UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

 

FORM 10-Q

 

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

Exchange Act of 1934

 

For the quarterly period ended March 31, 2004 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)

 

 

(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 requirement for the past 90 days: Yes ý No o

 

Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2):  Yes ý No o

 

 

Registrant’s number of common shares outstanding as of April 26, 2004:  63,868,326

 

 

PART I. FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS

 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Consolidated Statements of Income (Unaudited)

 

		Three Months Ended March 31,
		2004			2003
		(Expressed in thousands, except per share amounts)
Revenues:
Oil and gas		$	307,327		$	311,786
Other		555			887
Total		307,882			312,673
Operating Costs and Expenses:
Lease operating		34,875			30,791
General and administrative		17,232			13,372
Exploration		8,471			1,832
Dry hole and impairment		11,623			2,178
Depreciation, depletion and amortization		87,339			80,419
Production and other taxes		9,538			8,954
Transportation and other		5,125			7,293
Total		174,203			144,839
Operating Income		133,679			167,834
Interest:
Charges		(9,444		)	(13,695		)
Income		452			387
Capitalized		4,548			4,014
Foreign Currency Transaction Gain (Loss)		(44		)	226
Income Before Taxes and Cumulative Effect of Change in Accounting Principle		129,191			158,766
Income Tax Expense		(57,551		)	(66,123		)
Income Before Cumulative Effect of Change in Accounting Principle		71,640			92,643
Cumulative Effect of Change in Accounting Principle		—			(4,166		)
Net Income		$	71,640		$	88,477
Earnings Per Common Share
Basic:
Income before cumulative effect of change in accounting principle		$	1.13		$	1.52
Cumulative effect of change in accounting principle		—			(0.07		)
Net income		$	1.13		$	1.45
Diluted:
Income before cumulative effect of change in accounting principle		$	1.12		$	1.44
Cumulative effect of change in accounting principle		—			(0.07		)
Net income		$	1.12		$	1.37
Dividends Per Common Share		$	0.05		$	0.05
Weighted Average Number of Common Shares and Potential Common Shares Outstanding:
Basic		63,668			61,157
Diluted		64,213			65,128

 

See accompanying notes to consolidated financial statements.

 

2

 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Consolidated Balance Sheets (Unaudited)

 

		March 31, 2004			December 31, 2003
		(Expressed in thousands, except share amounts)
Assets
Current Assets:
Cash and cash equivalents		$	188,170		$	178,754
Accounts receivable		137,414			116,970
Other receivables		53,490			39,497
Inventories - product		3,844			5,951
Inventories - tubulars		12,898			7,735
Other		2,233			5,448
Total current assets		398,049			354,355
Property and Equipment:
Oil and gas, on the basis of successful efforts accounting
Proved properties		4,022,802			3,919,138
Unevaluated properties		107,559			107,708
Other, at cost		30,270			30,046
		4,160,631			4,056,892
Accumulated depreciation, depletion and amortization
Oil and gas		(1,745,986		)	(1,661,584		)
Other		(20,522		)	(19,467		)
		(1,766,508		)	(1,681,051		)
Property and equipment, net		2,394,123			2,375,841
Other Assets:
Deferred income tax		2,147			2,416
Foreign value added taxes receivable		4,888			4,188
Other		24,764			25,236
		31,799			31,840
		$	2,823,971		$	2,762,036

 

See accompanying notes to consolidated financial statements.

 

3

 

		March 31, 2004			December 31, 2003
		(Expressed in thousands, except share amounts)
Liabilities and Shareholders’ Equity
Current Liabilities:
Accounts payable - operating activities		$	67,117		$	55,543
Accounts payable - investing activities		76,375			73,179
Income taxes payable		75,333			20,220
Accrued interest payable		9,817			9,950
Accrued payroll and related benefits		3,330			3,242
Deferred income tax		5,324			5,324
Other		17,132			16,126
Total current liabilities		254,428			183,584
Long-Term Debt		391,347			487,261
Deferred Income Tax		547,394			546,709
Asset Retirement Obligation		84,345			70,790
Other Liabilities and Deferred Credits		21,300			20,039
Total liabilities		1,298,814			1,308,383
Commitments and Contingencies		—			—
Shareholders’ Equity:
Preferred stock, $1 par; 4,000,000 shares authorized		—			—
Common stock, $1 par; 200,000,000 shares authorized, 63,889,817 and 63,813,283 shares issued, respectively		63,890			63,813
Additional capital		917,225			914,492
Retained earnings		549,025			480,576
Deferred compensation		(3,273		)	(3,518		)
Accumulated other comprehensive income (loss)		—			—
Treasury stock (55,359 shares), at cost		(1,710		)	(1,710		)
Total shareholders’ equity		1,525,157			1,453,653
		$	2,823,971		$	2,762,036

 

See accompanying notes to consolidated financial statements.

 

4

 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Condensed Consolidated Statements of Cash Flows (Unaudited)

 

		Three Months Ended March 31,
		2004			2003
		(Expressed in thousands)
Cash Flows from Operating Activities:
Cash received from customers		$	292,206		$	294,921
Operating, exploration, and general and administrative expenses paid		(61,117		)	(49,734		)
Interest paid		(9,202		)	(9,001		)
Income taxes paid		(1,000		)	(5,000		)
Value added taxes paid		(700		)	(957		)
Price hedge contracts		—			(10,267		)
Other		882			4,013
Net cash provided by operating activities		221,069			223,975
Cash Flows from Investing Activities:
Capital expenditures		(93,767		)	(82,243		)
Purchase of properties		(20,727		)	—
Proceeds from the sale of properties		229			—
Net cash used in investing activities		(114,265		)	(82,243		)
Cash Flows from Financing Activities:
Borrowings under senior debt agreements		113,000			118,999
Payments under senior debt agreements		(209,000		)	(254,000		)
Payments of cash dividends on common stock		(3,191		)	(3,055		)
Payment of debt issue costs		—			(100		)
Proceeds from exercise of stock options		1,824			6,767
Net cash used in financing activities		(97,367		)	(131,389		)
Effect of exchange rate changes on cash		(21		)	46
Net increase in cash and cash equivalents		9,416			10,389
Cash and cash equivalents at the beginning of the year		178,754			134,449
Cash and cash equivalents at the end of the period		$	188,170		$	144,838
Reconciliation of net income to net cash provided by operating activities:
Net income		$	71,640		$	88,477
Adjustments to reconcile net income to net cash provided by operating activities -
Cumulative effect of change in accounting principle		—			4,166
(Gains) losses from the sales of properties		(228		)	62
Depreciation, depletion and amortization		87,339			80,419
Dry hole and impairment		11,623			2,178
Interest capitalized		(4,548		)	(4,014		)
Price hedge contracts		—			1,119
Other		2,041			4,101
Deferred income taxes		1,439			17,001
Change in operating assets and liabilities		51,763			30,466
Net cash provided by operating activities		$	221,069		$	223,975

 

See accompanying notes to consolidated financial statements.

 

5

 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Consolidated Statements of Shareholders’ Equity (Unaudited)

 

		For the Three Months Ended March 31,
		2004								2003
		Shareholders’ Equity					Compre-			Shareholders’ Equity					Compre-
							hensive								hensive
		Shares		Amount			Income			Shares		Amount			Income
		(Expressed in thousands, except share amounts)
Common Stock:
$ 1.00 par-200,000,000 shares authorized
Balance at beginning of year		63,813,283		$	63,813					61,061,888		$	61,062
Stock option activity and other		76,534		77						317,404		317
Issued at end of period		63,889,817		63,890						61,379,292		61,379
Additional Capital:
Balance at beginning of year				914,492								822,526
Stock option activity and other				2,733								8,356
Balance at end of period				917,225								830,882
Retained Earnings:
Balance at beginning of year				480,576								202,155
Net income				71,640			$	71,640				88,477			$	88,477
Dividends ($0.05 per common share)				(3,191		)						(3,055		)
Balance at end of period				549,025								287,577
Accumulated Other Comprehensive Income (Loss):
Balance at beginning of year				—								(6,249		)
Change in fair value of price hedge contracts				—			—					(9,550		)	(9,550		)
Reclassification adjustment for losses (gains) included in net income				—			—					7,004			7,004
Balance at end of period				—								(8,795		)
Deferred Compensation
Balance at beginning of year				(3,518		)						—
Activity during the period				245			—					—
Balance at end of period				(3,273		)						—			—
Comprehensive Income (Loss)							$	71,640							$	85,931
Treasury Stock:
Balance at beginning of year		(55,359	)	(1,710		)				(55,359	)	(1,710		)
Activity during the period		—		—						—		—
Balance at end of period		(55,359	)	(1,710		)				(55,359	)	(1,710		)
Common Stock Outstanding, at the End of the Period		63,834,458								61,323,933

 

See accompanying notes to consolidated financial statements.

 

6

 

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. Certain prior year amounts have been reclassified to conform to current year presentation.  Such reclassifications had no effect on the Company’s operating income, net income or shareholders’ equity.  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, 2003.

 

(2) 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 thousands, except per share amounts.

 

		Three Months Ended March 31, 2004								Three Months Ended March 31, 2003
		Income			Shares		Per Share			Income(a)			Shares		Per Share
Basic earnings per share -		$	71,640		63,668		$	1.13		$	92,643		61,157		$	1.52
Effect of dilutive securities:
Options to purchase common shares					545								1,245
2006 Notes (b)		—			—					1,028			2,726
Diluted earnings per share		$	71,640		64,213		$	1.12		$	93,671		65,128		$	1.44
Antidilutive securities -
Options to purchase common shares		—			—		$	—		—			69		$	40.92

 

(a) Reflects income before cumulative effect of change in accounting principle.

(b) Redeemed on July 7, 2003.

 

(3) ASSET RETIREMENT OBLIGATION –

 

The Company adopted Statement of Financial Accounting Standard (“SFAS”) No. 143, “Accounting for Asset Retirement Obligations” (“SFAS 143”), as of January 1, 2003.  SFAS 143 requires the Company to record the fair value of a liability for an asset retirement obligation (“ARO”) in the period in which it is incurred. Upon adoption of SFAS 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost (“ARC”) was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS 143, a cumulative effect of a change in accounting principle was also required in order to recognize a liability for any existing AROs adjusted for cumulative accretion, an increase to the carrying amount of the associated long-lived asset and accumulated depreciation on the capitalized cost. Subsequent to initial measurement, liabilities are required to be accreted to their present value each period and capitalized costs are depreciated over the estimated useful life of the related assets. This periodic accretion expense is recorded as “Transportation and other” in the consolidated statement of income.  Upon settlement of the liability, the Company will settle the obligation against its recorded amount and will record any resulting gain or loss.

 

The Company’s liability for expected future costs associated with site reclamation, facilities dismantlement, and plugging and abandonment of wells for the three month periods ending March 31, 2004 and 2003 is as follows (in thousands):

 

		2004			2003
ARO as of January 1,		$	70,790		$	63,643
Liabilities incurred during the three months ended March 31,		12,249			571
Accretion expense		1,306			1,195
Balance of ARO as of March 31,		$	84,345		$	65,409

 

For the three months ended March 31, 2004 and 2003 the Company recognized depreciation expense related to its ARO of $1,098,000 and $972,000, respectively.  As a result of the adoption of SFAS 143 on January 1, 2003, the Company recorded a $56,769,000 increase in the net capitalized cost of its oil and gas properties and recognized an after-tax charge of $4,166,000 for the cumulative effect of the change in accounting principle.

 

7

 

(4) GEOGRAPHIC INFORMATION –

 

Financial information by geographic segment is presented below:

 

			Three Months Ended March 31,
			2004			2003
			(Expressed in thousands)
Revenues:
United States			$	235,133		$	236,487
Kingdom of Thailand			72,749			76,184
Other			—			2
	Total		$	307,882		$	312,673
Operating Income (Loss):
United States			$	108,805		$	126,874
Kingdom of Thailand			34,762			41,721
Other			(9,888		)	(761		)
	Total		$	133,679		$	167,834

 

(5) 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 which produce the highest average compensation. The Company did not make a contribution to the plan during the first quarter of 2004 and does not expect to make a contribution during the remainder of 2004.

 

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 plans is comprised of the following components (in thousands of dollars):

 

		Retirement Plan						Post-Retirement Medical Plan
		2004			2003			2004			2003
Service cost		$	627		$	563		$	344		$	293
Interest cost		427			383			271			254
Expected return on plan assets		(663		)	(551		)	—			—
Amortization of prior service cost		12			10			—			—
Amortization of transition obligation		—			—			76			76
Amortization of net loss		152			235			56			45
		$	555		$	640		$	747		$	668

 

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, 2003.

 

(6) ACCOUNTING FOR STOCK-BASED COMPENSATION -

 

The Company’s incentive plans authorize awards granted wholly or partly in common stock (including rights or options which may be exercised for or settled in common stock) to key employees and non-employee directors (collectively, “Stock Awards”).  Effective January 1, 2003, the Company adopted the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, “Accounting for Stock Based Compensation” (“SFAS 123”) and the prospective method transition provisions of Statement of Financial Accounting Standards No. 148, “Accounting for Stock Based Compensation—Transition and Disclosure—an amendment of FAS No. 123”

 

8

 

(“SFAS 148”) for all Stock Awards granted, modified or settled after January 1, 2003.  The Company granted no Stock Awards during the three-month periods ended March 31, 2004 or 2003, respectively.

 

The following table illustrates the effect on the Company’s net income and earnings per share if the fair value recognition provisions of SFAS 123 for employee stock-based compensation had been applied to all Stock Awards outstanding during the three-month periods ending March 31, 2004 and 2003 (in thousands of dollars, except per share amounts):

 

				Three Months Ended March 31,
				2004			2003
Net income, as reported				$	71,640		$	88,477
Add:		Employee stock-based compensation expense, net of related tax effects, included in net income, as reported		485			—
Deduct:		Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects		(1,672		)	(1,523		)
Net income, pro forma				$	70,453		$	86,954
Earnings per share:
Income before the cumulative effect of change in accounting principle
		Basic - as reported		$	1.13		$	1.52
		Basic - pro forma		$	1.11		$	1.49
		Diluted - as reported		$	1.12		$	1.44
		Diluted - pro forma		$	1.10		$	1.42
Net income
	Basic - as reported			$	1.13		$	1.45
	Basic - pro forma			$	1.11		$	1.42
	Diluted - as reported			$	1.12		$	1.37
	Diluted - pro forma			$	1.10		$	1.35

 

(7) HEDGING ACTIVITIES -

 

As of March 31, 2004, the Company held no derivative instruments and there were no hedging activities during the first quarter of 2004.  During 2003, the Company was a party to 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 its exposure to price volatility.  During the three months ended March 31, 2003, the Company recognized a pre-tax loss of $10,775,000 ($7,004,000 after taxes) from its price hedge contracts, which was included in oil and gas revenues.  Unrealized losses on derivative instruments of $2,546,000, net of deferred taxes of $1,371,000, were reflected as a component of other comprehensive income for the three months ended March 31, 2003.

 

(8) SUBSEQUENT EVENT -

 

The Company gave notice on March 18, 2004 of its intent to redeem all $150,000,000 of its 10³/₈% Senior Subordinated Notes due 2009 (the “2009 Notes”) at 105.188% of their face amount.  On April 19, 2004, the Company paid $157,782,000 (excluding accrued interest) in cash to holders of the 2009 Notes.  The cash redemption payment was funded through borrowings under the Company’s existing bank credit facility.  The Company will record a pre-tax expense on the redemption of the 2009 Notes of approximately $10.9 million in the s econd quarter of 2004.

 

9

 

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, 2003. 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, 2003, 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

 

First quarter financial results for 2004 were among the best recorded in the Company’s 34-year history.  Net income for the quarter totaled $71,640,000 or $1.13 per share. Cash flow from operations totaled $221,069,000 or $3.47 per share.

 

The Company has continued to make improvements to its balance sheet and reduce financial leverage.  As of March 31, 2004, the Company’s debt balance stood at $393 million down $96 million from year-end 2003.  The Company’s debt-to-book capitalization ratio, an indicator of a company’s financial strength, was reduced to 21% from 25% at year-end 2003.  On April 19, 2004, the Company redeemed its 10 3/8% $150 million senior subordinated debentures.  The Company’s bank credit facility was used to redeem the aforementioned debt security for cash.  Cash and cash equivalents increased from $178,754,000 at year-end to $188,170,000 at quarter-end.

 

The Company has established a $415 million exploration and development budget (excluding property acquisitions), which is the largest in the Company’s history. This record budget represents an increase of 25% over 2003’s exploration and development expenditures. During the first quarter, the Company spent $93.8 million on exploratory and developmental activities, or 23% of its 2004 budget.  The capital budget calls for the drilling of approximately 300 wells during 2004, a record number.  During the first quarter of 2004, 55 wells were drilled with 51 successfully completed, a 93% success rate.  At March 31, 2004, 40 wells were either drilling or being completed.

 

The Company was an active participant in the Gulf of Mexico Outer Continental Shelf Lease Sale 190. The Company was the apparent high bidder on 15 leases for approximately $12.6 million dollars. All leases will be 100% owned by the Company, if and when, the Minerals Management Service awards them. Prospects contained on several of these blocks could be added to the capital budget before year-end.   During the quarter, the Company also acquired an additional interest in a Company operated producing field for $18.2 million.

 

2004 Production Outlook

 

The shutdown of the large Benchamas production facilities, for equipment upgrades, occurred on January 11, 2004.  The facility upgrade was completed and production has been restored. With the shutdown completed, the Company currently expects that full-year 2004 company wide equivalent hydrocarbon production should reach within 3% of the Company's 2003 production levels, subject to changes in circumstances, acquisitions and many other factors.

 

Results of Operations

 

Oil and Gas Revenues

 

The Company’s oil and gas revenues for the first quarter of 2004 were $307,327,000, a decrease of approximately 1% from oil and gas revenues of $311,786,000 for the first quarter of 2003.  The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in thousands) between 2004 and 2003.

 

10

 

			1st Qtr 2004 Compared to 1st Qtr 2003
Increase (decrease) in oil and gas revenues resulting in variances in:
Natural gas -
	Price		$	3,374
	Production		(766		)
			2,608
Crude oil and condensate -
	Price		16,169
	Production		(23,813		)
			(7,644		)
Natural gas liquids			577
	Increase in oil and gas revenues		$	(4,459	)

 

The decrease in the Company’s oil and gas revenues in the first quarter of 2004, compared to the first quarter of 2003, is related to a decrease in the Company’s hydrocarbon production volumes, partially offset by increases in the average price that the Company received for its natural gas, crude oil and condensate.

 

		1st Qtr 2004			1st Qtr 2003			% Change 2004 to 2003
Comparison of Increases in:
Natural Gas –
Average prices
United States (a)		$	5.48		$	5.64		(3	)%
Kingdom of Thailand (b)		$	2.50		$	2.32		8	%
Company-wide average price		$	4.79		$	4.67		3	%
Average daily production volumes
(MMcf per day):
United States (a)		230.5			215.8			7	%
Kingdom of Thailand		69.1			89.0			(22	)%
Company-wide average daily production		299.6			304.8			(2	)%

 

(a)          North American average prices reflect the impact of the Company’s price hedging activity for 2003.  The Company had no price hedging activity during the first quarter of 2004.  Price hedging activity reduced the average price of the Company’s United States natural gas production during the first quarter of 2003 by $0.39 per Mcf.  “MMcf” is an abbreviation for million cubic feet.

 

(b)         The Company is paid for its natural gas production in the Kingdom of Thailand in Thai Baht.  The average prices are presented in U.S. dollars based on the revenue recorded in the Company’s financial records.

 

11

 

		1st Qtr 2004			1st Qtr 2003			% Change 2004 to 2003
Comparison of Increases in:
Crude Oil and Condensate —
Average prices (a)
United States		$	35.28		$	32.32		9	%
Kingdom of Thailand		$	34.86		$	31.78		10	%
Company-wide average price		$	35.13		$	32.14		9	%
Average daily production volumes
(Bbls per day):
United States (a)		34,049			39,992			(15	)%
Kingdom of Thailand (b)		15,684			23,091			(32	)%
Company-wide average daily production		49,733			63,083			(21	)%
Total Liquid Hydrocarbons —
Company-wide average daily production (Bbls per day)(b)		54,245			67,602			(20	)%

 

(a)          Average prices are computed on production that is actually sold during the period and include the impact of the Company’s price hedging activity.  The Company had no price hedging activity during the first quarter of 2004.  Price hedging activity reduced the average price of the Company’s United States crude oil and condensate production by $0.91 per barrel during the first quarter of 2003.  For United States average prices, sales volumes equate to actual production.  However, in the Gulf of Thailand, crude oil and condensate sold may be more or less than actual production.  See footnote (b) below. “Bbls” is an abbreviation for barrels.

 

(b)         Oil and condensate production in the Gulf of Thailand is produced and stored on the FPSO and FSO pending sale and is sold in tanker loads that typically average between 300,000 and 750,000 barrels per sale. Therefore, oil and condensate sales volumes for a given period in the Gulf of Thailand may not equate to actual production.  In accordance with generally accepted accounting principles, reported revenues are based on sales volumes.  However, the Company believes that actual production volumes also provide a meaningful measure of the Company’s operating results.  The Company produced 206,000 barrels less than it sold in the first quarter of 2004 and 268,000 barrels more than it sold in the first quarter of 2003.

 

Natural Gas

 

Thailand Prices.     The price that the Company receives under the gas sales agreement with the Petroleum Authority of Thailand (“PTT”) is based upon a formula that takes into account a number of factors including, among other items, changes in the Thai/U.S. exchange rate and fuel oil prices in Singapore.  The contract price is also subject to adjustments for quality.  An amendment to the Gas Sales Agreement provided that for certain volumes which the Company produces in excess of the base contractual amount (currently 145 MMcf per day) the price that the Company receives from PTT will be equal to 88% of the then-current price calculated under its Gas Sales Agreement.

 

Production.     The decrease in the Company’s natural gas production during the first quarter of 2004, compared to the first quarter of 2003, was primarily related to the previously announced temporary shutdown of the Benchamas field in the Gulf of Thailand during January and February of 2004 to upgrade the Benchamas central processing platform.  The decrease in Benchamas natural gas production volumes was for the most part offset by increased natural gas production from the continuing success of the Company’s exploration program at Los Mogotes field in South Texas and production from fields purchased by the Company during the latter part of 2003.

 

Crude Oil and Condensate

 

Thailand Prices.     Since the inception of production from the Tantawan Field, crude oil and condensate have been stored on the FPSO until an economic quantity is accumulated for offloading and sale. The first such sale of crude oil and condensate from the Tantawan Field occurred in July 1997. Commencing in July 1999 when production began from the Benchamas Field, crude oil and condensate from that field has been stored on the FSO and sold as economic quantities are accumulated.  A typical sale ranges from 200,000 to 750,000 barrels. Prices that the Company receives for its crude oil and condensate production from Thailand are based on world benchmark prices, typically as a differential to Malaysian TAPIS crude, and are denominated in U.S. dollars.

 

Production.     The decrease in the Company’s crude oil and condensate production during the first quarter of 2004, compared to the first quarter of 2003, resulted primarily from the temporary shutdown of the Benchamas field in the Gulf of Thailand discussed above and, to a lesser extent, natural production declines at other properties.

 

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In accordance with generally accepted accounting principles, the Company records its oil production in the Kingdom of Thailand at the time of sale, rather than when produced.  At the end of each quarter, the crude oil and condensate stored on board the FSO and FPSO pending sale is accounted for as inventory at cost.  Reported revenues are based on sales volumes. When a tanker load of oil is sold in Thailand, the entire amount will be accounted for as production sold, regardless of when it was produced.  As of March 31, 2004, the Company had approximately 289,000 net barrels stored on board the FPSO and FSO.

 

NGL Production.     The Company’s oil and gas revenues, and its total liquid hydrocarbon production, also reflect the production and sale by the Company of NGL, which are liquid products that are extracted from natural gas production. The increase in NGL revenues for the first quarter of 2004, compared with the first quarter of 2003, primarily related to an increase in NGL prices received from $24.25 per barrel in the first quarter of 2003 to $25.43 per barrel in the first quarter of 2004, and, to a lesser extent, an increase in volumes extracted (primarily from the Company’s Mississippi Canyon Blocks 661/705 Field gas production.)

 

Costs and Expenses

 

		1st Quarter 2004			1st Quarter 2003			% Change 2004 to 2003
Comparison of Increases (Decreases) in:
Lease Operating Expenses
United States		$	23,472,000		$	21,156,000		11	%
Kingdom of Thailand		$	11,403,000		$	9,635,000		18	%
Total Lease Operating Expenses		$	34,875,000		$	30,791,000		13	%
General and Administrative Expenses		$	17,232,000		$	13,372,000		29	%
Exploration Expenses		$	8,471,000		$	1,832,000		362	%
Dry Hole and Impairment Expenses		$	11,623,000		$	2,178,000		434	%
Depreciation, Depletion and
Amortization (DD&A) Expenses		$	87,339,000		$	80,419,000		9	%
DD&A rate		$	1.50		$	1.29		16	%
Mcfe sold (a)		58,121,000			62,326,000			(7	)%
Production and Other Taxes		$	9,538,000		$	8,954,000		7	%
Transportation and Other		$	5,125,000		$	7,293,000		(30	)%
Interest—
Charges		$	(9,444,000	)	$	(13,695,000	)	(31	)%
Capitalized Interest Expense		$	4,548,000		$	4,014,000		13	%
Income Tax Expense		$	(57,551,000	)	$	(66,123,000	)	(13	)%

 

(a) “Mcfe” stands for thousands of cubic feet equivalent

 

Lease Operating Expenses

 

The increase in United States lease operating expenses for the first quarter of 2004, compared to the first quarter of 2003, is related primarily to expenses incurred on the properties acquired by the Company during the latter part of 2003 and also to increased expenses incurred as the Company continues to expand production in the Los Mogotes field in South Texas.

 

The increase in lease operating expenses in the Kingdom of Thailand for the first quarter of 2004, compared to the first quarter of 2003, primarily related to increased maintenance work performed during the first quarter 2004 temporary shutdown of production at the Benchamas field and to costs incurred to restore the Benchamas field to full production.  A substantial portion of the Company’s lease operating expenses in the Kingdom of Thailand are fixed costs related to the lease payments made in connection with the bareboat charters of the FPSO for the Tantawan field and the FSO for the Benchamas field.  Collectively, these lease payments accounted for approximately $3,400,000 (net to the Company’s interest) of the Company’s Thailand lease operating expenses for the first quarters of 2004 and 2003.  The Company currently expects these lease payments to remain relatively constant at approximately $14,500,000 per year (net to the Company’s interest) for the next several years.

 

On a per unit of production basis, the Company’s total lease operating expenses have increased from an average of $0.48 per Mcfe for the first quarter of 2003 to $0.61 per Mcfe for the first quarter of 2004.   The per unit of production increase is primarily related to the Benchamas production shutdown during the first quarter of 2004 which significantly reduced crude oil and condensate production while operating expenses on the Benchamas field did not decrease proportionately due to the factors discussed above.

 

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General and Administrative Expenses

 

The increase in general and administrative expenses for the first quarter of 2004 compared with the first quarter of 2003, primarily related to increases in compensation and related benefit expense and increased professional fees (due in part to compliance with Sarbanes-Oxley legislation) and, to a lesser extent, increased billings from the operator of the Company’s Thailand concession.  On a per unit of production basis, the Company’s general and administrative expenses increased to $0.30 per Mcfe in the first quarter of 2004 from $0.21 per Mcfe in the first quarter of 2003.

 

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. The increase in exploration expenses for the first quarter of 2004, compared to the first quarter of 2003, resulted primarily from the acquisition of approximately $7 million of 3-D seismic data covering approximately 1.4 million acres of the Gulf of Mexico.  The Company used this seismic data to identify prospective lease blocks for bid at the March 2004 federal oil and gas lease sale.  The Company was the high bidder on fifteen of the lease blocks at the March sale.  There were no expenditures of comparable size incurred during the first quarter of 2003.

 

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. During the first quarters of 2004 and 2003, the Company drilled three and one unsuccessful exploratory wells, respectively.  As previously announced, each of the unsuccessful exploratory wells evaluated during 2004 (totaling approximately $9.3 million) were in the Company’s Hungary acreage.  Generally accepted accounting principles also 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, these reserves must be impaired and written down to the property’s 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, impairment could be required on some of the Company’s properties and this impairment could have a material negative non-cash impact on the Company’s earnings and balance sheet.  During the first quarters of 2004 and 2003, the Company recognized miscellaneous impairments on various non-producing prospects and leases.

 

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. The Company generally creates cost centers on a field-by-field basis for oil and gas activities in the Gulf of Mexico and Gulf of Thailand. Generally, the Company establishes cost centers on the basis of an oil or gas trend or play for its onshore oil and gas activities. The increase in the Company’s DD&A expenses for the first quarter of 2004 compared to the first quarter of 2003 resulted primarily from an increase in the Company’s composite DD&A rate, partially offset by a decrease in the Company’s natural gas and liquid hydrocarbon production.

 

The increase in the composite DD&A rate for all of the Company’s producing fields for the first quarter of 2004, compared to the first quarter of 2003, 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 the Benchamas field and properties in the Gulf of Mexico) 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 increased production from properties acquired in the North Central acquisition).

 

Production and Other Taxes

 

The increase in production and other taxes during the first quarter of 2004, compared to the first quarter of 2003, relates primarily to increased severance taxes due to higher onshore prices. The Company also recognized $1,788,000 and $2,374,000 during the first quarters of 2004 and 2003, respectively, of the Special Remuneration Benefit (SRB) obligation related to the Company’s Kingdom of Thailand concession. SRB is a payment to the Thai government required by the Company’s concession agreement after certain specified revenue, expenditure and drilling criteria have been achieved.  It is currently anticipated that the Company will continue to pay SRB for the foreseeable future.

 

Transportation and Other

 

Transportation and other expense includes the Company’s cost to move its products to market (transportation costs), accretion expense related to Company asset retirement obligation, tubular inventory valuation write-offs and allowances, adjustments to the Company’s post-retirement benefit plan obligation and various other operating expenses, none of which represents more than 5% of this expense category.  The decrease in transportation and other expense for the first quarter of 2004, compared to the first quarter of 2003, relates primarily to a reduction in the Company’s transportation expense and the inclusion in 2003 of a $738,000 write down of the cost of the Company’s tubular inventory stock, for which no comparable expense was incurred in 2004. The Company incurred transportation expense of $3,125,000 and $4,217,000 in the first quarters of 2004 and 2003, respectively.

 

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Interest

 

Interest Charges.     The decrease in the Company’s interest charges for the first quarter of 2004, compared to the first quarter of 2003, resulted primarily from a decrease of approximately $197,000,000 in the average amount of the Company’s outstanding debt.

 

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 2004, compared to the first quarter of 2003, resulted primarily from an increase in the weighted average rate on remaining outstanding borrowings, after the decrease of approximately $197,000,000 of borrowings repaid mentioned above. The interest rates on the borrowings repaid were below the rates of the remaining borrowings, resulting in a higher weighted average rate to be applied to the cost of oil and gas projects in progress.  In addition the rate increase, but to a lesser extent, the Company experienced an increase in the amount of oil and gas projects in progress subject to interest capitalization during 2004 (approximately $216,000,000), compared to 2003 (approximately $206,000,000).

 

Income Tax Expense

 

Changes in the Company’s income tax expense are a function of the Company’s consolidated effective tax rate and its pre-tax income. The decrease in the Company’s tax expense for the first quarter of 2004, compared to the first quarter of 2003, resulted primarily from decreased pre-tax income during 2004, partially offset by a increase in the Company’s effective tax rate during the 2004 period. The Company’s consolidated effective tax rate for the first quarters of 2004 and 2003 was 45% and 42%, respectively.   The higher effective tax rate is the result of a higher percentage of the Company’s pre-tax income being derived from its Thailand operations during 2004 as compared to the 2003 period.  The Thailand income is taxed at a rate higher than the U.S. statutory rate.

 

Cumulative Effect of Change in Accounting Principle

 

The Company adopted SFAS No. 143, “Accounting for Asset Retirement Obligations,” (“SFAS 143”) as of January 1, 2003, which required the Company to record the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. Upon adoption of SFAS 143, the Company was required to recognize a liability for the present value of all legal obligations associated with the retirement of tangible long-lived assets and an asset retirement cost was capitalized as part of the carrying value of the associated asset. Upon initial application of SFAS 143, the Company recorded an after-tax charge to recognize the cumulative effect of a change in accounting principle of $4,166,000.  This charge was required in order to recognize a liability for any existing AROs adjusted for cumulative accretion, and also to increase the carryin g amount of the associated long-lived asset and its accumulated depreciation.

 

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 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 quarter of 2004 was $221,069,000 compared to cash flow from operating activities of $223,975,000 in the first quarter of 2003.  The decrease is attributable to the reasons described under “Results of Operations” above.  Cash flow from operating activities during the first quarter of 2004 was more than adequate to fund $114,265,000 in cash expenditures for capital and exploration projects for the year.  The Company also repaid approximately $96,000,000 of cash (net of borrowings) to settle debt obligations and paid $3,191,000 of dividends on the Company’s common stock during the first quarter of 2004.  As of March 31, 2004, the Company had cash and cash equivalents of $188,170,000 (including $169,794,000 in international subsidiaries which the Company intends to reinvest in its foreign operations) and long-term debt obligations of $393,000,000 (excluding debt discount of $1,653,000) with no repayment obligations until 2006.  On April 19, 2004, the Company redeemed all $150,000,000 of its 2009 Notes for $157,782,000 in cash. The Company may determine to repurchase additional 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 23, 2004, the Company’s lenders redetermined the borrowing base under its Credit Agreement at $900,000,000.  The available borrowing capacity under the Credit Agreement is currently $515,000,000.  As of April 26, 2004, the Company had an outstanding balance of $195,000,000 under its Credit Agreement.

 

Future Capital and Other Expenditure Requirements

 

The Company’s capital and exploration budget for 2004, 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 established by the Company’s Board of Directors at $415,000,000.  The Company has included 300 gross wells in its 2004 capital and exploration budget (55 of which were drilled in the first quarter of 2004), including wells to be drilled in the United States, the Kingdom of Thailand, Hungary and Denmark.  The Company currently anticipates that its available cash and cash investments, cash provided by operating activities and funds available under its Credit Agreement will be sufficient to fund the Company’s ongoing operating, interest and general and administrative expenses, its authorized

 

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capital budget, 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 remaining debt instruments, the general economic and regulatory climate and other factors deemed relevant by the Company’s Board of Directors.

 

Recent Accounting Developments

 

The Company has been made aware that an issue has arisen regarding the application of provisions of SFAS No. 141, “Business Combinations” and SFAS No. 142, “Goodwill and Other Intangible Assets” (“SFAS 142”) to companies in the extractive industries, including oil and gas companies.  The issue is whether SFAS 142 requires registrants to reclassify costs associated with mineral rights, including both proved and unproved leasehold acquisition costs, as intangible assets in the balance sheet, apart from other capitalized oil and gas property costs.  Historically, the Company and other oil and gas companies have included the cost of these oil and gas leasehold interests as part of oil and gas properties and provided the disclosures required by SFAS No. 69, “Disclosures about Oil and Gas Producing Activities” (“SFAS 69”).   Also under consideration is whether SFAS 142 requires registrants to provide the additional disclosures prescribed by SFAS 142 for intangible assets for costs associated with mineral rights.

 

The Emerging Issues Task Force (“EITF”) has recently decided to consider this issue.  If the EITF determines that SFAS 142 requires the Company to reclassify costs associated with mineral rights from property and equipment to intangible assets, the Company currently believes that its results of operations and financial condition would not be affected, since such intangible assets would continue to be depleted and assessed for impairment in accordance with existing successful efforts accounting rules and impairment standards.  In addition, costs associated with mineral rights would continue to be characterized as oil and gas property costs in the Company’s required disclosures under SFAS 69.

 

At March 31, 2004, the Company had undeveloped leaseholds of approximately $78 million that would be classified on the balance sheet as “intangible undeveloped leaseholds” and developed leaseholds of approximately $1,131 million (net of accumulated depletion) that would be classified as “intangible developed leaseholds” if the Company applied the interpretation currently being discussed.

 

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 limited 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.  As of April 26, 2004, the Company held no commodity derivative contracts.

 

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 26, 2004, 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 thousands) and related average interest rates by year of maturity for the Company’s debt obligations and their indicated fair market value at March 31, 2004:

 

 

		2004				2005			2006			2007			2008			Thereafter			Total			Fair Value
Long-Term Debt:
Variable Rate		$		0		$	0		$	43,000		$	0		$	0		$	0		$	43,000		$	43,000
Average Interest Rate		—				—			2.66		%	—			—			—			2.66		%	—
Fixed Rate		$	0			$	0		$	0		$	0		$	0		$	350,000		$	350,000		$	382,188
Average Interest Rate		—				—			—			—			—			9.16		%	9.16		%	—

 

Foreign Currency Exchange Rate Risk

 

In addition to the U.S. dollar, the Company and certain of its subsidiaries conduct their business in Thai Baht and Hungarian Forint and are therefore subject to foreign currency exchange rate risk on cash flows related to sales, expenses, financing and investing transactions. The Company conducts a substantial portion of its oil and gas production and sales in Southeast Asia. Southeast Asia in general, and the Kingdom of Thailand in particular, have experienced severe economic difficulties in the recent past, including sharply reduced economic activity, illiquidity, highly volatile foreign currency exchange rates and unstable stock markets.  The economic situation

 

16

 

in Thailand and the volatility of the Thai Baht against the dollar could have a material impact on the Company’s Thailand operations and prices that the Company receives for its oil and gas production there. Although the Company’s sales to PTT under the Gas Sales Agreement are denominated in Baht, because predominantly all of the Company’s crude oil sales and its capital and most other expenditures in the Kingdom of Thailand are denominated in U.S. dollars, the dollar is the functional currency for the Company’s operations in the Kingdom of Thailand. As of April 26, 2004, the Company is not a party to any foreign currency exchange agreement.

 

Exposure from market rate fluctuations related to activities in Hungary, where the Company’s functional currency is the U.S. dollar, is not material at this time.

 

ITEM 4.  Controls and Procedures.

 

The Company carried out an evaluation, under the supervision and with the participation of the Company’s management, including the Company’s Chairman, President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer, of the effectiveness of the Company’s disclosure controls and procedures pursuant to Rule 13a-15(e) under the Securities Exchange Act of 1934, as amended, as of the end of the period covered by this quarterly report.  Based upon that evaluation, the Company’s Chairman, President and Chief Executive Officer and its Senior Vice President and Chief Financial Officer concluded that the Company’s disclosure controls and procedures are effective in timely alerting them to material information required to be included in our periodic Securities and Exchange Commission filings.

 

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.

 

17

 

Part II.  Other Information

 

ITEM 4.  Submission of Matters to Vote of Security Holders

 

None

 

ITEM 6.  Exhibits and Reports on Form 8-K.

 

(A)        Exhibits

 

3.1 —		Restated Certificate of Incorporation of Pogo Producing Company, as filed on April 28, 2004
*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).
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.

 

(B)          Reports on Form 8-K

 

During the quarter for which this report is filed, the following report on Form 8-K was filed:

 

Report filed on January 27, 2004 relating to the date of the Company’s 2004 Annual meeting of Shareholders and also relating to the press release dated January 27, 2004 regarding the Company’s 2003 results.

 

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/ Thomas E. Hart
										Thomas E. Hart
										Vice President and Chief
										Accounting Officer
										/s/ James P. Ulm, II
										James P. Ulm, II
										Senior Vice President and Chief
										Financial Officer
Date: April 30, 2004

 

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