363 |
|
|
|
117,795 |
|
|
|
(11 |
)% |
|
|
103,732 |
|
|
|
117,911 |
|
|
|
(12 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt |
|
|
95,359 |
|
|
|
64,886 |
|
|
|
47 |
% |
|
|
89,475 |
|
|
|
63,718 |
|
|
|
40 |
% |
Australia |
|
|
10,478 |
|
|
|
8,367 |
|
|
|
25 |
% |
|
|
9,164 |
|
|
|
8,894 |
|
|
|
3 |
% |
North Sea |
|
|
59,688 |
|
|
|
56,570 |
|
|
|
6 |
% |
|
|
60,089 |
|
|
|
57,670 |
|
|
|
4 |
% |
Argentina |
|
|
11,948 |
|
|
|
12,067 |
|
|
|
(1 |
)% |
|
|
12,192 |
|
|
|
12,146 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
177,473 |
|
|
|
141,890 |
|
|
|
25 |
% |
|
|
170,920 |
|
|
|
142,428 |
|
|
|
20 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (1) |
|
|
281,836 |
|
|
|
259,685 |
|
|
|
9 |
% |
|
|
274,652 |
|
|
|
260,339 |
|
|
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Oil price Per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
57.00 |
|
|
$ |
97.64 |
|
|
|
(42 |
)% |
|
$ |
49.95 |
|
|
$ |
90.59 |
|
|
|
(45 |
)% |
Canada |
|
|
55.17 |
|
|
|
119.16 |
|
|
|
(54 |
)% |
|
|
46.49 |
|
|
|
106.33 |
|
|
|
(56 |
)% |
North America |
|
|
56.72 |
|
|
|
100.88 |
|
|
|
(44 |
)% |
|
|
49.41 |
|
|
|
92.93 |
|
|
|
(47 |
)% |
Egypt |
|
|
60.30 |
|
|
|
126.20 |
|
|
|
(52 |
)% |
|
|
51.90 |
|
|
|
112.28 |
|
|
|
(54 |
)% |
Australia |
|
|
63.01 |
|
|
|
133.79 |
|
|
|
(53 |
)% |
|
|
49.74 |
|
|
|
116.78 |
|
|
|
(57 |
)% |
North Sea |
|
|
58.77 |
|
|
|
121.10 |
|
|
|
(51 |
)% |
|
|
51.51 |
|
|
|
108.23 |
|
|
|
(52 |
)% |
Argentina |
|
|
46.17 |
|
|
|
50.12 |
|
|
|
(8 |
)% |
|
|
46.73 |
|
|
|
47.61 |
|
|
|
(2 |
)% |
International |
|
|
58.99 |
|
|
|
118.14 |
|
|
|
(50 |
)% |
|
|
51.28 |
|
|
|
105.41 |
|
|
|
(51 |
)% |
Total (2) |
|
|
58.15 |
|
|
|
110.32 |
|
|
|
(47 |
)% |
|
|
50.57 |
|
|
|
99.76 |
|
|
|
(49 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volume Mcf/d: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
662,834 |
|
|
|
758,524 |
|
|
|
(13 |
)% |
|
|
637,894 |
|
|
|
751,269 |
|
|
|
(15 |
)% |
Canada |
|
|
373,796 |
|
|
|
357,828 |
|
|
|
4 |
% |
|
|
365,551 |
|
|
|
359,289 |
|
|
|
2 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
|
1,036,630 |
|
|
|
1,116,352 |
|
|
|
(7 |
)% |
|
|
1,003,445 |
|
|
|
1,110,558 |
|
|
|
(10 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt |
|
|
376,737 |
|
|
|
233,793 |
|
|
|
61 |
% |
|
|
347,443 |
|
|
|
238,385 |
|
|
|
46 |
% |
Australia |
|
|
161,069 |
|
|
|
129,531 |
|
|
|
24 |
% |
|
|
151,607 |
|
|
|
160,355 |
|
|
|
(5 |
)% |
North Sea |
|
|
2,645 |
|
|
|
2,507 |
|
|
|
6 |
% |
|
|
2,663 |
|
|
|
2,556 |
|
|
|
4 |
% |
Argentina |
|
|
192,542 |
|
|
|
197,284 |
|
|
|
(2 |
)% |
|
|
192,250 |
|
|
|
181,209 |
|
|
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
732,993 |
|
|
|
563,115 |
|
|
|
30 |
% |
|
|
693,963 |
|
|
|
582,505 |
|
|
|
19 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (3) |
|
|
1,769,623 |
|
|
|
1,679,467 |
|
|
|
5 |
% |
|
|
1,697,408 |
|
|
|
1,693,063 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas price Per Mcf: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
3.88 |
|
|
$ |
10.62 |
|
|
|
(63 |
)% |
|
$ |
4.21 |
|
|
$ |
9.50 |
|
|
|
(56 |
)% |
Canada |
|
|
3.86 |
|
|
|
9.63 |
|
|
|
(60 |
)% |
|
|
4.26 |
|
|
|
8.59 |
|
|
|
(50 |
)% |
North America |
|
|
3.88 |
|
|
|
10.30 |
|
|
|
(62 |
)% |
|
|
4.23 |
|
|
|
9.21 |
|
|
|
(54 |
)% |
Egypt |
|
|
3.85 |
|
|
|
6.26 |
|
|
|
(39 |
)% |
|
|
3.73 |
|
|
|
5.72 |
|
|
|
(35 |
)% |
Australia |
|
|
1.82 |
|
|
|
2.17 |
|
|
|
(16 |
)% |
|
|
1.71 |
|
|
|
2.14 |
|
|
|
(20 |
)% |
North Sea |
|
|
12.24 |
|
|
|
21.90 |
|
|
|
(44 |
)% |
|
|
9.82 |
|
|
|
19.05 |
|
|
|
(48 |
)% |
Argentina |
|
|
1.89 |
|
|
|
1.39 |
|
|
|
36 |
% |
|
|
1.94 |
|
|
|
1.60 |
|
|
|
21 |
% |
International |
|
|
2.92 |
|
|
|
3.69 |
|
|
|
(21 |
)% |
|
|
2.82 |
|
|
|
3.51 |
|
|
|
(20 |
)% |
Total (4) |
|
|
3.48 |
|
|
|
8.09 |
|
|
|
(57 |
)% |
|
|
3.65 |
|
|
|
7.25 |
|
|
|
(50 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids (NGL) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume Barrels per day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
5,483 |
|
|
|
7,231 |
|
|
|
(24 |
)% |
|
|
5,198 |
|
|
|
7,236 |
|
|
|
(28 |
)% |
Canada |
|
|
2,052 |
|
|
|
1,868 |
|
|
|
10 |
% |
|
|
2,082 |
|
|
|
2,052 |
|
|
|
1 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
|
7,535 |
|
|
|
9,099 |
|
|
|
(17 |
)% |
|
|
7,280 |
|
|
|
9,288 |
|
|
|
(22 |
)% |
Argentina |
|
|
3,091 |
|
|
|
2,905 |
|
|
|
6 |
% |
|
|
3,114 |
|
|
|
2,812 |
|
|
|
11 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
10,626 |
|
|
|
12,004 |
|
|
|
(11 |
)% |
|
|
10,394 |
|
|
|
12,100 |
|
|
|
(14 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NGL Price Per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
27.36 |
|
|
$ |
65.27 |
|
|
|
(58 |
)% |
|
$ |
25.90 |
|
|
$ |
61.32 |
|
|
|
(58 |
)% |
Canada |
|
|
24.23 |
|
|
|
59.26 |
|
|
|
(59 |
)% |
|
|
22.40 |
|
|
|
56.05 |
|
|
|
(60 |
)% |
North America |
|
|
26.50 |
|
|
|
64.04 |
|
|
|
(59 |
)% |
|
|
24.90 |
|
|
|
60.15 |
|
|
|
(59 |
)% |
Argentina |
|
|
15.91 |
|
|
|
32.31 |
|
|
|
(51 |
)% |
|
|
16.51 |
|
|
|
39.98 |
|
|
|
(59 |
)% |
Total |
|
|
23.42 |
|
|
|
56.36 |
|
|
|
(58 |
)% |
|
|
22.39 |
|
|
|
55.46 |
|
|
|
(60 |
)% |
|
|
|
(1) |
|
Approximately eight percent of oil production was subject to financial derivative
hedges for the second quarter and six-month period of 2009; 18 percent for the 2008 second
quarter and six-month period. |
|
(2) |
|
Reflects a per barrel increase of $.51 and $1.04 from financial derivative hedging
activities for the 2009 second quarter and six-month period, respectively, and a decrease of
$8.72 and $6.40 from financial derivative hedging activities for the 2008 second quarter and
six-month period, respectively. |
|
(3) |
|
Approximately eight percent of natural gas production was subject to financial
derivative hedges for the second quarter and six-month period of 2009; 20 percent and 19
percent for the 2008 second quarter and six-month period, respectively. |
|
(4) |
|
Reflects a per Mcf increase of $.24 and $.18 from financial derivative hedging
activities for the 2009 second quarter and six-month period, respectively, and a decrease of
$.10 and $.03 from financial derivative hedging activities for the 2008 second quarter and
six-month period, respectively. |
31
Second-Quarter 2009 compared to Second-Quarter 2008
Crude Oil Revenues Second-quarter crude oil revenues of $1.5 billion were $1.1 billion lower
than the 2008 period, with gains driven by a nine percent increase in oil production more than
offset by a 47 percent decrease in average realized price. Crude oil accounted for 72 percent of
our oil and gas production revenues during the quarter and 48 percent of our equivalent production,
compared to 68 and 47 percent, respectively, for the same period last year. While production
increased in three of our six producing countries, production in North America declined from
natural decline on lower levels of capital investments. North American exploration and development
capital was 43 percent less than 2008.
U.S. oil revenues were $430 million less than the 2008 quarter: $370 million from lower price
and $60 million from lower production. Prices in the U.S. decreased 42 percent from the year-ago
period, while production declined 12 percent. Our Gulf Coast region production was down 15
percent; nine percent on natural decline and six percent from production shut-in as a result of the
hurricanes in the second half of 2008. Our Central region production decreased six percent from
natural decline.
Canadas revenues decreased $113 million, with $103 million of the decline attributed to lower
price realizations. Canadas oil prices averaged $55.17 per barrel, down from $119.16 in the 2008
comparative quarter. Production declined 11 percent, primarily from natural decline.
Egypts crude oil revenues were $222 million less than the prior-year quarter, despite a
significant increase in production. Oil price realizations were well below year-ago levels,
falling 52 percent, reducing revenues by $389 million. Production growth added $167 million,
relative to the 2008 period. Net production increased 47 percent while gross production was up
only 27 percent. Our drilling and recompletion programs at the Khalda, Khalda Extension, East
Bahariya, South Umbarka, Matruh and West Kalabsha concessions drove the gross production growth.
The additional gains in net production were related to an increased allocation of gross production
for cost recovery relative to the prior period, a function of lower prices and the mechanics of our
production sharing contracts.
Australias oil revenues dropped $42 million, with the impact of lower prices offsetting a 25
percent increase in production. Oil price realizations were 53 percent lower than the 2008 quarter
reducing revenues by $54 million. Production increased on restored volumes at Varanus Island, less
third-party downtime, and a successful workover and recompletion program at our Stag platform. The
additional production added $12 million in revenues. Repairs to the Varanus Island facility, which
was damaged in a 2008 gas pipeline explosion, and installation of a compressor to expand gross
compression capacity to 460 TJ/d will be completed in the third quarter and enable the facility to
produce above pre-incident levels.
North Sea crude oil revenues fell $304 million on a 51 percent decline in prices, reducing
revenues by $321 million. The impact of lower prices was partially offset by a six percent increase
in production. Production was up on a comparative basis because of our drilling program,
particularly at our Alpha platform, a successful workover program and less downtime.
On June 22, 2009, we announced that our Forties Charlie 6-3 well commenced production at a gross rate of 10,500
b/d, boosting our second-quarter exit-rate to more than 70,000 gross b/d.
Argentinas oil revenues fell $4.8 million, as the combination of lower production and lower
pricing impacted the current years quarter. Oil realizations declined eight percent, reducing
revenues by $4.3 million. Export price limitations imposed on our Argentine production limited the
volatility on price realizations that we experienced in other areas. Production declined one
percent as natural decline offset the impact of new wells and a successful workover program.
Natural Gas Revenues Second-quarter natural gas revenues of $560 million declined $675
million on a 57 percent decrease in realized natural gas prices. Worldwide production increased
five percent to 1,770 MMcf/d. Production increased in four of our six producing countries.
U.S. natural gas revenues decreased $499 million, with a 63 percent drop realized prices and a
13 percent decrease in production reducing revenues by $465 million and $34 million, respectively.
Natural gas prices averaged $3.88 per Mcf, down $6.74 per Mcf from the comparable year-ago period.
Central region production was down one percent from natural decline. Gulf Coast region production
was 20 percent lower, split between natural decline and production shut-in because of the 2008
hurricanes. Gulf Coast region gas production was impacted by the lower levels of capital investment
as discussed under Crude Oil Revenues above. The wells still shut-in are awaiting repairs to
third-party pipelines, the timing of which is beyond our control.
32
Canadas natural gas revenues fell $182 million on a 60 percent decrease in realized natural
gas prices. Gas price realizations fell $5.77 to $3.86 per Mcf, lowering revenues $188 million.
Natural gas production increased
four percent on improved net realizations resulting from a lower effective royalty rate, new
wells and recompletion activity. Increased production added $6 million in revenues.
Egypts natural gas revenues were essentially flat compared to the 2008 second quarter, with
$50 million of additional revenues attributed to production gains offsetting the $51 million
reduction related to a 39 percent price decline. Net production was up 61 percent, while gross
production rose only 33 percent. The increase in gross production followed the completion of two
new Salam Base gas trains and the Northern Pipeline compression project, which increased
transportation and processing capacity. The additional net production was primarily related to an
increased allocation of gross production for cost recovery relative to the prior period, a function
of lower prices and the mechanics of our production sharing contracts.
Australias natural gas revenues were flat to the prior-year period, with the impact of a 24
percent increase in production offsetting a 16 percent decrease in price. Prices were down mostly
on foreign currency fluctuations. Production was up primarily because of repairs to the Varanus
Island facility, which was damaged in a 2008 gas pipeline explosion. These repairs and
installation of a compressor to expand gross compression capacity to 460 TJ/d will be completed in
the third quarter and enable the facility to produce above pre-incident levels.
Argentinas gas revenues increased $8 million as higher prices offset the impact of slightly
lower production. Natural gas realizations averaged $1.89, up $.50 per Mcf from last years second
quarter as we delivered more of our gas into higher-priced contracts. The increase in price added
$9 million in revenues. Production declined two percent because of sales pipeline constraints.
Year-to-Date 2009 compared to Year-to-Date 2008
Crude Oil Revenues Crude oil revenues for the six-month period of 2009 totaled $2.5 billion
and were $2.2 billion lower than the 2008 period because of a 49 percent decrease in average
realized price. Crude oil for the six-month period accounted for 68 percent of our oil and gas
revenues and 48 percent of our equivalent production, compared to 67 and 47 percent, respectively,
for the same period last year. Production increased five percent, to 274,652 b/d, as a 20 percent
increase in production from our international regions more than offset a 12 percent decline in our
North America production. Production declines in North America stem from our reduction in
exploration and development capital, which was 43 percent below year-ago levels. Worldwide,
our exploration and development capital investments for the first half of the year decreased 33
percent from the same period in 2008.
U.S. oil revenues declined $862 million on a 45 percent decrease in realized crude oil prices
and a 13 percent decrease in production. The impact from price and production was $742 million and
$120 million, respectively. Gulf Coast region production was down 18 percent, two-thirds of
which was driven by natural decline which offset drilling and recompletion activities. The
remainder was associated with production that has not yet been restored after the hurricanes in the
second half of 2008. Production from our Central region decreased four percent from natural
decline and lower drilling activities.
Canadas revenues decreased $204 million, $191 million of which was related to lower price
realizations. Canadas oil prices averaged $46.49 per barrel, down from $106.33 in the comparative
period. Production declined eight percent, with the impact of natural decline, increases in
provincial royalties and property divestitures more than offsetting
a reduction in drilling activities.
Egypts oil revenues fell $462 million compared to last years six-month period, despite an
increase in production. Oil realizations fell 54 percent reducing revenues by $700 million. Net
production was 40 percent higher, while gross production increased only 24 percent. The increase
in gross production came from new wells and successful recompletions, notably from our East
Bahariya Extension, South Umbarka and Matruh concessions. Additional gains in net production
resulted from a higher allocation of gross production for cost recovery relative to the prior
period, a function of lower prices and the mechanics of our production sharing contracts.
Australias oil revenues were $107 million lower than the comparable period despite a three
percent increase in production. Prices, which were 57 percent lower than the prior year, reduced
revenues by $109 million. Production rose on less weather-related and third-party downtime, as
well as restored production volumes from Varanus Island.
33
North Sea crude oil revenues fell $576 million from year-ago levels, with a 52 percent drop in
realized prices reducing revenues by $595 million. Production rose 2,419 b/d driven by our
drilling program, a successful workover program and less downtime.
Argentinas oil revenues were down $2 million on lower prices. Oil realizations fell two
percent to $46.73 per barrel. Export price limitations imposed on our Argentine production limited
the volatility on realized prices that we experienced in other jurisdictions. Production rose
marginally from last years levels as new wells brought online offset production lost from natural
decline.
Natural Gas Revenues Natural gas revenues for the six-month period of 2009 totaled $1.1
billion, half of the comparable 2008 revenues. The decline reflects a 50 percent decrease in
realized natural gas prices. Production was flat period-over-period as a 10 percent decline in
North America production was offset by increased gas production internationally.
U.S. natural gas revenues decreased $813 million on a 56 percent decline in realized prices
and a 15 percent decrease in production. Natural gas prices averaged $4.21 per Mcf, down $5.29 per
Mcf from the comparable year-ago period, decreasing revenues by $723 million. In our Central
region, production was held flat, with drilling activities and strategic acquisitions offsetting
natural decline. In the Gulf Coast region, production was 25 percent lower, split between natural
decline and production shut-in from the 2008 hurricanes. The wells still shut-in are awaiting
repairs to damaged third-party pipelines, the timing of which is beyond our control.
Canadas natural gas revenues fell $280 million on a 50 percent decrease in realized natural
gas prices. Gas price realizations fell $4.33 to $4.26 per Mcf. Natural gas production increased
two percent on improved net realizations resulting from a lower effective royalty rate, in addition
to new wells and recompletion activity, relative to the prior-year period.
Egypts natural gas revenues fell $13 million. Increased net production did not fully offset
the impact of a 35 percent decrease in realized price, which lowered revenues $86 million.
Production gains increased revenues $73 million. Net production was up 46 percent, while gross
production rose only 22 percent. The increase in gross production followed the completion of two
new Salam Base gas trains and the Northern Pipeline compression project, which increased
transportation and processing capacity. The additional net production was primarily related to an
increased allocation of gross production for cost recovery relative to the prior period, a function
of lower prices and the mechanics of our production sharing contracts.
Australia reported a $16 million dollar decrease in natural gas revenues compared to last
years six-month period. Lower realized prices and production reduced revenues $13 million and $3
million, respectively. Realized prices fell 20 percent, mostly on foreign currency fluctuations.
Production was five percent lower on the impact of a June 2008 pipeline explosion and fire at the
Varanus Island facility, which shut-in production from our John Brookes field and Harriet Joint
Venture. Repairs to the Varanus Island facility and installation of a compressor to expand gross
compression capacity to 460 TJ/d will be completed in the third quarter and enable the facility to
produce above pre-incident levels.
Argentinas natural gas revenues rose $15 million on increases in both prices and production.
Production increased six percent from new wells and recompletions in the Neuquén basin, which more
than offset the impact of natural decline and increased re-injections at Tierra del Fuego. Prices
averaged $1.94 per Mcf, 21 percent higher than the prior-year period on a more favorable sales mix
achieved by delivering more of our gas into higher-priced contracts.
34
Costs
The table below presents a comparison of our expenses on an absolute dollar basis and an
equivalent unit of production (boe) basis. Our discussion may reference expenses either on a boe
basis, on an absolute dollar basis or both, depending on their relevance.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended June 30, |
|
|
For the Six Months Ended June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
|
(Per boe) |
|
|
(In millions) |
|
|
(Per boe) |
|
Depreciation, depletion and amortization
(DD&A): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas property |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring |
|
$ |
527 |
|
|
$ |
591 |
|
|
$ |
9.86 |
|
|
$ |
11.77 |
|
|
$ |
1,063 |
|
|
$ |
1,174 |
|
|
$ |
10.34 |
|
|
$ |
11.63 |
|
Additional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,818 |
|
|
|
|
|
|
|
27.41 |
|
|
|
|
|
Other assets |
|
|
46 |
|
|
|
37 |
|
|
|
.87 |
|
|
|
.74 |
|
|
|
91 |
|
|
|
74 |
|
|
|
.89 |
|
|
|
.73 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
|
573 |
|
|
|
628 |
|
|
|
10.73 |
|
|
|
12.51 |
|
|
|
3,972 |
|
|
|
1,248 |
|
|
|
38.64 |
|
|
|
12.36 |
|
Asset retirement obligation accretion |
|
|
27 |
|
|
|
25 |
|
|
|
.50 |
|
|
|
.51 |
|
|
|
53 |
|
|
|
52 |
|
|
|
.52 |
|
|
|
.52 |
|
Lease operating costs |
|
|
405 |
|
|
|
447 |
|
|
|
7.58 |
|
|
|
8.90 |
|
|
|
803 |
|
|
|
902 |
|
|
|
7.81 |
|
|
|
8.93 |
|
Gathering and transportation costs |
|
|
34 |
|
|
|
40 |
|
|
|
.62 |
|
|
|
.79 |
|
|
|
67 |
|
|
|
81 |
|
|
|
.65 |
|
|
|
.80 |
|
Taxes other than income |
|
|
116 |
|
|
|
298 |
|
|
|
2.17 |
|
|
|
5.95 |
|
|
|
203 |
|
|
|
541 |
|
|
|
1.98 |
|
|
|
5.36 |
|
General and administrative expense |
|
|
91 |
|
|
|
79 |
|
|
|
1.70 |
|
|
|
1.57 |
|
|
|
176 |
|
|
|
161 |
|
|
|
1.71 |
|
|
|
1.60 |
|
Financing costs, net |
|
|
61 |
|
|
|
39 |
|
|
|
1.14 |
|
|
|
.78 |
|
|
|
120 |
|
|
|
83 |
|
|
|
1.16 |
|
|
|
.83 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,307 |
|
|
$ |
1,556 |
|
|
$ |
24.44 |
|
|
$ |
31.01 |
|
|
$ |
5,394 |
|
|
$ |
3,068 |
|
|
$ |
52.47 |
|
|
$ |
30.40 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Second-Quarter 2009 compared to Second-Quarter 2008
Depreciation, Depletion and Amortization (DD&A) The following table details the changes in
recurring DD&A of oil and gas properties between the second quarters of 2009 and 2008:
|
|
|
|
|
|
|
Recurring DD&A |
|
|
|
(In millions) |
|
2008 DD&A |
|
$ |
591 |
|
Volume change |
|
|
11 |
|
Rate change |
|
|
(75 |
) |
|
|
|
|
|
|
|
|
|
2009 DD&A |
|
$ |
527 |
|
|
|
|
|
Recurring full-cost DD&A expense of $527 million decreased $64 million on an absolute dollar
basis: $75 million lower on rate offset by an increase of $11 million from higher production. The
Companys full-cost DD&A rate decreased $1.91 to $9.86 per boe. The decrease in rate reflects the
impact of a $5.33 billion non-cash write-down of the carrying value of our December 31, 2008 proved
oil and gas property balances in the U.S., U.K. North Sea, Canada and Argentina and a $2.82 billion
non-cash write-down of the carrying value of our March 31, 2009, proved oil and gas property
balances in the U.S. and Canada.
Under the full-cost method of accounting, the Company is required to review the carrying value
of its proved oil and gas properties each quarter on a country-by-country basis. Under these
rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income
taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas
reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing
future oil and gas production at the unescalated oil and gas prices and using costs in effect at
the end of each fiscal quarter and require a write-down if the ceiling is exceeded, even if
prices declined for only a short period of time.
Lease Operating Expenses (LOE) Our 2009 second-quarter LOE decreased nine percent on an
absolute dollar basis. On a per unit basis, LOE was down 15 percent when compared to the same
period in 2008: nine percent on lower cost and six percent on higher production.
Our LOE rate, which decreased $1.32 per boe, was impacted by the items below:
|
|
|
A stronger U.S. dollar relative to the prior-year quarter resulted in a $.56 reduction. |
|
|
|
|
Reduced workover costs in all regions, particularly on Permian Basin oil properties,
resulted in a reduction of $.53. |
|
|
|
|
Higher production reduced the rate by $.49. |
|
|
|
|
A reduction in power usage and declining rates per kilowatt hour in the U.S. Central
Region and Canada, lowered the rate by $.28. |
35
|
|
|
Hurricane repair costs in the U.S. added $.33 to the rate. |
|
|
|
|
The prior period includes a non-recurring LOE credit related to a reduction in our
accrual for an insurance contingency assessed by Oil Insurance Limited (OIL) should Apache
withdraw from the insurance pool. This credit in the second quarter of 2008 accounted for
$.21 of the increase in rate. |
Gathering and Transportation Gathering and transportation costs totaled $34 million in the
second quarter of 2009, down $6 million. On a per unit basis, gathering and transportation costs
were down 21 percent: 15 percent on
lower costs and six percent on higher total production. The following table presents
gathering and transportation costs paid by Apache directly to third-party carriers for each of the
periods presented:
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.S. |
|
$ |
8 |
|
|
$ |
11 |
|
Canada |
|
|
13 |
|
|
|
16 |
|
North Sea |
|
|
6 |
|
|
|
7 |
|
Egypt |
|
|
6 |
|
|
|
5 |
|
Argentina |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gathering and Transportation |
|
$ |
34 |
|
|
$ |
40 |
|
|
|
|
|
|
|
|
The decrease in Canada resulted primarily from the impact of foreign exchange rates, lower oil
production and decreased gas transportation rates. The decrease in the U.S. resulted primarily
from lower volumes transported under contracts where costs are paid directly to a third party.
Taxes other than Income Taxes other than income totaled $116 million, a decrease of $182
million. On a per unit basis, taxes other than income decreased 64 percent: 58 percent on lower
costs and six percent on higher total production. A detail of these taxes follows:
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.K. PRT |
|
$ |
73 |
|
|
$ |
220 |
|
Severance taxes |
|
|
18 |
|
|
|
47 |
|
Ad valorem taxes |
|
|
13 |
|
|
|
17 |
|
Canadian taxes |
|
|
4 |
|
|
|
4 |
|
Other |
|
|
8 |
|
|
|
10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Taxes other than Income |
|
$ |
116 |
|
|
$ |
298 |
|
|
|
|
|
|
|
|
North Sea Petroleum Revenue Tax (PRT) is assessed on net profits from subject fields in the
U.K. North Sea. U.K. PRT was $147 million less than the 2008 period on a 49 percent decrease in
net profits, driven by 50 percent lower realized oil prices.
Severance taxes are incurred primarily on onshore properties in the U.S. and certain
properties in Australia and Argentina. The decrease in severance taxes resulted from lower taxable
revenues in the U.S. and Australia, consistent with the lower realized oil and natural gas prices.
Ad valorem taxes are assessed on U.S. and Canadian assessed property values. The $4 million
decrease resulted from lower taxable valuations associated with decreases in oil and natural gas
prices.
General and Administrative Expenses General and administrative expenses (G&A) were $12
million higher, up $.13 to an average of $1.70 per boe. Non-recurring employee separation costs
incurred in the second quarter of 2009 added $.28 to the rate relative to 2008. Higher stock-based
compensation expense, which includes stock appreciation rights (SARs) expense, added $.03 to the
second-quarter 2009 rate as compared to 2008. These costs were partially offset by the impact of
production gains (-$.11 per boe) and various other miscellaneous corporate expense reductions
(-$.07 per boe).
36
Financing Costs, Net Financing costs incurred during the period noted are composed of the
following:
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Interest expense |
|
$ |
77,363 |
|
|
$ |
66,328 |
|
Amortization of deferred loan costs |
|
|
1,365 |
|
|
|
829 |
|
Capitalized interest |
|
|
(14,972 |
) |
|
|
(22,810 |
) |
Interest income |
|
|
(2,601 |
) |
|
|
(5,297 |
) |
|
|
|
|
|
|
|
Financing costs, net |
|
$ |
61,155 |
|
|
$ |
39,050 |
|
|
|
|
|
|
|
|
Net financing costs rose $22 million, or $.37 per boe. The increase in absolute dollars is
the result of an $11 million increase in interest expense related to higher average outstanding
debt balances, $8 million reduction in capitalized interest related to lower unproved property
balances and completion of long-term construction projects, and a $3 million decrease in interest
income. Higher production mitigated the impact of higher absolute costs on the rate per boe.
Provision for Income Taxes During interim periods, income tax expense is based on the
estimated effective income tax rate that is expected for the entire fiscal year, after
consideration of discrete items. No significant discrete tax events occurred during the second
quarter of 2009.
The provision for income taxes decreased $557 million to $342 million, 62 percent below prior
year, as income before taxes fell on lower oil and gas production revenues. The effective income
tax rate in the second quarter of 2009 was 43.5 percent compared to 38.3 percent in the second
quarter of 2008. The 2009 rate was higher on a $31 million non-cash deferred tax expense related
to the effect of the weakening U.S. dollar on re-measurement of our foreign deferred tax
liabilities. The foreign exchange impact on second-quarter 2008 income taxes was minimal.
Year-to-Date 2009 compared to Year-to-Date 2008
Depreciation, Depletion and Amortization (DD&A) The following table details the changes in
recurring DD&A of oil and gas properties between the six-month periods of 2009 and 2008:
|
|
|
|
|
|
|
Recurring DD&A |
|
|
|
(In millions) |
|
2008 DD&A |
|
$ |
1,174 |
|
Volume change |
|
|
(24 |
) |
Rate change |
|
|
(87 |
) |
|
|
|
|
|
|
|
|
|
2009 DD&A |
|
$ |
1,063 |
|
|
|
|
|
Recurring full-cost DD&A expense of $1.06 billion decreased $111 million on an absolute dollar
basis: $87 million lower on rate and $24 million from production mix, despite an increase in total
production. A higher percentage of production was contributed from regions with lower DD&A rates.
The Companys full-cost DD&A rate decreased $1.29 to $10.34 per boe. The decrease in rate
reflects the impact of a $5.33 billion non-cash write-down of the carrying value of our December
31, 2008 proved property balances in the U.S., U.K. North Sea, Canada and Argentina and a $2.82
billion non-cash write-down of the carrying value of our March 31, 2009, proved oil and gas
property balances in the U.S. and Canada.
Under the full-cost method of accounting, the Company is required to review the carrying value
of its proved oil and gas properties each quarter on a country-by-country basis. Under these
rules, capitalized costs of oil and gas properties, net of accumulated DD&A and deferred income
taxes, may not exceed the present value of estimated future net cash flows from proved oil and gas
reserves, discounted 10 percent, net of related tax effects. These rules generally require pricing
future oil and gas production at the unescalated oil and gas prices and using costs in effect at
the end of each fiscal quarter and require a write-down if the ceiling is exceeded, even if
prices declined for only a short period of time. Write-downs required by these rules do not impact
cash flow from operating activities. If oil and gas prices deteriorate from the Companys
quarter-end levels, additional write-downs may occur.
37
Lease Operating Expenses (LOE) Our first six months of 2009 LOE decreased 11 percent on an
absolute dollar basis. On a per unit basis, LOE was down 13 percent; 11 percent on lower costs and
two percent on higher production.
Our LOE rate, which decreased $1.12 per boe, was impacted by the items below:
|
|
|
A stronger U.S. dollar relative to the first six months of 2008 resulted in a $.64
reduction. |
|
|
|
|
Reduced workover costs in all regions, particularly on Permian Basin oil properties,
resulted in a reduction of $.47. |
|
|
|
|
Higher production reduced the rate by $.38. |
|
|
|
|
Lower labor and service costs reduced the rate by $.21. |
|
|
|
|
A reduction in power usage and declining rates per kilowatt hour in the U.S. Central
Region and Canada lowered the rate by $.16. |
|
|
|
|
Repair costs and shut-in production related to the 2008 Gulf of Mexico hurricanes added
$.55 to the rate. |
|
|
|
|
General cost increases in various other categories increased the rate by $.19. |
Gathering and Transportation Gathering and transportation costs totaled $67 million in the
first six months of 2009, down $14 million. On a per unit basis, gathering and transportation
costs were down 19 percent: 17 percent on lower costs and two percent on higher total production.
The following table presents gathering and transportation costs paid by Apache directly to
third-party carriers for each of the periods presented:
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.S. |
|
$ |
16 |
|
|
$ |
21 |
|
Canada |
|
|
24 |
|
|
|
34 |
|
North Sea |
|
|
13 |
|
|
|
15 |
|
Egypt |
|
|
12 |
|
|
|
9 |
|
Argentina |
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gathering and Transportation |
|
$ |
67 |
|
|
$ |
81 |
|
|
|
|
|
|
|
|
The decrease in the U.S resulted primarily from a decrease in volumes transported under
contracts where charges are paid directly to a third party. Canadas transportation was down
primarily from the impact of foreign exchange rates and lower transported volumes. North Sea costs
were down on foreign exchange rates. Egypt costs were up $3 million on an increase in exported
cargoes.
Taxes other than Income Taxes other than income totaled $203 million, a decrease of $338
million. On a per unit basis, taxes other than income decreased 63 percent: 61 percent on lower
costs and two percent on higher total production. A detail of these taxes follows:
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.K. PRT |
|
$ |
123 |
|
|
$ |
385 |
|
Severance taxes |
|
|
35 |
|
|
|
93 |
|
Ad valorem taxes |
|
|
21 |
|
|
|
39 |
|
Canadian taxes |
|
|
8 |
|
|
|
8 |
|
Other |
|
|
16 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Taxes other than Income |
|
$ |
203 |
|
|
$ |
541 |
|
|
|
|
|
|
|
|
North Sea PRT is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT
was $262 million less than the 2008 period on a 51 percent decrease in net profits driven by a 52
percent decrease in realized oil prices.
Severance taxes are incurred primarily on onshore properties in the U.S. and certain
properties in Australia and Argentina. The decrease in severance taxes resulted from lower taxable
revenues in the U.S., consistent with the lower realized oil and natural gas prices.
38
Ad valorem taxes are assessed on U.S. and Canadian assessed property values. The $18 million
decrease resulted from lower taxable valuations associated with decreases in oil and natural gas
prices.
General and Administrative Expenses General and administrative expenses (G&A) were $15
million higher, up $.11 to an average of $1.71 per boe. Expenses recognized pursuant to the
retirement of our founder and former chairman and separation costs related to staff reductions
added $.37 to the 2009 rate. These non-recurring costs were partially offset by lower incentive
compensation (-$.14), stock-based compensation, which includes SARs expense (-$.03), lower fringe
benefit cost (-$.06) and the impact of higher production (-$.03). SARs expense was down as a
result of a four percent decline in Apaches stock price during the first six months of 2009
compared to a 46 percent increase in the comparative 2008 period.
Financing Costs, Net Financing costs incurred during the periods noted are composed of the
following:
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Interest expense |
|
$ |
156,277 |
|
|
$ |
135,635 |
|
Amortization of deferred loan costs |
|
|
2,773 |
|
|
|
1,680 |
|
Capitalized interest |
|
|
(30,981 |
) |
|
|
(44,387 |
) |
Interest income |
|
|
(8,327 |
) |
|
|
(9,625 |
) |
|
|
|
|
|
|
|
Financing costs, net |
|
$ |
119,742 |
|
|
$ |
83,303 |
|
|
|
|
|
|
|
|
Net financing costs rose $36 million, or $.34 per boe. The increase in absolute dollars is
primarily the result of a $21 million increase in interest expense related to higher average
outstanding debt balances and a $13 million reduction in capitalized interest related to lower
unproved property balances and completion of long-term construction projects. Higher production
mitigated the impact of higher absolute costs on the rate per boe.
Provision for Income Taxes During interim periods, income tax expense is based on the
estimated effective income tax rate that is expected for the entire fiscal year, after
consideration of discrete items. The Companys non-cash write-down of the carrying value of its
proved oil and gas properties was deemed a discrete event, and therefore, the tax effects of the
write-down were recorded in the first quarter of 2009. No significant discrete tax events occurred
during the second quarter of 2009.
The provision for income taxes for the first six months of 2009 was a benefit of $354 million
compared to an expense of $1.55 billion in the 2008 period. The benefit was associated with the
non-cash write-down of the carrying value of our proved oil and gas properties previously
discussed. The effective income tax rate, impacted by the magnitude of the tax benefit related to
the write-down, was 21.3 percent compared to 38.6 percent in 2008. We recorded a $26 million
increase to tax expense in 2009 related to foreign currency fluctuations, compared to a $13 million
benefit in 2008.
CAPITAL RESOURCES AND LIQUIDITY
Our primary uses of cash are exploration, development and acquisition of oil and gas
properties, costs necessary to maintain ongoing operations, repayment of principal and interest on
outstanding debt and payment of dividends.
Our business, as with other extractive industries, is a depleting one in which each barrel
produced must be replaced or the Company and our reserves, a critical source of future liquidity,
will shrink. Cash investments are continuously required to fund exploration and development
projects and acquisitions, which are necessary to offset the inherent declines in production and
proven reserves. Future success in maintaining and growing reserves and production is highly
dependent on having capital resources available, the success of our exploration and development
activities and on acquiring additional reserves.
We fund our exploration and development activities primarily through net cash provided by
operating activities (operating cash flows or cash flows) and budget our capital expenditures
based on projected cash flows. Our long-term operating cash flows are dependent on commodity
prices, reserve replacement and the level of costs required for ongoing operations. Our operating
cash flows, both in the short-term and the long-term, are impacted by highly volatile oil and
natural gas prices (see Commodity Price below). Sales volumes and costs have also impacted cash
flows in the short-term, but have not been as volatile as commodity prices.
39
While cash flows are our primary source of liquidity, we may also elect to utilize available
committed borrowing capacity, access to both debt and equity capital markets or proceeds from the
occasional sale of nonstrategic assets for all other liquidity and capital resource needs.
Apaches ability to access the debt and equity capital markets is supported by its investment-grade
credit ratings. We believe the liquidity and capital resource alternatives available to Apache,
combined with internally-generated cash flows, will be adequate to fund our short-term and
long-term operations, including our capital spending program, repayment of debt maturities and any
amount that may ultimately be paid in connection with contingencies.
The ongoing disruption in the credit markets has had a significant adverse impact on a number
of financial institutions. We regularly review the credit worthiness of the banks and financial
institutions with which we do business. Thus far, our financial position and sources of liquidity
have not been materially impacted. However, further deterioration in the credit markets could
adversely affect the availability of external sources of short-term and long-term capital funding.
See Part II, Other Information, Item 1A, Risk Factors of this Form 10-Q and Part 1, Item 1
and 2, Business and Properties, Risk Factors Related to Our Business and Operations, in our
Annual Report on Form 10-K for the fiscal year ended December 31, 2008.
Commodity Prices
Crude oil trades in a global market; consequently, prices for all types and grades of crude
oil have historically moved in the same general direction. Natural gas has a limited global
transportation system and, therefore, is currently subject to local supply and demand conditions.
Approximately 60 percent of our natural gas is sold in the North American market, which tracks New
York Mercantile Exchange (NYMEX) prices, while our remaining international gas is not subject to
fluctuating daily gas spot markets.
Our average natural gas price realizations have been on a downward trend since peaking in July
2008, reaching a multi-year low of $3.38 per Mcf in April 2009. Our crude oil realizations
initially followed a similar trend, bottoming at a monthly average of $36.45 per barrel in December
2008, before increasing to an average of $68.76 in June 2009. Second-quarter 2009 average realized
prices were substantially lower than 2008 second-quarter prices. Average realized prices for
natural gas and crude oil in the first six months of 2009 were $3.65 per Mcf and $50.57 per barrel,
respectively, substantially below the $7.25 per Mcf and $99.76 per barrel realized in the
year-earlier period.
Following is a table of published monthly average NYMEX prices in the first half of 2009 and
2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2009 |
|
|
June |
|
May |
|
April |
|
March |
|
February |
|
January |
Crude Oil (per bbl)
|
|
$ |
69.72 |
|
|
$ |
59.51 |
|
|
$ |
50.48 |
|
|
$ |
48.25 |
|
|
$ |
39.47 |
|
|
$ |
41.99 |
|
|
Natural Gas (per Mcf)
|
|
$ |
3.53 |
|
|
$ |
3.29 |
|
|
$ |
3.97 |
|
|
$ |
4.13 |
|
|
$ |
4.49 |
|
|
$ |
5.96 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2008 |
|
|
June |
|
May |
|
April |
|
March |
|
February |
|
January |
Crude Oil (per bbl)
|
|
$ |
134.65 |
|
|
$ |
125.67 |
|
|
$ |
112.62 |
|
|
$ |
105.15 |
|
|
$ |
94.92 |
|
|
$ |
92.96 |
|
|
Natural Gas (per Mcf)
|
|
$ |
11.86 |
|
|
$ |
11.01 |
|
|
$ |
9.52 |
|
|
$ |
9.11 |
|
|
$ |
8.03 |
|
|
$ |
7.08 |
|
As we have experienced over the last 12 months, commodity prices remain volatile. Future
prices cannot be accurately predicted. For these reasons, we have historically based our capital
expenditure budget on projected cash flows, modifying initial annual budgets in the event of
significant changes in commodity prices. Given the recent commodity price levels, our expenditures
for the second quarter and first six months of 2009 were substantially lower than 2008 levels. We
continue to monitor prices and will adjust our capital budgets accordingly. Any price
deterioration will negatively impact our future oil and gas production revenues, earnings, cash
flows and liquidity.
40
Sources and Uses of Cash
The following table presents the sources and uses of our cash and cash equivalents for the
periods presented.
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Sources of Cash and Cash Equivalents: |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
1,367 |
|
|
$ |
3,738 |
|
Sale of short-term investments |
|
|
792 |
|
|
|
|
|
Sales of property and equipment |
|
|
|
|
|
|
300 |
|
Net commercial paper and bank loan borrowings |
|
|
148 |
|
|
|
|
|
Restricted cash |
|
|
14 |
|
|
|
|
|
Common stock issuances |
|
|
10 |
|
|
|
29 |
|
Other |
|
|
12 |
|
|
|
45 |
|
|
|
|
|
|
|
|
|
|
|
2,343 |
|
|
|
4,112 |
|
|
|
|
|
|
|
|
Uses of Cash and Cash Equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures(1) |
|
$ |
2,464 |
|
|
$ |
2,789 |
|
Payments on fixed-rate notes |
|
|
100 |
|
|
|
|
|
Dividends |
|
|
103 |
|
|
|
136 |
|
Restricted cash |
|
|
|
|
|
|
94 |
|
Net commercial paper and bank loan repayments |
|
|
|
|
|
|
183 |
|
Other |
|
|
86 |
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
2,753 |
|
|
|
3,229 |
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
$ |
(410 |
) |
|
$ |
883 |
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The table presents capital expenditures on a cash basis; therefore, the
amounts differ from those discussed elsewhere in this document, which include accruals. |
Net Cash Provided by Operating Activities Net cash provided by operating activities is our
primary source of capital and liquidity. Factors affecting operating cash flows are largely the
same as those that affect net earnings, with the exception of non-cash expenses such as DD&A, ARO
accretion and deferred income tax expense.
Operating cash flows totaled $1.4 billion for the first six months of the year, down $2.4
billion from the comparable 2008 period. The primary driver of the reduction was a $3.4 billion
decrease in oil and gas revenues, with the impact of lower commodity prices (oil and gas
realizations declined 49 percent and 50 percent, respectively) more than offsetting a two percent
increase in equivalent production. Also negatively impacting operating cash flows was a $449
million net decrease in working capital. These items were partially offset by the positive impact
of a $399 million decline in cash based expenses (expenses excluding non-cash expenses described
above) and lower current taxes, which decreased $969 million.
For a detailed discussion of commodity prices, production, costs and expenses, refer to the
Results of Operations of this Item 2. For additional detail of the changes in operating assets
and liabilities and the non-cash expenses which do not impact net cash provided by operating
activities, see the Statement of Consolidated Cash Flows in Item 1, Financial Statements of this
Form 10-Q.
Short-term Investments We occasionally invest in highly-liquid, short-term investments in
order to maximize our income on available cash balances. As needed, we may reduce such short-term
investment balances to further supplement our operating cash flows. At December 31, 2008, we had
$792 million invested in U.S. Treasury securities with original maturities greater than three
months but less than one year. These securities matured on April 2, 2009. At June 30, 2009, we
held no short-term investments.
Net commercial paper and bank loan borrowings One of the Companys Australian subsidiaries
has a secured revolving syndicated credit facility for its Van Gogh and Pyrenees oil developments
offshore Western Australia. During the year, the amount outstanding under that facility increased
$145 million, to $245 million.
Capital Expenditures As a result of the global economic slowdown and decline in oil and gas
prices, we substantially reduced our 2009 capital budget to approximately half of 2008 spending in
an effort to keep expenditures in line with our cash flows. Capital spending for the first half of
the year is in line with our Plan. As is our custom, we will review and revise our capital
expenditure estimates throughout the year based on changing industry conditions and
results-to-date.
41
Capital expenditures totaled $2.3 billion for the first six months of 2009, $944 million lower
than the first half of 2008. The following table presents a summary of the Companys capital
expenditures for the six months ended June 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
For the Six Months |
|
|
|
Ended |
|
|
|
June 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Exploration and Development Costs: |
|
|
|
|
|
|
|
|
United States |
|
$ |
569 |
|
|
$ |
1,005 |
|
Canada |
|
|
210 |
|
|
|
353 |
|
|
|
|
|
|
|
|
North America |
|
|
779 |
|
|
|
1,358 |
|
|
|
|
|
|
|
|
|
|
Egypt |
|
|
389 |
|
|
|
413 |
|
Australia |
|
|
285 |
|
|
|
453 |
|
North Sea |
|
|
216 |
|
|
|
255 |
|
Argentina |
|
|
82 |
|
|
|
146 |
|
Chile |
|
|
4 |
|
|
|
4 |
|
|
|
|
|
|
|
|
International |
|
|
976 |
|
|
|
1,271 |
|
|
|
|
|
|
|
|
Worldwide Exploration and Development Costs |
|
|
1,755 |
|
|
|
2,629 |
|
|
|
|
|
|
|
|
|
|
Gathering Transmission and Processing Facilities: |
|
|
|
|
|
|
|
|
Canada |
|
|
56 |
|
|
|
10 |
|
Egypt |
|
|
95 |
|
|
|
218 |
|
Australia |
|
|
13 |
|
|
|
5 |
|
Argentina |
|
|
1 |
|
|
|
3 |
|
|
|
|
|
|
|
|
Total Gathering Transmission and Processing Facility Cost |
|
|
165 |
|
|
|
236 |
|
|
|
|
|
|
|
|
|
Asset Retirement Costs |
|
|
88 |
|
|
|
172 |
|
|
Capitalized Interest |
|
|
31 |
|
|
|
44 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital Expenditures, excluding acquisitions |
|
|
2,039 |
|
|
|
3,081 |
|
|
|
|
|
|
|
|
|
Acquisitions Oil and Gas Properties |
|
|
249 |
|
|
|
151 |
|
|
|
|
|
|
|
|
|
Total Capital Expenditures |
|
$ |
2,288 |
|
|
$ |
3,232 |
|
|
|
|
|
|
|
|
Worldwide exploration and development (E&D) expenditures were down 33 percent from the same
period last year, with decreases in all six countries in which we have exploration and production
interests. The most significant decrease in spending occurred in North America, where E&D
investments declined 43 percent on lower activity. Decreased drilling activity in the Western
Desert drove Egypts E&D spending $24 million lower than the prior-year period. However, Egypts
percentage of worldwide E&D spending rose to 22 percent, up from 16 percent, as this decline was
less pronounced than in other regions. Australias E&D expenditures decreased nearly 37 percent on
lower drilling activity and reduced investments in platforms and production facilities. North Sea
E&D expenditures were $39 million lower upon completion of several platform upgrade projects in
2008.
Payments on fixed-rate notes The $100 million Apache Finance Pty Ltd (Apache Finance
Australia) 7.0% notes matured on March 15, 2009. The notes were repaid using existing cash
balances.
Dividends Common stock dividends of $100 million paid during the first six months of 2009
were $33 million less than in 2008. The 2008 common stock dividends included a special cash
dividend of 10 cents per common share paid on March 18, 2008. During the first six months of 2009
and 2008, Apache paid $2.8 million in dividends on its Series B Preferred Stock issued in August
1998.
42
Liquidity
The following table presents a summary of our key financial indicators at June 30, 2009 and
December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
June 30, |
|
December 31, |
|
|
2009 |
|
2008 |
|
|
(In millions of dollars, except as indicated) |
Cash |
|
$ |
772 |
|
|
$ |
1,181 |
|
Short-term investments |
|
|
|
|
|
|
792 |
|
Restricted cash |
|
|
|
|
|
|
14 |
|
Total debt |
|
|
4,967 |
|
|
|
4,922 |
|
Shareholders equity |
|
|
14,959 |
(2) |
|
|
16,509 |
(1) |
Available committed borrowing capacity |
|
|
2,405 |
|
|
|
2,550 |
|
Floating-rate debt/total debt |
|
|
5 |
% |
|
|
2 |
% |
Percent of total debt-to-capitalization |
|
|
25 |
% (2) |
|
|
23 |
% (1) |
|
|
|
(1) |
|
Our year-end shareholders equity balance and debt-to-capitalization ratio
were impacted by a $3.6 billion (after-tax) non-cash write-down in the carrying value
of oil and gas properties on December 31, 2008. |
|
(2) |
|
Our June 30, 2009, shareholders equity balance and debt-to-capitalization
ratio were impacted by a $3.6 billion (after-tax) non-cash write-down in the carrying
value of oil and gas properties on December 31, 2008, and a $1.98 billion (after-tax)
non-cash write-down in the carrying value of oil and gas properties on March 31, 2009. |
Cash and Cash Equivalents We had $772 million in cash and cash equivalents at June 30, 2009,
compared to $1.2 billion at December 31, 2008. At June 30, 2009, $415 million of cash was held by
foreign subsidiaries and $357 million was held by Apache Corporation and U.S. subsidiaries. The
cash held by foreign subsidiaries is subject to additional U.S. income taxes if repatriated.
Almost all of the cash is denominated in U.S. dollars and, at times, is invested in highly liquid,
investment grade securities with maturities of three months or less at the time of purchase. We
intend to use cash from our international subsidiaries to fund international projects.
Short-term Investments We occasionally invest in highly-liquid, short-term investments in
order to maximize our income on available cash balances. At June 30, 2009, we held no short-term
investments.
Debt At June 30, 2009, outstanding debt, which consisted of notes, debentures and uncommitted
bank lines, totaled $4.97 billion. Current debt includes $12 million borrowed under uncommitted
overdraft lines in Argentina.
Available committed borrowing capacity We ended the quarter with $2.4 billion of available
committed borrowing capacity, as discussed below.
As of June 30, 2009, the Company had unsecured committed revolving syndicated bank credit
facilities totaling $2.3 billion. The facilities consist of a $1.5 billion facility and a $450
million facility in the U.S., a $200 million facility in Australia and a $150 million facility in
Canada. Since there are no outstanding borrowings or commercial paper at quarter-end, the full
$2.3 billion of unsecured credit facilities are available to the Company.
The Company has available a $1.95 billion commercial paper program, which generally enables
Apache to borrow funds for up to 270 days at competitive interest rates. If the Company is unable
to issue commercial paper following a significant credit downgrade or dislocation in the market,
the Companys U.S. credit facilities are available as a 100-percent backstop.
One of the Companys Australian subsidiaries has a secured revolving syndicated credit
facility for its Van Gogh and Pyrenees oil developments offshore Western Australia. The facility
provides for total commitments of $350 million, with availability determined by a borrowing base
formula. The borrowing base was set at $350 million and will be redetermined after the fields
commence production and certain tests have been met, and semi-annually thereafter. As of June 30,
2009, there was $245 million outstanding under the facility, allowing for additional available
borrowing capacity of $105 million.
The Company was in compliance with the terms of all credit facilities as of June 30, 2009.
Percent of total debt to capitalization The Companys June 30, 2009, debt-to-capitalization
ratio was 25 percent, up from 23 percent at December 31, 2008.
Credit Rating As of June 30, 2009, we have maintained our single-A credit ratings. We cannot
predict, nor can we assure, that we will not receive a ratings downgrade in the future.
43
ITEM 3 QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Risk
We periodically enter into hedging activities on a portion of our projected oil and natural
gas production through a variety of financial and physical arrangements intended to support oil and
natural gas prices at targeted levels and to manage our overall exposure to oil and gas price
fluctuations. For the first six months of 2009, approximately eight percent of our natural gas and
crude oil production was subject to financial derivative hedges.
Apache may use futures contracts, swaps, options and fixed-price physical contracts to hedge
its commodity prices. Realized gains or losses from the Companys price-risk management activities
are recognized in oil and gas production revenues when the associated production occurs. Apache
does not generally hold or issue derivative instruments for trading purposes.
On June 30, 2009, the Company had open natural gas derivative hedges in an asset position with
a fair value of $60 million. A 10 percent increase in natural gas prices would reduce the fair
value by approximately $33 million, while a 10 percent decrease in prices would increase the fair
value by approximately $36 million. The Company also had open oil derivatives in a liability
position with a fair value of $153 million. A 10 percent increase in oil prices would increase the
liability by approximately $170 million, while a 10 percent decrease in prices would move the
derivatives to an asset position of $11 million. These fair value changes assume volatility based
on prevailing market parameters at June 30, 2009. See Note 2 Derivative Instruments and Hedging
Activities in Item 1 of this Form 10-Q for notional volumes and terms associated with the Companys
derivative contracts.
Interest Rate Risk
The Company considers its interest rate risk exposure to be minimal as a result of fixing
interest rates on approximately 95 percent of the Companys debt. At June 30, 2009, total debt
included $257 million of floating-rate debt. As a result, Apaches annual interest costs in 2009
will fluctuate based on short-term interest rates on what is
approximately five percent of our total debt outstanding at June 30, 2009. The impact on cash
flow of a 10 percent change in the floating interest rate from that at June 30, 2009, would be
approximately $144,000 per quarter.
Foreign Currency Risk
The Companys cash flows relating to certain international operations are based on the U.S.
dollar equivalent of cash flows measured in foreign currencies. In Australia, oil production is
sold under U.S. dollar contracts, and the majority of our gas production is sold under fixed-price
Australian dollar contracts. Approximately half of our costs incurred for Australian operations
are paid in U.S. dollars. In Canada, the majority of oil and gas production is sold under Canadian
dollar contracts. The majority of our costs incurred are paid in Canadian dollars. Our North Sea
production is sold under U.S. dollar contracts, and the majority of costs incurred are paid in
British pounds. In Egypt, all oil and gas production is sold under U.S. dollar contracts, and the
majority of the costs incurred are denominated in U.S. dollars. Argentine revenues and
expenditures are largely denominated in U.S. dollars but converted into Argentine pesos at the time
of payment. Revenue and disbursement transactions denominated in Australian dollars, Canadian
dollars, British pounds, Egyptian pounds and Argentine pesos are converted to U.S. dollar
equivalents based on the average exchange rates during the period.
Foreign currency gains and losses also arise when monetary assets and monetary liabilities
denominated in foreign currencies are translated at the end of each month. Currency gains and
losses are included as either a component of Other under Revenues and Other, or, as is the case
when we remeasure our foreign tax liabilities, as a component of the Companys income tax provision
(benefit) on the Statement of Consolidated Operations in Item 1 of this quarterly report.
44
Forward-Looking Statements and Risk
This report includes forward-looking statements within the meaning of Section 27A of the
Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as
amended. All statements other than statements of historical facts included or incorporated by
reference in this report, including, without limitation, statements regarding our future financial
position, business strategy, budgets, projected revenues, projected costs, and plans and objectives
of management for future operations, are forward-looking statements. Such forward-looking
statements are based on our examination of historical operating trends, the information that was
used to prepare our estimate of proved reserves as of December 31, 2008, and other data in our
possession or available from third parties. In addition, forward-looking statements generally can
be identified by the use of forward-looking terminology such as may, will, expect, intend,
project, estimate, anticipate, believe, continue or similar terminology. Although we
believe that the expectations reflected in such forward-looking statements are reasonable, we can
give no assurance that such expectations will prove to have been correct. Important factors that
could cause actual results to differ materially from our expectations include, but are not limited
to, our assumptions about:
|
|
|
the market prices of oil, natural gas, NGLs and other products or services; |
|
|
|
|
our commodity hedging arrangements; |
|
|
|
|
the supply and demand for oil, natural gas, NGLs and other products or services; |
|
|
|
|
production and reserve levels; |
|
|
|
|
drilling risks; |
|
|
|
|
economic and competitive conditions; |
|
|
|
|
the availability of capital resources; |
|
|
|
|
capital expenditure and other contractual obligations; |
|
|
|
|
currency exchange rates; |
|
|
|
|
weather conditions; |
|
|
|
|
inflation rates; |
|
|
|
|
the availability of goods and services; |
|
|
|
|
legislative or regulatory changes; |
|
|
|
|
terrorism; |
|
|
|
|
occurrence of property acquisitions or divestitures; |
|
|
|
|
the securities or capital markets and related risks such as general credit, liquidity,
market and interest-rate risks; and |
|
|
|
|
other factors disclosed under Items 1 and 2 Business and Properties Estimated
Proved Reserves and Future Net Cash Flows, Item 1A Risk Factors, Item 7
Managements Discussion and Analysis of Financial Condition and Results of Operations,
Item 7A Quantitative and Qualitative Disclosures About Market Risk and elsewhere in our
most recently filed Form 10-K. |
All subsequent written and oral forward-looking statements attributable to the Company, or
persons acting on its behalf, are expressly qualified in their entirety by the cautionary
statements. We assume no duty to update or revise our forward-looking statements based on changes
in internal estimates or expectations or otherwise.
45
ITEM 4 CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
G. Steven Farris, the Companys Chairman and Chief Executive Officer, in his capacity as
principal executive officer, and Roger B. Plank, the Companys President, in his capacity as
principal financial officer, evaluated the effectiveness of our disclosure controls and procedures
as of June 30, 2009, the end of the period covered by this report. Based on that evaluation and as
of the date of that evaluation, these officers concluded that the Companys disclosure controls and
procedures were effective, providing effective means to ensure that information we are required to
disclose under applicable laws and regulations is recorded, processed, summarized and reported
within the time periods specified in the Commissions rules and forms and communicated to our
management, including our principal executive officer and principal financial officer, to allow
timely decisions regarding required disclosure.
We periodically review the design and effectiveness of our disclosure controls, including
compliance with various laws and regulations that apply to our operations both inside and outside
the United States. We make modifications to improve the design and effectiveness of our disclosure
controls, and may take other corrective action, if our reviews identify deficiencies or weaknesses
in our controls.
Changes in Internal Control over Financial Reporting
There was no change in our internal controls over financial reporting during the period
covered by this quarterly report on Form 10-Q that materially affected, or is reasonably likely to
materially affect, our internal controls over financial reporting.
46
PART II OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
|
|
|
Please refer to both Part I, Item 3 of our Annual Report on Form 10-K for the fiscal
year ended December 31, 2008 (filed with the SEC on March 1, 2009) and Part I, Item 1 of
each of our Quarterly Reports on Form 10-Q for the fiscal quarters ended March 31, 2009
and June 30, 2009, for a description of material legal proceedings. |
ITEM 1A. RISK FACTORS
|
|
|
During the quarter ending June 30, 2009, there were no material changes from the risk
factors as previously disclosed in the Companys Annual Report on Form 10-K for the year
ended December 31, 2008 other than the following: |
|
|
|
|
Federal climate change regulation could increase our operating and capital costs. |
|
|
|
|
The American Clean Energy and Security Act of 2009 (ACES), also known as the
Waxman-Markey Bill, was approved by the U.S. House of Representatives on June 26, 2009.
The ACES, if passed by the U.S. Senate, would establish a variant of a cap-and-trade
plan for greenhouse gases (GHG) in order to address climate change. A cap-and-trade
plan would require businesses that emit more greenhouse gases than permitted to acquire
emission allowances from other businesses that emit greenhouse gases at levels lower
than the limits specified and then surrender these allowances as a credit against such
emissions. As a result of such a plan, we could be required to implement costly
compliance technology and procedures in the U.S. |
|
|
|
|
Although it is not possible at this time to predict the final outcome of the ACES, any
new federal restrictions on GHG emissions, including a cap-and-trade-plan, that may be
imposed in areas in which we conduct business could result in increased compliance costs
or additional operating restrictions, and could have an adverse effect on our business
or demand for the crude oil and natural gas we produce in the U.S. |
|
|
|
|
The proposed U.S. federal budget for fiscal year 2010 includes certain provisions that,
if passed as originally submitted, will have an adverse effect on our financial
position, results of operations, and cash flows. |
|
|
|
|
On February 26, 2009, the Office of Management and Budget released a summary of the
proposed U.S. federal budget for fiscal year 2010. The proposed budget repeals many tax
incentives and deductions that are currently used by U.S. oil and gas companies and
imposes new taxes. The provisions include: elimination of the ability to fully deduct
intangible drilling costs in the year incurred; increases in the taxation of foreign
source income; levy of an excise tax on Gulf of Mexico oil and gas production; repeal of
the manufacturing tax deduction for oil and gas companies; and increase in the
geological and geophysical amortization period for independent producers. |
|
|
|
|
Should some or all of these provisions become law our taxes will increase, potentially
significantly, which would have a negative impact on our net income and cash flows. This
could also reduce our drilling activities in the U.S. Since none of these proposals have
yet to be voted on or become law, we do not know the ultimate impact these proposed
changes may have on our business. |
|
|
|
|
Proposed federal regulation regarding hydraulic fracturing could increase our operating
and capital costs. |
|
|
|
|
Several proposals are before the U.S. Congress that if implemented would either prohibit
the practice of hydraulic fracturing or subject the process to regulation under the Safe
Drinking Water Act. We routinely use fracturing techniques in the U.S. and other
regions to expand the available space for natural gas to migrate toward the well-bore.
It is typically done at substantial depths in very tight formations. |
|
|
|
|
Although it is not possible at this time to predict the final outcome of the legislation
regarding hydraulic fracturing, any new federal restrictions on hydraulic fracturing
that may be imposed in areas in which we conduct business could result in increased
compliance costs or additional operating restrictions in the U.S. |
47
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
|
|
|
The Companys annual meeting of stockholders was held in Houston, Texas, at 10:00 a.m.
local time, on Thursday, May 7, 2009. Proxies for the meeting were solicited pursuant
to Regulation 14 under the Securities Exchange Act of 1934. |
|
|
|
|
Out of a total of 335,174,637 shares of the Companys common stock outstanding and
entitled to vote, 290,759,619 shares were present at the meeting in person or by proxy,
representing 86.75 percent of the shares entitled to vote. Matters voted upon at the
meeting were as follows: |
|
|
|
We received stockholder votes for the election of four directors of Apache, each to
serve until Apaches annual meeting in 2012, or until their successors are duly
elected. We counted and tabulated all votes and determined the results of the votes
as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
Nominee |
|
For |
|
Against |
|
Abstain |
Frederick M. Bohen |
|
|
263,940,934 |
|
|
|
26,394,545 |
|
|
|
424,140 |
|
George D. Lawrence |
|
|
264,008,005 |
|
|
|
26,334,486 |
|
|
|
417,128 |
|
Rodman D. Patton |
|
|
282,665,960 |
|
|
|
7,762,956 |
|
|
|
330,703 |
|
Charles J. Pitman |
|
|
275,517,526 |
|
|
|
14,918,628 |
|
|
|
323,465 |
|
|
|
|
The name of each director whose term of office as a director continued after the
meeting is listed below: |
|
|
|
|
|
G. Steven Farris
|
|
Randolph M. Ferlic |
|
Eugene C. Fiedorek
|
|
A. D. Frazier, Jr. |
|
Patricia Albjerg Graham
|
|
John A. Kocur |
|
F. H. Merelli |
|
|
ITEM 5. OTHER INFORMATION
|
|
|
On August 6, 2009, the Board of Directors of Apache Corporation (Apache) amended
Sections 4 and 5 of Article IV and Section 4 of Article XI of Apaches bylaws, in
compliance with applicable law, to delete all references to 50 days therein and
replace such text with 60 days, which extends the period between the record date for
stockholders meetings and the associated meeting date to 60 days (from 50 days). This
description is qualified in its entirety by reference to the full text of Apaches
bylaws, as amended August 6, 2009, which is listed under Item 6 as Exhibit 3.1 and
incorporated herein by reference. |
48
ITEM 6. EXHIBITS
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3.1
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Restated Certificate of Incorporation of Registrant,
dated February 11, 2004, as filed with the Secretary of State of Delaware on February
12, 2004 (incorporated by reference to Exhibit 3.1 to Registrants Annual Report on
Form 10-K for year ended December 31, 2003, SEC File No. 001-4300). |
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*3.2
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Bylaws of Apache Corporation, as amended August 6, 2009. |
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*12.1
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Statement of computation of ratio of earnings to fixed charges and
combined fixed charges and preferred stock dividends. |
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*31.1
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Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the
Exchange Act) by Principal Executive Officer. |
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*31.2
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Certification (pursuant to 13a-14(a) or Rule 15d-14(a) of the
Exchange Act) by Principal Financial Officer. |
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**32.1
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Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906)
by Principal Executive Officer and Principal Financial Officer. |
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**101
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The following materials from Apache Corporations
Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, formatted in XBRL
(Extensible Business Reporting Language): (i) Consolidated Statement of Income, (ii)
Consolidated Balance Sheet, (iii) Consolidated Statement of Cash Flows, (iv)
Consolidated Statement of Equity, and (v) Notes to Consolidated Financial Statements,
tagged as blocks of text. |
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* |
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Filed herewith |
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** |
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Furnished herewith |
49
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly
caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
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APACHE CORPORATION
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Dated: August 7, 2009 |
/s/ ROGER B. PLANK
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Roger B. Plank |
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President
(Principal Financial Officer) |
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Dated: August 7, 2009 |
/s/ REBECCA A. HOYT
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Rebecca A. Hoyt |
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Vice President and Controller
(Principal Accounting Officer) |
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