e10vq
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
|
|
|
þ |
|
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended September 30, 2009
OR
|
|
|
o |
|
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)
|
|
|
Delaware
|
|
41-0747868 |
(State or other jurisdiction of
|
|
(I.R.S. Employer |
incorporation or organization)
|
|
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.
|
|
|
|
|
|
|
Large accelerated filer þ
|
|
Accelerated filer o
|
|
Non-accelerated filer o
|
|
Smaller reporting company o |
|
|
|
|
(Do not check if a smaller reporting company) |
|
|
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of
the Exchange Act). Yes o No þ
Number of shares of registrants common stock outstanding as of September 30, 2009
336,174,361
TABLE OF CONTENTS
PART I FINANCIAL INFORMATION
ITEM 1 FINANCIAL STATEMENTS
APACHE CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter |
|
|
For the Nine Months |
|
|
|
Ended September 30, |
|
|
Ended September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands, except per common share data) |
|
REVENUES AND OTHER: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and gas production revenues |
|
$ |
2,325,705 |
|
|
$ |
3,368,882 |
|
|
$ |
6,003,663 |
|
|
$ |
10,450,949 |
|
Other |
|
|
6,726 |
|
|
|
(3,998 |
) |
|
|
55,971 |
|
|
|
1,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,332,431 |
|
|
|
3,364,884 |
|
|
|
6,059,634 |
|
|
|
10,452,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Recurring |
|
|
625,898 |
|
|
|
600,887 |
|
|
|
1,779,874 |
|
|
|
1,849,044 |
|
Additional |
|
|
|
|
|
|
|
|
|
|
2,818,161 |
|
|
|
|
|
Asset retirement obligation accretion |
|
|
26,053 |
|
|
|
24,970 |
|
|
|
79,274 |
|
|
|
77,146 |
|
Lease operating expenses |
|
|
445,535 |
|
|
|
488,166 |
|
|
|
1,248,297 |
|
|
|
1,389,542 |
|
Gathering and transportation |
|
|
36,232 |
|
|
|
42,375 |
|
|
|
103,050 |
|
|
|
123,118 |
|
Taxes other than income |
|
|
183,931 |
|
|
|
304,280 |
|
|
|
387,211 |
|
|
|
845,406 |
|
General and administrative |
|
|
82,492 |
|
|
|
57,561 |
|
|
|
258,443 |
|
|
|
218,856 |
|
Financing costs, net |
|
|
61,684 |
|
|
|
33,291 |
|
|
|
181,426 |
|
|
|
116,594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,461,825 |
|
|
|
1,551,530 |
|
|
|
6,855,736 |
|
|
|
4,619,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE INCOME TAXES |
|
|
870,606 |
|
|
|
1,813,354 |
|
|
|
(796,102 |
) |
|
|
5,833,110 |
|
Current income tax provision |
|
|
262,430 |
|
|
|
305,735 |
|
|
|
483,171 |
|
|
|
1,495,641 |
|
Deferred income tax provision (benefit) |
|
|
166,160 |
|
|
|
316,794 |
|
|
|
(409,069 |
) |
|
|
679,902 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) |
|
|
442,016 |
|
|
|
1,190,825 |
|
|
|
(870,204 |
) |
|
|
3,657,567 |
|
Preferred stock dividends |
|
|
1,420 |
|
|
|
1,420 |
|
|
|
4,260 |
|
|
|
4,260 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) ATTRIBUTABLE TO COMMON STOCK |
|
$ |
440,596 |
|
|
$ |
1,189,405 |
|
|
$ |
(874,464 |
) |
|
$ |
3,653,307 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME (LOSS) PER COMMON SHARE: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Basic |
|
$ |
1.31 |
|
|
$ |
3.55 |
|
|
$ |
(2.61 |
) |
|
$ |
10.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted |
|
$ |
1.30 |
|
|
$ |
3.52 |
|
|
$ |
(2.61 |
) |
|
$ |
10.84 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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)
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
CASH FLOWS FROM OPERATING ACTIVITIES: |
|
|
|
|
|
|
|
|
Net income (loss) |
|
$ |
(870,204 |
) |
|
$ |
3,657,567 |
|
Adjustments to reconcile net income (loss) to net cash
provided by operating activities: |
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
4,598,035 |
|
|
|
1,849,044 |
|
Asset retirement obligation accretion |
|
|
79,274 |
|
|
|
77,146 |
|
Provision for (benefit from) deferred income taxes |
|
|
(409,069 |
) |
|
|
679,902 |
|
Unrealized loss on derivatives |
|
|
|
|
|
|
35,586 |
|
Other |
|
|
140,527 |
|
|
|
(11,231 |
) |
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
Receivables |
|
|
(228,095 |
) |
|
|
251,920 |
|
Inventories |
|
|
11,897 |
|
|
|
(7,729 |
) |
Advances and other |
|
|
(49,569 |
) |
|
|
27,891 |
|
Deferred charges and other |
|
|
868 |
|
|
|
(200,038 |
) |
Accounts payable |
|
|
(183,884 |
) |
|
|
71,188 |
|
Accrued expenses |
|
|
(351,153 |
) |
|
|
(367,553 |
) |
Deferred credits and noncurrent liabilities |
|
|
(59,156 |
) |
|
|
(35,125 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY OPERATING ACTIVITIES |
|
|
2,679,471 |
|
|
|
6,028,568 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
Additions to oil and gas property |
|
|
(2,838,537 |
) |
|
|
(4,062,975 |
) |
Additions to gas gathering, transmission and processing facilities |
|
|
(203,783 |
) |
|
|
(420,850 |
) |
Acquisition of Marathon properties |
|
|
(181,133 |
) |
|
|
|
|
Short-term investments |
|
|
791,999 |
|
|
|
|
|
Restricted cash |
|
|
13,880 |
|
|
|
(13,844 |
) |
Proceeds from sale of oil and gas properties |
|
|
|
|
|
|
306,701 |
|
Other, net |
|
|
(98,096 |
) |
|
|
(42,509 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES |
|
|
(2,515,670 |
) |
|
|
(4,233,477 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
Commercial paper, credit facility and bank notes, net |
|
|
230,176 |
|
|
|
(169,042 |
) |
Payments on fixed-rate notes |
|
|
(100,000 |
) |
|
|
(353 |
) |
Dividends paid |
|
|
(155,125 |
) |
|
|
(187,735 |
) |
Common stock activity |
|
|
19,028 |
|
|
|
31,207 |
|
Treasury stock activity, net |
|
|
5,344 |
|
|
|
4,171 |
|
Cost of debt and equity transactions |
|
|
(618 |
) |
|
|
(1,224 |
) |
Other |
|
|
13,308 |
|
|
|
46,666 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES |
|
|
12,113 |
|
|
|
(276,310 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE IN CASH AND CASH EQUIVALENTS |
|
|
175,914 |
|
|
|
1,518,781 |
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR |
|
|
1,181,450 |
|
|
|
125,823 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT END OF PERIOD |
|
$ |
1,357,364 |
|
|
$ |
1,644,604 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SUPPLEMENTARY CASH FLOW DATA: |
|
|
|
|
|
|
|
|
Interest paid, net of capitalized interest |
|
$ |
199,570 |
|
|
$ |
137,106 |
|
Income taxes paid, net of refunds |
|
|
461,024 |
|
|
|
1,512,864 |
|
The accompanying notes to consolidated financial statements
are an integral part of this statement.
2
APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
ASSETS |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT ASSETS: |
|
|
|
|
|
|
|
|
Cash and cash equivalents |
|
$ |
1,357,364 |
|
|
$ |
1,181,450 |
|
Short-term investments |
|
|
|
|
|
|
791,999 |
|
Receivables, net of allowance |
|
|
1,590,913 |
|
|
|
1,356,979 |
|
Inventories |
|
|
539,442 |
|
|
|
498,567 |
|
Drilling advances |
|
|
138,889 |
|
|
|
93,377 |
|
Derivative instruments |
|
|
29,166 |
|
|
|
154,280 |
|
Prepaid taxes |
|
|
292,332 |
|
|
|
303,414 |
|
Prepaid assets and other |
|
|
71,596 |
|
|
|
70,908 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,019,702 |
|
|
|
4,450,974 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT: |
|
|
|
|
|
|
|
|
Oil and gas, on the basis of full-cost accounting: |
|
|
|
|
|
|
|
|
Proved properties |
|
|
43,516,994 |
|
|
|
40,639,281 |
|
Unproved properties and properties under
development, not being amortized |
|
|
1,370,951 |
|
|
|
1,300,347 |
|
Gas gathering, transmission and processing facilities |
|
|
3,087,572 |
|
|
|
2,883,789 |
|
Other |
|
|
481,619 |
|
|
|
452,989 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
48,457,136 |
|
|
|
45,276,406 |
|
Less: Accumulated depreciation, depletion and amortization |
|
|
(25,911,605 |
) |
|
|
(21,317,889 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,545,531 |
|
|
|
23,958,517 |
|
|
|
|
|
|
|
|
OTHER ASSETS: |
|
|
|
|
|
|
|
|
Restricted cash |
|
|
|
|
|
|
13,880 |
|
Goodwill, net |
|
|
189,252 |
|
|
|
189,252 |
|
Deferred charges and other |
|
|
471,011 |
|
|
|
573,862 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
27,225,496 |
|
|
$ |
29,186,485 |
|
|
|
|
|
|
|
|
The accompanying notes to consolidated financial statements
are an integral part of this statement.
3
APACHE CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Unaudited)
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
LIABILITIES AND SHAREHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Accounts payable |
|
$ |
391,900 |
|
|
$ |
548,945 |
|
Accrued operating expense |
|
|
114,409 |
|
|
|
168,531 |
|
Accrued exploration and development |
|
|
662,387 |
|
|
|
964,859 |
|
Accrued compensation and benefits |
|
|
122,216 |
|
|
|
111,907 |
|
Accrued interest |
|
|
75,153 |
|
|
|
91,456 |
|
Accrued income taxes |
|
|
50,311 |
|
|
|
48,028 |
|
Current debt |
|
|
39,669 |
|
|
|
112,598 |
|
Asset retirement obligation |
|
|
267,269 |
|
|
|
339,155 |
|
Derivative instruments |
|
|
63,842 |
|
|
|
|
|
Other |
|
|
199,793 |
|
|
|
134,956 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,986,949 |
|
|
|
2,520,435 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT |
|
|
5,010,030 |
|
|
|
4,808,975 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER NONCURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
Income taxes |
|
|
2,643,522 |
|
|
|
3,166,657 |
|
Asset retirement obligation |
|
|
1,623,347 |
|
|
|
1,555,529 |
|
Other |
|
|
606,326 |
|
|
|
626,168 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,873,195 |
|
|
|
5,348,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES (Note 7) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
SHAREHOLDERS EQUITY: |
|
|
|
|
|
|
|
|
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,
343,907,219 and 342,754,114 shares issued, respectively |
|
|
214,942 |
|
|
|
214,221 |
|
Paid-in capital |
|
|
4,563,848 |
|
|
|
4,472,826 |
|
Retained earnings |
|
|
10,904,323 |
|
|
|
11,929,827 |
|
Treasury stock, at cost, 7,732,858 and 8,044,050 shares,
respectively |
|
|
(219,472 |
) |
|
|
(228,304 |
) |
Accumulated other comprehensive income (loss) |
|
|
(206,706 |
) |
|
|
21,764 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
15,355,322 |
|
|
|
16,508,721 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
27,225,496 |
|
|
$ |
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 |
|
$ |
3,657,567 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,657,567 |
|
|
|
|
|
|
|
|
|
|
|
3,657,567 |
|
Commodity hedges, net of income tax
benefit of $89,376 |
|
|
(172,989 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(172,989 |
) |
|
|
(172,989 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income |
|
$ |
3,484,578 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,260 |
) |
|
|
|
|
|
|
|
|
|
|
(4,260 |
) |
Common ($.55 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(183,735 |
) |
|
|
|
|
|
|
|
|
|
|
(183,735 |
) |
Common shares issued |
|
|
|
|
|
|
|
|
|
|
|
885 |
|
|
|
36,109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36,994 |
|
Treasury shares issued, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
247 |
|
|
|
|
|
|
|
9,283 |
|
|
|
|
|
|
|
9,530 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65,645 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
65,645 |
|
FIN 48 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,770 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(23,770 |
) |
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
131 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
145 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT SEPTEMBER 30, 2008 |
|
|
|
|
|
|
$ |
98,387 |
|
|
$ |
214,211 |
|
|
$ |
4,445,511 |
|
|
$ |
14,927,178 |
|
|
$ |
(228,981 |
) |
|
$ |
(693,200 |
) |
|
$ |
18,763,106 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
$ |
(870,204 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(870,204 |
) |
|
|
|
|
|
|
|
|
|
|
(870,204 |
) |
Commodity hedges, net of income tax
benefit of $124,671 |
|
|
(228,470 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(228,470 |
) |
|
|
(228,470 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive loss |
|
$ |
(1,098,674 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Preferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(4,260 |
) |
|
|
|
|
|
|
|
|
|
|
(4,260 |
) |
Common ($.45 per share) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(151,040 |
) |
|
|
|
|
|
|
|
|
|
|
(151,040 |
) |
Common shares issued |
|
|
|
|
|
|
|
|
|
|
|
721 |
|
|
|
3,778 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,499 |
|
Treasury shares issued, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(5,706 |
) |
|
|
|
|
|
|
8,832 |
|
|
|
|
|
|
|
3,126 |
|
Compensation expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95,731 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
95,731 |
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,781 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,781 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
BALANCE AT SEPTEMBER 30, 2009 |
|
|
|
|
|
|
$ |
98,387 |
|
|
$ |
214,942 |
|
|
$ |
4,563,848 |
|
|
$ |
10,904,323 |
|
|
$ |
(219,472 |
) |
|
$ |
(206,706 |
) |
|
$ |
15,355,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 accounting principles generally accepted in the United States (U.S. 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 September 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 U.S. 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 flow therefrom, asset retirement obligations and
income taxes. 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. This
guidance has been primarily codified into the FASB Accounting Standards Codification (ASC, also
known collectively as the Codification) Topic 805, Business Combinations. The guidance 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 standard 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. 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 this statement effective
January 1, 2009. However, since the Company did not close any material business combinations
during the nine months ended September 30, 2009, the adoption had a negligible impact on the
Companys consolidated financial statements.
Also in December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated
Financial Statements, which was primarily codified into ASC Topic 810, Consolidations. This
statement amends Accounting Research Bulletin No. 51, Consolidated Financial Statements. This
guidance 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 this statement 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, which was primarily codified into ASC Topic 815, Derivatives and Hedging.
This guidance 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 derivative instruments and related gains and losses, and disclosures about credit
risk-related contingent features in derivative agreements. This statement is effective for
financial statements issued for fiscal years and interim periods beginning after November 15, 2008.
Apache adopted this standard 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, which was primarily codified into ASC Topic 260, Earnings Per Share. This guidance
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, also codified into ASC
Topic 260. This guidance 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 this standard 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 was primarily codified into ASC Topic
825, Financial Instruments. This guidance 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 this statement.
In May 2009, the FASB issued SFAS No. 165, Subsequent Events, which was primarily codified
into ASC Topic 855, Subsequent Events. This guidance 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, this statement 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; |
|
|
|
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. |
This standard is effective for interim or annual periods ending after June 15, 2009, and is to
be applied prospectively. Apache adopted this statement as of June 30, 2009. For evaluation of
subsequent events, see Note 8 Subsequent Events of this Form 10-Q.
In June 2009, the FASB issued SFAS No. 168, The FASB Accounting Standards
CodificationTM and the Hierarchy of Generally Accepted Accounting Principles, which has
been primarily codified into ASC Topic 105, Generally Accepted Accounting Standards. This
guidance establishes the FASB Accounting Standards 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 U.S. GAAP for SEC registrants. All other
accounting literature excluded from the Codification is 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 does not change U.S. GAAP. This
statement is effective for financial statements issued for interim and annual periods ending after
September 15, 2009. Apache has adopted this standard for the quarter ending September 30, 2009.
The standard has had a minimal effect on the Companys financial statement disclosures, as all
references to authoritative accounting literature are referenced in accordance with the
Codification.
7
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, which was primarily codified into ASC Topic 715, Compensation
Retirement Benefits. This guidance 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. This standard 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.
In January 2009, the 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. In September
2009, the FASB issued Proposed Accounting Standards Update (ASU),
Extractive IndustriesOil and
Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (Exposure Draft No. 1730-100), to
align the guidance in U.S. GAAP with the changes the SEC made in December 2008. 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 public comment period for the Proposed
ASU ended October 15, 2009; however, no final guidance has been issued by the FASB. The Company is
continuing to evaluate the impact of this release.
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 are swaps and options and are
generally designated as cash flow hedges.
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 17
counterparties as of September 30, 2009. All of these counterparties are 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.
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
As of September 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 |
|
|
3,036 |
|
|
$ |
63.24 |
|
|
$ |
78.13 |
|
2010 (2) |
|
|
12,049 |
|
|
|
65.44 |
|
|
|
77.54 |
|
2011 |
|
|
9,122 |
|
|
|
67.45 |
|
|
|
79.09 |
|
2012 |
|
|
5,846 |
|
|
|
68.84 |
|
|
|
78.91 |
|
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. |
|
(2) |
|
Subsequent to September 30, 2009, Apache entered into crude oil hedges totaling 730
thousands of barrels (Mbbls). After consideration of these hedges, the weighted average
floor and ceiling prices for our 2010 production period positions are $65.70 and $78.58 per
barrel, respectively. |
As of September 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 |
|
|
22,036 |
|
|
$ |
5.63 |
|
|
$ |
7.34 |
|
2010 (2) |
|
|
128,071 |
|
|
|
5.59 |
|
|
|
5.62 |
|
2011 |
|
|
35,985 |
|
|
|
6.61 |
|
|
|
6.67 |
|
2012 |
|
|
42,927 |
|
|
|
6.72 |
|
|
|
6.98 |
|
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 dollar-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. |
|
(2) |
|
Subsequent to September 30, 2009, Apache entered into natural gas hedges totaling
21,900 MMBtu (in 000s). After consideration of these hedges, the weighted average floor and ceiling
prices for our 2010 production period positions are $5.62 and $5.82 per MMBtu,
respectively. |
As of September 30, 2009, Apache had the following open natural gas financial basis swap
contracts:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted |
|
|
|
|
|
|
Average |
Production |
|
MMBtu |
|
Price |
Period |
|
(in 000s) |
|
Differential
(1) |
2009 |
|
|
2,760 |
|
|
$ |
(0.52 |
) |
2010 |
|
|
41,975 |
|
|
|
(0.54 |
) |
|
|
|
(1) |
|
Natural gas financial basis swap contracts represent a weighted average
differential between prices at Inside FERC PEPL and NYMEX Henry Hub prices. |
9
Fair Values of Derivative Instruments Recorded in the Consolidated Balance Sheet
The Company accounts for derivative instruments and hedging activity in accordance with ASC
Topic 815, Derivatives and Hedging, 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:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Current Assets: Derivative instruments |
|
$ |
29 |
|
|
$ |
154 |
|
Other Assets: Deferred charges and other |
|
|
23 |
|
|
|
65 |
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
52 |
|
|
$ |
219 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current Liabilities: Derivative instruments |
|
$ |
63 |
|
|
$ |
|
|
Noncurrent Liabilities: Other |
|
|
130 |
|
|
|
7 |
|
|
|
|
|
|
|
|
Total Liabilities |
|
$ |
193 |
|
|
$ |
7 |
|
|
|
|
|
|
|
|
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.
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 |
|
For the Nine |
|
|
|
|
Ended |
|
Months Ended |
|
|
Gain (Loss) on Derivatives |
|
September 30, |
|
September 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 |
|
$ |
48 |
|
|
$ |
(202 |
) |
|
$ |
154 |
|
|
$ |
(515 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gain (loss) on
derivatives
recognized in
operations
(ineffective
portion and basis) |
|
Revenues and Other: Other |
|
$ |
2 |
|
|
$ |
(39 |
) |
|
$ |
|
|
|
$ |
(34 |
) |
Commodity Derivative Activity in Accumulated Other Comprehensive Income (Loss)
As of September 30, 2009, substantially all of the Companys derivative instruments were
designated as cash flow hedges in accordance with ASC Topic 815. 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 as of December 31, 2008 |
|
$ |
212 |
|
|
$ |
138 |
|
Realized amounts reclassified into earnings |
|
|
(154 |
) |
|
|
(105 |
) |
Net change in derivative fair value |
|
|
(199 |
) |
|
|
(124 |
) |
Ineffectiveness and basis swaps reclassified into earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unrealized loss on derivatives as of September 30, 2009 |
|
$ |
(141 |
) |
|
$ |
(91 |
) |
|
|
|
|
|
|
|
Based on market prices as of September 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 $141 million ($91 million after tax). Gains and losses on hedges are
realized in future earnings through mid-2014, in the same period as the related sales of natural
gas and crude oil production applicable to specific hedges. Included in accumulated other
comprehensive income (loss) as of September 30, 2009 is a net loss of approximately $33 million
($21 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.
10
3. DEBT
As of September 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 is 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 September 30, 2009 and December 31, 2008, respectively, was $335
million and $100 million. As of September 30, 2009, available borrowing capacity was $15 million.
Under the terms of the agreement, the facility amount begins reducing on June 30, 2010 and
semi-annually thereafter until maturity on March 31, 2014. The outstanding amount under this
facility must not exceed $300 million on June 30, 2010. Accordingly, $35 million of the current
balance will be repaid by June 30, 2010 and has been classified as current debt at September 30,
2009.
At September 30, 2009 and December 31, 2008, there was $4.7 million and $12.6 million,
respectively, borrowed on uncommitted overdraft lines.
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 Nine Months Ended |
|
|
|
September 30, |
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
2009 |
|
|
2008 |
|
|
|
(In thousands) |
|
Interest expense |
|
$ |
76,860 |
|
|
$ |
66,055 |
|
|
$ |
233,137 |
|
|
$ |
201,690 |
|
Amortization of deferred loan costs |
|
|
1,400 |
|
|
|
818 |
|
|
|
4,173 |
|
|
|
2,498 |
|
Capitalized interest |
|
|
(14,345 |
) |
|
|
(24,032 |
) |
|
|
(45,325 |
) |
|
|
(68,419 |
) |
Interest income |
|
|
(2,231 |
) |
|
|
(9,550 |
) |
|
|
(10,559 |
) |
|
|
(19,175 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing costs, net |
|
$ |
61,684 |
|
|
$ |
33,291 |
|
|
$ |
181,426 |
|
|
$ |
116,594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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. 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 or
capital taxes 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 September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
Income |
|
|
Shares |
|
|
Per Share |
|
|
Income |
|
|
Shares |
|
|
Per Share |
|
|
|
(In thousands, except per share amounts) |
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income attributable to common stock |
|
$ |
440,596 |
|
|
|
336,159 |
|
|
$ |
1.31 |
|
|
$ |
1,189,405 |
|
|
|
334,825 |
|
|
$ |
3.55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Dilutive Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and other |
|
|
|
|
|
|
1,713 |
|
|
|
|
|
|
|
|
|
|
|
3,069 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income attributable to common stock,
including assumed conversions |
|
$ |
440,596 |
|
|
|
337,872 |
|
|
$ |
1.30 |
|
|
$ |
1,189,405 |
|
|
|
337,894 |
|
|
$ |
3.52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
Loss |
|
|
Shares |
|
|
Per Share |
|
|
Income |
|
|
Shares |
|
|
Per Share |
|
|
|
(In thousands, except per share amounts) |
|
Basic: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) attributable to common stock |
|
$ |
(874,464 |
) |
|
|
335,637 |
|
|
$ |
(2.61 |
) |
|
$ |
3,653,307 |
|
|
|
334,145 |
|
|
$ |
10.93 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Effect of Dilutive Securities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Stock options and other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,006 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Diluted: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income (Loss) attributable to common stock,
including assumed conversions |
|
$ |
(874,464 |
) |
|
|
335,637 |
|
|
$ |
(2.61 |
) |
|
$ |
3,653,307 |
|
|
|
337,151 |
|
|
$ |
10.84 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The diluted earnings per share calculation excludes options and restricted stock that
were anti-dilutive totaling 2.4 million and 4.0 million for the three- and nine-month periods
ending September 30, 2009, respectively, and 358,000 for the three- and nine-month periods ending
September 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 ASC Topic 260, Earnings Per
Share. The adoption of ASC Topic 260 had a negligible impact on Apaches earnings per share.
Common and Preferred Stock Dividends
For each of the quarters ending September 30, 2009 and 2008, Apache paid $50 million in
dividends on its common stock. For the nine-month periods ended September 30, 2009 and 2008, the
Company paid $151 million and $183 million, respectively. The higher common stock dividends for
the first nine months of 2008 were attributable to a special cash dividend of 10 cents per common
share paid on March 18, 2008. In addition, for each of the three- and nine-month periods ended
September 30, 2009 and 2008, Apache paid a total of $1.4 million and $4.3 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:
|
|
|
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
program would be payable in five equal annual installments. As of September 30, 2009,
neither share price threshold had been met. |
12
|
|
|
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 nine months ended September 30, 2009:
|
|
|
|
|
|
|
(In thousands) |
|
Asset retirement obligation at December 31, 2008 |
|
$ |
1,894,684 |
|
Liabilities incurred |
|
|
180,133 |
|
Liabilities settled |
|
|
(304,806 |
) |
Accretion expense |
|
|
79,274 |
|
Revisions in estimated liabilities |
|
|
41,331 |
|
|
|
|
|
|
|
|
|
|
Asset retirement obligation at September 30, 2009 |
|
|
1,890,616 |
|
|
|
|
|
|
Less current portion |
|
|
267,269 |
|
|
|
|
|
Asset retirement obligation, long-term |
|
$ |
1,623,347 |
|
|
|
|
|
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 $18 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.
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. On October 5,
2009, the United States Supreme Court denied Mr. Grynbergs petition for a writ of certiorari. This
matter is concluded.
13
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.
Hurricane Related Litigation In a case styled Ned Comer, et al vs. Murphy Oil USA, Inc., et
al, Case No: 1:05-cv-00436; U.S.D.C., United States District Court, Southern District of
Mississippi, Mississippi property owners allege that hurricanes meteorological effects increased
in frequency and intensity due to global warming, and there will be continued future damage from
increasing intensity of storms and sea level rises. They claim this was caused by the various
defendants (oil and gas companies, electric and coal companies, and chemical manufacturers).
Plaintiffs claim defendants emissions of greenhouse gases cause global warming, which they blame
as the cause of their damages. They also claim that the oil company defendants artificially
inflated and manipulated the prices of gasoline, diesel fuel, jet fuel, natural gas, and other
end-use petrochemicals, and covered it up by misrepresentations. They further allege a conspiracy
to disseminate misinformation and cover up the relationship between the defendants and global
warming. Plaintiffs seek, among other damages, actual, consequential, and punitive or exemplary
damages. The District Court dismissed the case on August 30, 2007. The plaintiffs appealed the
dismissal. Prior to the dismissal, the plaintiffs filed a motion to amend the lawsuit to add
additional defendants, including Apache. On October 16, 2009, the United States Court of Appeals
for the Fifth Circuit reversed the judgment of the District Court and remanded the case to the
District Court. The Fifth Circuit held that plaintiffs have pleaded sufficient facts to
demonstrate standing for their public and private nuisance, trespass, and negligence claims, and
that those claims are justifiable and do not present a political question. However, the Fifth
Circuit declined to find standing for the unjust enrichment, civil conspiracy, and fraudulent
misrepresentation claims, and therefore dismissed those claims.
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 AU$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 September 30, 2009, the Company had an undiscounted reserve for environmental
remediation of approximately $29 million. The Company is not aware of any environmental claims
existing as of September 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.
14
8. SUBSEQUENT EVENTS
Subsequent
events have been evaluated for recognition and disclosure through November 6, 2009,
the date these financial statements were filed with the SEC.
On October 22, 2009, Apache and Kuwait Foreign Petroleum Exploration Co. (KUFPEC) signed an
exclusive agreement to supply gas from the Julimar and Brunello discoveries and become foundation
equity partners in Chevrons Wheatstone liquefied natural gas (LNG) hub in Western Australia,
opening up new markets for gas reserves from two of Apaches largest discoveries. Apache holds a
65-percent interest in the discoveries. Apaches projected net sales would approximate 190 MMcf/d
and 5,100 b/d with a projected 15-year production plateau when the multi-year project is fully
operational.
Chevron, which has a 100-percent interest in the Wheatstone field, will operate the LNG
facilities with a 75-percent project interest. Apache and KUFPEC will own the remaining 25-percent
project interest. Wheatstones first phase will consist of an offshore processing platform and
pipeline to shore, along with two LNG processing trains with a combined capacity of approximately
8.6 million tons per year. Our net capital for the project is currently estimated to be $1.2
billion for upstream development of the Julimar and Brunello fields and $3.0 billion in the
Wheatstone facilities. The investment will be funded as the multi-year project is developed.
9. FAIR VALUE MEASUREMENTS
ASC 820-10-35 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.
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 reputable third-party. These valuations are Level 2 inputs. See Note 2
Derivative Instruments and Hedging Activities of this Form 10-Q for further information.
The following table presents the Companys material assets and liabilities measured at fair
value on a recurring basis for each hierarchy level:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 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 |
|
$ |
|
|
|
$ |
81 |
|
|
$ |
|
|
|
$ |
81 |
|
|
$ |
(29 |
) |
|
$ |
52 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity Derivative Instruments |
|
|
|
|
|
|
222 |
|
|
|
|
|
|
|
222 |
|
|
|
(29 |
) |
|
|
193 |
|
|
|
|
(1) |
|
The derivative fair values above are based on analysis of each contract as
required by ASC Topic 820. 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 September 30, 2009. |
15
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
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. AROs 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 ASC 825-10-50, 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 September 30, 2009 and December 31, 2008:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
September 30, 2009 |
|
December 31, 2008 |
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Amount |
|
Value |
|
Amount |
|
Value |
|
|
(In millions) |
Total Debt, Net of Unamortized Discount |
|
$ |
5,050 |
|
|
$ |
5,718 |
|
|
$ |
4,922 |
|
|
$ |
5,092 |
|
16
10. BUSINESS SEGMENT INFORMATION
Apache is engaged in a single line of business. Both domestically and internationally, the
Company explores for, develops, and produces natural gas, crude oil and natural gas liquids. The
Company 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. Apache also has exploration interests 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
September 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Revenues |
|
$ |
801,841 |
|
|
$ |
213,840 |
|
|
$ |
697,207 |
|
|
$ |
115,868 |
|
|
$ |
411,148 |
|
|
$ |
85,801 |
|
|
$ |
|
|
|
$ |
2,325,705 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (1) |
|
$ |
295,292 |
|
|
$ |
52,223 |
|
|
$ |
476,828 |
|
|
$ |
15,160 |
|
|
$ |
151,300 |
|
|
$ |
17,253 |
|
|
$ |
|
|
|
$ |
1,008,056 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,726 |
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(82,492 |
) |
Financing costs, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(61,684 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
870,606 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended
September 30, 2009 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Revenues |
|
$ |
2,104,781 |
|
|
$ |
639,234 |
|
|
$ |
1,772,498 |
|
|
$ |
245,429 |
|
|
$ |
976,101 |
|
|
$ |
265,620 |
|
|
$ |
|
|
|
$ |
6,003,663 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income (Loss) (1) |
|
$ |
(561,283 |
) |
|
$ |
(1,442,810 |
) |
|
$ |
1,140,765 |
|
|
$ |
15,051 |
|
|
$ |
379,102 |
|
|
$ |
56,971 |
|
|
$ |
|
|
|
$ |
(412,204 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55,971 |
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(258,443 |
) |
Financing costs, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(181,426 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Loss Before Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
(796,102 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
10,547,529 |
|
|
$ |
4,549,469 |
|
|
$ |
5,273,039 |
|
|
$ |
3,147,525 |
|
|
$ |
2,269,512 |
|
|
$ |
1,406,548 |
|
|
$ |
31,874 |
|
|
$ |
27,225,496 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended
September 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Revenues |
|
$ |
1,311,052 |
|
|
$ |
462,470 |
|
|
$ |
778,124 |
|
|
$ |
76,817 |
|
|
$ |
642,563 |
|
|
$ |
97,856 |
|
|
$ |
|
|
|
$ |
3,368,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income(1) |
|
$ |
734,907 |
|
|
$ |
245,126 |
|
|
$ |
606,142 |
|
|
$ |
20,297 |
|
|
$ |
286,704 |
|
|
$ |
15,028 |
|
|
$ |
|
|
|
$ |
1,908,204 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3,998 |
) |
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(57,561 |
) |
Financing costs, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(33,291 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,813,354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended
September 30, 2008 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Production Revenues |
|
$ |
4,345,687 |
|
|
$ |
1,384,790 |
|
|
$ |
2,328,440 |
|
|
$ |
328,415 |
|
|
$ |
1,787,367 |
|
|
$ |
276,250 |
|
|
$ |
|
|
|
$ |
10,450,949 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating Income(1) |
|
$ |
2,587,714 |
|
|
$ |
721,435 |
|
|
$ |
1,870,362 |
|
|
$ |
134,398 |
|
|
$ |
806,239 |
|
|
$ |
46,545 |
|
|
$ |
|
|
|
$ |
6,166,693 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Income (Expense) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,867 |
|
General and administrative |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(218,856 |
) |
Financing costs, net |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(116,594 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income Before Income Taxes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
5,833,110 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Assets |
|
$ |
13,689,943 |
|
|
$ |
7,824,649 |
|
|
$ |
4,481,858 |
|
|
$ |
2,443,667 |
|
|
$ |
2,736,426 |
|
|
$ |
1,792,951 |
|
|
$ |
22,938 |
|
|
$ |
32,992,432 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(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 nine-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. |
17
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.
18
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended September 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 |
|
$ |
728,072 |
|
|
$ |
|
|
|
$ |
1,597,633 |
|
|
$ |
|
|
|
$ |
2,325,705 |
|
Equity in net income (loss) of affiliates |
|
|
315,186 |
|
|
|
8,480 |
|
|
|
(8,100 |
) |
|
|
(315,566 |
) |
|
|
|
|
Other |
|
|
1,240 |
|
|
|
14,824 |
|
|
|
(8,302 |
) |
|
|
(1,036 |
) |
|
|
6,726 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,044,498 |
|
|
|
23,304 |
|
|
|
1,581,231 |
|
|
|
(316,602 |
) |
|
|
2,332,431 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
228,120 |
|
|
|
|
|
|
|
397,778 |
|
|
|
|
|
|
|
625,898 |
|
Asset retirement obligation accretion |
|
|
15,607 |
|
|
|
|
|
|
|
10,446 |
|
|
|
|
|
|
|
26,053 |
|
Lease operating expenses |
|
|
193,952 |
|
|
|
|
|
|
|
251,583 |
|
|
|
|
|
|
|
445,535 |
|
Gathering and transportation costs |
|
|
8,526 |
|
|
|
|
|
|
|
27,706 |
|
|
|
|
|
|
|
36,232 |
|
Taxes other than income |
|
|
27,408 |
|
|
|
|
|
|
|
156,523 |
|
|
|
|
|
|
|
183,931 |
|
General and administrative |
|
|
64,001 |
|
|
|
|
|
|
|
19,527 |
|
|
|
(1,036 |
) |
|
|
82,492 |
|
Financing costs, net |
|
|
58,295 |
|
|
|
14,110 |
|
|
|
(10,721 |
) |
|
|
|
|
|
|
61,684 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
595,909 |
|
|
|
14,110 |
|
|
|
852,842 |
|
|
|
(1,036 |
) |
|
|
1,461,825 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME BEFORE INCOME TAXES |
|
|
448,589 |
|
|
|
9,194 |
|
|
|
728,389 |
|
|
|
(315,566 |
) |
|
|
870,606 |
|
Provision for income taxes |
|
|
6,573 |
|
|
|
8,814 |
|
|
|
413,203 |
|
|
|
|
|
|
|
428,590 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
442,016 |
|
|
|
380 |
|
|
|
315,186 |
|
|
|
(315,566 |
) |
|
|
442,016 |
|
Preferred stock dividends |
|
|
1,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK |
|
$ |
440,596 |
|
|
$ |
380 |
|
|
$ |
315,186 |
|
|
$ |
(315,566 |
) |
|
$ |
440,596 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Quarter Ended September 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 |
|
$ |
1,290,323 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
2,086,279 |
|
|
$ |
(7,720 |
) |
|
$ |
3,368,882 |
|
Equity in net income (loss) of affiliates |
|
|
842,215 |
|
|
|
36,760 |
|
|
|
27,015 |
|
|
|
124,596 |
|
|
|
(3,705 |
) |
|
|
(1,026,881 |
) |
|
|
|
|
Other |
|
|
(51,534 |
) |
|
|
(24,263 |
) |
|
|
24,263 |
|
|
|
14,701 |
|
|
|
33,757 |
|
|
|
(922 |
) |
|
|
(3,998 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,081,004 |
|
|
|
12,497 |
|
|
|
51,278 |
|
|
|
139,297 |
|
|
|
2,116,331 |
|
|
|
(1,035,523 |
) |
|
|
3,364,884 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
257,091 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
343,796 |
|
|
|
|
|
|
|
600,887 |
|
Asset retirement obligation accretion |
|
|
16,174 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,796 |
|
|
|
|
|
|
|
24,970 |
|
Lease operating expenses |
|
|
229,018 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
259,148 |
|
|
|
|
|
|
|
488,166 |
|
Gathering and transportation costs |
|
|
11,928 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
38,167 |
|
|
|
(7,720 |
) |
|
|
42,375 |
|
Taxes other than income |
|
|
57,863 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
246,417 |
|
|
|
|
|
|
|
304,280 |
|
General and administrative |
|
|
43,661 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
14,822 |
|
|
|
(922 |
) |
|
|
57,561 |
|
Financing costs, net |
|
|
32,780 |
|
|
|
(2,777 |
) |
|
|
4,523 |
|
|
|
14,152 |
|
|
|
(15,387 |
) |
|
|
|
|
|
|
33,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
648,515 |
|
|
|
(2,777 |
) |
|
|
4,523 |
|
|
|
14,152 |
|
|
|
895,759 |
|
|
|
(8,642 |
) |
|
|
1,551,530 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE INCOME TAXES |
|
|
1,432,489 |
|
|
|
15,274 |
|
|
|
46,755 |
|
|
|
125,145 |
|
|
|
1,220,572 |
|
|
|
(1,026,881 |
) |
|
|
1,813,354 |
|
Provision (benefit) for income taxes |
|
|
241,664 |
|
|
|
(7,628 |
) |
|
|
9,995 |
|
|
|
141 |
|
|
|
378,357 |
|
|
|
|
|
|
|
622,529 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
1,190,825 |
|
|
|
22,902 |
|
|
|
36,760 |
|
|
|
125,004 |
|
|
|
842,215 |
|
|
|
(1,026,881 |
) |
|
|
1,190,825 |
|
Preferred stock dividends |
|
|
1,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,420 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK |
|
$ |
1,189,405 |
|
|
$ |
22,902 |
|
|
$ |
36,760 |
|
|
$ |
125,004 |
|
|
$ |
842,215 |
|
|
$ |
(1,026,881 |
) |
|
$ |
1,189,405 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
20
\
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 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 |
|
$ |
1,913,223 |
|
|
$ |
|
|
|
$ |
4,090,440 |
|
|
$ |
|
|
|
$ |
6,003,663 |
|
Equity in net income (loss) of affiliates |
|
|
(323,601 |
) |
|
|
(526,463 |
) |
|
|
133,123 |
|
|
|
716,941 |
|
|
|
|
|
Other |
|
|
1,632 |
|
|
|
44,138 |
|
|
|
13,272 |
|
|
|
(3,071 |
) |
|
|
55,971 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,591,254 |
|
|
|
(482,325 |
) |
|
|
4,236,835 |
|
|
|
713,870 |
|
|
|
6,059,634 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
1,871,151 |
|
|
|
|
|
|
|
2,726,884 |
|
|
|
|
|
|
|
4,598,035 |
|
Asset retirement obligation accretion |
|
|
48,082 |
|
|
|
|
|
|
|
31,192 |
|
|
|
|
|
|
|
79,274 |
|
Lease operating expenses |
|
|
540,759 |
|
|
|
|
|
|
|
707,538 |
|
|
|
|
|
|
|
1,248,297 |
|
Gathering and transportation costs |
|
|
24,222 |
|
|
|
|
|
|
|
78,828 |
|
|
|
|
|
|
|
103,050 |
|
Taxes other than income |
|
|
69,696 |
|
|
|
|
|
|
|
317,515 |
|
|
|
|
|
|
|
387,211 |
|
General and administrative |
|
|
210,178 |
|
|
|
|
|
|
|
51,336 |
|
|
|
(3,071 |
) |
|
|
258,443 |
|
Financing costs, net |
|
|
169,706 |
|
|
|
42,338 |
|
|
|
(30,618 |
) |
|
|
|
|
|
|
181,426 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,933,794 |
|
|
|
42,338 |
|
|
|
3,882,675 |
|
|
|
(3,071 |
) |
|
|
6,855,736 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE INCOME TAXES |
|
|
(1,342,540 |
) |
|
|
(524,663 |
) |
|
|
354,160 |
|
|
|
716,941 |
|
|
|
(796,102 |
) |
Provision (benefit) for income taxes |
|
|
(472,336 |
) |
|
|
(131,323 |
) |
|
|
677,761 |
|
|
|
|
|
|
|
74,102 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET LOSS |
|
|
(870,204 |
) |
|
|
(393,340 |
) |
|
|
(323,601 |
) |
|
|
716,941 |
|
|
|
(870,204 |
) |
Preferred stock dividends |
|
|
4,260 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,260 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LOSS ATTRIBUTABLE TO COMMON STOCK |
|
$ |
(874,464 |
) |
|
$ |
(393,340 |
) |
|
$ |
(323,601 |
) |
|
$ |
716,941 |
|
|
$ |
(874,464 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
21
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS
For the Nine Months Ended September 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 |
|
$ |
4,267,293 |
|
|
$ |
|
|
|
$ |
|
|
|
$ |
|
|
|
$ |
6,230,045 |
|
|
$ |
(46,389 |
) |
|
$ |
10,450,949 |
|
Equity in net income (loss) of affiliates |
|
|
2,267,847 |
|
|
|
51,205 |
|
|
|
51,760 |
|
|
|
307,270 |
|
|
|
(4,893 |
) |
|
|
(2,673,189 |
) |
|
|
|
|
Other |
|
|
(41,679 |
) |
|
|
(16,880 |
) |
|
|
16,804 |
|
|
|
44,024 |
|
|
|
2,365 |
|
|
|
(2,767 |
) |
|
|
1,867 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,493,461 |
|
|
|
34,325 |
|
|
|
68,564 |
|
|
|
351,294 |
|
|
|
6,227,517 |
|
|
|
(2,722,345 |
) |
|
|
10,452,816 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OPERATING EXPENSES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation, depletion and amortization |
|
|
845,486 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,003,558 |
|
|
|
|
|
|
|
1,849,044 |
|
Asset retirement obligation accretion |
|
|
50,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26,264 |
|
|
|
|
|
|
|
77,146 |
|
Lease operating expenses |
|
|
644,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
745,198 |
|
|
|
|
|
|
|
1,389,542 |
|
Gathering and transportation costs |
|
|
32,904 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
136,603 |
|
|
|
(46,389 |
) |
|
|
123,118 |
|
Taxes other than income |
|
|
173,689 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
671,717 |
|
|
|
|
|
|
|
845,406 |
|
General and administrative |
|
|
176,373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
45,250 |
|
|
|
(2,767 |
) |
|
|
218,856 |
|
Financing costs, net |
|
|
102,882 |
|
|
|
(8,272 |
) |
|
|
13,518 |
|
|
|
42,378 |
|
|
|
(33,912 |
) |
|
|
|
|
|
|
116,594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,026,560 |
|
|
|
(8,272 |
) |
|
|
13,518 |
|
|
|
42,378 |
|
|
|
2,594,678 |
|
|
|
(49,156 |
) |
|
|
4,619,706 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME (LOSS) BEFORE INCOME TAXES |
|
|
4,466,901 |
|
|
|
42,597 |
|
|
|
55,046 |
|
|
|
308,916 |
|
|
|
3,632,839 |
|
|
|
(2,673,189 |
) |
|
|
5,833,110 |
|
Provision (benefit) for income taxes |
|
|
809,334 |
|
|
|
(3,056 |
) |
|
|
3,841 |
|
|
|
432 |
|
|
|
1,364,992 |
|
|
|
|
|
|
|
2,175,543 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCOME |
|
|
3,657,567 |
|
|
|
45,653 |
|
|
|
51,205 |
|
|
|
308,484 |
|
|
|
2,267,847 |
|
|
|
(2,673,189 |
) |
|
|
3,657,567 |
|
Preferred stock dividends |
|
|
4,260 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,260 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
INCOME ATTRIBUTABLE TO COMMON STOCK |
|
$ |
3,653,307 |
|
|
$ |
45,653 |
|
|
$ |
51,205 |
|
|
$ |
308,484 |
|
|
$ |
2,267,847 |
|
|
$ |
(2,673,189 |
) |
|
$ |
3,653,307 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 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 |
|
$ |
983,028 |
|
|
$ |
(22,377 |
) |
|
$ |
1,718,820 |
|
|
$ |
|
|
|
$ |
2,679,471 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas property |
|
|
(859,789 |
) |
|
|
|
|
|
|
(1,978,748 |
) |
|
|
|
|
|
|
(2,838,537 |
) |
Additions to gas gathering, transmission and
processing facilities |
|
|
|
|
|
|
|
|
|
|
(203,783 |
) |
|
|
|
|
|
|
(203,783 |
) |
Acquisition of Marathon properties |
|
|
(181,133 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(181,133 |
) |
Short-term investments |
|
|
791,999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
791,999 |
|
Restricted cash for acquisition settlement |
|
|
13,880 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
13,880 |
|
Proceeds from sale of oil & gas properties |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment in subsidiaries, net |
|
|
(308,246 |
) |
|
|
|
|
|
|
|
|
|
|
308,246 |
|
|
|
|
|
Other, net |
|
|
(30,770 |
) |
|
|
|
|
|
|
(67,326 |
) |
|
|
|
|
|
|
(98,096 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES |
|
|
(574,059 |
) |
|
|
|
|
|
|
(2,249,857 |
) |
|
|
308,246 |
|
|
|
(2,515,670 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Debt borrowings |
|
|
996 |
|
|
|
60 |
|
|
|
531,533 |
|
|
|
(302,413 |
) |
|
|
230,176 |
|
Payments on debt |
|
|
|
|
|
|
|
|
|
|
(100,000 |
) |
|
|
|
|
|
|
(100,000 |
) |
Dividends paid |
|
|
(155,125 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(155,125 |
) |
Common stock activity |
|
|
19,028 |
|
|
|
20,606 |
|
|
|
(14,773 |
) |
|
|
(5,833 |
) |
|
|
19,028 |
|
Treasury stock activity, net |
|
|
5,344 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
5,344 |
|
Cost of debt and equity transactions |
|
|
(618 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(618 |
) |
Other |
|
|
2,672 |
|
|
|
|
|
|
|
10,636 |
|
|
|
|
|
|
|
13,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING
ACTIVITIES |
|
|
(127,703 |
) |
|
|
20,666 |
|
|
|
427,396 |
|
|
|
(308,246 |
) |
|
|
12,113 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS |
|
|
281,266 |
|
|
|
(1,711 |
) |
|
|
(103,641 |
) |
|
|
|
|
|
|
175,914 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
$ |
423,292 |
|
|
$ |
3 |
|
|
$ |
934,069 |
|
|
$ |
|
|
|
$ |
1,357,364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
23
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS
For the Nine Months Ended September 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 |
|
$ |
2,548,120 |
|
|
$ |
(12,424 |
) |
|
$ |
(11,967 |
) |
|
$ |
(26,375 |
) |
|
$ |
3,531,214 |
|
|
$ |
|
|
|
$ |
6,028,568 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM INVESTING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to oil and gas property |
|
|
(1,663,706 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2,399,269 |
) |
|
|
|
|
|
|
(4,062,975 |
) |
Additions to gas gathering, transmission and processing
facilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(420,850 |
) |
|
|
|
|
|
|
(420,850 |
) |
Restricted cash |
|
|
(13,844 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(13,844 |
) |
Proceeds from sale of oil & gas properties |
|
|
206,748 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
99,953 |
|
|
|
|
|
|
|
306,701 |
|
Investment in subsidiaries, net |
|
|
(230,924 |
) |
|
|
(12,975 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
243,899 |
|
|
|
|
|
Other, net |
|
|
(34,814 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7,695 |
) |
|
|
|
|
|
|
(42,509 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH USED IN INVESTING ACTIVITIES |
|
|
(1,736,540 |
) |
|
|
(12,975 |
) |
|
|
|
|
|
|
|
|
|
|
(2,727,861 |
) |
|
|
243,899 |
|
|
|
(4,233,477 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH FLOWS FROM FINANCING ACTIVITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commercial paper and money market borrowings, net |
|
|
(138,511 |
) |
|
|
|
|
|
|
65 |
|
|
|
56 |
|
|
|
(30,652 |
) |
|
|
|
|
|
|
(169,042 |
) |
Payments on fixed-rate debt |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(353 |
) |
|
|
|
|
|
|
(353 |
) |
Dividends paid |
|
|
(187,735 |
) |
|
|
4,940 |
|
|
|
(1,073 |
) |
|
|
(2,130 |
) |
|
|
143,313 |
|
|
|
(145,050 |
) |
|
|
(187,735 |
) |
Common stock activity |
|
|
31,207 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
31,207 |
|
Treasury stock activity, net |
|
|
4,171 |
|
|
|
19,975 |
|
|
|
12,975 |
|
|
|
26,699 |
|
|
|
39,200 |
|
|
|
(98,849 |
) |
|
|
4,171 |
|
Cost of debt and equity transactions |
|
|
(1,224 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1,224 |
) |
Other |
|
|
44,115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,551 |
|
|
|
|
|
|
|
46,666 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET CASH PROVIDED BY (USED IN) FINANCING
ACTIVITIES |
|
|
(247,977 |
) |
|
|
24,915 |
|
|
|
11,967 |
|
|
|
24,625 |
|
|
|
154,059 |
|
|
|
(243,899 |
) |
|
|
(276,310 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS |
|
|
563,603 |
|
|
|
(484 |
) |
|
|
|
|
|
|
(1,750 |
) |
|
|
957,412 |
|
|
|
|
|
|
|
1,518,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT
BEGINNING OF YEAR |
|
|
3,626 |
|
|
|
484 |
|
|
|
1 |
|
|
|
1,751 |
|
|
|
119,961 |
|
|
|
|
|
|
|
125,823 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CASH AND CASH EQUIVALENTS AT
END OF PERIOD |
|
$ |
567,229 |
|
|
$ |
|
|
|
$ |
1 |
|
|
$ |
1 |
|
|
$ |
1,077,373 |
|
|
$ |
|
|
|
$ |
1,644,604 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
24
APACHE CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATING BALANCE SHEET
As of September 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 |
|
$ |
423,291 |
|
|
$ |
3 |
|
|
$ |
934,070 |
|
|
$ |
|
|
|
$ |
1,357,364 |
|
Receivables, net of allowance |
|
|
526,047 |
|
|
|
|
|
|
|
1,064,866 |
|
|
|
|
|
|
|
1,590,913 |
|
Short-term investments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Inventories |
|
|
61,879 |
|
|
|
|
|
|
|
477,563 |
|
|
|
|
|
|
|
539,442 |
|
Drilling advances and other |
|
|
251,908 |
|
|
|
1,095 |
|
|
|
249,814 |
|
|
|
|
|
|
|
502,817 |
|
Derivative instruments |
|
|
11,534 |
|
|
|
|
|
|
|
17,632 |
|
|
|
|
|
|
|
29,166 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,274,659 |
|
|
|
1,098 |
|
|
|
2,743,945 |
|
|
|
|
|
|
|
4,019,702 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
PROPERTY AND EQUIPMENT, NET |
|
|
9,243,054 |
|
|
|
|
|
|
|
13,302,477 |
|
|
|
|
|
|
|
22,545,531 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
OTHER ASSETS: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intercompany receivable, net |
|
|
1,488,184 |
|
|
|
|
|
|
|
246,773 |
|
|
|
(1,734,957 |
) |
|
|
|
|
Restricted cash |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Goodwill, net |
|
|
|
|
|
|
|
|
|
|
189,252 |
|
|
|
|
|
|
|
189,252 |
|
Equity in affiliates |
|
|
10,929,246 |
|
|
|
1,075,503 |
|
|
|
42,021 |
|
|
|
(12,046,770 |
) |
|
|
|
|
Deferred charges and other |
|
|
161,380 |
|
|
|
1,003,113 |
|
|
|
306,518 |
|
|
|
(1,000,000 |
) |
|
|
471,011 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
23,096,523 |
|
|
$ |
2,079,714 |
|
|
$ |
16,830,986 |
|
|
$ |
(14,781,727 |
) |
|
$ |
27,225,496 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LIABILITIES AND SHAREHOLDERS EQUITY |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
CURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term debt |
|
$ |
|
|
|
$ |
|
|
|
$ |
39,669 |
|
|
$ |
|
|
|
$ |
39,669 |
|
Accounts payable |
|
|
259,367 |
|
|
|
247,866 |
|
|
|
1,619,624 |
|
|
|
(1,734,957 |
) |
|
|
391,900 |
|
Accrued exploration and development |
|
|
145,893 |
|
|
|
|
|
|
|
516,494 |
|
|
|
|
|
|
|
662,387 |
|
Other accrued expenses |
|
|
533,198 |
|
|
|
62,905 |
|
|
|
296,890 |
|
|
|
|
|
|
|
892,993 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
938,458 |
|
|
|
310,771 |
|
|
|
2,472,677 |
|
|
|
(1,734,957 |
) |
|
|
1,986,949 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
LONG-TERM DEBT |
|
|
4,062,000 |
|
|
|
647,131 |
|
|
|
300,899 |
|
|
|
|
|
|
|
5,010,030 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
DEFERRED CREDITS AND OTHER
NONCURRENT LIABILITIES: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes |
|
|
1,193,920 |
|
|
|
4,288 |
|
|
|
1,445,314 |
|
|
|
|
|
|
|
2,643,522 |
|
Asset retirement obligation |
|
|
903,313 |
|
|
|
|
|
|
|
720,034 |
|
|
|
|
|
|
|
1,623,347 |
|
Derivative instruments |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other |
|
|
643,510 |
|
|
|
|
|
|
|
962,816 |
|
|
|
(1,000,000 |
) |
|
|
606,326 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,740,743 |
|
|
|
4,288 |
|
|
|
3,128,164 |
|
|
|
(1,000,000 |
) |
|
|
4,873,195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
COMMITMENTS AND CONTINGENCIES
SHAREHOLDERS EQUITY |
|
|
15,355,322 |
|
|
|
1,117,524 |
|
|
|
10,929,246 |
|
|
|
(12,046,770 |
) |
|
|
15,355,322 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
23,096,523 |
|
|
$ |
2,079,714 |
|
|
$ |
16,830,986 |
|
|
$ |
(14,781,727 |
) |
|
$ |
27,225,496 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25
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 |
|
|
319,648 |
|
|
|
|
|
|
|
|
|
|
|
1,786 |
|
|
|
146,265 |
|
|
|
|
|
|
|
467,699 |
|
Derivative instruments |
|
|
137,308 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
16,972 |
|
|
|
|
|
|
|
154,280 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
Accrued exploration and development |
|
|
279,746 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
685,113 |
|
|
|
|
|
|
|
964,859 |
|
Other accrued expenses |
|
|
575,451 |
|
|
|
(10,097 |
) |
|
|
165,432 |
|
|
|
290,587 |
|
|
|
1,058,431 |
|
|
|
(1,185,771 |
) |
|
|
894,033 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
26
|
|
|
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 and Managements Discussion and Analysis of Financial Condition and
Results of Operations included in our most recent Annual Report on Form 10-K.
OPERATING HIGHLIGHTS
Apache produced a record 607,118 barrels of oil equivalent (boe) per day in the third quarter
of 2009, up three percent from the second quarter of 2009 and 19 percent from the third quarter of
2008. Year-to-date 2009 production increased eight percent over the comparable 2008 period. Our
diverse asset base contains a balance of near-term investment opportunities and a pipeline of
longer-term, individually significant impactive projects. This platform, coupled with production
restoration from the 2008 hurricanes and fire at Varanus Island, enabled us to deliver production
growth for the year (despite curtailed capital spending, which was 37 percent below the first nine
months of 2008) and is the foundation for solid long-term growth.
Operational highlights for the third quarter of 2009 and growth drivers for 2010 and beyond
are as follows:
Third-quarter 2009 operational highlights
|
|
|
Our Egypt Region achieved a new quarterly record for gross production of 290,452 boe per
day, up six percent from the second quarter of 2009 and 27 percent from the third quarter
of 2008. The increase was driven by higher gas output primarily from Apaches Qasr field through two new processing trains at the Salam Gas Plant and additional oil
production from several discoveries in the Faghur Basin in the Khalda Offset Concession. |
|
|
|
|
In Australia, net gas production averaged a record 225 million cubic feet of gas per day
(MMcf/d) following completion of repairs at the Varanus Island gas processing facility in
the second quarter of 2009. While the facility was undergoing repairs for damage caused by
a June 2008 explosion, gross compression capacity was expanded to 460 terajoules per day
(TJ/d). As a result, average net gas production for the third quarter of 2009 was
approximately 15 percent higher than pre-incident levels. |
|
|
|
|
At the Forties Field in the North Sea, we set a record for monthly production since
acquiring the property in 2003. Net production for July 2009 averaged 71,472 boe per day
and contributed to the second-highest quarterly production posted since Apache took over
operations. Third-quarter 2009 oil output increased 13 percent from the second quarter of
2009 and 11 percent from the third quarter of 2008, on strong drilling results and
increased field efficiency. |
|
|
|
|
We had our first full quarter of production from our deepwater Geauxpher Field discovery
in the Gulf of Mexico. The field produced 98 MMcf/d gross, adding 39MMcf/d net to Apache
during the third quarter of 2009. |
|
|
|
|
Continued restorations from the 2008 hurricanes returned nearly 900 barrels of oil per
day (b/d) (net) and 26 MMcf/d (net) to production during the third quarter. |
27
Growth drivers for 2010 and beyond
|
|
|
In Australia, our Van Gogh field is projected to add 20,000 b/d net to Apache when it is
fully operational. The Ningaloo Vision floating production, storage and offloading vessel
(FPSO) is scheduled to arrive at the Van Gogh field in the Exmouth Basin in December 2009,
with first production projected for early 2010. |
|
|
|
|
Pyrenees, a second oil project in the Exmouth Basin, is scheduled to begin producing late in
the first quarter of 2010. Production is projected to build to a peak of 20,000 b/d net to
Apache in 2010. |
|
|
|
|
In Canada, at Apaches Horn River Basin shale development in northeast British Columbia,
Apache and its joint venture partner are scheduled to bring an additional 27 horizontal
wells (gross) on production by the end of the first half of the 2010. |
|
|
|
|
We recently announced the results of our first operated horizontal Granite Wash well
drilled in our Central Region. The Hostetter #1-23H in Washita County, Oklahoma is
producing 17 MMcf/d and 800 b/d after approximately six weeks of production. Apache owns a
72-percent working interest in the well. The Granite Wash has long been a core stacked
play for our Central Region, where we have drilled hundreds of vertical wells over the past
decade. As a result, we now control over 200,000 gross acres in the play, most held by
production. Horizontal multi-fracture technology has vastly improved the potential
recoveries. The wells generally have a high associated liquid yield and produce higher
rates of return than wells in gas-only resource plays during periods of low gas prices. We
expect to utilize four horizontal rigs throughout 2010 to drill at least 20 new horizontal
wells. We have hundreds of additional potential locations across this play, adding
opportunities beyond 2010. |
|
|
|
|
In Egypt, production from the Phiops area in the Faghur basin is presently facilities
constrained to 6,500 b/d. Expansion to 8,000 b/d is planned by year-end 2009, and
expansion to 20,000 b/d is targeted for the second half of 2010. |
|
|
|
|
On October 22, 2009, Apache and Kuwait Foreign Petroleum Exploration Co. (KUFPEC) signed
an exclusive agreement to supply gas from the Julimar and Brunello discoveries and become
foundation equity partners in Chevrons Wheatstone liquefied natural gas (LNG) hub in
Western Australia, opening up new markets for gas reserves from two of Apaches largest
discoveries. Apache holds a 65-percent interest in the discoveries. Apaches projected
net sales would approximate 190 MMcf/d and 5,100 b/d with a projected 15-year production
plateau when the multi-year project is fully operational. |
|
|
|
|
Chevron, which has a 100-percent interest in the Wheatstone field, will operate the LNG
facilities with a 75-percent project interest. Apache and KUFPEC will own the remaining
25-percent project interest. Wheatstones first phase will consist of an offshore
processing platform and pipeline to shore, along with two LNG processing trains and
associated off-take facilities with a
combined capacity of approximately 8.6 million tons per year. Our net capital for the
project is currently estimated to be $1.2 billion for upstream development of the Julimar
and Brunello fields and $3.0 billion in the Wheatstone facilities. The investment will be
funded as the multi-year project is developed. |
|
|
|
|
In September 2009, we broke ground at our Devil Creek Domestic Gas Hub in Western
Australia. Natural gas from our
Reindeer field will be delivered to the mainland via pipeline. First production is
currently scheduled for the third quarter of 2011 and is projected to
add 60 MMcf/d (gross)
at realized prices substantially higher than we currently realize in
Australia. We operate and own a 55-percent interest in the
Reindeer field. |
|
|
|
|
In Argentina, Apache was given approval to supply up to 50 MMcf/d from two fields in
Argentinas Neuquén and Rio Negro provinces at a price of $5 per MMBtu. Delivery under the
program the first approved by the Secretary of Energy under the governments Gas Plus
program is scheduled to commence in January 2011, although the customer, a power plant
operator, has indicated it may begin taking gas in mid-2010. Apache has submitted five
additional development projects for approval under the Gas Plus program, which is designed
to bring new supplies to market. In the third quarter of 2009, Argentinas realized gas
prices averaged $1.89 per thousand cubic feet of gas (Mcf). |
28
COMMODITY PRICES
Third-quarter 2009 earnings and net cash provided by operating activities (operating cash
flows or cash flows) benefited from strengthening oil prices: average prices for the quarter were
the highest realized since the third quarter of 2008. While liquids accounted for 49 percent of
our oil and gas production during the third quarter of 2009, they generated 75 percent of our oil
and gas revenues, a reflection of the benefit of our balanced commodity production portfolio.
However, commodity prices remain lower than a year ago, which resulted in cash flows lower than
2008 record levels. North American gas prices remained relatively weak in the third quarter of
2009, and, in the face of increasing North American gas supplies, we believe they will likely
remain depressed in the near-term.
In order to manage the variability in cash flows on an additional portion of our 2010 gas and
crude oil production, we increased our commodity hedge position during the third quarter of 2009.
As of the date of this filing, we had hedged an average of just over 410,000 million British
thermal units (MMBtu) per day of our projected 2010 North American natural gas production,
utilizing a combination of swaps and collars. Approximately 90 percent of the hedged volume was
swapped at an average price of just over $5.60 per MMBtu. The balance was hedged using collars with
average floor and ceiling prices of approximately $5.65 and $7.55 per MMBtu, respectively. For
perspective, these 2010 hedges represent approximately 21 percent of our 2009 third-quarter
worldwide daily gas volumes and approximately 36 percent of our 2009 third-quarter North American
daily gas production. For comparative purposes, our average realized North American gas prices
were $3.86 and $4.10 per Mcf for the third quarter and the first nine months of 2009, respectively.
On the oil side, we have currently hedged an average of just over 35,000 b/d for 2010,
primarily utilizing collars with average floor and ceiling prices of approximately $65.70 and
$78.58 per barrel, respectively. For perspective, these 2010 hedges represent approximately 12
percent of our third-quarter 2009 worldwide daily oil production. For comparative purposes, our
average realized oil prices were $64.89 and $55.52 per barrel for the third quarter and the first
nine months of 2009, respectively. See Note 2 Derivative Instruments and Hedging Activities in
Part I, Item 1 of this Form 10-Q for additional information regarding our derivative contracts.
FINANCIAL POSITION
We believe our strong balance sheet will continue to provide us with the financial flexibility
to take advantage of exceptional investment opportunities that may materialize. We exited the third quarter
of 2009 with approximately $1.4 billion in cash, up $586 million from the second quarter of 2009.
This compares to approximately $2 billion of cash and short-term investments at December 31, 2008.
We have $2.3 billion of available committed borrowing capacity and a debt-to-capitalization ratio
of 25 percent. In addition, we have the ability to access debt and equity capital markets, options
supported by our investment-grade credit ratings. Apaches current debt ratings are A-, A3, and A-
from Standard & Poors, Moodys Investor Service and Fitch Ratings, respectively.
EARNINGS AND CASH FLOW
Our third-quarter 2009 earnings of $441 million ($1.30 per diluted common share), as compared
to third-quarter 2008 earnings of $1.2 billion ($3.52 per share), were negatively impacted by
significantly lower crude oil and natural gas price realizations. Oil and gas revenues for the
third quarter of 2009 were 31 percent, or $1 billion, lower than the third quarter of 2008, driven
by a 36 percent drop in average crude oil realizations and a 53 percent drop in natural gas
realizations. Equivalent daily production increased 19 percent from the third quarter of 2008,
with gains in five of our six producing countries. Total operating expenses were six percent lower
than the third quarter of 2008 on an absolute dollar basis, and 21 percent lower on a per unit
basis. Service costs have trended downward since the third quarter of 2008; however, we continue
to monitor service costs very closely and actively pursue further cost reductions. We make
adjustments to drilling and development schedules as warranted.
Our nine-month period earnings in 2009, relative to 2008, were also negatively impacted by
lower crude oil and natural gas price realizations and by a $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 loss of $2.61 per share for the 2009
nine-month period compared to earnings of $10.84 per share in the 2008 period. Operating cash
flows for the 2009 nine-month period totaled $2.7 billion, compared to $6 billion in the comparable
2008 period.
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 September 30, 2007 |
|
$ |
1,627,467 |
|
|
$ |
819,351 |
|
|
$ |
51,776 |
|
|
$ |
2,498,594 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume increase (decrease) |
|
|
(115,470 |
) |
|
|
(167,640 |
) |
|
|
(12,974 |
) |
|
|
(296,084 |
) |
Price increase |
|
|
870,081 |
|
|
|
458,763 |
|
|
|
19,770 |
|
|
|
1,348,614 |
|
Impact of hedges (decrease) |
|
|
(128,808 |
) |
|
|
(53,434 |
) |
|
|
|
|
|
|
(182,242 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in 2008 |
|
$ |
625,803 |
|
|
$ |
237,689 |
|
|
$ |
6,796 |
|
|
$ |
870,288 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues for the quarter ended September 30, 2008 |
|
$ |
2,253,270 |
|
|
$ |
1,057,040 |
|
|
$ |
58,572 |
|
|
$ |
3,368,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution to total third-quarter 2008 revenues |
|
|
67 |
% |
|
|
31 |
% |
|
|
2 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume increase |
|
|
257,060 |
|
|
|
96,027 |
|
|
|
4,927 |
|
|
|
358,014 |
|
Price decrease |
|
|
(977,432 |
) |
|
|
(627,690 |
) |
|
|
(32,559 |
) |
|
|
(1,637,681 |
) |
Impact of hedges increase |
|
|
171,567 |
|
|
|
64,923 |
|
|
|
|
|
|
|
236,490 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in 2009 |
|
$ |
(548,805 |
) |
|
$ |
(466,740 |
) |
|
$ |
(27,632 |
) |
|
$ |
(1,043,177 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues for the quarter ended September 30, 2009 |
|
$ |
1,704,465 |
|
|
$ |
590,300 |
|
|
$ |
30,940 |
|
|
$ |
2,325,705 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution to total third-quarter 2009 revenues |
|
|
73 |
% |
|
|
26 |
% |
|
|
1 |
% |
|
|
100 |
% |
Changes in Oil and Gas Production Revenues Nine Months
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
|
Natural Gas |
|
|
NGLs |
|
|
Total |
|
|
|
|
|
|
|
(In thousands) |
|
|
|
|
|
Revenues for the nine months ended September 30, 2007 |
|
$ |
4,261,017 |
|
|
$ |
2,568,847 |
|
|
$ |
135,828 |
|
|
$ |
6,965,692 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume increase (decrease) |
|
|
315,047 |
|
|
|
(294,882 |
) |
|
|
(15,940 |
) |
|
|
4,225 |
|
Price increase |
|
|
2,845,712 |
|
|
|
1,087,197 |
|
|
|
60,825 |
|
|
|
3,993,734 |
|
Impact of hedges (decrease) |
|
|
(441,882 |
) |
|
|
(70,820 |
) |
|
|
|
|
|
|
(512,702 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase in 2008 |
|
$ |
2,718,877 |
|
|
$ |
721,495 |
|
|
$ |
44,885 |
|
|
$ |
3,485,257 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues for the nine months ended September 30, 2008 |
|
$ |
6,979,894 |
|
|
$ |
3,290,342 |
|
|
$ |
180,713 |
|
|
$ |
10,450,949 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution to total year-to-date 2008 revenues |
|
|
67 |
% |
|
|
31 |
% |
|
|
2 |
% |
|
|
100 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume increase (decrease) |
|
|
353,417 |
|
|
|
102,895 |
|
|
|
(3,327 |
) |
|
|
452,985 |
|
Price decrease |
|
|
(3,641,227 |
) |
|
|
(1,812,566 |
) |
|
|
(104,330 |
) |
|
|
(5,558,123 |
) |
Impact of hedges increase |
|
|
526,409 |
|
|
|
131,443 |
|
|
|
|
|
|
|
657,852 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Decrease in 2009 |
|
$ |
(2,761,401 |
) |
|
$ |
(1,578,228 |
) |
|
$ |
(107,657 |
) |
|
$ |
(4,447,286 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revenues for the nine months ended September 30, 2009 |
|
$ |
4,218,493 |
|
|
$ |
1,712,114 |
|
|
$ |
73,056 |
|
|
$ |
6,003,663 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contribution to total 2009 year-to-date revenues |
|
|
70 |
% |
|
|
29 |
% |
|
|
1 |
% |
|
|
100 |
% |
30
Production and Pricing
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended September 30, |
|
|
For the Nine Months Ended September 30, |
|
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
|
|
|
|
|
|
|
Increase |
|
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
|
2009 |
|
|
2008 |
|
|
(Decrease) |
|
Oil Volume b/d: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
88,213 |
|
|
|
80,284 |
|
|
|
10 |
% |
|
|
87,835 |
|
|
|
93,622 |
|
|
|
(6 |
)% |
Canada |
|
|
14,595 |
|
|
|
16,655 |
|
|
|
(12 |
)% |
|
|
15,586 |
|
|
|
17,247 |
|
|
|
(10 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
|
102,808 |
|
|
|
96,939 |
|
|
|
6 |
% |
|
|
103,421 |
|
|
|
110,869 |
|
|
|
(7 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt |
|
|
93,550 |
|
|
|
64,803 |
|
|
|
44 |
% |
|
|
90,848 |
|
|
|
64,082 |
|
|
|
42 |
% |
Australia |
|
|
10,849 |
|
|
|
7,083 |
|
|
|
53 |
% |
|
|
9,732 |
|
|
|
8,286 |
|
|
|
17 |
% |
North Sea |
|
|
67,288 |
|
|
|
60,856 |
|
|
|
11 |
% |
|
|
62,515 |
|
|
|
58,740 |
|
|
|
6 |
% |
Argentina |
|
|
11,026 |
|
|
|
12,729 |
|
|
|
(13 |
)% |
|
|
11,799 |
|
|
|
12,342 |
|
|
|
(4 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
182,713 |
|
|
|
145,471 |
|
|
|
26 |
% |
|
|
174,894 |
|
|
|
143,450 |
|
|
|
22 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (1) |
|
|
285,521 |
|
|
|
242,410 |
|
|
|
18 |
% |
|
|
278,315 |
|
|
|
254,319 |
|
|
|
9 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Oil price Per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
64.57 |
|
|
$ |
93.69 |
|
|
|
(31 |
)% |
|
$ |
54.89 |
|
|
$ |
91.48 |
|
|
|
(40 |
)% |
Canada |
|
|
63.79 |
|
|
|
111.81 |
|
|
|
(43 |
)% |
|
|
51.95 |
|
|
|
108.10 |
|
|
|
(52 |
)% |
North America |
|
|
64.46 |
|
|
|
96.80 |
|
|
|
(33 |
)% |
|
|
54.45 |
|
|
|
94.07 |
|
|
|
(42 |
)% |
Egypt |
|
|
65.64 |
|
|
|
105.60 |
|
|
|
(38 |
)% |
|
|
56.67 |
|
|
|
110.01 |
|
|
|
(48 |
)% |
Australia |
|
|
73.70 |
|
|
|
99.66 |
|
|
|
(26 |
)% |
|
|
58.74 |
|
|
|
111.86 |
|
|
|
(47 |
)% |
North Sea |
|
|
65.76 |
|
|
|
113.56 |
|
|
|
(42 |
)% |
|
|
56.68 |
|
|
|
110.08 |
|
|
|
(49 |
)% |
Argentina |
|
|
48.53 |
|
|
|
50.95 |
|
|
|
(5 |
)% |
|
|
47.29 |
|
|
|
48.76 |
|
|
|
(3 |
)% |
International |
|
|
65.13 |
|
|
|
103.86 |
|
|
|
(37 |
)% |
|
|
56.15 |
|
|
|
104.88 |
|
|
|
(46 |
)% |
Total (2) |
|
|
64.89 |
|
|
|
101.04 |
|
|
|
(36 |
)% |
|
|
55.52 |
|
|
|
100.17 |
|
|
|
(45 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Volume Mcf/d: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
699,062 |
|
|
|
635,891 |
|
|
|
10 |
% |
|
|
658,507 |
|
|
|
712,529 |
|
|
|
(8 |
)% |
Canada |
|
|
371,516 |
|
|
|
349,000 |
|
|
|
6 |
% |
|
|
367,562 |
|
|
|
355,834 |
|
|
|
3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
|
1,070,578 |
|
|
|
984,891 |
|
|
|
9 |
% |
|
|
1,026,069 |
|
|
|
1,068,363 |
|
|
|
(4 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Egypt |
|
|
372,312 |
|
|
|
287,231 |
|
|
|
30 |
% |
|
|
355,824 |
|
|
|
254,786 |
|
|
|
40 |
% |
Australia |
|
|
225,349 |
|
|
|
54,726 |
|
|
|
312 |
% |
|
|
176,457 |
|
|
|
124,888 |
|
|
|
41 |
% |
North Sea |
|
|
2,983 |
|
|
|
2,697 |
|
|
|
11 |
% |
|
|
2,771 |
|
|
|
2,604 |
|
|
|
6 |
% |
Argentina |
|
|
183,504 |
|
|
|
217,091 |
|
|
|
(15 |
)% |
|
|
189,303 |
|
|
|
193,257 |
|
|
|
(2 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
International |
|
|
784,148 |
|
|
|
561,745 |
|
|
|
40 |
% |
|
|
724,355 |
|
|
|
575,535 |
|
|
|
26 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total (3) |
|
|
1,854,726 |
|
|
|
1,546,636 |
|
|
|
20 |
% |
|
|
1,750,424 |
|
|
|
1,643,898 |
|
|
|
6 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Natural Gas price Per Mcf: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
3.99 |
|
|
$ |
9.96 |
|
|
|
(60 |
)% |
|
$ |
4.13 |
|
|
$ |
9.64 |
|
|
|
(57 |
)% |
Canada |
|
|
3.61 |
|
|
|
8.70 |
|
|
|
(59 |
)% |
|
|
4.04 |
|
|
|
8.63 |
|
|
|
(53 |
)% |
North America |
|
|
3.86 |
|
|
|
9.51 |
|
|
|
(59 |
)% |
|
|
4.10 |
|
|
|
9.30 |
|
|
|
(56 |
)% |
Egypt |
|
|
3.86 |
|
|
|
5.62 |
|
|
|
(31 |
)% |
|
|
3.78 |
|
|
|
5.68 |
|
|
|
(33 |
)% |
Australia |
|
|
2.04 |
|
|
|
2.36 |
|
|
|
(14 |
)% |
|
|
1.85 |
|
|
|
2.18 |
|
|
|
(15 |
)% |
North Sea |
|
|
14.89 |
|
|
|
27.17 |
|
|
|
(45 |
)% |
|
|
11.66 |
|
|
|
21.88 |
|
|
|
(47 |
)% |
Argentina |
|
|
1.89 |
|
|
|
1.41 |
|
|
|
34 |
% |
|
|
1.92 |
|
|
|
1.53 |
|
|
|
25 |
% |
International |
|
|
2.92 |
|
|
|
3.78 |
|
|
|
(23 |
)% |
|
|
2.85 |
|
|
|
3.60 |
|
|
|
(21 |
)% |
Total (4) |
|
|
3.46 |
|
|
|
7.43 |
|
|
|
(53 |
)% |
|
|
3.58 |
|
|
|
7.30 |
|
|
|
(51 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural Gas Liquids (NGL) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Volume Barrels per day: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
|
7,019 |
|
|
|
5,450 |
|
|
|
29 |
% |
|
|
5,812 |
|
|
|
6,636 |
|
|
|
(12 |
)% |
Canada |
|
|
2,166 |
|
|
|
2,034 |
|
|
|
6 |
% |
|
|
2,110 |
|
|
|
2,046 |
|
|
|
3 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
North America |
|
|
9,185 |
|
|
|
7,484 |
|
|
|
23 |
% |
|
|
7,922 |
|
|
|
8,682 |
|
|
|
(9 |
)% |
Argentina |
|
|
3,291 |
|
|
|
3,005 |
|
|
|
10 |
% |
|
|
3,174 |
|
|
|
2,877 |
|
|
|
10 |
% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
12,476 |
|
|
|
10,489 |
|
|
|
19 |
% |
|
|
11,096 |
|
|
|
11,559 |
|
|
|
(4 |
)% |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average NGL Price Per barrel: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
United States |
|
$ |
33.20 |
|
|
$ |
72.82 |
|
|
|
(54 |
)% |
|
$ |
28.87 |
|
|
$ |
64.49 |
|
|
|
(55 |
)% |
Canada |
|
|
24.22 |
|
|
|
63.77 |
|
|
|
(62 |
)% |
|
|
23.03 |
|
|
|
58.62 |
|
|
|
(61 |
)% |
North America |
|
|
31.08 |
|
|
|
70.36 |
|
|
|
(56 |
)% |
|
|
27.32 |
|
|
|
63.11 |
|
|
|
(57 |
)% |
Argentina |
|
|
15.44 |
|
|
|
36.63 |
|
|
|
(58 |
)% |
|
|
16.13 |
|
|
|
38.81 |
|
|
|
(58 |
)% |
Total |
|
|
26.96 |
|
|
|
60.70 |
|
|
|
(56 |
)% |
|
|
24.12 |
|
|
|
57.06 |
|
|
|
(58 |
)% |
|
|
|
(1) |
|
Approximately 12 percent and nine percent of oil production was subject to financial
derivative hedges for the 2009 third quarter and nine-month period, respectively; 20
percent and 19 percent for the 2008 third quarter and nine-month period, respectively. |
|
(2) |
|
Reflects a per barrel increase of $.13 and $.72 from financial derivative hedging
activities for the 2009 third quarter and nine-month period, respectively, and a decrease
of $7.54 and $6.77 from financial derivative hedging activities for the 2008 third quarter
and nine-month period, respectively. |
|
(3) |
|
Approximately eight percent of natural gas production was subject to financial
derivative hedges for the 2009 third quarter and nine-month period, respectively; 22
percent and 20 percent for the 2008 third quarter and nine-month period, respectively. |
|
(4) |
|
Reflects a per Mcf increase of $.27 and $.21 from financial derivative hedging
activities for the 2009 third quarter and nine-month period, respectively, and a decrease
of $.13 and $.06 from financial derivative hedging activities for the 2008 third quarter
and nine-month period, respectively. |
31
Third-Quarter 2009 compared to Third-Quarter 2008
Crude Oil Revenues Crude oil accounted for 47 percent of our equivalent production and 73
percent of our oil and gas production revenues during the third quarter of 2009, compared to 47 and
67 percent, respectively, for the same period last year. Third-quarter 2009 crude oil revenues of
$1.7 billion were $549 million lower than the 2008 period. The impact of a 36 percent decrease in
average realized price more than offset additional revenues provided by increased production.
Worldwide production increased 18 percent; with growth in four of our six producing countries.
Egypts gross oil production increased 26 percent on successful new wells and recompletions at our
East Bahariya Extension, South Umbarka, West Kalabsha and Matruh concessions. Egypts net
production to Apache increased 44 percent with the additional benefit of an increased allocation of
gross production for cost recovery, a function of lower prices and the mechanics of our
production-sharing contracts. In the U.S., production increased 10 percent, driven by a 23 percent
increase in our Gulf Coast Region where production continued to be restored following the 2008
hurricanes. The North Seas production was the second highest quarterly average since we purchased
the property in 2003. Production increased 11 percent from the third quarter of 2008 on strong
drilling results and increased field efficiency. Australia production was up 53 percent primarily
on production restored following completion of repairs at Varanus Island, but also because of
additional liquids following an increase in throughput from expansion of plant capacity as
discussed in gas below. Production declined 13 percent in Argentina and 12 percent in Canada,
where capital spending was significantly reduced in the first nine months of the year and natural
decline more than offset production from new wells.
Natural Gas Revenues Gas accounted for 51 percent of our equivalent production and 26 percent
of our oil and gas production revenues during the third quarter of 2009, compared to 50 and 31
percent, respectively, for the same period last year. Third-quarter 2009 natural gas revenues of
$590 million declined $467 million from the third quarter of 2008 on a 53 percent decrease in
realized natural gas prices, which more than offset higher production.
Worldwide production increased 20 percent to a record 1,855 MMcf/d, with increases in four of
our five major gas producing countries. Australias production increased over 300% when compared
to the 2008 period, primarily on production restored following completion of repairs to the Varanus
Island facility. While the facility was undergoing repairs the gross compression capacity was
expanded, allowing for higher customer takes. As a result, average net gas production for the
third-quarter was approximately 15 percent higher than pre-incident levels. Egypts gross gas
production increased 28 percent, driven by successful drilling and recompletion activities at our
Matruh concession and higher gas output from two new processing trains at the Salem Gas Plant.
Egypts net production increased 30 percent with the additional benefit of an increased allocation
of cost recovery volumes, a function of lower prices and the mechanics of our production-sharing
contracts. U.S. production increased 10 percent, driven by a 23 percent increase in our Gulf Coast
Region with contributions from both restored volumes following shut-ins related to the 2008
hurricanes and a full quarter of production from our Geauxpher field discovery. Canadas gas
production increased from drilling and recompletion activities and a lower effective royalty rate.
Argentina production decreased 15 percent primarily on natural decline and an increase in gas
re-injections.
Year-to-Date 2009 compared to Year-to-Date 2008
Crude Oil Revenues Crude oil accounted for 48 percent of our equivalent production and 70
percent of our oil and gas production revenues for the nine-month period of 2009, compared to 47
and 67 percent, respectively, for the same period last year. Crude oil revenues for the nine-month
period of 2009 totaled $4.2 billion and were $2.8 billion lower than the 2008 period. The impact
of a 45 percent decrease in average realized price more than offset additional revenues provided by
increased production.
Worldwide production was up nine percent, driven by increases in Egypt, Australia and the
North Sea. Egypts gross oil production increased 24 percent on successful new wells and
recompletions at our East Bahariya Extension, South Umbarka, West Kalabsha and Matruh concessions.
Egypts net production to Apache increased 42 percent with the additional benefit of an increased
allocation of gross production for cost recovery, a function of lower prices and the mechanics of
our production-sharing contracts. Australia production was up 17 percent primarily on production
restored following completion of repairs at Varanus Island. Production in the North Sea was up six
percent on successful drilling and recompletion programs. Production was down in Canada, the U.S.
and Argentina (10 percent, six percent and four percent, respectively), as natural decline more
than offset the impact of drilling and recompletion activities. In those three countries, capital
spending during the first nine months of 2009 was less than half of the amount invested during the
same period of 2008.
32
Natural Gas Revenues Gas accounted for 51 percent of our equivalent production and 29 percent
of our oil and gas production revenues for the nine-month period of 2009, compared to 51 and 31
percent, respectively, for the
same period last year. Natural gas revenues for the nine-month period of 2009 totaled $1.7
billion and were $1.6 billion lower than the 2008 period, reflecting a 51 percent decline in
realized natural gas prices, which more than offset higher production.
Worldwide production increased six percent. Australia production was up 41 percent, mostly on
production restored following completion of repairs to the Varanus Island facility. Egypts gross
gas production increased 24 percent, driven by successful drilling and recompletion activities at
our Matruh concession and higher gas output from two new processing trains at the Salem Gas Plant.
Egypts net production to Apache increased 40 percent with the additional benefit of an increased
allocation of cost recovery volumes, a function of lower prices and the mechanics of our
production-sharing contracts. Canada saw production gains from our drilling and recompletion
program and a lower effective royalty rate. Production was down eight percent in the U.S. as a
result of properties shut-in for repairs to third-party pipelines and 2008 hurricanes in the Gulf
of Mexico. The benefits of the acquired Marathon properties and our drilling and recompletion
activities offset natural decline. Argentina decreased two percent on natural decline.
Operating Expenses
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. Amounts included in this
table and in the discussion below are rounded to millions and may differ slightly from those
presented in elsewhere in this document.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended September 30, |
|
|
For the Nine Months Ended September 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
|
|
$ |
576 |
|
|
$ |
560 |
|
|
$ |
10.31 |
|
|
$ |
11.93 |
|
|
$ |
1,638 |
|
|
$ |
1,734 |
|
|
$ |
10.33 |
|
|
$ |
11.72 |
|
Additional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,818 |
|
|
|
|
|
|
|
17.76 |
|
|
|
|
|
Other assets |
|
|
50 |
|
|
|
41 |
|
|
|
.90 |
|
|
|
.86 |
|
|
|
142 |
|
|
|
115 |
|
|
|
.89 |
|
|
|
.78 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total DD&A |
|
|
626 |
|
|
|
601 |
|
|
|
11.21 |
|
|
|
12.79 |
|
|
|
4,598 |
|
|
|
1,849 |
|
|
|
28.98 |
|
|
|
12.50 |
|
Asset retirement obligation accretion |
|
|
26 |
|
|
|
25 |
|
|
|
.47 |
|
|
|
.53 |
|
|
|
79 |
|
|
|
77 |
|
|
|
.50 |
|
|
|
.52 |
|
Lease operating costs |
|
|
446 |
|
|
|
488 |
|
|
|
7.98 |
|
|
|
10.39 |
|
|
|
1,248 |
|
|
|
1,390 |
|
|
|
7.87 |
|
|
|
9.39 |
|
Gathering and transportation costs |
|
|
36 |
|
|
|
43 |
|
|
|
.65 |
|
|
|
.90 |
|
|
|
103 |
|
|
|
123 |
|
|
|
.65 |
|
|
|
.83 |
|
Taxes other than income |
|
|
184 |
|
|
|
304 |
|
|
|
3.29 |
|
|
|
6.48 |
|
|
|
387 |
|
|
|
846 |
|
|
|
2.44 |
|
|
|
5.72 |
|
General and administrative expense |
|
|
82 |
|
|
|
58 |
|
|
|
1.48 |
|
|
|
1.22 |
|
|
|
259 |
|
|
|
219 |
|
|
|
1.63 |
|
|
|
1.48 |
|
Financing costs, net |
|
|
62 |
|
|
|
33 |
|
|
|
1.10 |
|
|
|
.71 |
|
|
|
182 |
|
|
|
116 |
|
|
|
1.14 |
|
|
|
.79 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,462 |
|
|
$ |
1,552 |
|
|
$ |
26.18 |
|
|
$ |
33.02 |
|
|
$ |
6,856 |
|
|
$ |
4,620 |
|
|
$ |
43.21 |
|
|
$ |
31.23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Third-Quarter 2009 compared to Third-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 third quarters of 2008 and 2009:
|
|
|
|
|
|
|
Recurring DD&A |
|
|
|
(In millions) |
|
2008 DD&A |
|
$ |
560 |
|
Volume change |
|
|
95 |
|
Rate change |
|
|
(79 |
) |
|
|
|
|
|
|
|
|
|
2009 DD&A |
|
$ |
576 |
|
|
|
|
|
Recurring full-cost DD&A expense of $576 million increased $16 million on an absolute dollar
basis. A 19 percent increase in equivalent production added $95 million and was mostly offset by a
decrease in rate per boe produced. The rate decreased $1.62, to $10.31 per boe produced. The
decrease in rate is the result 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.
33
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.
Lease Operating Expenses (LOE) Our 2009 third-quarter LOE decreased nine percent on an
absolute dollar basis compared to the third quarter of 2008. On a per unit basis, LOE was down 23
percent, or $2.41 per boe, when compared to the same period in 2008: nine percent on lower cost and
14 percent on higher production. The rate was impacted by the items below:
|
|
|
|
|
Higher production |
|
$ |
(1.50 |
) |
Power and fuel |
|
|
(.50 |
) |
Workover costs |
|
|
(.38 |
) |
Foreign exchange rate impact |
|
|
(.33 |
) |
Varanus Island repair costs |
|
|
(.12 |
) |
Other |
|
|
(.13 |
) |
Hurricane repairs |
|
|
.30 |
|
Stock based compensation, primarily SARs |
|
|
.25 |
|
|
|
|
|
|
|
|
|
|
Change |
|
$ |
(2.41 |
) |
|
|
|
|
Gathering and Transportation Gathering and transportation costs totaled $36 million in the
third quarter of 2009, down $7 million from the third quarter of 2008. On a per unit basis,
gathering and transportation costs were down 28 percent: 14 percent on lower costs and 14 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 |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.S |
|
$ |
9 |
|
|
$ |
12 |
|
Canada |
|
|
14 |
|
|
|
16 |
|
North Sea |
|
|
7 |
|
|
|
8 |
|
Egypt |
|
|
5 |
|
|
|
6 |
|
Argentina |
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gathering and Transportation |
|
$ |
36 |
|
|
$ |
43 |
|
|
|
|
|
|
|
|
The decreases in the U.S. and Canada were driven by lower volumes transported under
third-party contracts and rate decreases. Canada also benefited from the impact of foreign
exchange rates.
Taxes other than Income Taxes other than income totaled $184 million in the third quarter of
2009, a decrease of $120 million from the third quarter of 2008. On a per unit basis, taxes other
than income decreased 49 percent: 39 percent on lower costs and 10 percent on higher production. A
detail of these taxes follows:
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.K. PRT |
|
$ |
133 |
|
|
$ |
228 |
|
Severance taxes |
|
|
26 |
|
|
|
48 |
|
Ad valorem taxes |
|
|
13 |
|
|
|
16 |
|
Canadian taxes |
|
|
5 |
|
|
|
4 |
|
Other |
|
|
7 |
|
|
|
8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Taxes other than Income |
|
$ |
184 |
|
|
$ |
304 |
|
|
|
|
|
|
|
|
34
North Sea Petroleum Revenue Tax (PRT) is assessed on net profits from subject fields in the
U.K. North Sea. U.K. PRT was $95 million less than the 2008 period on a 36 percent decrease in net
profits, driven by 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 based on U.S. and Canadian assessed property values. The $3 million
decrease resulted from a decline in taxable valuations associated with lower oil and natural gas
prices.
General and Administrative Expenses General and administrative expenses (G&A) increased $24
million compared to the third quarter of 2008. Stock-based compensation expense, which includes
the mark-to-market of stock appreciation rights (SARs), added $20 million. SARs expense was up as
a result of a 27 percent increase in Apaches stock price during the third quarter of 2009 compared
to a 25 percent decrease in the comparative 2008 period. Insurance costs drove the remainder of
the increase. On a per unit basis, G&A increased $.26 per boe, with production gains partially
offsetting the impact of higher reported expense.
Financing Costs, Net Financing costs incurred during the periods noted are composed of the
following:
|
|
|
|
|
|
|
|
|
|
|
For the Quarter Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Interest expense |
|
$ |
77 |
|
|
$ |
66 |
|
Amortization of deferred loan costs |
|
|
1 |
|
|
|
1 |
|
Capitalized interest |
|
|
(14 |
) |
|
|
(24 |
) |
Interest income |
|
|
(2 |
) |
|
|
(10 |
) |
|
|
|
|
|
|
|
Financing costs, net |
|
$ |
62 |
|
|
$ |
33 |
|
|
|
|
|
|
|
|
Net financing costs rose $29 million in the third quarter of 2009, up $.39 per boe from the
third quarter of 2008. The increase in absolute dollars is the result of an $11 million increase
in interest expense related to higher average outstanding debt balances, a $10 million reduction in
capitalized interest related to lower unproved property balances and completion of several
long-term construction projects, and an $8 million decrease in interest income on a lower average
cash balance.
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 provision for income taxes decreased $194 million to $429 million in the third quarter of
2009, 31 percent below the prior year, as income before taxes fell on lower oil and gas production
revenues. The effective income tax rate in the third quarter of 2009 was 49.2 percent compared to
34.3 percent in the third quarter of 2008. The third-quarter 2009 rate was impacted by a $92
million non-cash charge related to the effect of the weakening U.S. dollar, while third-quarter
2008 included a $114 million benefit, as the U.S. dollar was strengthening during that period.
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 nine-month periods of 2008 and 2009:
|
|
|
|
|
|
|
Recurring DD&A |
|
|
|
(In millions) |
|
2008 DD&A |
|
$ |
1,734 |
|
Volume change |
|
|
68 |
|
Rate change |
|
|
(164 |
) |
|
|
|
|
|
|
|
|
|
2009 DD&A |
|
$ |
1,638 |
|
|
|
|
|
Recurring full-cost DD&A expense of $1.64 billion in the first nine months of 2009 was $96
million less than the comparable 2008 period: $68 million from 7 percent higher equivalent
production offset by $164 million on a lower rate per boe produced. The Companys full-cost DD&A
rate decreased $1.39 to $10.33 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.
35
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.
Lease Operating Expenses (LOE) In the first nine months of 2009, LOE decreased 10 percent on
an absolute dollar basis compared to the first nine months of 2008. On a per unit basis, LOE was
down 16 percent, or $1.52 per boe, when compared to the same period of 2008: 10 percent on lower
costs and six percent on higher production. The rate was impacted by the items below:
|
|
|
|
|
Higher production |
|
$ |
(.57 |
) |
Foreign exchange rate impact |
|
|
(.55 |
) |
Workover activity and costs |
|
|
(.44 |
) |
Power and fuel |
|
|
(.31 |
) |
Other |
|
|
(.06 |
) |
Hurricane repairs |
|
|
.30 |
|
Stock based compensation, primarily SARs |
|
|
.07 |
|
Varanus Island repairs and recommissioning |
|
|
.04 |
|
|
|
|
|
|
|
|
|
|
Change |
|
$ |
(1.52 |
) |
|
|
|
|
Gathering and Transportation Gathering and transportation costs totaled $103 million in the
first nine months of 2009, down $20 million from the first nine months of 2008. On a per unit
basis, gathering and transportation costs were down 22 percent: 16 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 Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.S |
|
$ |
25 |
|
|
$ |
33 |
|
Canada |
|
|
38 |
|
|
|
49 |
|
North Sea |
|
|
20 |
|
|
|
23 |
|
Egypt |
|
|
17 |
|
|
|
15 |
|
Argentina |
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Gathering and Transportation |
|
$ |
103 |
|
|
$ |
123 |
|
|
|
|
|
|
|
|
The decrease in the U.S. resulted from both lower volumes transported under third-party
contracts and rate decreases. 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.
Taxes other than Income Taxes other than income totaled $387 million in the first nine months
of 2009, a decrease of $459 million from the first nine months of 2008. On a per unit basis, taxes
other than income decreased 57 percent: 54 percent on lower costs and three percent on higher total
production. A detail of these taxes follows:
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
U.K. PRT |
|
$ |
256 |
|
|
$ |
613 |
|
Severance taxes |
|
|
61 |
|
|
|
141 |
|
Ad valorem taxes |
|
|
34 |
|
|
|
55 |
|
Canadian taxes |
|
|
13 |
|
|
|
13 |
|
Other |
|
|
23 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total Taxes other than Income |
|
$ |
387 |
|
|
$ |
846 |
|
|
|
|
|
|
|
|
36
North Sea PRT is assessed on net profits from subject fields in the U.K. North Sea. U.K. PRT
was $357 million less than the 2008 period on a 45 percent decrease in net profits driven by 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., consistent with lower realized oil and natural gas prices.
Ad valorem taxes are based on U.S. and Canadian assessed property values. The $21 million
decrease resulted from a decline in taxable valuations associated with lower in oil and natural gas
prices.
General and Administrative Expenses General and administrative expenses (G&A) were $40
million higher in the first nine months of 2009, a result of $41 million of nonrecurring charges
related to the retirement of our founder and former chairman and staff reduction separation costs.
Stock-based compensation expense, which includes the mark-to-market of our SARs, increased $16
million on higher stock appreciation relative to the first nine months of 2008. Net reductions in
other corporate expenses decreased G&A expense by $17 million.
Financing Costs, Net Financing costs incurred during the periods noted are composed of the
following:
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Interest expense |
|
$ |
233 |
|
|
$ |
201 |
|
Amortization of deferred loan costs |
|
|
4 |
|
|
|
2 |
|
Capitalized interest |
|
|
(45 |
) |
|
|
(68 |
) |
Interest income |
|
|
(10 |
) |
|
|
(19 |
) |
|
|
|
|
|
|
|
Financing costs, net |
|
$ |
182 |
|
|
$ |
116 |
|
|
|
|
|
|
|
|
Net financing costs rose $66 million, or $.35 per boe, in the first nine months of 2009
compared to the first nine months of 2008. The increase in absolute dollars is primarily the
result of a $32 million increase in interest expense related to higher average outstanding debt
balances, a $23 million reduction in capitalized interest related to lower unproved property
balances and completion of several long-term construction projects, and a $9 million decrease in
interest income on a lower average cash balance.
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.
The provision for income taxes for the first nine months of 2009 was $74 million compared to
$2.2 billion in the 2008 period. The calculation of the 2009 effective income tax rate is not
meaningful because of the magnitude of the non-cash write-down of the carrying value of our proved
oil and gas properties previously discussed. Absent the write-down, the 2009 effective rate would
have been 45 percent compared to 37 percent in 2008. The 2009 rate was impacted by a $116 million
non-cash charge related to the weakening U.S. dollar compared to a $125 million benefit in 2008.
CAPITAL RESOURCES AND LIQUIDITY
Operating cash flows are our primary source of liquidity. Our cash flows, both in the
short-term and the long-term, are impacted by highly volatile oil and natural gas prices.
Significant deterioration in commodity prices negatively impacts our revenues, earnings and cash
flows, and potentially our liquidity, if costs do not trend downward as well. Sales volumes and
costs also impact cash flows; however, these historically have not been as volatile or as impactive
as commodity prices in the short-term.
Our long-term operating cash flows are dependent on reserve replacement and the level of costs
required for ongoing operations. 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 required continuously 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 the success of our exploration and development activities or our
ability to acquire additional reserves at reasonable costs.
37
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.
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.
We fund our exploration and development activities primarily through net cash flows and budget
our capital expenditures based on projected cash flows.
See Part II, Item 1A, Risk Factors of this Form 10-Q and Part I, Items 1 and 2, Business
and Properties, and Item 1A, Risk Factors Related to Our Business and Operations, in our Annual
Report on Form 10-K for the fiscal year ended December 31, 2008.
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 Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Sources of Cash and Cash Equivalents: |
|
|
|
|
|
|
|
|
Net cash provided by operating activities |
|
$ |
2,679 |
|
|
$ |
6,029 |
|
Sale of short-term investments |
|
|
792 |
|
|
|
|
|
Sales of property and equipment |
|
|
|
|
|
|
307 |
|
Net commercial paper and bank loan borrowings |
|
|
230 |
|
|
|
|
|
Restricted cash |
|
|
14 |
|
|
|
|
|
Common stock issuances |
|
|
19 |
|
|
|
31 |
|
Other |
|
|
18 |
|
|
|
50 |
|
|
|
|
|
|
|
|
|
|
|
3,752 |
|
|
|
6,417 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Uses of Cash and Cash Equivalents: |
|
|
|
|
|
|
|
|
Capital expenditures(1) |
|
$ |
3,043 |
|
|
$ |
4,484 |
|
Acquisitions |
|
|
181 |
|
|
|
|
|
Payments on fixed-rate notes |
|
|
100 |
|
|
|
|
|
Dividends |
|
|
155 |
|
|
|
188 |
|
Restricted cash |
|
|
|
|
|
|
14 |
|
Net commercial paper and bank loan repayments |
|
|
|
|
|
|
169 |
|
Other |
|
|
97 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
3,576 |
|
|
|
4,898 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash and cash equivalents |
|
$ |
176 |
|
|
$ |
1,519 |
|
|
|
|
|
|
|
|
|
|
|
(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 Cash flows are our primary source of capital and
liquidity and is impacted, both in the short-term and the long-term, by highly volatile oil and
natural gas prices.
Our average natural gas price realizations have been on a downward trend since peaking in July
2008, rebounding slightly in June and July 2009 before reaching a multi-year low of $3.24 per Mcf
in September 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 $70.06 in
August 2009, then falling slightly to an average of $64.04 in September 2009. Average realized
prices for natural gas and crude oil in the first nine months of 2009 were $3.58 per Mcf and $55.52
per barrel, respectively, substantially below the respective $7.30 per Mcf and $100.17 per barrel
realized in the first nine months of 2008.
38
In order manage the variability in cash flows on an additional portion of our 2010 gas and
crude oil production, we increased our commodity hedge position during the third quarter of 2009.
As of the date of this filing, we had hedged an average of just over 410,000 MMBtu per day of our
projected 2010 North American natural gas production. Nearly all of the volumes were hedged using
fixed-price swaps at an average price of just over $5.60 per MMBtu. In addition, we currently have an
average of just over 35,000 b/d of oil production hedged for 2010. Crude oil production was
primarily hedged using collars that had average floor and ceiling prices of approximately $65.70
and $78.58 per barrel, respectively. For perspective, the 2010 hedges represent 21 percent of our
daily worldwide third-quarter 2009 natural gas volumes, 12 percent of our daily worldwide oil
volumes for the same quarter and 36 percent of third-quarter 2009 North America natural gas
volumes. See Note 2 Derivative Instruments and Hedging Activities in Part I, Item 1 of this
Form 10-Q for additional information regarding our derivative contracts. See Commodity Risk in
Part I, Item 3 of this Form 10-Q for quantitative and qualitative information regarding our use of
derivatives to manage commodity price risk.
The 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.
For the first nine months of 2009, operating cash flows totaled $2.7 billion, down $3.3
billion from the comparable 2008 period. The primary driver of the reduction was a $4.4 billion
decrease in oil and gas revenues, with the impact of lower commodity prices more than offsetting an
eight percent increase in equivalent daily production. Also negatively impacting operating cash
flows was a net decrease in operating assets and liabilities. These items were partially offset by the positive
impact of a decline in cash-based expenses (expenses excluding non-cash expenses described above)
and lower current taxes.
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 Part I, Item 1, Financial Statements
of this Form 10-Q.
Short-term Investments We occasionally invest in highly-liquid, short-term investments until
funds are needed 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 September 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. The outstanding balance under the facility has increased $235 million
during the year, from $100 million at December 31, 2008 to $335 million at September 30, 2009. For
a more detailed discussion of this facility and information regarding our available committed
borrowing capacity, refer to Liquidity of this Form 10-Q.
Capital Expenditures
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 or costs. Given the recent commodity price levels, our
expenditures for the third quarter and first nine months of 2009 were substantially lower than 2008
levels.
We entered the year with a 2009 capital budget that was approximately half of 2008 spending in
an effort to keep expenditures in line with our projected cash flows. As a result of strengthening
oil prices and declining drilling costs, we increased our 2009 capital budget, and spending is now
projected to be approximately $4.1 billion. We will continue to review and revise our capital
budgets throughout the year based on changing industry conditions and results-to-date.
39
Capital expenditures totaled $3.2 billion for the first nine months of 2009, $1.9 billion
lower than the first nine months of 2008. The following table presents a summary of the Companys
capital expenditures for the nine months ended September 30, 2009 and 2008:
|
|
|
|
|
|
|
|
|
|
|
For the Nine Months Ended |
|
|
|
September 30, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions) |
|
Exploration and Development Costs: |
|
|
|
|
|
|
|
|
United States |
|
$ |
748 |
|
|
$ |
1,606 |
|
Canada |
|
|
313 |
|
|
|
526 |
|
|
|
|
|
|
|
|
North America |
|
|
1,061 |
|
|
|
2,132 |
|
|
|
|
|
|
|
|
|
|
Egypt |
|
|
535 |
|
|
|
624 |
|
Australia |
|
|
421 |
|
|
|
662 |
|
North Sea |
|
|
293 |
|
|
|
369 |
|
Argentina |
|
|
109 |
|
|
|
235 |
|
Chile |
|
|
4 |
|
|
|
11 |
|
|
|
|
|
|
|
|
International |
|
|
1,362 |
|
|
|
1.901 |
|
|
|
|
|
|
|
|
Worldwide Exploration and Development Costs |
|
|
2,423 |
|
|
|
4,033 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gathering Transmission and Processing Facilities: |
|
|
|
|
|
|
|
|
Canada |
|
|
69 |
|
|
|
16 |
|
Egypt |
|
|
110 |
|
|
|
374 |
|
Australia |
|
|
23 |
|
|
|
13 |
|
Argentina |
|
|
2 |
|
|
|
3 |
|
|
|
|
|
|
|
|
Total Gathering Transmission and Processing Facility Cost |
|
|
204 |
|
|
|
406 |
|
|
|
|
|
|
|
|
Asset Retirement Costs |
|
|
216 |
|
|
|
350 |
|
Capitalized Interest |
|
|
45 |
|
|
|
69 |
|
|
|
|
|
|
|
|
Capital Expenditures, excluding Acquisitions |
|
|
2,888 |
|
|
|
4,858 |
|
Acquisitions Oil and Gas Properties |
|
|
264 |
|
|
|
156 |
|
|
|
|
|
|
|
|
Total Capital Expenditures |
|
$ |
3,152 |
|
|
$ |
5,014 |
|
|
|
|
|
|
|
|
Worldwide exploration and development (E&D) expenditures were down 40 percent in the first
nine months of 2009 compared to the first nine months of 2008, with decreases in all countries.
The most significant decrease in spending occurred in North America, where E&D investments declined
50 percent. Decreased drilling activity in the Western Desert drove Egypts E&D spending $89
million lower than the prior-year period. However, Egypts percentage of worldwide E&D spending
rose to 22 percent, up from 15 percent, as this decline was less pronounced than in other regions.
Australias E&D expenditures decreased 36 percent on lower drilling activity and lower investments
in platforms and production facilities. North Sea E&D expenditures were $76 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 paid during the first nine months of 2009 totaled $151
million, compared with $183 million paid in the first nine months of 2008. The 2008 period
included a special cash dividend of 10 cents per common share paid on March 18, 2008. During the
first nine months of each of 2009 and 2008, Apache paid $4.3 million in dividends on its Series B
Preferred Stock issued in August 1998.
40
Liquidity
The following table presents a summary of our key financial indicators for the periods
presented:
|
|
|
|
|
|
|
|
|
|
|
September 30, |
|
|
December 31, |
|
|
|
2009 |
|
|
2008 |
|
|
|
(In millions of dollars, except as indicated) |
|
Cash |
|
$ |
1,357 |
|
|
$ |
1,181 |
|
Short-term investments |
|
|
|
|
|
|
792 |
|
Restricted cash |
|
|
|
|
|
|
14 |
|
|
|
|
|
|
|
|
Cash and short-term investments |
|
|
1,357 |
|
|
|
1,987 |
|
|
Total debt |
|
|
5,050 |
|
|
|
4,922 |
|
Shareholders equity |
|
|
15,355 |
(2) |
|
|
16,509 |
(1) |
Available committed borrowing capacity |
|
|
2,315 |
|
|
|
2,550 |
|
Floating-rate debt/total debt |
|
|
7 |
% |
|
|
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 September 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 $1.4 billion in cash and cash equivalents at September 30,
2009, compared to $1.2 billion at December 31, 2008. At September 30, 2009, $920 million of cash
was held by foreign subsidiaries and $437 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. At
September 30, 2009, we held no short-term investments.
Debt At September 30, 2009, outstanding debt, which consisted of notes, debentures,
uncommitted bank lines and project financing, totaled $5.05 billion. Current debt of $40 million
includes $35 million borrowed under our subsidiarys
project financing facility for our Van Gogh and Pyrenees oil
developments and $4.7 million
borrowed under uncommitted overdraft lines.
Available committed borrowing capacity We ended the third quarter of 2009 with $2.3 billion
of available committed borrowing capacity, as discussed below.
As of September 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. The outstanding
balance under the facility as of September 30, 2009 and December 31, 2008, respectively, was $335
million and $100 million. As of September 30, 2009, available borrowing capacity was $15 million.
Under the terms of the agreement, the facility amount begins reducing on June 30, 2010 and
semi-annually thereafter until the maturity on March 31, 2014. The outstanding amount under this
facility must not exceed $300 million on June 30, 2010. Accordingly, $35 million of the current
balance will be repaid by June 30, 2010 and has been classified as current debt at September 30,
2009.
The Company was in compliance with the terms of all credit facilities as of September 30,
2009.
Credit Ratings As of September 30, 2009, the Companys debt ratings are A-, A3, and A- from
Standard & Poors, Moodys Investor Service and Fitch Ratings, respectively. We cannot predict,
nor can we assure, that we will not receive a ratings downgrade from our current ratings in the
future.
41
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 third quarter and first nine months of 2009, approximately eight percent of
our natural gas production was subject to financial derivative hedges. In the third quarter of
2009, we entered into additional hedges on our 2010 projected North American gas production. For
perspective, these 2010 hedges represent approximately 21 percent of our 2009 third-quarter
worldwide daily gas volumes and approximately 36 percent of our 2009 third-quarter North American
daily gas production.
For the third quarter and first nine months of 2009, approximately 12 and nine percent,
respectively, of our crude oil production was subject to financial derivative hedges. In the third
quarter of 2009, we entered into additional crude oil hedges on our 2010 projected production. For
perspective, these 2010 hedges represent approximately 12 percent of our third-quarter 2009
worldwide daily oil production.
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 September 30, 2009, the Company had open natural gas derivative hedges in a liability
position with a fair value of $15 million. A 10 percent increase in natural gas prices would
reduce the fair value by approximately $105 million, while a 10 percent decrease in prices would
increase the fair value by approximately $106 million. The Company also had open oil derivatives
in a liability position with a fair value of $126 million. A 10 percent increase in oil prices
would increase the liability by approximately $185 million, while a 10 percent decrease in prices
would move the derivatives to an asset position of $53 million. These fair value changes assume
volatility based on prevailing market parameters at September 30, 2009. See Part I, Item 1, Note 2
- Derivative Instruments and Hedging Activities of this Form 10-Q for notional volumes and terms
associated with the Companys derivative contracts.
Interest Rate Risk
On September 30, 2009, the Companys debt with fixed interest rates represented approximately
93 percent of total debt. As a result, the interest expense on approximately seven percent of
Apaches debt will fluctuate based on short-term interest rates. A 10 percent change in floating
interest rates on September 30, 2009 floating debt balances would change annual interest expense by
approximately $112,000.
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 Part I, Item 1 of this Quarterly Report on
Form 10-Q.
42
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 Annual Report on 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.
43
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 September 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.
44
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,
June 30, 2009 and September 30, 2009 for a description of material legal proceedings.
ITEM 1A. RISK FACTORS
During the quarter ending September 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:
Proposed 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 GHG than permitted to acquire emission
allowances from other businesses that emit GHG 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.
45
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
None
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
None
ITEM 5. OTHER INFORMATION
None
ITEM 6. EXHIBITS
|
|
|
|
|
|
|
|
|
*3.1
|
|
|
|
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). |
|
|
|
|
|
|
|
|
|
*3.2
|
|
|
|
Bylaws of Registrant, as amended August 6, 2009 (incorporated by
reference to Exhibit 3.2 to Registrants Quarterly Report on Form 10-Q for quarter
ended June 30, 2009, SEC File No. 001-4300). |
|
|
|
|
|
|
|
|
|
**12.1
|
|
|
|
Statement of computation of ratio of earnings to fixed charges and combined
fixed charges and preferred stock dividends. |
|
|
|
|
|
|
|
|
|
**31.1
|
|
|
|
Certification (pursuant to Rule 13a-14(a) or Rule 15d-14(a) of the Exchange
Act) by Principal Executive Officer. |
|
|
|
|
|
|
|
|
|
**31.2
|
|
|
|
Certification (pursuant to 13a-14(a) or Rule 15d-14(a) of the Exchange Act)
by Principal Financial Officer. |
|
|
|
|
|
|
|
|
|
**32.1
|
|
|
|
Section 1350 Certification (pursuant to Sarbanes-Oxley Section 906) by
Principal Executive Officer and Principal Financial Officer. |
|
|
|
|
|
|
|
|
|
***101
|
|
|
|
The following materials from the Apache Corporations Quarterly Report on Form
10-Q for the quarter ended September 30, 2009, formatted in XBRL (Extensible
Business Reporting Language): (i) Statement of Consolidated Operations, (ii)
Consolidated Balance Sheet, (iii) Statement of Consolidated Cash Flows, (iv)
Statement of Consolidated Shareholders Equity, and (v) Notes to Consolidated
Financial Statements, tagged as blocks of text. |
|
|
|
* |
|
Incorporated by reference. |
|
** |
|
Filed herewith. |
|
*** |
|
Furnished herewith. |
46
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.
|
|
|
|
|
|
|
APACHE CORPORATION |
|
|
|
|
|
|
|
Dated: November 6, 2009
|
|
/s/ ROGER B. PLANK
Roger B. Plank
|
|
|
|
|
President |
|
|
|
|
(Principal Financial Officer) |
|
|
|
|
|
|
|
Dated: November 6, 2009
|
|
/s/ REBECCA A. HOYT
Rebecca A. Hoyt
|
|
|
|
|
Vice President and Controller |
|
|
|
|
(Principal Accounting Officer) |
|
|