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 March 31, 2007

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		77046-0504
Houston, Texas		(Zip Code)
(Address of principal executive offices)

(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: 58,492,797 shares as of April 25, 2007

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statements of Income (Unaudited)

	Three Months Ended
	March 31,
	2007			2006


Revenue and Other Income
Oil and gas	$	321.2		$	354.4
Other	30.2			19.1
Total	351.4			373.5

Operating Costs and Expenses:
Lease operating	67.5			57.1
General and administrative	34.7			28.7
Exploration	9.6			2.7
Dry hole and impairment	71.8			25.6
Depreciation, depletion and amortization	133.9			110.1
Production and other taxes	20.0			13.5
Natural gas purchases	24.8			17.9
Other	7.5			7.6
Total	369.8			263.2

Operating Income	(18.4		)	110.3
Interest:
Charges	(43.0		)	(28.3		)
Income	0.4			0.5
Capitalized	19.4			16.2
Commodity Derivative Income (Expense)	(3.1		)	3.3
Foreign Currency Transaction Gain (Loss)	0.9			(0.2		)

Income (Loss) Before Taxes	(43.8		)	101.8
Income Tax Benefit (Expense)	22.6			(34.3		)

Net Income (Loss)	$	(21.2	)	$	67.5

Earnings (Loss) per Common Share:
Basic	$	(0.37	)	$	1.18
Diluted	$	(0.37	)	$	1.16

Dividends per Common Share	$	0.075		$	0.075

Potential Common Shares Outstanding:
Basic	57,701			57,334
Diluted	57,701			57,953

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Balance Sheets (Unaudited)

	March 31,			December 31,
	2007			2006
	(Expressed in millions)
Assets
Current Assets:
Cash and cash equivalents	$	17.1		$	22.7
Accounts receivable	161.3			175.8
Other receivables	43.1			47.6
Federal income tax receivable	1.6			55.8
Inventories - product	11.7			15.5
Inventories - tubulars	27.6			27.7
Commodity derivative contracts	—			10.9
Other	8.4			12.2
Total current assets	270.8			368.2

Property and Equipment:

Oil and gas, on the basis of successful efforts accounting
Proved properties	7,383.0			7,369.0
Unevaluated properties	1,041.1			1,033.2
Other, at cost	54.1			50.7
	8,478.2			8,452.9
Accumulated depreciation, depletion and amortization
Oil and gas	(1,902.0		)	(1,863.1		)
Other	(34.8		)	(32.7		)
	(1,936.8		)	(1,895.8		)
Property and equipment, net	6,541.4			6,557.1

Other Assets:
Commodity derivative contracts	2.1			5.0
Other	41.2			40.8
Assets held for sale	90.7			—
	134.0			45.8

	$	6,946.2		$	6,971.1

See accompanying notes to consolidated financial statements.

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

Current Liabilities:
Accounts payable - operating activities	$	185.9		$	181.2
Accounts payable - investing activities	150.0			159.1
Income taxes payable	30.1			0.8
Accrued interest payable	42.3			26.0
Accrued payroll and related benefits	7.7			5.1
Commodity derivative contracts	7.8			—
Deferred income tax	2.4			7.2
Other	21.8			22.4
Total current liabilities	448.0			401.8

Long-Term Debt	2,308.7			2,319.7

Deferred Income Tax	1,420.4			1,478.0

Asset Retirement Obligation	158.8			156.3

Other Liabilities and Deferred Credits	52.0			47.9

Total liabilities	4,387.9			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, 65,841,656 and 65,794,206 shares issued, respectively	65.8			65.8
Additional capital	977.6			971.4
Retained earnings	1,867.4			1,892.9
Accumulated other comprehensive income (loss)	8.8			(1.4		)
Treasury stock (7,365,359 shares, at cost)	(361.3		)	(361.3		)
Total shareholders’ equity	2,558.3			2,567.4

	$	6,946.2		$	6,971.1

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended
	March 31,
	2007			2006
	(Expressed in millions)
Cash Flows from Operating Activities:
Cash received from customers	$	363.2		$	371.0
Operating, exploration, and general and administrative expenses paid	(164.5		)	(105.5		)
Interest paid	(6.4		)	(20.4		)
Income taxes paid	(9.2		)	(3.2		)
Income tax refund	52.0			1.6
Other	12.8			(3.1		)
Net cash provided by operating activities	247.9			240.4

Cash Flows from Investing Activities:
Capital expenditures	(258.3		)	(176.1		)
Purchase of corporations and property	(14.4		)	(23.4		)
Sale of properties	14.4			—
Insurance proceeds	18.6			2.5
Other	—			(1.1		)
Net cash used in investing activities	(239.7		)	(198.1		)

Cash Flows from Financing Activities:
Borrowings under senior debt agreements	332.0			183.0
Payments under senior debt agreements	(343.0		)	(249.0		)
Purchase of Company stock	—			(7.7		)
Payments of cash dividends on common stock	(4.3		)	(4.3		)
Payment of debt issue costs	—			(0.1		)
Proceeds from exercise of stock awards	2.0			1.6
Net cash used in financing activities	(13.3		)	(76.5		)
Effect of exchange rate changes on cash	(0.5		)	0.2
Net decrease in cash and cash equivalents	(5.6		)	(34.0		)
Cash and cash equivalents at the beginning of the period	22.7			57.7
Cash and cash equivalents at the end of the period	$	17.1		$	23.7

Reconciliation of net income to net cash provided by operating activities:
Net income (loss)	$	(21.2	)	$	67.5
Adjustments to reconcile net income (loss) to net cash provided by operating activities -
Gains from the sales of properties	(2.3		)	—
Depreciation, depletion and amortization	133.9			110.1
Dry hole and impairment	71.8			25.6
Commodity derivative contracts	6.3			(3.0		)
Other	(8.4		)	(11.7		)
Deferred income taxes	(26.0		)	1.0
Change in operating assets and liabilities	93.8			50.9
Net cash provided by operating activities	$	247.9		$	240.4

See accompanying notes to consolidated financial statements.

POGO PRODUCING COMPANY AND SUBSIDIARIES

Consolidated Statement of Shareholders’ Equity (Unaudited)

	For the Three Months Ended March 31,
	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	53,400		—
Shares forfeited	(5,950	)	—
Issued at end of period	65,841,656		65.8

Additional Capital:
Balance at beginning of year			971.4
Stock options exercised — proceeds			2.0
Stock based compensation - excess federal tax benefit			0.2
Stock based compensation - restricted stock			4.0
Balance at end of period			977.6

Retained Earnings:
Balance at beginning of year			1,892.9
Net income (loss)			(21.2		)
Dividends ($0.075 per common share)			(4.3		)
Balance at end of period			1,867.4

Accumulated Other Comprehensive Income (Loss):
Balance at beginning of year			(1.4		)
Cumulative foreign currency translation adjustment, net of tax			18.9
Reclassification adjustment for retirement and post-retirement actuarial losses and prior service costs included in net income, net of tax			0.9
Change in fair value of commodity derivative contracts, net of tax			(12.5		)
Reclassification adjustment for losses on commodity derivative contracts included in net income, net of tax			2.9
Balance at end of period			8.8

Treasury Stock:
Balance at beginning of year	(7,365,359	)	(361.3		)
Activity during the period	—		—
Balance at end of period	(7,365,359	)	(361.3		)

Common Stock Outstanding, at the End of the Period	58,476,297

Total Shareholders’ Equity			$	2,558.3

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 presentation 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 Annual Report on Form 10-K for the year ended December 31, 2006. Certain prior year amounts have been reclassified to conform to the current year presentation. Such reclassifications had no effect on the Company’s operating income, net income, or shareholders’ equity. 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.

(2) 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

In addition to the Latigo acquisition, the Company also completed the corporate acquisition of a Canadian company on February 21, 2006 for cash consideration totaling approximately $18.6 million. The Company recorded the estimated fair value of assets and liabilities that consisted primarily of $26.9 million of oil and gas properties and deferred tax liabilities of $8.0 million. No goodwill was recorded in connection with either of these transactions.

Pro Forma Information

The following summary presents unaudited pro forma consolidated results of operations for the three months ended March 31, 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.

	Three Months Ended
Pro Forma:	March 31, 2006
Revenues	$	405.1
Net income	71.1
Earnings per share:
Basic -	$	1.24
Diluted -	$	1.23

(3) 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
	March 31,
	2007			2006
Net income (loss) (numerator) - basic and diluted	$	(21.2	)	$	67.5


Weighted average shares (denominator):
Weighted average shares - basic	57.7			57.3
Dilution effect of stock options and unvested restricted stock outstanding at end of period	—			0.6

Weighted average shares - diluted	57.7			57.9

Earnings (loss) per share:
Basic	$	(0.37	)	$	1.18
Diluted	$	(0.37	)	$	1.16

For the three months ended March 31, 2007, the Company has excluded from the diluted loss per share calculation common stock equivalents totaling 0.7 million shares because their effect on loss per share was anti-dilutive.

(4) LONG-TERM DEBT —

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

	March 31,			December 31,
	2007			2006
Senior debt -
Bank revolving credit agreement:
LIBOR based loans, borrowings at March 31, 2007 and December 31, 2006 at interest rates of 6.82% and 6.8524%, respectively	$	761.0		$	797.0
LIBOR Rate Advances, borrowings at March 31, 2007 and December 31, 2006 at interest rates of 6.695% and 6.6833%, respectively	100.0			75.0
Total senior debt	861.0			872.0
Senior subordinated debt -
8.25% Senior subordinated notes, due 2011	200.0			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	1,450.0			1,450.0
Unamortized discount on 2015 Notes	(2.3		)	(2.3		)
Total debt	2,308.7			2,319.7
Amount due within one year	—			—
Long-term debt	$	2,308.7		$	2,319.7

(5) INCOME TAXES —

The components of income (loss) before income taxes for each of the quarters ended March 31 are as follows (expressed in millions):

	2007			2006
United States	$	(48.2	)	$	73.3
Foreign	4.4			28.5
Income (loss) before income taxes	$	(43.8	)	$	101.8

The components of income tax expense (benefit) for each of the quarters ended March 31 are as follows (expressed in millions):

	2007			2006
Current
United States	$	—		$	26.9
Foreign	3.5			6.3
Deferred
United States	(16.3		)	(0.4		)
Foreign	(9.8		)	1.5
Income tax (benefit) expense	$	(22.6	)	$	34.3

Total income tax expense (benefit) for each of the quarters ended March 31 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):

	2007		2006
Federal statutory income tax rate	(35.0	)%	35.0	%
Increases (decreases) resulting from:
Canadian income tax	(18.3	)	(2.7	)
State income taxes, net of federal benefits	0.3		1.2
Other	1.4		0.2
	(51.6	)%	33.7	%

The quarterly effective tax rate includes an annualized tax benefit for the cross-border financing and the phase-in of a deduction for crown royalties in Canada. As pre-tax book income changes in future quarters, the Company’s effective tax rate may increase or decrease.

Where the Company’s present intention is to reinvest the unremitted earnings in its foreign operations, the Company does not provide for U.S. income taxes on unremitted earnings of foreign subsidiaries. Unremitted earnings of foreign subsidiaries for which U.S. income taxes have not been provided are approximately $236.0 million at March 31, 2007. It is not practicable to determine the amount of U.S. income taxes that would be payable upon remittance of the assets that represent those earnings.

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 March 31, 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 2003. The Company’s Canadian subsidiary is no longer subject to examinations by Canadian taxing authorities for years prior to 2002.

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 March 31, 2007.

(6) 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 three month period ended March 31, 2007 is as follows (in millions):

	2007
ARO as of January 1,	$	166.9
Liabilities incurred during the three months ended March 31,	4.6
Liabilities settled during the three months ended March 31,	(5.1		)
Accretion expense	3.1
Balance of ARO as of March 31,	169.5
Less: current portion of ARO	(10.7		)
Long-term ARO as of March 31,	$	158.8

For the three months ended March 31, 2007 and 2006, the Company recognized depreciation expense related to its asset retirement cost (“ARC”) of $2.6 million and $2.2 million, respectively.

(7) 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. As of March 31, 2007, the Company has recorded $2.9 million in general and administrative expense related to retention benefits.

(8) SUSPENDED WELL COSTS

The Company’s net changes in suspended well costs for the three months ended March 31, 2007, in accordance with FASB Staff Position No. 19-1, “Accounting for Suspended Well Costs”, are presented below (in millions):

	Three Months
	Ended
	March 31, 2007
Balance at December 31, 2006	$	38.5
Additions pending the determination of proved reserves	27.6
Reclassifications to proved reserves	(7.2		)
Charged to dry hole costs	(1.4		)
Foreign currency translation	0.2

Balance at March 31, 2007	$	57.7

The following table provides an aging of suspended well costs as of March 31, 2007 (in millions, except well count):

	As of
	March 31,
	2007

Capitalized exploratory well costs that have been capitalized for a period of less than one year	$	41.2
Capitalized exploratory well costs that have been capitalized for a period greater than one year	16.5
Total	$	57.7

Number of projects that have exploratory well costs that have been capitalized for a period greater than one year	4

As of March 31, 2007, the majority of the exploratory well costs that have been capitalized for a period greater than one year relate to two wells in the Northwest Territories that are currently pending evaluation.

(9) GEOGRAPHIC INFORMATION

The Company’s reportable geographic information is identified below. The Company evaluates performance based on operating income (loss). Financial information by geographic region is presented below:

	2007				2006
	(Expressed in millions)
Long-Lived Assets:
As of March 31,
United States	$	3,688.6	$	2,634.6
Canada	2,852.7		2,714.5
Other	0.1		—
Total	$	6,541.4	$	5,349.1

Capital Expenditures: (including interest capitalized) For the three months ended March 31,
United States	$	170.3	$	96.9
Canada	92.7		116.9
Total	$	263.0	$	213.8

	For the Three Months Ended
	March 31,
	2007			2006
	(Expressed in millions)
Revenues:
United States	$	213.8		$	243.7
Canada	137.5			129.8
Other	0.1			—
Total	$	351.4		$	373.5

Depreciation, depletion, and amortization expense:
United States	$	84.3		$	63.3
Canada	49.6			46.8
Total	$	133.9		$	110.1

Operating income (loss):
United States	$	(21.8	)	$	82.1
Canada	5.2			29.2
Other	(1.8		)	(1.0		)
Total	$	(18.4	)	$	110.3

(10) COMMODITY DERIVATIVES AND HEDGING ACTIVITIES —

As of March 31, 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 months ended March 31, 2007 and 2006, the Company recognized a pre-tax gain of $1.9 million and a pre-tax loss of $4.4 million, respectively, in its oil and gas revenues related to settled price hedge contracts. The Company recognized pre-tax losses of $3.2 million and $0.3 million in “Other” expense due to ineffectiveness on unsettled hedge contracts during the first quarter of 2007 and 2006, respectively. Unrealized pre-tax losses on derivative instruments of $4.8 million ($3 million after taxes) have been reflected as a component of other comprehensive income at March 31, 2007. Based on the fair market value of the hedge contracts as of March 31, 2007, the Company would reclassify additional pre-tax losses of approximately $7.2 million (approximately $4.5 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 March 31, 2007 are as follows:

		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)
						(in millions)
Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
April 2007 — December 2007	4,125	$	6.00	$	12.00	$	(0.3	)
April 2007 — December 2007	1,375	$	6.00	$	12.15	$	(0.1	)
April 2007 — December 2007	6,875	$	6.00	$	12.50	$	(0.2	)
April 2007 — December 2007	688	$	8.00	$	13.40	$	0.4
April 2007 — December 2007	2,063	$	8.00	$	13.50	$	1.3
April 2007 — December 2007	688	$	8.00	$	13.52	$	0.4
April 2007 — December 2007	688	$	8.00	$	13.65	$	0.4
January 2008 — December 2008	1,830	$	8.00	$	12.05	$	0.8
January 2008 — December 2008	2,745	$	8.00	$	12.10	$	1.3
January 2008 — December 2008	915	$	8.00	$	12.25	$	0.4

Crude Oil Contracts (Barrels)
Collar Contracts:
April 2007 — December 2007	1,100,000	$	50.00	$	75.00	$	(2.9	)
April 2007 — December 2007	275,000	$	50.00	$	75.25	$	(0.7	)
April 2007 — December 2007	2,750,000	$	50.00	$	77.50	$	(5.5	)
April 2007 — December 2007	137,500	$	60.00	$	82.75	$	0.1
April 2007 — December 2007	412,500	$	60.00	$	83.00	$	0.1
April 2007 — December 2007	137,500	$	60.00	$	84.00	$	0.1
January 2008 — December 2008	183,000	$	60.00	$	80.00	$	(0.2	)
January 2008 — December 2008	183,000	$	60.00	$	80.05	$	(0.2	)
January 2008 — December 2008	183,000	$	60.00	$	80.10	$	(0.2	)
January 2008 — December 2008	366,000	$	60.00	$	80.25	$	(0.3	)

(a) MMBtu means million British Thermal Units

Although the Company’s collars are effective as economic hedges, the sale of 50% of the Company’s Gulf of Mexico interests on May 31, 2006 and the shut-in forecasted hydrocarbon production from the Company’s Gulf of Mexico properties (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 $3.1 million during the three month period ended March 31, 2007, and $3.3 million of realized and unrealized gains for the three month period ended March 31, 2006. As of March 31, 2007, the Company had the following open collar contracts that no longer qualify for hedge accounting:

		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Liability
						(in millions)
Natural Gas Contracts (MMBtu)
Collar Contracts:
April 2007 — December 2007	5,500	$	6.00	$	12.15	$	(0.3	)
April 2007 — December 2007	2,750	$	6.00	$	12.20	$	(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 March 31, 2007, the Company has a projected benefit obligation of $13.6 million related to its pension plan. The Company did not make a contribution to the plan during the first three months of 2007; however, the Company is currently evaluating the need for a contribution during the remainder 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.

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
	March 31,
	2007			2006
Service cost	$	1.3		$	1.1
Interest cost	0.6			0.6
Expected return on plan assets	(0.7		)	(0.7		)
Amortization of prior service cost	0.1			—
Amortization of net loss	0.5			0.5
	$	1.8		$	1.5

	Post-Retirement Medical Plan
	Three Months Ended
	March 31,
	2007		2006
Service cost	$	0.6	$	0.4
Interest cost	0.3		0.3
Amortization of prior service cost	0.1		—
Amortization of net loss	0.1		0.1
	$	1.1	$	0.8

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
	March 31,
	2007			2006
Net income (loss)	$	(21.2	)	$	67.5
Foreign currency translation adjustment, net of tax	18.9			(7.9		)
Reclassification adjustment for retirement and post- retirement actuarial losses and prior service costs included in net income, net of tax	0.9			—
Change in fair value of price hedge contracts, net of tax	(12.5		)	21.9
Reclassification adjustment for hedge contract losses included in net income, net of tax	2.9			0.2
Comprehensive income (loss)	$	(11.0	)	$	81.7

(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 quarter 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 was a reduction of a previously accrued insurance receivable.

(14) ASSETS HELD FOR SALE AND SUBSEQUENT EVENTS

During the first quarter of 2007, the Company sold or entered into agreements to sell properties in the onshore Texas and Louisiana areas for approximately $100 million as part of the Company’s strategic alternative initiative to enhance shareholder value. Two deals totaling $9.1 million closed during the first quarter, while deals totaling $90.7 closed in April, 2007. The latter have been classified, net of their associated asset retirement obligations of $3.8 million and property impairments of $34.2 million, as “Assets held for sale” in the Company’s balance sheet as of March 31, 2007.

On April 23, 2007, the Company entered into a definitive agreement to sell properties located in the Gulf of Mexico for approximately $420 million. The sale is expected to close during the second quarter.

(15) RECENT ACCOUNTING PRONOUNCEMENTS—

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 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 Annual Report on Form 10-K for the year ended December 31, 2006 as well as the risk factors therein. 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, and disposed of 50% of its interests in its Gulf of Mexico properties on May 31, 2006. 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 2 — “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 first quarter of 2007.

Strategic Alternatives Process

On February 15, 2007, the Company confirmed that its Board of Directors previously initiated the exploration of a range of strategic alternatives to enhance shareholder value and is continuing to do so, including the possible sale or merger of Pogo, the sale of its Canadian, Gulf Coast, Gulf of Mexico or other significant assets, and changes to the Company’s business plan. Pogo has retained Goldman, Sachs & Co. and TD Securities Inc. as financial advisors for the process.

Sale of Gulf Coast and Gulf of Mexico Assets

During the first quarter of 2007, the Company sold or entered into agreements to sell properties in the onshore Texas and Louisiana areas for approximately $100 million as part of the Company’s strategic alternative initiative to enhance shareholder value. Two deals totaling $9.1 million closed during the first quarter, while deals totaling $90.7 million closed in April, 2007. The Company used the proceeds from the sales to reduce outstanding debt.

First Quarter Results

Total revenue for the first quarter of 2007 was $351.4 million and net loss totaled $(21.2) million, or $(0.37) per share. Cash flow from operations totaled $247.9 million. As of March 31, 2007, long-term debt was $2.3 billion, decreasing from December 31, 2006 by $11 million. The Company’s debt to total capitalization ratio, an indicator of a company’s financial strength, was 48% at March 31, 2007 and cash and cash equivalents decreased from $22.7 million at December 31, 2006 to approximately $17.1 million at March 31, 2007.

Oil and gas capital and exploration expenditures for the first quarter were approximately $253.1 million. Exploration and development drilling were allocated approximately $191.4 million. For the first quarter of 2007, the Company drilled 97 wells with 89 successfully completed, a 92% success rate.

The Company recognized $57.8 million in impairment charges primarily from the sale of certain Gulf Coast properties and certain leases in its Canadian operations. The impairment associated with the sale of the Company’s Gulf Coast assets totaled approximately $34.2 million (offset by $1 million of gains on completed sales of Gulf Coast assets), and $21.8 million was associated with the impairment of certain leases in its Canadian operations.

Commodity Derivatives

Although the Company’s collars are effective as economic hedges, the sale of 50% of the Company’s Gulf of Mexico interests on May 31, 2006 and the forecasted shut-in hydrocarbon production from the Company’s Gulf of Mexico properties (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. The Company recognized a $3.1 million non-cash loss related to these contracts in the first quarter of 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.

2007 Production Outlook Update

The Company provided 2007 production guidance in its Form 8-K dated April 24, 2007. These estimates are subject to change, and actual results could differ materially, depending upon the amount of Gulf of Mexico production that remains shut-in, the timing of any such production coming back on-line, the availability of oilfield services, acquisitions, divestitures and many other factors that are beyond the Company’s control. Please read “Forward-Looking Statements.”

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 first quarter of 2007 were $321.2 million, a decrease of approximately 9.3% from oil and gas revenues of $354.4 million for the first quarter 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.

	1st Qtr. 2007
	Compared to
	1st Qtr. 2006
Increase (decrease) in oil and gas revenues resulting from variances in:
Natural gas -
Price	$	(18.3	)
Production	2.4
	(15.9		)
Crude oil and condensate -
Price	3.9
Production	(20.4		)
	(16.5		)

Natural gas liquids
Price	0.4
Production	(1.2		)
	(0.8		)

Increase (decrease) in oil and gas revenues	$	(33.2	)

The most significant cause for the decrease in hydrocarbon production was the decreased crude oil and condensate production in the Company’s Gulf of Mexico region due to natural production declines and maintenance related shut in conditions, which decreased oil and condensate revenues by approximately $16.2 million, and natural production declines in the Red River area of SE Saskatchewan, which accounted for approximately $3.6 million of the decrease in oil and condensate revenues. The following tables reflect the relative changes in hydrocarbon volumes and prices by geographic area:

					% Change
	1st Quarter				2006 to
Comparison of Increases (Decreases) in:	2007		2006		2007
Natural Gas —
Average prices (per Mcf)
United States (a)	$	6.45	$	7.13	(10	)%
Canada	$	6.96	$	7.82	(11	)%
Company-wide average price	$	6.59	$	7.31	(10	)%

Average daily production volumes
(MMcf per day) (a):
United States	206.0		207.7		(1	)%
Canada	80.0		74.5		7	%
Company-wide average daily production	286.0		282.2		1	%

a) Price hedging activity increased the average price of the Company’s United States natural gas production during the first quarter of 2007 by $0.08 per Mcf. Price hedging activity reduced the average price of the Company’s United States natural gas production during the first quarter of 2006 by $0.17 per Mcf. “MMcf” is an abbreviation for million cubic feet.

					% Change
	1st Quarter				2006 to
Comparison of Increases (Decreases) in:	2007		2006		2007
Crude Oil and Condensate —
Average prices (per Bbl)
United States (a)	$	54.88	$	54.60	1	%
Canada	$	46.72	$	43.29	8	%
Company-wide average price	$	51.14	$	49.83	3	%

Average daily production volumes (Bbls per day) (a):
United States	15,690		19,274		(19	)%
Canada	13,256		14,111		(6	)%
Company-wide average daily production	28,946		33,385		(13	)%

Natural Gas Liquids —
Average prices (per Bbl)
United States	$	35.09	$	33.38	5	%
Canada	$	34.94	$	38.50	(9	)%
Company-wide average price	$	35.05	$	34.37	2	%

Average daily production volumes (Bbls per day) (a):
United States	4,337		4,998		(13	)%
Canada	1,439		1,178		22	%
Company-wide average daily production	5,776		6,176		(6	)%

Total Liquid Hydrocarbons —
Company-wide average daily production (Bbls per day)	34,722		39,561		(12	)%

(a) During the first quarter of 2007, price hedging activity increased the average price of the Company’s United States crude oil and condensate production by $0.32 per barrel. Price hedging activity had no effect on the average price of the Company’s United States crude oil and condensate production during the first quarter of 2006. “Bbls” is an abbreviation for barrels.

Other Income

Other income is derived from sources other than the current production of hydrocarbons. This income includes, among other items, natural gas inventory sales, gains (losses) on sales of property, income from salt-water disposal activities, and pipeline imbalance settlements. The Company recognized $27.2 million and $18.3 million of natural gas inventory sales from the Company’s Canadian operations in the first quarter of 2007 and 2006, respectively.

Costs and Expenses

							% Change
	1st Quarter						2006 to
Comparison of Increases (Decreases) in:	2007			2006			2007
	(Expressed in millions,
	except DD&A statistics)
Lease Operating Expenses:
United States	$	46.9		$	39.2		20	%
Canada	$	20.6		$	17.9		15	%
Total	$	67.5		$	57.1		18	%

General and Administrative Expenses	$	34.7		$	28.7		21	%
Exploration Expenses	$	9.6		$	2.7		256	%
Dry Hole and Impairment Expenses	$	71.8		$	25.6		180	%
Depreciation, Depletion and Amortization (DD&A) Expenses	$	133.9		$	110.1		22	%
DD&A rate	$	3.01		$	2.36		28	%
MMcfe produced	44,494			46,761			(5	)%
Production and Other Taxes	$	20.0		$	13.5		48	%
Natural Gas Purchases	$	24.8		$	17.9		39	%
Other	$	7.5		$	7.6		(1	)%
Interest—
Charges	$	(43.0	)	$	(28.3	)	52	%
Capitalized Interest	$	19.4		$	16.2		20	%
Commodity Derivative Income (Expense)	$	(3.1	)	$	3.3		(194	)%
Income Tax Benefit (Expense)	$	22.6		$	(34.3	)	(166	)%

Lease Operating Expenses

The increase in United States lease operating expenses for the first quarter of 2007, compared to the first quarter of 2006, is primarily related to the acquisition of Latigo in May 2006, which contributed approximately $9.2 million in additional lease operating expenses during the first quarter of 2007. The Company expects lease operating expenses to decrease during 2007 should the sale of significant assets occur.

On a per unit of production basis, the Company’s total lease operating expenses have increased from an average of $1.22 per Mcfe for the first quarter of 2006 to $1.52 per Mcfe for the first quarter of 2007. These increases in unit costs are primarily related to the increased expenses discussed above, compounded by the production impact discussed in “Oil and Gas Revenues.”

General and Administrative Expenses

The increase in general and administrative expenses for the first quarter of 2007, compared with the same period in 2006, is related primarily to an increase in the size of the Company’s workforce due to the Latigo acquisition, which added approximately $2.8 million in salary and benefit expenses; increased benefit expenses excluding the Latigo employees of approximately $2.4 million; and legal and advisory fees associated with both the strategic alternatives process and the Shareholders’ Agreement (see “Other Matters”) of approximately $1.0 million.

On a per unit of production basis, the Company’s general and administrative expenses increased to $0.78 per Mcfe in the first quarter of 2007, up from $0.61 per Mcfe in the first quarter of 2006. These increases in unit costs are primarily related to the increased expenses discussed above, compounded by the production impact 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 first quarter of 2007 resulted primarily from $7.4 million and $1.0 million of seismic activity in the Company’s Gulf Coast and Canadian divisions,

respectively, and delay rentals. Exploration expenses for the first quarter of 2006 consisted primarily of $1.5 million of seismic activity in the Company’s Canadian and Gulf Coast divisions, and delay rentals in the United States.

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 increase in dry hole and impairment expense for the first quarter of 2007, compared to the first quarter of 2006, was the result of increased impairments, which were only partially offset by a decrease in exploratory dry hole costs incurred from approximately $19.4 million during the first quarter of 2006 to approximately $13.9 million in the first quarter of 2007. The Company had approximately $57.7 million of costs attributable to exploratory wells in progress as of March 31, 2007 that, as of April 25, 2007 were either still in progress or pending evaluation.

Generally accepted accounting principles 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, and the Company’s results of operations, 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 first quarter of 2007 and 2006, the Company recognized impairments on various prospects and leases in the amount of $57.8 million and $6.2 million, respectively. Of the 2007 amount, $21.8 million is related to various prospects in the Company’s Canadian operation, while $34.2 million is related to the properties in the Company’s Gulf Coast sales package that have been reclassified as “Assets held for sale” per the rules of SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets”, which require that long-lived assets classified as held for sale be measured at the lower of their carrying amount or fair value less cost to sell.

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 first quarter of 2007 compared to the first quarter of 2006 resulted primarily from an increase in the Company’s composite DD&A rate.

The increase in the composite DD&A rate for all of the Company’s producing fields for the first quarter of 2007, compared to the 2006 period, 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 increase in production and other taxes during the first quarter of 2007, compared to the first quarter of 2006, relates primarily to the Latigo acquisition, which increased the number of properties that are subject to production taxes and added $3.4 million in taxes during the first quarter of 2007, in addition to increased property and franchise taxes of approximately $3.1 million related to higher property and equity valuations.

Natural gas inventory purchases

Gas inventory purchases are related to the Company’s Canadian operations. Each month, the Company purchases gas for injection into the East Cantaur gas facility to maintain operation pressure and enters into contracts with various other third parties to sell those volumes at a fixed price in a subsequent month up to 12 months in the future. The Company recognized $24.8 million and $17.9 million of natural gas inventory purchases in the first quarter of 2007 and 2006, respectively, which, combined with the natural gas sales included in other income, resulted in the recognition of $2.3 million of pre-tax income in the first quarter of 2007, compared to $0.5 million of pre-tax income during the same period in 2006.

Interest

Interest Charges. The increase in the Company’s interest charges for the first quarter of 2007, compared to the first quarter of 2006, resulted primarily from an increase in the average amount of the Company’s outstanding debt (incurred primarily to fund the purchase of Latigo) from $1.6 billion in the first quarter of 2006 to $2.3 billion in the first quarter of 2007. See “Liquidity and Capital Resources” below.

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. The increase in capitalized interest for the first quarter of 2007, compared to the same period in 2006, was primarily due to an increase from $938.5 million to $1.1 billion in the weighted average dollar amount of oil and gas projects in progress subject to interest capitalization, including $157 million of unproved property acquired in the Latigo transaction in May 2006.

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 Income (Expense)

Commodity derivative income (expense) for the first three months of both 2006 and 2007 represents both realized and unrealized gains and losses on derivative contracts that no longer qualify for hedge accounting treatment. Although the Company’s collars are effective as economic hedges, the sale of 50% of the Company’s Gulf of Mexico interests on May 31, 2006 and the shut-in forecasted hydrocarbon production from the Company’s Gulf of Mexico properties (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.

Income Tax Benefit (Expense)

Changes in the Company’s income tax benefit (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 first quarter of 2007, compared to the first quarter of 2006, primarily resulted from a decrease in pre-tax income, the favorable impact of cross-border financing related to the acquisition of Northrock Resources, reductions in the statutory federal income tax rates in Canada from approximately 26% to 19% (phased in through 2010), and the phase-in of a deduction in Canada for Crown royalties. The Company’s consolidated effective tax rate was a 51.6% benefit for the first quarter of 2007, compared to a 33.7% expense for the first quarter of 2006.

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 Company’s cash flow provided by operating activities for the first three months of 2007 was $247.9 million, compared to cash flow provided by operating activities of $240.4 million during the first three months of 2006. First quarter 2007 operating cash flows included a tax refund of $52 million for the overpayment of estimated taxes in the third quarter of 2006. Cash flow used in investing activities increased from $198.1 during the first quarter of 2006 to $239.7 million during the first quarter of 2007, primarily due to an increase in capital expenditures in the United States. Cash flow from operating activities and debt financing were used during the first three months of 2007 to fund $253.3 million in cash expenditures (excluding capitalized interest) for capital and exploration projects and property acquisitions. During the first three months of 2007, the Company repaid senior debt obligations using cash of approximately $11 million (net of borrowings). In addition, the Company paid $4.3 million of common stock dividends. As of March 31, 2007, the Company had cash and cash equivalents of $17.1 million and long-term debt obligations of $2.3 billion (excluding debt discount) with no repayment obligations until 2009. 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 April 30, 2007, the Company’s lenders redetermined the borrowing base under its bank credit facility at $1.5 billion. As of April 25, 2007, the Company had an outstanding balance of $720 million and a $1.0 billion borrowing capacity under the facility. As such, the available borrowing capacity under the facility was $280 million.

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 2011 Notes, 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 April 25, 2007, there was $100 million outstanding under these agreements.

Property Sales

During the first quarter of 2007, the Company sold or entered into agreements to sell properties in the onshore Texas and Louisiana areas for approximately $100 million as part of the Company’s strategic alternative initiative to enhance shareholder value. Two deals totaling $9.1 million closed during the first quarter, while deals totaling $90.7 million closed in April, 2007. The Company used the proceeds from the sales to reduce outstanding debt.

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, of which approximately $251.6 million was spent to drill 97 wells in the United States and Canada during the three months ended March 31, 2007.

The Company currently anticipates that its available cash, cash provided by operating activities and funds available under its bank credit facility will be sufficient to fund the Company’s ongoing operating, interest and general and administrative expenses, capital expenditures, and dividend payments at current levels for the foreseeable future. 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, 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

Other Matters

Stockholders Agreement

On March 12, 2007, the Company and Third Point LLC (“Third Point”) announced that they had reached an agreement under which Pogo’s Board of Directors would be expanded from eight to ten members, and that Daniel S. Loeb and Bradley L. Radoff of Third Point had been appointed to fill the new seats. As permitted by the agreement, Pogo may at a later date offer to appoint Robert B. Rowling of TRT Holdings, Inc. to an additional seat on Pogo’s Board of Directors. Third Point and its affiliates agreed not to solicit proxies in connection with Pogo’s 2007 annual meeting or take certain other stockholder actions. Additional details about the agreement can be found in the Company’s Form 8-K filed on March 13, 2007, or its definitive proxy statement filed April 23, 2007.

The Company believes this agreement will avoid a potentially costly and disruptive proxy contest at a time when it is exploring a range of strategic alternatives to enhance shareholder value. As previously announced, the Company and its financial advisors, Goldman, Sachs & Co. and TD Securities, are actively exploring these alternatives, including the sale or merger of the Company. In addition, the Company is continuing to simultaneously pursue the potential sale of significant assets including its Canadian, Gulf of Mexico, or other properties. By obtaining Third Point’s agreement not to solicit proxies in connection with the 2007 annual meeting, the Company avoided the consequences of a change in control that would have occurred had Third Point been successful in its proxy fight, including the acceleration of indebtedness and triggering of certain rights under executive employment agreements and severance and retention plans.

Sale of Gulf of Mexico Properties

On April 23, 2007, the Company entered into a purchase and sale agreement with Energy XXI GOM, LLC, a Delaware limited liability company, whereby the Company agreed to sell substantially all of its federal and state Gulf of Mexico oil and gas leasehold interests and related pipelines and equipment for a cash purchase price of approximately $420 million, subject to customary purchase price adjustments. The closing is expected to occur in early June 2007, subject to customary closing conditions, and will represent an exit from operations in the Gulf of Mexico.

Gulf of Mexico Regulatory Issue

In a letter received in mid-February, the Company received notice that the Minerals Management Service (“MMS”), the federal agency that manages natural gas, oil, and other resources in the Gulf of Mexico Outer Continental Shelf (“OCS”), had placed the Company on probation for a period of one year, and that it is a candidate for disqualification as a designated operator of properties in the OCS. The MMS cited concerns focused on recent events, inspections and incidents of noncompliance on the Company’s South Pass Block 49 Field, Main Pass 61 Field, and Main Pass 73 Field, as well as the Company’s 2006 compliance record. The violations relate to safety and environmental matters. During the probation period, the MMS intends to increase the frequency of inspections of the properties operated by the Company; initial inspections have been completed for all platforms, which required the shut down of operations during the procedures. In addition, the Company is prohibited from becoming the designated operator on any additional offshore leases. The Company has submitted to the MMS a Performance Improvement Plan detailing how it intends to bring its facilities into compliance. The MMS has stated it will continue to analyze the Company’s compliance performance during the probationary period and could remove the Company from probation if it determines the Company’s performance is improving. However, if the MMS determines that the Company’s compliance performance remains unsatisfactory, the MMS may take further actions, which its letter stated may include facility-specific, district-specific, region-specific, or OCS-wide disqualification as a designated operator. The MMS has notified the Company’s co-lessees of the probation. The pending sale of the Company’s remaining operations in the Gulf of Mexico will represent its exit from that region.

Recent Accounting Pronouncements

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 March 31, 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. The Company designated a significant portion of 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.

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.

		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Asset/(Liability)
						(in millions)
Natural Gas Contracts (MMBtu) (a)
Collar Contracts:
April 2007 — December 2007	4,125	$	6.00	$	12.00	$	(0.3	)
April 2007 — December 2007	1,375	$	6.00	$	12.15	$	(0.1	)
April 2007 — December 2007	6,875	$	6.00	$	12.50	$	(0.2	)
April 2007 — December 2007	688	$	8.00	$	13.40	$	0.4
April 2007 — December 2007	2,063	$	8.00	$	13.50	$	1.3
April 2007 — December 2007	688	$	8.00	$	13.52	$	0.4
April 2007 — December 2007	688	$	8.00	$	13.65	$	0.4
January 2008 — December 2008	1,830	$	8.00	$	12.05	$	0.8
January 2008 — December 2008	2,745	$	8.00	$	12.10	$	1.3
January 2008 — December 2008	915	$	8.00	$	12.25	$	0.4

Crude Oil Contracts (Barrels)
Collar Contracts:
April 2007 — December 2007	1,100,000	$	50.00	$	75.00	$	(2.9	)
April 2007 — December 2007	275,000	$	50.00	$	75.25	$	(0.7	)
April 2007 — December 2007	2,750,000	$	50.00	$	77.50	$	(5.5	)
April 2007 — December 2007	137,500	$	60.00	$	82.75	$	0.1
April 2007 — December 2007	412,500	$	60.00	$	83.00	$	0.1
April 2007 — December 2007	137,500	$	60.00	$	84.00	$	0.1
January 2008 — December 2008	183,000	$	60.00	$	80.00	$	(0.2	)
January 2008 — December 2008	183,000	$	60.00	$	80.05	$	(0.2	)
January 2008 — December 2008	183,000	$	60.00	$	80.10	$	(0.2	)
January 2008 — December 2008	366,000	$	60.00	$	80.25	$	(0.3	)

(a) MMBtu means million British Thermal Units

Although the Company’s collars are effective as economic hedges, the sale of 50% of the Company’s Gulf of Mexico interests on May 31, 2006 and the shut-in forecasted hydrocarbon production from the Company’s Gulf of Mexico properties (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 March 31, 2007, the Company had the following open collar contracts that no longer qualify for hedge accounting:

		NYMEX
		Contract				Fair Value
Contract Period and		Price				of
Type of Contract	Volume	Floor		Ceiling		Liability
						(in millions)
Natural Gas Contracts (MMBtu)
Collar Contracts:
April 2007 — December 2007	5,500	$	6.00	$	12.15	$	(0.3	)
April 2007 — December 2007	2,750	$	6.00	$	12.20	$	(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 April 25, 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 March 31, 2007:

	2007		2008		2009			2010		2011			Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate	$	0.0	$	0.0	$	861.0		$	0.0	$	0.0		$	0.0		$	861.0		$	861.0
Average Interest Rate	—		—		6.81		%	—		—			—			6.81		%	—
Fixed Rate	$	0.0	$	0.0	$	0.0		$	0.0	$	200.0		$	1,250.0		$	1,450.0		$	1,440.5
Average Interest Rate	—		—		—			—		8.25		%	7.18		%	7.32		%	—

Foreign Currency Exchange Rate Risk

The Company does not actively manage foreign currency risk in its foreign subsidiaries where the U.S. dollar is not the functional currency, primarily Canada, since the majority of transactions are denominated in the local currency. A substantial amount of the Company’s cash is located in Canada, in Canadian dollars, which provides a natural hedge against foreign currency risk. Exposure from market rate fluctuations related to activities in New Zealand and Vietnam is not material at this time. As of April 25, 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.

ITEM 5. Other Information.

ITEM 6. Exhibits

*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).

*10.1		Stockholders Agreement dated March 12, 2007 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, dated March 12, 2007, File No. 1-7792).

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: May 3, 2007