Edgar Filing: POGO PRODUCING CO

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x Quarterly report pursuant to section 13 or 15(d) of the Securities

Exchange Act of 1934

For the quarterly period ended September 30, 2007 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 1-7792

POGO PRODUCING COMPANY

(Exact Name of Registrant as Specified in Its Charter)

Delaware	74-1659398
(State or Other Jurisdiction of	(I.R.S. Employer
Incorporation or Organization)	Identification No.)

5 Greenway Plaza, Suite 2700
Houston, Texas	77046-0504
(Address of principal executive offices)	(Zip Code)

(713) 297-5000

(Registrant’s Telephone Number, Including Area Code)

Not Applicable

(Former Name, Former Address and Former Fiscal Year, if Changed Since Last Report)

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 x No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See the definition of accelerated filer and large accelerated filer in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer o Non-accelerated filer o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). : Yes o No x

Indicate the number of shares outstanding of each of the issuer’s classes of common stock, as of the latest practicable date.

Common Stock, par value $1.00 per share:

58,733,325 shares as of October 26, 2007

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Expressed in millions, except per share amounts)

Revenue and Other Income
Oil and gas	$	200.3		$	228.0		$	631.2		$	708.0
Other	0.8			4.1			4.3			5.3
Total	201.1			232.1			635.5			713.3

Operating Costs and Expenses:
Lease operating	38.0			45.8			134.6			132.2
General and administrative	27.4			31.9			84.3			73.3
Exploration	5.6			3.1			19.6			4.8
Dry hole and impairment	7.7			32.4			59.4			68.3
Depreciation, depletion and amortization	79.5			72.0			243.4			199.3
Production and other taxes	14.0			19.6			46.9			47.6
Net loss (gain) on sales of properties	(2.4		)	3.1			(131.9		)	(305.3		)
Other	16.7			(2.6		)	29.8			8.0
Total	186.5			205.3			486.1			228.2

Operating Income	14.6			26.8			149.4			485.1
Interest:
Charges	(31.4		)	(41.3		)	(115.2		)	(105.6		)
Income	10.3			—			10.4			0.3
Capitalized	13.5			21.6			53.5			56.4
Commodity Derivative Income (Expense)	(1.7		)	10.6			(6.3		)	6.8
Loss on Debt Extinguishment	(6.9		)	—			(6.9		)	—

Income (Loss) from Continuing Operations Before Taxes	(1.6		)	17.7			84.9			443.0
Income Tax Benefit (Expense)	1.3			(6.7		)	(22.9		)	(49.5		)

Income from Continuing Operations	(0.3		)	11.0			62.0			393.5
Income (Loss) from Discontinued Operations, net of tax	(45.6		)	22.3			(173.9		)	69.2
Net Income (Loss)	$	(45.9	)	$	33.3		$	(111.9	)	$	462.7

Earnings (Loss) per Common Share:
Basic
Income from Continuing Operations	$	—		$	0.19		$	1.07		$	6.83
Income (Loss) from Discontinued Operations, net of tax	(0.79		)	0.39			(3.00		)	1.21
Net Income (Loss)	$	(0.79	)	$	0.58		$	(1.93	)	$	8.04

Diluted
Income from Continuing Operations	$	—		$	0.19		$	1.06		$	6.78
Income (Loss) from Discontinued Operations, net of tax	(0.79		)	0.39			(2.97		)	1.19
Net Income (Loss)	$	(0.79	)	$	0.58		$	(1.91	)	$	7.97

Dividends per Common Share	$	0.075		$	0.075		$	0.225		$	0.225

Potential Common Shares Outstanding:
Basic	58,164			57,618			58,074			57,578
Diluted	58,164			57,863			58,492			58,047

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	September 30,			December 31,
	2007			2006
	(Expressed in millions)

Assets
Current Assets:
Cash and cash equivalents	$	1,325.0		$	22.7
Accounts receivable	78.9			103.9
Other receivables	32.0			47.6
Federal income tax receivable	—			58.0
Inventories - tubulars	15.6			18.5
Commodity derivative contracts	0.2			10.9
Assets from discontinued operations	—			96.5
Other	4.6			10.1
Total current assets	1,456.3			368.2

Property and Equipment:

Oil and gas, on the basis of successful efforts accounting
Proved properties	4,377.2			5,056.6
Unevaluated properties	279.9			301.8
Other, at cost	41.8			43.2
	4,698.9			5,401.6
Accumulated depreciation, depletion and amortization
Oil and gas	(1,274.4		)	(1,619.8		)
Other	(33.5		)	(30.5		)
	(1,307.9		)	(1,650.3		)
Property and equipment, net	3,391.0			3,751.3

Other Assets:
Commodity derivative contracts	0.3			5.0
Assets from discontinued operations	—			2,819.5
Other	23.3			27.1
	23.6			2,851.6

	$	4,870.9		$	6,971.1

See accompanying notes to consolidated financial statements.

	September 30,			December 31,
	2007			2006
	(Expressed in millions,
	except share amounts)
Liabilities and Shareholders’ Equity

Current Liabilities:
Accounts payable - operating activities	$	97.8		$	107.6
Accounts payable - investing activities	73.6			74.2
Income taxes payable	7.8			0.4
Accrued interest payable	34.0			26.0
Accrued payroll and related benefits	12.8			5.1
Deferred income tax	4.5			7.2
Liabilities from discontinued operations	55.5			162.7
Other	18.0			18.6
Total current liabilities	304.0			401.8

Long-Term Debt	1,247.8			2,319.7

Deferred Income Tax	760.3			804.3

Asset Retirement Obligation	61.4			114.9

Other Liabilities and Deferred Credits	50.7			44.3

Liabilities from Discontinued Operations	—			718.7
Total liabilities	2,424.2			4,403.7

Commitments and Contingencies	—			—

Shareholders’ Equity:
Preferred stock, $1 par; 4,000,000 shares authorized	—			—
Common stock, $1 par; 200,000,000 shares authorized, 66,034,291 and 65,794,206 shares issued, respectively	66.0			65.8
Additional capital	992.0			971.4
Retained earnings	1,767.8			1,892.9
Accumulated other comprehensive loss	(16.7		)	(1.4		)
Treasury stock (7,387,766 shares, at cost)	(362.4		)	(361.3		)
Total shareholders’ equity	2,446.7			2,567.4

	$	4,870.9		$	6,971.1

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended
	September 30,
	2007			2006
	(Expressed in millions)
Cash Flows from Operating Activities:
Cash received from customers	$	654.3		$	766.2
Operating, exploration, and general and administrative expenses paid	(313.6		)	(347.9		)
Interest paid	(56.6		)	(82.4		)
Income taxes paid	(62.7		)	(116.8		)
Income tax refund	52.0			3.2
Price hedge contracts	6.3			(2.6		)
Business interruption insurance proceeds	4.2			14.0
Other	8.6			8.4
Net cash provided by continuing operating activities	292.5			242.1
Net cash provided by discontinued operations	210.2			220.2
Net cash provided by operating activities	502.7			462.3

Cash Flows from Investing Activities:
Capital expenditures	(478.9		)	(369.8		)
Purchase of corporations and property	(20.6		)	(806.2		)
Sale of Northrock (net of cash of $28.5 million)	1,946.4			—
Sale of properties	607.5			449.3
Insurance proceeds	18.6			12.4
Other	(1.6		)	(1.0		)
Net cash provided by (used in) continuing investing activities	2,071.4			(715.3		)
Net cash used in discontinued operations	(198.9		)	(244.8		)
Net cash provided by (used in) investing activities	1,872.5			(960.1		)

Cash Flows from Financing Activities:
Borrowings under senior debt agreements	1,666.0			1,839.0
Payments under senior debt agreements	(2,538.0		)	(1,793.0		)
Proceeds from 2013 Notes	—			450.0
Redemption of 2011 Notes	(200.0		)	—
Purchase of Company stock	(1.1		)	(7.7		)
Payments to discontinued operations	(8.1		)	—
Payments of cash dividends on common stock	(13.2		)	(13.1		)
Tax benefits of stock awards	1.9			0.6
Payment of debt issue costs	—			(11.2		)
Proceeds from exercise of stock awards	9.2			3.7
Net cash provided by (used in) continuing financing activities	(1,083.3		)	468.3
Net cash provided by discontinued operations	8.1			—
Net cash provided by (used in) financing activities	(1,075.2		)	468.3
Effect of exchange rate changes on cash	2.3			0.8
Net increase (decrease) in cash and cash equivalents	1,302.3			(28.7		)
Cash and cash equivalents from continuing operations, beginning of the year	5.6			8.0
Cash and cash equivalents from discontinued operations, beginning of the year	17.1			49.7
Cash and cash equivalents at the end of the period	$	1,325.0		$	29.0

Reconciliation of net income to net
cash provided by operating activities:
Net income (loss)	$	(111.9	)	$	462.7
Adjustments to reconcile net income (loss) to net cash provided by operating activities - Loss (Income) from discontinued operations, net of tax	173.9			(69.2		)
Net gains from the sales of properties	(131.9		)	(305.3		)
Depreciation, depletion and amortization	243.4			199.3
Dry hole and impairment	59.4			68.3
Commodity derivative contracts	8.3			(3.3		)
Other	0.2			(51.8		)
Deferred income taxes	(53.1		)	(45.8		)
Change in operating assets and liabilities	104.2			(12.8		)
Net cash provided by continuing operating activities	292.5			242.1
Net cash provided by discontinued operations	210.2			220.2
Net cash provided by operating activities	$	502.7		$	462.3

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statement of Shareholders’ Equity (Unaudited)

	For the Nine Months Ended September 30, 2007
	Shareholders’
	Equity
	Shares		Amount
	(Expressed in millions, except share amounts)
Common Stock:
$ 1.00 par-200,000,000 shares authorized
Balance at beginning of year	65,794,206		$	65.8
Stock option activity	254,735		0.2
Restricted stock activity	(14,650	)	—
Issued at end of period	66,034,291		66.0

Additional Capital:
Balance at beginning of year			971.4
Stock options exercised - proceeds			9.0
Stock based compensation - excess federal tax benefit			1.9
Stock based compensation - restricted stock			9.7
Balance at end of period			992.0

Retained Earnings:
Balance at beginning of year			1,892.9
Net loss			(111.9		)
Dividends ($0.225 per common share)			(13.2		)
Balance at end of period			1,767.8

Accumulated Other
Comprehensive Loss:
Balance at beginning of year			(1.4		)
Cumulative foreign currency translation adjustment, net of tax			(11.5		)
Deferred post-retirement benefit costs, net of tax			1.8
Change in fair value of commodity derivative contracts, net of tax			(5.8		)
Reclassification adjustment for losses on commodity derivative contracts included in net income, net of tax			0.2
Balance at end of period			(16.7		)

Treasury Stock:
Balance at beginning of year	(7,365,359	)	(361.2		)
Activity during the period	(22,407	)	(1.2		)
Balance at end of period	(7,387,766	)	(362.4		)

Common Stock Outstanding, at the End of the Period	58,646,525

Total Shareholders’ Equity			$	2,446.7

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Notes to Consolidated Financial Statements (Unaudited)

(1) GENERAL INFORMATION -

The consolidated financial statements included herein have been prepared by Pogo Producing Company (the “Company”) without audit and include all adjustments (of a normal and recurring nature), which are, in the opinion of management, necessary for the fair statement of interim results. The interim results are not necessarily indicative of results for the entire year. The financial statements should be read in conjunction with the consolidated financial statements and notes thereto included in the Company’s Form 8-K filed with the SEC on August 17, 2007.

The Company’s results for all periods presented reflect its oil and gas exploration, development, and production activities in Canada as discontinued operations. Except where noted and for pro forma earnings per share, the discussions in the following notes relate to the Company’s continuing operations only. Certain prior year amounts have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company’s net income or shareholders’ equity. The Company changed the classification of “Net gains on sales of properties” from “Revenue and Other Income” to reflect it as a component of “Operating Costs and Expenses” for both the current and prior periods. The Company also changed the classification of interest capitalized in the Statement of Cash Flows from an operating cash outflow to an investing cash outflow in the fourth quarter of 2006. The Company elected not to change the classification of interest capitalized in the Statement of Cash Flows for periods prior to the fourth quarter of 2006 due to the immateriality of the amounts.

On July 17, 2007 Plains Exploration & Production Company (“PXP”) and the Company entered into a definitive agreement providing for the merger of Pogo into a subsidiary of PXP in exchange for cash and PXP common stock. On October 1, 2007 PXP and the Company each scheduled November 6, 2007 as the date for their respective upcoming special stockholder meetings. At these meetings, the Company’s stockholders will vote on, among other items, the proposed merger with PXP and the PXP stockholders will vote on, among other items, the issuance of PXP common stock to Pogo stockholders pursuant to the merger. The record date for the meetings was September 25, 2007.

(2) DISCONTINUED OPERATIONS –

Under SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (“SFAS No. 144”), the Company classifies assets to be disposed of as held for sale, or, if appropriate, discontinued operations, when the criteria defined in SFAS No. 144 have been met, including a commitment by the Company’s management or Board of Directors to sell the assets. On May 28, 2007, the Company entered into an agreement to sell all of the outstanding stock of its wholly-owned subsidiary, Northrock Resources Ltd. (“Northrock”) for approximately $2.0 billion in cash. The Company completed the sale on August 14, 2007 and used the proceeds to reduce outstanding debt and invested the remainder while evaluating additional debt repayment strategies. The Company recognized a loss on the sale of approximately $267.2 million (including U.S. income tax expense of $30.0 million related to previously unremitted foreign earnings), of which $184.5 million (including U.S. income tax expense of $23.0 million related to previously unremitted foreign earnings) had been recognized in the second quarter of 2007 in accordance with SFAS No. 144, which requires that long-lived assets classified as discontinued operations be measured at the lower of their carrying amount or fair value less cost to sell. The financial results and financial position for Northrock have been classified as discontinued operations in the Company’s financial statements for all periods presented.

The summarized financial results and financial position of the discontinued operations for the periods presented are as follows:

Operating Results Data

	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006			2007			2006

Revenues	$	66.3		$	124.7		$	345.5		$	383.3
Costs and expenses	(42.5		)	(102.8		)	(279.8		)	(300.9		)
Other income (expense)	0.5			0.3			9.0			2.0
Income (loss) before income taxes	24.3			22.2			74.7			84.4
Income tax benefit (expense)	12.8			0.1			18.6			(15.2		)
Income (loss) before loss from discontinued operations, net of tax	37.1			22.3			93.3			69.2
Loss on sale of Northrock, including tax expense (1)	(82.7		)	—			(267.2		)	—
Income(loss) from discontinued operations, net of tax	$	(45.6	)	$	22.3		$	(173.9	)	$	69.2

(1) Loss on sale of Northrock includes $7.0 million and $30.0 million of U.S tax on previously unremitted Canadian earnings for the three and nine months ended September 30, 2007, respectively.

Financial Position Data

	September 30,		December 31,
	2007		2006

Assets of Discontinued Operations
Accounts receivable	$	—	$	69.7
Inventories	—		24.8
Other current assets	—		2.0
Total current assets	—		96.5
Property, plant, and equipment, net	—		2,805.8
Other long-term assets	—		13.7
Total assets	$	—	$	2,916.0

Liabilities of Discontinued Operations
Accounts payable	$	—	$	158.5
Income taxes payable	30.0		0.4
Other current liabilities	25.5		3.8
Total current liabilities	55.5		162.7
Deferred income tax	—		673.7
Asset retirement obligation	—		41.4
Other deferred credits	—		3.6
Total liabilities	$	55.5	$	881.4

The remaining liabilities of discontinued operations consist of $8.5 million of transaction costs to be paid, $30.0 million of U.S. income tax on previously unremitted foreign earnings, and approximately $17.0 million that will be paid to reimburse the purchaser for Northrock “change of control” taxes at the time they become due.

(3) OTHER DIVESTITURES –

During the three months ended September 30, 2007 the Company recognized a net gain on property sales of $2.4 million, which consisted primarily of a gain of approximately $3.9 million on the sale of Main Pass 76, which was partially offset by post-closing adjustment losses related to previous property sales. In addition to the third quarter activity, during the nine months ended September 30, 2007 the Company completed the sale of properties in the onshore Texas and Louisiana areas and the Texas Panhandle for approximately $190.2 million and the sale of certain of its federal and state Gulf of Mexico oil and gas leasehold interests and related pipelines and equipment for approximately $419.5 million before purchase price adjustments. The proceeds from these sales transactions were used to reduce outstanding senior debt. The transactions resulted in gains on the sale of properties of $131.9 million for the nine months ended September 30, 2007, respectively, which consisted primarily of the gain of $3.9 million on Main Pass 76, a gain of $224.8 million on the Gulf of Mexico sale and losses of $8.8 million on the South Texas, Texas Gulf Coast and Louisiana Gulf Coast sale and $89.7 million on the Texas Panhandle sale. Additionally, the Company recognized impairments for $34.4 million during the nine months ended September 30, 2007 on the Gulf Coast properties prior to the completion of the sales.

(4) ACQUISITIONS –

2006 - On May 2, 2006, the Company completed the acquisition of Latigo Petroleum, Inc. (“Latigo”), a privately held corporation for approximately $764.9 million in cash, including transaction costs. The purchase price was funded using cash on hand and debt financing. At the date of purchase, Latigo owned approximately 100,100 net producing acres, plus approximately 304,600 net acres of undeveloped leasehold. Latigo’s operations are concentrated in west Texas and the Texas Panhandle with key exploration plays in the Texas Panhandle. The Company acquired Latigo primarily to strengthen its position in domestic exploration and development properties. The following is a calculation and final allocation of purchase price to the acquired assets and liabilities based on their relative fair values:

CALCULATION OF PURCHASE PRICE (IN MILLIONS)
Cash paid, including transaction costs	$	764.9

Plus fair market value of liabilites assumed:
Deferred income taxes	205.9
Other liabilities	55.1
Total purchase price for assets acquired	$	1,025.9

ALLOCATION OF PURCHASE PRICE (IN MILLIONS)
Proved oil and gas properties	$	846.9
Unproved oil and gas properties	157.0
Other assets	22.0
Total	$	1,025.9

Pro Forma Information

The following summary presents unaudited pro forma consolidated results of operations for the nine months ended September 30, 2006 as if the acquisition of Latigo had occurred as of January 1, 2006. The pro forma results are for illustrative purposes only and include adjustments in addition to the pre-acquisition historical results of Latigo, such as increased depreciation, depletion and amortization expense resulting from the allocation of fair value to oil and gas properties acquired, increased interest expense on acquisition debt and the related tax effects of these adjustments. The unaudited pro forma information (presented in millions of dollars, except per share amounts) is not necessarily indicative of the operating results that would have occurred had the acquisition been consummated at that date, nor is it necessarily indicative of future operating results.

Pro Forma:
	Nine Months Ended
	September 30, 2006
Revenues	$	754.9
Income from continuing operations	$	371.6
Net income	440.8
Earnings per share:
Basic -	$	7.66
Diluted -	$	7.59

(5) EARNINGS PER SHARE -

Earnings per common share (basic earnings per share) are based on the weighted average number of shares of common stock outstanding during the periods. Earnings per share and potential common shares (diluted earnings per share) consider the effect of dilutive securities as set out below. Amounts are expressed in millions, except per share amounts.

	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007			2006		2007			2006

Income (numerator):
Income (loss) from continuing operations	$	(0.3	)	$	11.0	$	62.0		$	393.5
Income (loss) from discontinued operations, net of tax	(45.6		)	22.3		(173.9		)	69.2

Net Income (loss) - basic and diluted	$	(45.9	)	$	33.3	$	(111.9	)	$	462.7

Weighted average shares (denominator):
Weighted average shares - basic	58.2			57.6		58.1			57.6
Dilution effect of stock options and unvested restricted stock outstanding at end of period	—			0.3		0.4			0.5

Weighted average shares - diluted	58.2			57.9		58.5			58.1

Earnings per share:
Basic:
Income from continuing operations	$	—		$	0.19	$	1.07		$	6.83
Income (loss) from discontinued operations	(0.79		)	0.39		(3.00		)	1.21
Basic earnings (loss) per share	$	(0.79	)	$	0.58	$	(1.93	)	$	8.04

Diluted:
Income from continuing operations	$	—		$	0.19	$	1.06		$	6.78
Income (loss) from discontinued operations	(0.79		)	0.39		(2.97		)	1.19
Diluted earnings (loss) per share	$	(0.79	)	$	0.58	$	(1.91	)	$	7.97

For the three months ended September 30, 2007, the Company has excluded from the diluted loss per share calculation common stock equivalents totaling 1.4 million shares because their effect on loss per share was anti-dilutive. There were no adjustments for anti-dilutive shares for the nine months ended September 30, 2007. For the three and nine months ended September 30, 2006, the Company excluded from the diluted earnings per share calculation common stock equivalents totaling 0.02 million shares because their effect on earnings per share was anti-dilutive.

(6) LONG-TERM DEBT –

Long-term debt at September 30, 2007 and December 31, 2006, consists of the following (dollars expressed in millions):

	September 30,			December 31,
	2007			2006
Senior debt -
Bank revolving credit agreement:
LIBOR based loans, borrowings at September 30, 2007 and December 31, 2006 at an interest rate of 6.8524% at December 31, 2006	$	—		$	797.0
LIBOR Rate Advances, borrowings at September 30, 2007 and December 31, 2006 at an interest rate of 6.6833% at December 31, 2006	—			75.0
Total senior debt	—			872.0
Senior subordinated debt -
8.25% Senior subordinated notes, due 2011	—			200.0
7.875% Senior subordinated notes, due 2013	450.0			450.0
6.625% Senior subordinated notes, due 2015	300.0			300.0
6.875% Senior subordinated notes, due 2017	500.0			500.0
Total senior subordinated debt	1,250.0			1,450.0
Unamortized discount on 2015 Notes	(2.2		)	(2.3		)
Total debt	1,247.8			2,319.7
Amount due within one year	—			—
Long-term debt	$	1,247.8		$	2,319.7

On September 20, 2007 the Company completed the redemption of all $200 million of its outstanding 8.25% Senior Subordinated Notes due 2011 (the “Notes”). The Notes were redeemed for approximately $212.6 million, which included a premium of $5.5 million plus accrued interest to September 19, 2007 of $7.1 million. The cash redemption payment was funded using available cash on hand. The Company recorded a pre-tax expense on the redemption of $6.9 million (including the write-off of $1.4 million of unamortized debt issuance costs), which is reflected as “Loss on Debt Extinguishment” in the Company’s financial statements.

On October 3, 2007, in anticipation of the pending merger with PXP, the Company commenced cash tender offers for $450 million outstanding principal amount of its 7.875% Senior Subordinated Notes due 2013, $300 million outstanding principal amount of its 6.625% Senior Subordinated Notes due 2015 and $500 million outstanding principal amount of its 6.875% Senior Subordinated Notes due 2017 (the “Notes”). In connection with each tender offer, the Company solicited related consents from the holders of the Notes to eliminate substantially all the restrictive covenants and certain events of default from the indentures governing the Notes. The terms and conditions of the tender offers and consent solicitations are set forth in the related offer to purchase and consent solicitation statement dated October 3, 2007.

The consent solicitations with respect to the Notes expired on October 17, 2007. At the expiration, the Company had not received the required number of consents to the proposed amendments to the indentures governing the Notes. However, holders of Notes may continue to tender Notes prior to 5:00 p.m. (New York City Time) on November 5, 2007, when the tender offers will expire (unless earlier terminated or extended). The Company reserves the right to terminate, withdraw or amend, or waive certain aspects of, the tender offers or consent solicitations at any time, subject to applicable law.

Consummation of the tender offers or the consent solicitations is not a condition to the closing of the Company’s pending merger with PXP.

(7) INCOME TAXES –

The components of income (loss) from continuing operations before income taxes for the three and nine month periods ended September 30, 2007 and 2006 are as follows (expressed in millions):

	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006			2007			2006
United States	$	(0.1	)	$	18.1		$	92.0		$	440.1
Foreign	(1.5		)	(0.4		)	(7.1		)	2.9
Income (loss) before income taxes	$	(1.6	)	$	17.7		$	84.9		$	443.0

The components of income tax expense (benefit) for the three and nine month periods ended September 30, 2007 and 2006 are as follows (expressed in millions):

	Three months ended						Nine months ended
	September 30,						September 30,
	2007			2006			2007			2006
Current
United States	$	(23.3	)	$	(49.9	)	$	75.1		$	95.3
Foreign	0.1			—			0.8			—
Deferred
United States	21.9			56.5			(42.6		)	66.4
Foreign (a)	—			0.1			(10.4		)	(112.2		)
Income tax (benefit) expense	$	(1.3	)	$	6.7		$	22.9		$	49.5

(a) The foreign income tax benefit for the nine months ended September 30, 2007 and 2006 is a result of reductions in the Canadian federal and provincial tax rates. Generally accepted accounting principles (“GAAP”) require that the entire tax effect of a change in enacted tax rates be allocated to continuing operations.

Total income tax expense (benefit) for the three and nine month periods ended September 30, 2007 and 2006, differs from the amounts computed by applying the statutory federal income tax rate to income before taxes as follows (expressed as percent of pretax income):

	Three months ended				Nine months ended
	September 30,				September 30,
	2007		2006		2007		2006
Federal statutory income tax rate	(35.0	)%	35.0	%	35.0	%	35.0	%
Increases (decreases) resulting from:
Canadian rate change	—		0.6		(12.3	)	(25.3	)
State income taxes, net of federal benefits	3.4		1.6		1.2		1.6
Other	(49.7	)	0.4		3.1		(0.1	)
	(81.3	)%	37.6	%	27.0	%	11.2	%

As pre-tax book income changes in future quarters, the Company’s effective tax rate may increase or decrease. The exceptionally high effective tax rate for the third quarter of 2007 is the result of the Company’s low level of pre-tax earnings in the period.

The decision to sell Northrock in 2007 resulted in the recognition for financial reporting purposes of U.S. income tax of approximately $30 million on previously unremitted foreign earnings. This U.S. tax has been included in the loss from discontinued operations in the Company’s consolidated statement of income and therefore is not included in the tables above

On January 1, 2007, the Company adopted the provisions of FASB Interpretation No. 48 (“FIN 48”), “Accounting for Uncertainty in Income Taxes.” The Company has determined that no uncertain tax positions exist where the Company would be required to make additional tax payments. As a result, the Company has not recorded any additional liabilities for any unrecognized tax benefits as of September 30, 2007.

The Company and its subsidiaries file income tax returns in the U.S. federal and various state and foreign jurisdictions. The Company is no longer subject to U.S. federal, state, or local tax examinations by tax authorities for years prior to 2004. The Company’s Canadian subsidiary is no longer subject to examinations by Canadian taxing authorities for years prior to 2002. Under agreement with the purchaser of Northrock, the Company has agreed to indemnify the purchaser for additional tax liabilities asserted by Canadian tax authorities for all open tax years. The Company is indemnified for tax liabilities associated with the tax years in 2003, 2004, and the short period ended September 27, 2005 by the previous owner of Northrock.

The Company’s accounting policy is to recognize penalties and interest related to unrecognized tax benefits as income tax expense. The Company does not have an accrued liability for the payment of penalties and interest at September 30, 2007.

(8) ASSET RETIREMENT OBLIGATION –

The Company’s liability for expected future costs associated with site reclamation, facilities dismantlement, and plugging and abandonment of wells for the nine month period ended September 30, 2007 is as follows (in millions):

	2007
ARO as of January 1,	$	121.7
Liabilities incurred during the nine months ended September 30,	2.8
Liabilities settled during the nine months ended September 30, (1)	(66.1		)
Accretion expense	5.3
Balance of ARO as of September 30,	63.7
Less: current portion of ARO	(2.3		)
Long-term ARO as of September 30,	$	61.4

(1) Primarily relates to the sale of the Company’s remaining interest in the Gulf of Mexico during the second quarter of 2007.

For the three months ended September 30, 2007 and 2006, the Company recognized depreciation expense related to its asset retirement cost (“ARC”) of $1.2 million and $1.3 million, respectively. For the nine months ended September 30, 2007 and 2006, the Company recognized depreciation expense related to its ARC of $4.9 million and $4.1 million, respectively.

(9) SEVERANCE AND RETENTION INCENTIVE PROGRAM

The Company established a Change of Control Severance and Retention Program (the “Plan”), effective as of January 1, 2007, to provide severance benefits and a retention incentive to employees who are designated by the Plan Administrator as eligible for benefits under the Plan in the event of a “Change of Control.” Employees who are selected to participate in the Plan will receive retention benefits on the earlier of (i) involuntary termination of employment by the Company, other than for cause, (ii) a change of control, or (iii) December 31, 2007. For the three months and nine months ended September 30, 2007, the Company recorded general and administrative expense related to retention benefits of $2.8 million and $8.3 million, respectively.

(10) COMMODITY DERIVATIVES AND HEDGING ACTIVITIES -

As of September 30, 2007, the Company held various derivative instruments. During 2005 and 2006, the Company entered into natural gas and crude oil option agreements referred to as “collars”. Collars are designed to establish floor and ceiling prices on anticipated future natural gas and crude oil production. The Company designated these contracts as cash flow hedges designed to achieve a more predictable cash flow, as well as to reduce exposure to price volatility. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Currently, the Company does not expect losses due to creditworthiness of its counterparties.

During the three and nine month periods ended September 30, 2007, the Company recognized pre-tax gains of $3.8 million and $6.3 million, respectively, in its oil and gas revenues related to settled price hedge contracts. During the three and nine month periods ended September 30, 2006, the Company recognized a pre-tax gain of $0.7 million and a pre-tax loss of $2.5 million, respectively, in its oil and

gas revenues related to settled price hedge contracts. The Company recognized a pre-tax gain of $1.3 million and a pre-tax loss of $ 1.9 million in “Other” expense due to ineffectiveness on unsettled hedge contracts during the three and nine month periods ended September 30, 2007, respectively. The Company recognized pre-tax gains of $0.5 million and $1.5 million in “Other” expense due to ineffectiveness on unsettled hedge contracts during the three and nine month periods ended September 30, 2006, respectively. Unrealized pre-tax losses on derivative instruments of $1.7 million ($1.1 million after taxes) have been reflected as a component of other comprehensive income at September 30, 2007. Based on the fair market value of the hedge contracts as of September 30, 2007, the Company would reclassify additional pre-tax gains of approximately $2.0 million (approximately $1.3 million after taxes) from accumulated other comprehensive income (shareholders’ equity) to net income during the next twelve months.

The gas derivative contracts are generally settled based upon the average of the reported settlement prices on the NYMEX for the last three trading days of a particular contract month. The oil derivative transactions are generally settled based on the average of the reported settlement prices for West Texas Intermediate on the NYMEX for each trading day of a particular calendar month. For any particular collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price of such transaction.

The estimated fair value of these contracts is based upon various factors that include closing exchange prices on the NYMEX, volatility and the time value of options. Further details related to the Company’s hedging activities as of September 30, 2007 are as follows:

Contract Period and		NYMEX Contract Price				Fair Value of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)
						(in millions)
Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
October 2007 - December 2007	1,380	$	6.00	$	12.00	$	0.1
October 2007 - December 2007	460	$	6.00	$	12.15	$	—
October 2007 - December 2007	2,300	$	6.00	$	12.50	$	0.1
October 2007 - December 2007	230	$	8.00	$	13.40	$	0.3
October 2007 - December 2007	690	$	8.00	$	13.50	$	0.8
October 2007 - December 2007	230	$	8.00	$	13.52	$	0.3
October 2007 - December 2007	230	$	8.00	$	13.65	$	0.3
January 2008 - December 2008	1,830	$	8.00	$	12.05	$	1.6
January 2008 - December 2008	2,745	$	8.00	$	12.10	$	2.4
January 2008 - December 2008	915	$	8.00	$	12.25	$	0.8

Crude Oil Contracts (Barrels)
Collar Contracts:
October 2007 - December 2007	138,000	$	50.00	$	77.50	$	(0.7	)
October 2007 - December 2007	46,000	$	60.00	$	82.75	$	(0.1	)
January 2008 - December 2008	183,000	$	60.00	$	80.00	$	(0.7	)
January 2008 - December 2008	183,000	$	60.00	$	80.05	$	(0.7	)
January 2008 - December 2008	183,000	$	60.00	$	80.10	$	(0.6	)
January 2008 - December 2008	366,000	$	60.00	$	80.25	$	(1.3	)

(a) MMBtu means million British Thermal Units

Although the Company’s collars are effective as economic hedges, the Gulf of Mexico sales, along with the shut-in forecasted hydrocarbon production from the Company’s Gulf of Mexico properties prior to the sales (resulting primarily from hurricane activity during the third quarter of 2005) caused certain of the gas and crude oil collar contracts to lose their qualification for hedge accounting under SFAS 133. The Company recognizes changes in the fair value of these contracts in the consolidated statement of income for the period in which the change occurs under the caption “Commodity derivative income (expense).” The Company recognized realized and unrealized losses related to these contracts of $1.7 million and $6.3 million during the three and nine month periods ended September 30, 2007, respectively. The Company recognized $10.6 million and $6.8 million of realized and unrealized gains for the three and nine month

periods ended September 30, 2006, respectively. As of September 30, 2007, the Company had the following open collar contracts that no longer qualify for hedge accounting:

Contract Period and		NYMEX Contract Price				Fair Value of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)
						(in millions)
Natural Gas Contracts (MMBtu)
Collar Contracts:
October 2007 - December 2007	1,840	$	6.00	$	12.15	$	0.1
October 2007 - December 2007	920	$	6.00	$	12.20	$	—

Crude Oil Contracts (Barrels)
Collar Contracts:
October 2007 - December 2007	368,000	$	50.00	$	77.50	$	(1.8	)
October 2007 - December 2007	138,000	$	60.00	$	83.00	$	(0.3	)
October 2007 - December 2007	46,000	$	60.00	$	84.00	$	(0.1	)

(11) EMPLOYEE BENEFIT PLANS -

The Company has adopted a trusteed retirement plan for its U.S. salaried employees. The benefits are based on years of service and the employee’s average compensation for five consecutive years within the final ten years of service that produce the highest average compensation. As of September 30, 2007, the Company has a projected benefit obligation of $16.5 million related to its pension plan. The Company did not make a contribution to the plan during the first nine months of 2007; however, the Company plans to make a contribution of $5.0 million during the fourth quarter of 2007.

Although the Company has no obligation to do so, the Company currently provides full medical benefits to its retired U.S. employees and dependents. For current employees, the Company assumes all or a portion of post-retirement medical and term life insurance costs based on the employee’s age and length of service with the Company. The post-retirement medical plan has no assets and is currently funded by the Company on a pay-as-you-go basis.

If the Company’s proposed merger with PXP is approved by shareholders, the Company believes that its post retirement medical benefit obligation will be modified to exclude employees that are not retired as of the merger date and that current retirees and their dependents will be required to begin funding the full cost of their medical benefits within three years of the merger date. Additionally, if the merger is completed, it is the Company’s belief that the current pension plan will be frozen and then terminated by PXP.

The Company’s net periodic benefit cost for its benefit plans is comprised of the following components (in millions of dollars):

	Retirement Plan
	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006
Service cost	$	1.4		$	1.1		$	4.4		$	3.3
Interest cost	0.8			0.6			2.3			1.9
Expected return on plan assets	(0.8		)	(0.7		)	(2.5		)	(2.1		)
Amortization of prior service cost	—			—			0.1			—
Amortization of net loss	0.5			0.5			1.5			1.4
	$	1.9		$	1.5		$	5.8		$	4.5

	Post-Retirement Medical Plan
	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
Service cost	$	0.8	$	0.4	$	2.3	$	1.3
Interest cost	0.4		0.3		1.3		0.9
Amortization of prior service cost	—		—		0.1		—
Amortization of net loss	0.1		0.1		0.3		0.2
	$	1.3	$	0.8	$	4.0	$	2.4

The assumptions used in the valuation of the Company’s employee benefit plans and the target investment allocations have remained the same as those disclosed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006.

In December 2003, the Medicare Prescription Drug Improvement and Modernization Act of 2003 (the Act) was signed into law. The Act introduced a prescription drug benefit under Medicare (Medicare Part D), as well as a nontaxable federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D. The Company has elected not to reflect changes in the Act in its financial statements since the Company has concluded that the effects of the Act are not a significant event that calls for remeasurement under SFAS 106.

(12) COMPREHENSIVE INCOME (LOSS)-

As of the indicated dates, the Company’s comprehensive income (loss) consisted of the following (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2006			2007			2006

Net income (loss)	$	(45.9	)	$	33.3		$	(111.9	)	$	462.7
Foreign currency translation adjustment, net of tax	9.5			(2.7		)	199.5			72.6
Reclassification adjustment for foreign currency gains included in net income due to the sale of Northrock, net of tax	(211.0		)	—			(211.0		)	—
Deferred post-retirement benefit costs, net of tax	0.4			—			1.8			—
Change in fair value of price hedge contracts, net of tax	6.3			44.3			(5.8		)	63.3
Reclassification adjustment for hedge contract losses included in net income, net of tax	(3.2		)	(10.2		)	0.2			(4.8		)
Comprehensive income (loss)	$	(243.9	)	$	64.7		$	(127.2	)	$	593.8

(13) INSURANCE RECOVERIES-

On February 28, 2007, the Company reached an agreement with its insurers to settle all outstanding claims related to Hurricanes Katrina and Rita. During the first nine months of 2007, the Company recorded $4.2 million of business interruption insurance recoveries as a reduction of “Other” expenses and $18.6 million in property damage recoveries, of which $13.8 million was used to partially offset

hurricane-related property damage repair costs recorded in “Lease operating expense” and $4.8 million reduced a previously accrued insurance receivable.

(14) RECENT ACCOUNTING PRONOUNCEMENTS-

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements” which is effective for fiscal years beginning after November 15, 2007 and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. The Company is currently evaluating the impact, if any, that the adoption of SFAS 157 will have on its financial statements.

On February 15, 2007, the FASB issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115 (“SFAS 159”).” The Statement permits entities to choose to measure eligible financial instruments and certain other items at fair market value, with the objective of improving financial reporting by giving entities the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Statement is effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 159 is not expected to have a material impact, if any, on the Company’s financial statements.

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

This discussion should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations included in the Company’s Form 8-K filed with the SEC on August 17, 2007 and the risk factors included in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006 and its Quarterly Report on Form 10-Q for the period ended June 30, 2007. The assets comprising the Company’s operations have changed substantially during the periods presented in this report, which affects comparability between those periods of the Company’s results of operations and financial condition. The Company acquired Latigo on May 2, 2006, disposed of 50% of its interests in its Gulf of Mexico properties on May 31, 2006, disposed of substantially all of its remaining interests in the Gulf of Mexico on April 23, 2007 (“the Gulf of Mexico sales”), disposed of certain Texas Panhandle and Gulf Coast properties in April and June of 2007 (“Onshore sales”), and sold all of the outstanding stock of its wholly-owned subsidiary, Northrock Resources Ltd. (“Northrock”) on August 14, 2007. The financial results of Northrock through the date of its sale, including the loss on sale, are classified as discontinued operations in the Company’s financial statements for all periods presented. Except where noted, discussions in this report relate to the Company’s continuing operations, which include, for the periods during which the Company owned the properties, the financial results from Latigo and the properties disposed of in the Gulf of Mexico and Onshore sales.. For summary pro forma results of operations from the Company’s continuing operations as if the Latigo acquisition had occurred on January 1, 2006, please refer to Note 4 – “Acquisitions” to the Unaudited Consolidated Financial Statements in this report. Some of the statements in the discussion are “Forward Looking Statements” and are thus prospective. As further discussed in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006, these forward-looking statements are subject to risks, uncertainties and other factors that could cause actual results to differ materially from future results expressed or implied by such forward-looking statements.

Executive Overview

Below is an overview of the significant transactions and financial matters which occurred during the third quarter of 2007.

Definitive Agreement for the Sale of Pogo Producing Company

On July 17, 2007, Plains Exploration & Production Company (“PXP”) and the Company entered into a definitive agreement for PXP to acquire the Company for consideration of approximately 40 million shares of PXP common stock and approximately $1.5 billion in cash. In the merger, Company stockholders will receive, on an aggregate basis, 0.68201 shares of PXP common stock and $24.88 in cash for each share of the Company’s common stock. The Company’s stockholders have the right to elect to receive cash or PXP stock, subject to proration if either the cash or stock election is oversubscribed. The transaction is expected to qualify as a tax-free reorganization under Section 368(a) of the Internal Revenue Code, to the extent Pogo stockholders receive stock pursuant to the merger.

The Company and PXP have each scheduled November 6, 2007 as the special meeting date for their respective stockholders of record as of September 25, 2007 to vote on the transaction. The Company expects the merger to close promptly after the stockholder meetings if the necessary stockholder approvals are obtained.

Sale of Northrock Resources

On August 14, 2007, the Company closed the sale of its Canadian Northrock subsidiary to Abu Dhabi National Energy Company PJSC (“TAQA”) for $2.0 billion in cash. The Company recognized a loss on the sale of approximately $267.2 million. The results of operations of Northrock through the date of its sale have been reflected in the financial statements as discontinued operations.

Third Quarter Results

Total revenue for the third quarter of 2007 from continuing operations was $201.1 million and the Company reported a net loss from continuing operations of $0.3 million. Net cash provided by continuing operating activities totaled $292.5 million. As of September 30, 2007, long-term debt was $1.25 billion, decreasing from $2.3 billion by approximately $1.1 billion, primarily due to the paydown of all of the Company’s senior debt under its revolving credit facility and the redemption of the Company’s 8.25% Senior Subordinated Notes due 2011 using available cash on hand. Cash and cash equivalents increased from $22.7 million at December 31, 2006 to approximately $1.3 billion at September 30, 2007.

2007 Capital Budget

The Company has established a $720 million exploration and development budget (excluding property acquisitions) for 2007. The Company expects to spend approximately $199 million on exploration and $521 million on development activities. The capital budget calls for the drilling of approximately 370 wells during 2007, including wells in the United States, Canada, and New Zealand. Oil and gas capital and exploration expenditures for the nine months ended September 30, 2007 were approximately $463.6 million. Exploration and development drilling for the nine months ended September 30, 2007 totaled approximately $352.7 million. The Company’s capital expenditures for the remainder of the year may vary from the capital budget if the merger with PXP is consummated.

Redemption of $200 million 8.25% Senior Subordinated Notes due 2011

Tender Offers and Consent Solicitations for Senior Subordinated Notes

Consummation of the tender offers or the consent solicitations is not a condition to the closing of the Company’s pending merger with PXP.

Exposure to Oil and Gas Prices and Availability of Oilfield Services

Oil and natural gas prices have historically been seasonal, cyclical and volatile. Prices depend on many factors that the Company cannot control such as weather and economic, political and regulatory conditions. The average prices the Company is currently receiving for production are higher than historical average prices. A future drop in oil and gas prices could have a serious adverse effect on cash flow and profitability. Sustained periods of low prices could have a serious adverse effect on the Company’s operations and financial condition. Additionally, the cost of drilling, completing and operating wells and installing facilities and pipelines is often uncertain and have each increased substantially. The market for oil field services is currently very competitive and shortages or delays in delivery or availability of equipment or fabrication yards could impact the Company’s ability to conduct oil and gas drilling and completion operations.

Results of Operations

Oil and Gas Revenues

The Company’s oil and gas revenues for the third quarter of 2007 were $200.3 million, a decrease of approximately 12.2% from oil and gas revenues of $228.0 million for the third quarter of 2006. The Company’s oil and gas revenues for the first nine months of 2007 were $631.2 million, a decrease of approximately 10.9% from oil and gas revenues of $708.0 million from the first nine months of 2006. The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in millions) between 2007 and 2006:

	3rd Qtr. 2007			1st 9 Mos. 2007
	Compared to			Compared to
	3rd Qtr. 2006			1st 9 Mos. 2006

Increase (decrease) in oil and gas revenues resulting from variances in:
Natural gas -
Price	$	(6.3	)	$	(9.2	)
Production	(3.3		)	(0.8		)
	(9.6		)	(10.0		)
Crude oil and condensate -
Price	6.4			(7.6		)
Production	(21.6		)	(57.4		)
	(15.2		)	(65.0		)

Natural gas liquids
Price	(0.5		)	2.1
Production	(2.5		)	(3.9		)
	(3.0		)	(1.8		)

Decrease in oil and gas revenues	$	(27.8	)	$	(76.8	)

The most significant cause for the decrease in natural gas production for the three months ended September 30, 2007 compared to the same period in 2006 was the sale of the Company’s remaining interests in the Gulf of Mexico on June 8, 2007, which decreased natural gas revenues by approximately $3.8 million, and a decrease in natural gas production due to the Onshore sales, which decreased natural gas revenues by approximately $4.9 million; these decreases were only partially offset by an increase in production in the Company’s Los Mogotes field, which increased natural gas revenues by approximately $4.2 million. Natural gas production decreased during the nine months ended September 30, 2007 compared to the same period in 2006, primarily due to the sale of the Company’s remaining interests in the Gulf of Mexico, which decreased natural gas revenues by approximately $31.8 million, and a decrease in natural gas production due to the Onshore sales, which decreased natural gas revenues by approximately $18.4 million; these decreases were offset by production from the acquisition of Latigo on May 2, 2006, which increased natural gas revenues by approximately $25.4 million, in addition to an increase in natural gas production in the Company’s Los Mogotes and New Mexico areas, which added natural gas revenues of approximately $25.9 million.

The most significant cause for the decrease in oil and condensate production for the three months ended September 30, 2007 compared to the same period in 2006 was also the sale of the Company’s interests in the Gulf of Mexico, which decreased oil and condensate revenues by approximately $31.2 million which was only partially offset by an increase in oil and condensate production in the Company’s Western and Gulf Coast regions, which increased oil and condensate revenues by approximately $10.7 million. Oil and condensate production for the nine months ended September 30, 2007 decreased due to the sale of the Company’s interests in the Gulf of Mexico, which decreased oil and condensate revenues by approximately $91.7 million, which was only partially offset by the acquisition of Latigo, which increased oil and condensate revenues by approximately $31.8 million. The following tables reflect the relative changes in hydrocarbon volumes and prices:

					% Change						% Change
Comparison of Increases (Decreases) in:	3rd Quarter				2006 to		1st Nine Months				2006 to
Natural Gas —	2007		2006		2007		2007		2006		2007

Average prices (per Mcf) (a)	$	5.46	$	5.81	(6	)%	$	6.12	$	6.29	(3	)%

Average daily production volumes (MMcf per day) (a):	191.3		197.7		(3	)%	198.8		199.2		—

a) Price hedging activity increased the average price of the Company’s natural gas production during the third quarter and first nine months of 2007 by $0.22 and $0.11 per Mcf, respectively. Price hedging activity increased the average price of the Company’s natural gas production during the third quarter of 2006 by $0.04 per Mcf and reduced the average price of the Company’s natural gas production during the first nine months of 2006 by $0.05 per Mcf. “Mcf” and “MMcf” are abbreviations for thousand cubic feet and million cubic feet, respectively.

					% Change						% Change
Comparison of Increases (Decreases) in:	3rd Quarter				2006 to		1st Nine Months				2006 to
Crude Oil and Condensate —	2007		2006		2007		2007		2006		2007

Average prices (per Bbl) (a)	$	72.54	$	68.31	6	%	$	62.67	$	64.21	(2	)%

Average daily production volumes (Bbls per day) (a):	13,290		16,535		(20	)%	14,767		18,125		(19	)%

Natural Gas Liquids —

Average prices (per Bbl) (a)	$	43.67	$	44.88	(3	)%	$	40.57	$	38.85	4	%

Average daily production volumes (Bbls per day) (a):	3,875		4,491		(14	)%	4,192		4,542		(8	)%

Total Liquid Hydrocarbons —
Company-wide average daily production (Bbls per day)	17,165		21,026		(18	)%	18,959		22,667		(16	)%

(a) During the third quarter of 2007, price hedging activity had no effect on the average price of the Company’s crude oil and condensate production; during the first nine months of 2007 it increased the average price by $0.11 per barrel. Price hedging activity had no effect on the average price of the Company’s crude oil and condensate production during the third quarter and first nine months of 2006. “Bbls” is an abbreviation for barrels.

Other Income

Other income is derived from sources other than the current production of hydrocarbons. The most significant item affecting Other Income was a gain of $2.2 million from the assignment of an accounts receivable (which had been fully reserved) to a third party that was recognized in the first half of 2007. The most significant item recognized during the nine months ended September 30, 2006 was a gain of $3.3 million related to hedge ineffectiveness.

Costs and Expenses

							% Change								% Change
	3rd Quarter						2006 to		1st Nine Months						2006 to
Comparison of Increases (Decreases) in:	2007			2006			2007		2007			2006			2007
	(Expressed in millions, except DD&A statistics)

Lease Operating Expenses	$	38.0		$	45.8		(17	)%	$	134.6		$	132.2		2	%
General and Administrative Expenses	$	27.4		$	31.9		(14	)%	$	84.3		$	73.3		15	%
Exploration Expenses	$	5.6		$	3.1		81	%	$	19.6		$	4.8		308	%
Dry Hole and Impairment Expenses	$	7.7		$	32.4		(76	)%	$	59.4		$	68.3		(13	)%
Depreciation, Depletion and Amortization (DD&A) Expenses	$	79.5		$	72.0		10	%	$	243.4		$	199.3		22	%
DD&A rate	$	2.88		$	2.36		22	%	$	2.80		$	2.13		32	%
MMcfe produced	27,074			29,798			(9	)%	85,318			91,522			(7	)%
Production and Other Taxes	$	14.0		$	19.6		(29	)%	$	46.9		$	47.6		(1	)%
Net Loss (Gain) on Sales of Properties	$	(2.4	)	$	3.1		(177	)%	$	(131.9	)	$	(305.3	)	(57	)%
Other	$	16.7		$	(2.6	)	N/M		$	29.8		$	8.0		273	%
Interest—
Charges	$	(31.4	)	$	(41.3	)	(24	)%	$	(115.2	)	$	(105.6	)	9	%
Interest Income	$	10.3		$	—		N/A		$	10.4		$	0.3		N/M
Capitalized Interest	$	13.5		$	21.6		(38	)%	$	53.5		$	56.4		(5	)%
Loss on Debt Extinguishment	$	(6.9	)	$	—		N/A		$	(6.9	)	$	—		N/A
Commodity Derivative Income (Expense)	$	(1.7	)	$	10.6		(116	)%	$	(6.3	)	$	6.8		(193	)%
Income Tax Benefit (Expense)	$	1.3		$	(6.7	)	(119	)%	$	(22.9	)	$	(49.5	)	(54	)%

Lease Operating Expenses

The decrease in lease operating expenses for the three months ended September 30, 2007 compared to the same period in 2006 is primarily related to the absence of hurricane-related workover activity in the third quarter of 2007 due to the sale of the Company’s Gulf of Mexico interests in the second quarter of 2007, which decreased lease operating expenses by approximately $6.4 million. The increase in lease operating expenses for the nine months ended September 30, 2007 compared to the same period in 2006 is due to the Latigo acquisition, which contributed approximately $14.3 million of additional lease operating expenses, and miscellaneous increases of approximately $3.7 million; these increases were partially offset by a decrease in hurricane-related workover activity of $16.7 million.

On a per unit of production basis, the Company’s total lease operating expenses decreased from an average of $1.54 per Mcfe for the third quarter of 2006 to $1.40 per Mcfe for the third quarter of 2007. For the nine months ended September 30, 2007, the Company’s total lease operating expenses on a per unit of production basis increased to $1.58 per Mcfe, compared to $1.44 per Mcfe for the first nine months of 2006. These variances in unit costs are primarily related to the variances in lease operating expenses discussed above, compounded by the production decreases discussed in “Oil and Gas Revenues.”

General and Administrative Expenses

The decrease in general and administrative expenses for the third quarter of 2007, compared with the same period in 2006, is primarily related to a decrease in employee benefits of approximately $7.0 million, which was partially offset by an increase in retention expenses of $1.8 million and additional legal fees of approximately $0.6 million related to the Company’s previously announced strategic alternatives process. The increase in general and administrative expenses for the nine months ended September 30, 2007, compared to the same period in 2006, is primarily related to an increase in retention expenses of $6.5 million, an increase of approximately $2.0 million related to increased activity in the Company’s offices in New Zealand and Vietnam; and increased legal expenses associated with the strategic alternatives process of approximately $1.8 million.

On a per unit of production basis, the Company’s general and administrative expenses decreased to $1.01 per Mcfe in the third quarter of 2007, down from $1.07 per Mcfe in the third quarter of 2006. For the nine months ended September 30, 2007, the Company’s general and administrative expenses on a per unit of production basis increased to $0.99 per Mcfe, compared to $0.80 per Mcfe for the first nine months of 2006. These variances in unit costs are primarily related to the variances in general and administrative expenses discussed above, compounded by the production decreases discussed in “Oil and Gas Revenues.”

Exploration Expenses

Exploration expenses consist primarily of rental payments required under oil and gas leases to hold non-producing properties (“delay rentals”) and exploratory geological and geophysical costs that are expensed as incurred. Exploration expenses for the third quarter of 2007 increased from the third quarter of 2006 due to additional seismic expenditures of $2.3 million in 2007 in the Company’s Permian/San Juan region. For the nine months ended September 30, 2007, exploration expenses increased over the same period of 2006 due to the New Zealand seismic license sale, which decreased 2006 expenses by $4.3 million, and additional seismic expenditures in 2007 of $8.4 million, $4.8 million and $3.0 million in the Company’s Asia/Pacific, Gulf Coast and Permian/San Juan regions, respectively.

Dry Hole and Impairment Expenses

Dry hole and impairment expenses relate to costs of unsuccessful exploratory wells drilled and impairment of oil and gas properties. The decrease in dry hole and impairment expense for the third quarter of 2007, compared to the third quarter of 2006, was the result of decreased impairments discussed below, and a decrease in exploratory dry hole costs incurred from approximately $19.2 million during the third quarter of 2006 to approximately $5.1 million in the third quarter of 2007. Dry hole and impairment expenses decreased during the first nine months of 2007 from the same period in 2006 primarily due to a decrease in exploratory dry hole costs incurred from approximately $44.7 million to $16.8 million, which were only partially offset by an increase in impairments (see below). The Company had approximately $1.2 million of costs attributable to exploratory wells in progress as of September 30, 2007 that, as of October 26, 2007 were either still in progress or pending evaluation.

Generally accepted accounting principles (“GAAP”) require that if the expected future cash flow of the Company’s reserves on a property fall below the cost that is recorded on the Company’s books, the property must be impaired and written down to its fair value. Depending on market conditions, including the prices for oil and natural gas, the Company’s results of operations, or a pending sale, a similar test may be conducted at any time to determine whether impairments are appropriate. Depending on the results of this test, impairments could be required on some of the Company’s properties, and such impairments could have a material negative non-cash impact on the Company’s earnings and balance sheet. During the third quarter of 2007 and 2006, the Company recognized impairments on various prospects and leases in the amount of $2.6 million and $13.2 million, respectively. During the nine months ended September 30, 2007 and 2006, the Company recognized impairments on various prospects and leases in the amount of $42.6 million and $23.7 million, respectively. Of the 2007 amount, $34.4 million is related to the properties in the Company’s Gulf Coast area that were sold, which were required to be measured at the lower of their carrying amount or fair value less cost to sell at the time they were classified as held for sale.

Depreciation, Depletion and Amortization Expenses

The Company’s provision for DD&A expense is based on its capitalized costs and is determined on a cost center by cost center basis using the units of production method. Generally, the Company establishes cost centers on the basis of a reasonable aggregation of properties with a common geologic structural feature or stratigraphic condition for its onshore oil and gas activities. The Company generally creates cost centers on a field-by-field basis for oil and gas activities in offshore areas. The increase in the Company’s DD&A expenses for the three and nine months ended September 30, 2007 resulted primarily from an increase in the Company’s composite DD&A rate, which was only partially offset by decreased hydrocarbon production.

The increase in the composite DD&A rate for all of the Company’s producing fields for the three and nine months ended September 30, 2007, compared to the 2006 periods, resulted primarily from a decrease in the percentage of the Company’s production coming from fields that have DD&A rates that are lower than the Company’s recent historical composite DD&A rate (principally offshore fields and legacy onshore fields) and a corresponding increase in the percentage of the Company’s production coming from fields that have DD&A rates that are higher than the Company’s recent historical composite rate (principally production from the Latigo acquisition). The Company currently expects its average DD&A rate to increase from the 2006 rate over the remainder of 2007, as the effects of the higher rate per Mcf Latigo properties and the sale of the lower rate per Mcf Gulf of Mexico properties have a greater impact on the Company’s overall production profile.

Production and Other Taxes

The decrease in production and other taxes during the third quarter of 2007, compared to the third quarter of 2006, relates primarily a decrease in Texas franchise tax obligations of $3.2 million and a decrease in production taxes of approximately $4.0 million due to property sales, which was partially offset by an increase in ad valorem taxes of $1.6 million due to increasing property valuations. Production taxes for the nine months ended September 30, 2007 decreased from the same period in 2006 due primarily to a reduction in Texas franchise tax obligations of approximately $6.7 million, which was partially offset by an increase in ad valorem taxes of $6.1 million due to increasing property valuations.

Net Loss (Gain) on Sales of Properties

During the three months ended September 30, 2007, the Company recognized gains on the sale of properties of $2.4 million, which consisted primarily of a $3.9 million gain on the sale of Main Pass 76, which was partially offset by post-closing adjustments related to previous property sales. During the nine months ended September 30, 2007 the Company recognized gains on the sale of properties of $131.9 million, which consisted primarily of the gain of approximately $3.9 million on Main Pass 76, a gain of approximately $224.8 on the Gulf of Mexico sale and losses of approximately $8.8 million on the South Texas, Texas Gulf Coast and Louisiana Gulf Coast sales and

approximately $89.7 million on the Texas Panhandle sale. During the three and nine months ended September 30, 2006, the Company recognized a loss on the sale of properties of $3.1 million and a gain on the sale of properties of $305.3 million, respectively; the gain was primarily related to the sale of 50% of the Company’s working interest in its Gulf of Mexico properties.

Other

Other expense includes the Company’s cost to move its products to market (transportation costs), accretion expense related to Company asset retirement obligations under generally accepted accounting principles, recognition of recoveries from business interruption insurance, the write-off of uncollectible receivables, and various other operating expenses. The following table shows the significant items included in “Other” (income)/expense (expressed in millions):

	For the Quarter Ended September 30,						For the Nine Months Ended September 30,
	2007			2006			2007			2006
Transportation costs	$	3.5		$	2.6		10.5			$	9.4
Business interruption insurance	—			(5.5		)	(4.2		)	(9.2		)
Accretion expense	2.6			1.5			6.8			5.1
Advisory fee	5.0			—			5.0			—
Hedge ineffectiveness	(1.3		)	(1.5		)	1.9			—
Hurricane repair costs	0.8			—			2.0			—
Bad debts & allowance for doubtful accounts	3.5			—			3.5			0.7
Other	2.6			0.3			4.3			2.0
Total	$	16.7		$	(2.6	)	$	29.8		$	8.0

The Company recognized a $3.5 million valuation allowance for doubtful accounts in the third quarter of 2007 as a result of progress made in an accounts receivable collection project. This project was instituted to determine the Company’s ability to collect past due joint interest billing accounts receivable.

Interest

Interest Charges. The decrease in the Company’s interest charges for the third quarter of 2007, compared to the third quarter of 2006, resulted primarily from a decrease the average amount of outstanding debt from $2.1 billion to $1.6 billion. The increase in interest charges for the nine months ended September 30, 2007, compared to the same period in 2006, was due to an increase in the average amount of outstanding debt from $1.8 billion to $2.0 billion. See “Liquidity and Capital Resources” below.

Interest Income. The increase in the Company’s interest income for the three and nine months ended September 30, 2007 compared to the same periods in 2006, resulted from an increase in the amount of cash temporarily invested due to the receipt of proceeds from the sale of Northrock.

Capitalized Interest. Interest costs related to financing major oil and gas projects in progress are capitalized until the projects are substantially complete and ready for their intended use if projects are evaluated as successful. These include Northrock properties, which have been classified as discontinued operations. The decrease in capitalized interest for the third quarter of 2007, compared to the same period in 2006, was primarily due to a decrease in the weighted average dollar amount of oil and gas projects in progress subject to interest capitalization from $1.3 billion to $722.4 million. For the nine months ended September 30, 2007, capitalized interest decreased compared to the same period in 2006 primarily due to a decrease in the weighted average dollar amount of oil and gas projects in progress subject to interest capitalization, which went from $1.1 billion to $974 million.

The Company changed the classification of interest capitalized in the Statement of Cash Flows from an operating cash outflow to an investing cash outflow in the fourth quarter of 2006. The Company elected not to change the classification of interest capitalized in the Statement of Cash Flows for periods prior to the fourth quarter of 2006 due to the immateriality of the amounts.

Commodity Derivative Expense

Commodity derivative expense for the three month and nine month periods ended September 30, 2006 and 2007, respectively, represents both realized and unrealized gains and losses on derivative contracts that no longer qualify for hedge accounting treatment. The Company’s Gulf of Mexico sales, along with the shut-in forecasted hydrocarbon production from the Company’s Gulf of Mexico properties prior to the sales (resulting primarily from hurricane activity during the third quarter of 2005) caused certain of the gas and crude oil collar contracts to lose their qualification for hedge accounting under SFAS 133.

Loss on Debt Extinguishment

On September 20, 2007 the Company completed the redemption of all $200 million of its outstanding 8.25% Senior Subordinated Notes due 2011 (the “Notes”). The Notes were redeemed for approximately $212.6 million, which included a premium of $5.5 million plus accrued interest to September 19, 2007 of $7.1 million. The cash redemption payment was funded using available cash on hand. The Company recorded a pre-tax expense on the redemption of $6.9 million (including the write-off of $1.4 million of unamortized debt issuance costs) which is reflected as “Loss on Debt Extinguishment” in the Company’s financial statements.

Income Tax Expense

Changes in the Company’s income tax expense are a function of the Company’s consolidated effective tax rate, the Company’s pre-tax income (loss) and the jurisdiction in which the income (loss) is generated. The decrease in the Company’s income tax expense for the third quarter of 2007, compared to the third quarter of 2006, primarily resulted from lower pre-tax book income in the third quarter of 2007 versus 2006. In 2006, the Canadian federal rate was reduced from approximately 26% to 19% (phased in through 2010). In 2007 the tax rate in 2011 was further reduced from 19% to 18.5%. The Canadian tax rate reductions are reflected in the Company’s continuing operations as required by GAAP, although all other Northrock related tax effects have been included in discontinued operations. The Company’s consolidated effective tax rate was 81.3% for the third quarter of 2007, compared to 37.6% expense for the third quarter of 2006. The exceptionally high effective tax rate for the third quarter of 2007 is the result of the Company’s low level of pre-tax earnings in the period.

Loss from Discontinued Operations

The increase in the Company’s loss from discontinued operations for the three and nine months ended September 30, 2007 compared to the same period in 2006, was primarily due to the decision to sell Northrock in 2007, including an associated impairment on the ultimate loss on sale. The summarized financial results of the discontinued operations for the periods presented are as follows:

Operating Results Data

	Three months ended September 30,						Nine months ended September 30,
	2007			2006			2007			2006

Revenues	$	66.3		$	124.7		$	345.5		$	383.3
Costs and expenses	(42.5		)	(102.8		)	(279.8		)	(300.9		)
Other income (expense)	0.5			0.3			9.0			2.0
Income (loss) before income taxes	24.3			22.2			74.7			84.4
Income tax benefit (expense)	12.8			0.1			18.6			(15.2		)
Income (loss) before loss from discontinued operations, net of tax	37.1			22.3			93.3			69.2
Loss on sale of Northrock, including tax expense (1)	(82.7		)	—			(267.2		)	—
Income(loss) from discontinued operations, net of tax	$	(45.6	)	$	22.3		$	(173.9	)	$	69.2

(1) Loss on sale of Northrock includes $7 million and $30 million of U.S tax on previously unremitted Canadian earnings for the three and nine months ended September 30, 2007, respectively.

Liquidity and Capital Resources

The Company’s primary needs for cash are for exploration, development, acquisition and production of oil and gas properties, repayment of principal and interest on outstanding debt and payment of income taxes. The Company funds its exploration and development activities primarily through internally generated cash flows and debt financing, and budgets capital expenditures based on projected cash flows. The Company adjusts capital expenditures in response to changes in oil and natural gas prices, drilling and acquisition results, and cash flow. The Company has historically utilized net cash provided by operating activities, available cash, debt, and equity as capital resources to obtain necessary funding for all other cash needs. The following discussion includes cash flows from both continuing and discontinued operations.

The Company’s cash flow provided by operating activities for the nine months ended September 30, 2007 was $502.7 million, compared to cash flow provided by operating activities of $462.3 million for the nine months ended September 30, 2006. Operating cash flows for the nine months ended September 30, 2007 included a tax refund of $52 million for the overpayment of estimated taxes in the third quarter of 2006, and tax payments of $62.7 million primarily resulting from taxes due in conjunction with the Company’s recent property sales. Investing activities used cash flows of $960.1 million during the first nine months of 2006, primarily due to the Latigo acquisition, but generated cash flows of $1.9 billion during the first nine months of 2007 due to an excess of funds provided by the Gulf of Mexico and Northrock sales over capital expenditures. Cash flow from operating activities were used during the first nine months of 2007

to fund $644.9 million in cash expenditures (excluding capitalized interest) for capital and exploration projects and property acquisitions in the United States and Canada. During the nine months ended September 30, 2007, the Company repaid senior debt obligations of approximately $872.0 million (net of borrowings) using available cash on hand. The Company also redeemed the 8.25% 2011 Notes for $200 million. In addition, the Company paid $13.2 million of common stock dividends. As of September 30, 2007, the Company had cash and cash equivalents of approximately $1.3 billion and long-term debt obligations of $1.25 billion (excluding debt discount) with no repayment obligations until 2013. The Company may determine to repurchase outstanding debt in the future, including in market transactions, privately negotiated transactions or otherwise, depending on market conditions, liquidity requirements, contractual restrictions and other factors.

Effective July 12, 2007, the Company’s lenders redetermined the borrowing base under its bank credit facility at $1.3 billion. As of October 26, 2007, the Company had no borrowings and a $1.0 billion borrowing capacity under the facility. As such, the available borrowing capacity under the facility was $1.0 billion.

LIBOR Rate Advances

Under separate Promissory Note Agreements with various lenders, LIBOR rate advances are made available to the Company on an uncommitted basis up to $100 million. Advances drawn under these agreements are reflected as long-term debt on the Company’s balance sheet because the Company currently has the ability and intent to refinance such amounts through borrowings under its bank credit facility, which is due in December 2009. The Company’s 2013 Notes, 2015 Notes and 2017 Notes may restrict all or a portion of the amounts that may be borrowed under the Promissory Note Agreements. The Promissory Note Agreements permit either party to terminate the letter agreements at any time upon three business days notice. As of October 26, 2007, there were no advances outstanding under these agreements.

Tender Offers and Consent Solicitations for Senior Subordinated Notes

Consummation of the tender offers or the consent solicitations is not a condition to the closing of the Company’s pending merger with PXP.

Future Capital and Other Expenditure Requirements

The Company’s capital and exploration budget, which does not include any amounts that may be expended for acquisitions or any interest which may be capitalized resulting from projects in progress, was set at $720 million for 2007 ($470 million for continuing operations), of which approximately $463.6 million was spent in the United States and Canada during the nine months ended September 30, 2007. The Company’s capital expenditures for the remainder of the year may vary from the capital budget if the merger with PXP is consummated.

The Company currently anticipates that its available cash, cash provided by operating activities and property sales, and funds available under its bank credit facility will be sufficient to fund the Company’s ongoing operating, interest and general and administrative expenses and capital expenditures. The declaration and amount of future dividends on the Company’s common stock will depend upon, among other things, the Company’s future earnings and financial condition, liquidity and capital requirements, consummation of the merger with PXP, its ability to pay dividends and other payments under covenants contained in its debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company’s Board of Directors.

Insurance Recoveries

Recent Accounting Pronouncements

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” which is effective for fiscal years beginning after November 15, 2007 and for interim periods within those years. This statement defines fair value, establishes a framework for measuring fair value and expands the related disclosure requirements. The Company is currently evaluating the impact, if any, that the adoption of SFAS 157 will have on its financial statements.

On February 15, 2007, the Financial Accounting Standards Board (“FASB”) issued Statement No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities – Including an amendment of FASB Statement No. 115 (“SFAS 159”).” The Statement permits entities to choose to measure eligible financial instruments and certain other items at fair market value, with the objective of improving financial reporting by giving entities the opportunity to mitigate volatility in reported earnings caused by measuring related assets and liabilities differently without having to apply complex hedge accounting provisions. The Statement is effective for fiscal years beginning after November 15, 2007. The adoption of SFAS 159 is not expected to have a material impact, if any, on the Company’s financial statements.

ITEM 3. Quantitative and Qualitative Disclosures about Market Risk.

The Company is exposed to market risk, including adverse changes in commodity prices, interest rates and foreign currency exchange rates as discussed below.

Commodity Price Risk

The Company produces and sells natural gas, crude oil, condensate and NGLs. As a result, the Company’s financial results can be significantly affected as these commodity prices fluctuate widely in response to changing market forces. The Company makes use of a variety of derivative financial instruments only for non-trading purposes as a hedging strategy to manage commodity prices associated with oil and gas sales and to reduce the impact of commodity price fluctuations.

Current Hedging Activity

As of September 30, 2007 the Company held various derivative instruments. The Company has entered into natural gas and crude oil option agreements referred to as “collars”. Collars are designed to establish floor and ceiling prices on anticipated future natural gas and crude oil production. These contracts are designed to achieve a more predictable cash flow, as well as to reduce exposure to price volatility. While the use of these derivative instruments limits the downside risk of adverse price movements, they may also limit future revenues from favorable price movements. The use of derivatives also involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. Currently, the Company does not expect losses due to creditworthiness of its counterparties.

The gas derivative transactions are generally settled based upon the average of the reporting settlement prices on the NYMEX for the last three trading days of a particular contract month. The oil derivative transactions are generally settled based on the average of the reported settlement prices for West Texas Intermediate on the NYMEX for each trading day of a particular calendar month. For any particular collar transaction, the counterparty is required to make a payment to the Company if the settlement price for any settlement period is below the floor price for such transaction, and the Company is required to make a payment to the counterparty if the settlement price for any settlement period is above the ceiling price of such transaction.

Contract Period and		NYMEX Contract Price				Fair Value of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)
						(in millions)
Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
October 2007 - December 2007	1,380	$	6.00	$	12.00	$	0.1
October 2007 - December 2007	460	$	6.00	$	12.15	$	—
October 2007 - December 2007	2,300	$	6.00	$	12.50	$	0.1
October 2007 - December 2007	230	$	8.00	$	13.40	$	0.3
October 2007 - December 2007	690	$	8.00	$	13.50	$	0.8
October 2007 - December 2007	230	$	8.00	$	13.52	$	0.3
October 2007 - December 2007	230	$	8.00	$	13.65	$	0.3
January 2008 - December 2008	1,830	$	8.00	$	12.05	$	1.6
January 2008 - December 2008	2,745	$	8.00	$	12.10	$	2.4
January 2008 - December 2008	915	$	8.00	$	12.25	$	0.8

Crude Oil Contracts (Barrels)
Collar Contracts:
October 2007 - December 2007	138,000	$	50.00	$	77.50	$	(0.7	)
October 2007 - December 2007	46,000	$	60.00	$	82.75	$	(0.1	)
January 2008 - December 2008	183,000	$	60.00	$	80.00	$	(0.7	)
January 2008 - December 2008	183,000	$	60.00	$	80.05	$	(0.7	)
January 2008 - December 2008	183,000	$	60.00	$	80.10	$	(0.6	)
January 2008 - December 2008	366,000	$	60.00	$	80.25	$	(1.3	)

(a) MMBtu means million British Thermal Units

Although the Company’s collars are effective as economic hedges, the Gulf of Mexico sales, along with the shut-in forecasted hydrocarbon production from the Company’s Gulf of Mexico properties prior to the sales (resulting primarily from hurricane activity during the third quarter of 2005) caused certain of the gas and crude oil collar contracts to lose their qualification for hedge accounting under SFAS 133. The Company now recognizes changes in the fair value of these contracts in the consolidated statement of income for the period in which the change occurs under the caption “Commodity derivative income (expense).” As of September 30, 2007, the Company had the following open collar contracts that no longer qualify for hedge accounting:

Contract Period and		NYMEX Contract Price				Fair Value of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)
						(in millions)
Natural Gas Contracts (MMBtu)
Collar Contracts:
October 2007 - December 2007	1,840	$	6.00	$	12.15	$	0.1
October 2007 - December 2007	920	$	6.00	$	12.20	$	—


Crude Oil Contracts (Barrels)
Collar Contracts:
October 2007 - December 2007	368,000	$	50.00	$	77.50	$	(1.8	)
October 2007 - December 2007	138,000	$	60.00	$	83.00	$	(0.3	)
October 2007 - December 2007	46,000	$	60.00	$	84.00	$	(0.1	)

Interest Rate Risk

From time to time, the Company has entered into various financial instruments, such as interest rate swaps, to manage the impact of changes in interest rates. As of October 26, 2007, the Company has no open interest rate swap or interest rate lock agreements. Therefore, the Company’s exposure to changes in interest rates primarily results from its short-term and long-term debt with both fixed and floating interest rates. The following table presents principal or notional amounts (stated in millions) and related average interest rates by year of maturity for the Company’s debt obligations and their indicated fair market value at September 30, 2007:

	2007		2008		2009		2010		2011		Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate	$	0.0	$	0.0	$	0.0	$	0.0	$	0.0	$	0.0		$	0.0		$	0.0
Average Interest Rate	—		—		—		—		—		—			—			—
Fixed Rate	$	0.0	$	0.0	$	0.0	$	0.0	$	0.0	$	1,250.0		$	1,250.0		$	1,269.0
Average Interest Rate	—		—		—		—		—		7.18		%	7.18		%	—

Foreign Currency Exchange Rate Risk

The Company does not actively manage foreign currency risk in its foreign subsidiaries since the U.S. dollar is the functional currency. Exposure from market rate fluctuations related to activities in New Zealand and Vietnam is not material at this time. As of October 26, 2007, the Company had no foreign currency financial derivatives.

ITEM 4. Controls and Procedures.

The Company has established disclosure controls and procedures to ensure that material information relating to the Company, including its consolidated subsidiaries, is made known to the officers who certify the Company’s financial reports and to other members of senior management and the Board of Directors.

Based on their evaluation as of the end of the period covered by this quarterly report, the Company’s Chairman, President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer have concluded that the Company’s disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) are effective to ensure that the information required to be disclosed by the Company in the reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in SEC rules and forms.

There were no changes in the Company’s internal control over financial reporting that occurred during the most recent fiscal quarter that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

ITEM 1A. Risk Factors.

In addition to the other information set forth in this report, you should carefully consider the factors discussed in Part I, “Item 1A. Risk Factors” in the Company’s Annual Report on Form 10-K for the year ended December 31, 2006 and Part II, “Item 1A. Risk Factors” in the Company’s Quarterly Report for Form 10-Q for the quarter ended June 30, 2007.

ITEM 6. Exhibits

*2.1	Agreement and Plan of Merger, Dated July 17, 2007, by and among Plains Exploration & Production Company, PXP Acquisition LLC and Pogo Producing Company (a copy of any omitted schedule will be furnished supplementally to the SEC upon request)(Exhibit 2.1, Current Report on Form 8-K filed on July 20, 2007).

*3.1	Restated Certificate of Incorporation of Pogo Producing Company, as filed on April 28, 2004 (Exhibit 3.1, Quarterly Report on Form 10-Q for the quarter ended March 31, 2004, File No. 1-7796).

*3.2	Bylaws of Pogo Producing Company, as amended and restated through July 16, 2002 (Exhibit 4.1, Quarterly Report on Form 10-Q for the quarter ended June 30, 2002, File No. 1-7792).

*4.1	Amendment to Rights Agreement between Pogo Producing Company and Conputershare Trust Company, N.N., dated as of July 17, 2007 (Exhibit 4.1, Current Report on Form 8-K filed on July 20, 2007).

*10.1	Termination Agreement, dated July 17, 2007, by and among Pogo Producing Company, Third Point LLC, Mr. Daniel S. Loeb, Mr. Bradley L. Radoff, Third Point Offshore Fund, Ltd., Third Point Ultra Ltd., Third Point Partners LP, Third Point Partners Qualified LP, and Lyxor/Third Point Fund Limited (Exhibit 10.1, Current Report on Form 8-K filed on July 20, 2007).

10.2	Second Amendment to Credit Agreement, dated as of May 17, 2006.

10.3	Form of Amendment to Restricted Stock Award Agreement under Incentive Plans

31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Executive Officer.

32.2	Certification pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, by Chief Financial Officer.

* Asterisk indicates an exhibit incorporated by reference as shown.

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 thereunto duly authorized.

	Pogo Producing Company
	(Registrant)


	/s/	James P. Ulm, II
		James P. Ulm, II
		Senior Vice President and Chief
		Financial Officer


	/s/	Robert C. Marlowe
		Robert C. Marlowe
		Vice President - Accounting


Date: October 31, 2007