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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, 2005 or

 

o Transition report pursuant to section 13 or 15(d) of the Securities

Exchange Act of 1934

 

For the transition period from     to     

 

Commission file number 1-7792

 

POGO PRODUCING COMPANY

(Exact Name of Registrant as Specified in Its Charter)

 

Delaware

 

74-1659398

(State or Other Jurisdiction of
Incorporation or Organization)

 

(I.R.S. Employee
Identification No.)

 

 

 

5 Greenway Plaza, Suite 2700
Houston, Texas

 

77046-0504

(Address of principal executive offices)

 

(Zip Code)

 

(713) 297-5000

(Registrant’s Telephone Number, Including Area Code)

 

Not Applicable

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

 

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days: Yes 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 May 2, 2005:

60,996,981

 

 

 

 



 

PART I. FINANCIAL INFORMATION

 

ITEM 1. FINANCIAL STATEMENTS

 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Consolidated Statements of Income (Unaudited)

 

 

 

Three Months Ended
March 31,

 

 

 

2005

 

2004

 

 

 

(Expressed in thousands,
except per share amounts)

 

 

 

 

 

 

 

Revenues:

 

 

 

 

 

Oil and gas

 

$

355,700

 

$

307,327

 

Other

 

13,090

 

555

 

Total

 

368,790

 

307,882

 

 

 

 

 

 

 

Operating Costs and Expenses:

 

 

 

 

 

Lease operating

 

40,249

 

34,875

 

General and administrative

 

20,727

 

17,232

 

Exploration

 

11,285

 

8,471

 

Dry hole and impairment

 

47,403

 

11,623

 

Depreciation, depletion and amortization

 

100,645

 

87,339

 

Production and other taxes

 

21,799

 

9,538

 

Transportation and other

 

6,296

 

5,125

 

Total

 

248,404

 

174,203

 

 

 

 

 

 

 

Operating Income

 

120,386

 

133,679

 

Interest:

 

 

 

 

 

Charges

 

(10,211

)

(9,444

)

Income

 

1,210

 

452

 

Capitalized

 

2,197

 

4,548

 

Foreign Currency Transaction Gain (Loss)

 

179

 

(44

)

Income Tax Expense

 

(54,525

)

(57,551

)

Net Income

 

$

59,236

 

$

71,640

 

 

 

 

 

 

 

Earnings Per Common Share

 

 

 

 

 

Basic

 

$

0.93

 

$

1.13

 

Diluted

 

$

0.93

 

$

1.12

 

 

 

 

 

 

 

Dividends Per Common Share

 

$

0.0625

 

$

0.05

 

 

 

 

 

 

 

Weighted Average Number of Common Shares
and Potential Common Shares Outstanding:

 

 

 

 

 

Basic

 

63,506

 

63,668

 

Diluted

 

64,067

 

64,213

 

 

See accompanying notes to consolidated financial statements.

 



 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Consolidated Balance Sheets (Unaudited)

 

 

 

March 31,
2005

 

December 31,
2004

 

 

 

(Expressed in thousands,
except share amounts)

 

Assets

 

 

 

 

 

Current Assets:

 

 

 

 

 

Cash and cash equivalents

 

$

231,060

 

$

86,456

 

Current investments

 

 

135,000

 

Accounts receivable

 

173,436

 

140,988

 

Other receivables

 

48,503

 

37,229

 

Federal income tax receivable

 

 

10,708

 

Inventories - product

 

4,234

 

5,062

 

Inventories - tubulars

 

20,442

 

17,850

 

Price hedge contracts

 

 

6,722

 

Other

 

2,894

 

5,395

 

Total current assets

 

480,569

 

445,410

 

 

 

 

 

 

 

Property and Equipment:

 

 

 

 

 

 

 

 

 

 

 

Oil and gas, on the basis of successful efforts accounting

 

 

 

 

 

Proved properties

 

5,017,575

 

4,931,264

 

Unevaluated properties

 

94,182

 

83,196

 

Other, at cost

 

38,986

 

36,492

 

 

 

5,150,743

 

5,050,952

 

Accumulated depreciation, depletion and amortization

 

 

 

 

 

Oil and gas

 

(2,114,959

)

(2,017,900

)

Other

 

(25,061

)

(23,858

)

 

 

(2,140,020

)

(2,041,758

)

Property and equipment, net

 

3,010,723

 

3,009,194

 

 

 

 

 

 

 

Other Assets:

 

 

 

 

 

Foreign value added taxes receivable

 

5,927

 

8,471

 

Other

 

18,959

 

18,034

 

 

 

24,886

 

26,505

 

 

 

 

 

 

 

 

 

$

3,516,178

 

$

3,481,109

 

 

See accompanying notes to consolidated financial statements.

 

2



 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Consolidated Balance Sheets (Unaudited)

 

 

 

March 31,
2005

 

December 31,
2004

 

 

 

(Expressed in thousands,
except share amounts)

 

Liabilities and Shareholders’ Equity

 

 

 

 

 

 

 

 

 

 

 

Current Liabilities:

 

 

 

 

 

Accounts payable - operating activities

 

$

84,963

 

$

72,228

 

Accounts payable - investing activities

 

114,119

 

128,075

 

Income taxes payable

 

77,712

 

34,776

 

Accrued interest payable

 

9,156

 

4,550

 

Accrued payroll and related benefits

 

3,751

 

3,609

 

Price hedge contracts

 

14,663

 

 

Deferred income tax

 

1,582

 

4,919

 

Other

 

43,390

 

31,862

 

Total current liabilities

 

349,336

 

280,019

 

 

 

 

 

 

 

Long-Term Debt

 

777,305

 

755,000

 

 

 

 

 

 

 

Deferred Income Tax

 

597,374

 

601,688

 

 

 

 

 

 

 

Price Hedge Contracts

 

4,478

 

2,119

 

 

 

 

 

 

 

Asset Retirement Obligation

 

93,129

 

95,140

 

 

 

 

 

 

 

Other Liabilities and Deferred Credits

 

20,101

 

19,248

 

 

 

 

 

 

 

Total liabilities

 

1,841,723

 

1,753,214

 

 

 

 

 

 

 

Commitments and Contingencies

 

 

 

 

 

 

 

 

 

Shareholders’ Equity:

 

 

 

 

 

Preferred stock, $1 par; 4,000,000 shares authorized

 

 

 

Common stock, $1 par; 200,000,000 shares authorized, 64,677,440 and 64,580,639 shares issued, respectively

 

64,677

 

64,581

 

Additional capital

 

947,479

 

943,690

 

Retained earnings

 

783,962

 

728,723

 

Deferred compensation

 

(9,217

)

(9,954

)

Accumulated other comprehensive income (loss)

 

(12,117

)

2,565

 

Treasury stock (2,169,159 and 55,359 shares, respectively), at cost

 

(100,329

)

(1,710

)

Total shareholders’ equity

 

1,674,455

 

1,727,895

 

 

 

 

 

 

 

 

 

$

3,516,178

 

$

3,481,109

 

 

See accompanying notes to consolidated financial statements.

 

3



 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Condensed Consolidated Statements of Cash Flows (Unaudited)

 

 

 

Three Months Ended
March 31,

 

 

 

2005

 

2004

 

 

 

(Expressed in thousands)

 

Cash Flows from Operating Activities:

 

 

 

 

 

Cash received from customers

 

$

351,212

 

$

292,206

 

Operating, exploration, and general
and administrative expenses paid

 

(84,858

)

(61,117

)

Interest paid

 

(5,320

)

(9,202

)

Income taxes paid

 

 

(1,000

)

Value added taxes (paid)/received

 

2,544

 

(700

)

Other

 

100

 

882

 

Net cash provided by operating activities

 

263,678

 

221,069

 

 

 

 

 

 

 

Cash Flows from Investing Activities:

 

 

 

 

 

Capital expenditures

 

(170,255

)

(93,767

)

Purchase of properties

 

(20,934

)

(20,727

)

Sale of current investments

 

151,750

 

22,597

 

Purchase of current investments

 

(16,750

)

(42,756

)

Proceeds from the sale of properties

 

250

 

229

 

Net cash used in investing activities

 

(55,939

)

(134,424

)

 

 

 

 

 

 

Cash Flows from Financing Activities:

 

 

 

 

 

Borrowings under senior debt agreements

 

669,000

 

113,000

 

Payments under senior debt agreements

 

(944,000

)

(209,000

)

Proceeds from 2015 Notes

 

297,303

 

 

Purchase of Company stock

 

(81,451

)

 

Payments of cash dividends on common stock

 

(3,997

)

(3,191

)

Payment of debt issue costs

 

(2,553

)

 

Proceeds from exercise of stock options

 

2,765

 

1,824

 

Net cash used in financing activities

 

(62,933

)

(97,367

)

Effect of exchange rate changes on cash

 

(202

)

(21

)

 

 

 

 

 

 

Net (decrease) increase in cash and cash equivalents

 

144,604

 

(10,743

)

Cash and cash equivalents at the beginning of the year

 

86,456

 

104,474

 

Cash and cash equivalents at the end of the period

 

$

231,060

 

$

93,731

 

 

 

 

 

 

 

Reconciliation of net income to net cash provided by operating activities:

 

 

 

 

 

Net income

 

$

59,236

 

$

71,640

 

Adjustments to reconcile net income to net cash provided by operating activities -

 

 

 

 

 

Gains from the sales of properties

 

(250

)

(228

)

Depreciation, depletion and amortization

 

100,645

 

87,339

 

Dry hole and impairment

 

47,403

 

11,623

 

Interest capitalized

 

(2,197

)

(4,548

)

Price hedge contracts

 

1,156

 

 

Other

 

3,000

 

2,041

 

Deferred income taxes

 

882

 

1,439

 

Change in operating assets and liabilities

 

53,803

 

51,763

 

Net cash provided by operating activities

 

$

263,678

 

$

221,069

 

 

See accompanying notes to consolidated financial statements.

 

4



 

POGO PRODUCING COMPANY AND SUBSIDIARIES

 

Consolidated Statements of Shareholders’ Equity (Unaudited)

 

 

 

For the Three Months Ended March 31,

 

 

 

2005

 

2004

 

 

 

Shareholders’
Equity

 

Comprehensive

 

Shareholders’
Equity

 

Comprehensive

 

 

 

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

 

64,580,639

 

$

64,581

 

 

 

63,813,283

 

$

63,813

 

 

 

Stock option activity and other

 

95,401

 

95

 

 

 

76,534

 

77

 

 

 

Shares issued as compensation

 

1,400

 

1

 

 

 

 

 

 

 

Issued at end of period

 

64,677,440

 

64,677

 

 

 

63,889,817

 

63,890

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Additional Capital:

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at beginning of year

 

 

 

943,690

 

 

 

 

 

914,492

 

 

 

Stock option activity and other

 

 

 

3,715

 

 

 

 

 

2,733

 

 

 

Shares issued as compensation

 

 

 

74

 

 

 

 

 

 

 

 

Balance at end of period

 

 

 

947,479

 

 

 

 

 

917,225

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Retained Earnings:

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at beginning of year

 

 

 

728,723

 

 

 

 

 

480,576

 

 

 

Net income

 

 

 

59,236

 

$

59,236

 

 

 

71,640

 

$

71,640

 

Dividends ($0.0625 and $0.05 per common share, respectively)

 

 

 

(3,997

)

 

 

 

 

(3,191

)

 

 

Balance at end of period

 

 

 

783,962

 

 

 

 

 

549,025

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Accumulated Other
Comprehensive Income (Loss):

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at beginning of year

 

 

 

2,565

 

 

 

 

 

 

 

 

Change in fair value of price hedge contracts

 

 

 

(13,526

)

(13,526

)

 

 

 

 

Reclassification adjustment for losses (gains) included in net income

 

 

 

(1,156

)

(1,156

)

 

 

 

 

Balance at end of period

 

 

 

(12,117

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Deferred Compensation

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at beginning of year

 

 

 

(9,954

)

 

 

 

 

(3,518

)

 

 

Activity during the period

 

 

 

737

 

 

 

 

 

245

 

 

 

Balance at end of period

 

 

 

(9,217

)

 

 

 

 

(3,273

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Comprehensive Income (Loss)

 

 

 

 

 

$

44,554

 

 

 

 

 

$

71,640

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Treasury Stock:

 

 

 

 

 

 

 

 

 

 

 

 

 

Balance at beginning of year

 

(55,359

)

(1,710

)

 

 

(55,359

)

(1,710

)

 

 

Activity during the period

 

(2,113,800

)

(98,619

)

 

 

 

 

 

 

Balance at end of period

 

(2,169,159

)

(100,329

)

 

 

(55,359

)

(1,710

)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Common Stock Outstanding, at the End of the Period

 

62,508,281

 

 

 

 

 

63,834,458

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Shareholders’ Equity

 

 

 

$

1,674,455

 

 

 

 

 

$1,525,157

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

See accompanying notes to consolidated financial statements.

 

5



 

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), whic h 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, 2004.

 

Revision in the Classification of Certain Securities—

 

In connection with the preparation of the December 31, 2004 10-K, the Company concluded that it was appropriate to classify our auction rate municipal bonds and variable rate municipal demand notes as current investments. Previously, such investments had been classified as cash and cash equivalents. Accordingly, the classification in the March 31, 2004 Condensed Consolidated Statement of Cash Flows has been revised to report sales of current investments of $22.6 million and purchases of current investments of $42.8 million as investing activities rather than as cash and cash equivalents. For the quarter ended March 31, 2004 net cash used in investing activities related to these current investments of $20.2 million was previously included in cash and cash equivalents in the Condensed Consolidated Statement of Cash Flows. This change in classification does not affect previously reported cash flows from operating or financing activities, or the previously reported Condensed Consolidated Statement of Income.

 

 

(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, 2005

 

 

 

Income

 

Shares

 

Per Share

 

Basic earnings per share -

 

$

59,236

 

63,506

 

$

0.93

 

Effect of dilutive securities:

 

 

 

 

 

 

 

Options to purchase common shares

 

 

 

561

 

 

 

Diluted earnings per share

 

$

59,236

 

64,067

 

$

0.93

 

Antidilutive securities -
Options to purchase common shares

 

 

 

25

 

$

49.02

 

 

 

 

Three Months Ended
March 31, 2004

 

 

 

Income

 

Shares

 

Per Share

 

Basic earnings per share -

 

$

71,640

 

63,668

 

$

1.13

 

Effect of dilutive securities:

 

 

 

 

 

 

 

Options to purchase common shares

 

 

 

545

 

 

 

Diluted earnings per share

 

$

71,640

 

64,213

 

$

1.12

 

Antidilutive securities -
Options to purchase common shares

 

 

 

 

$

 

 

(3) LONG-TERM DEBT –

 

Long-term debt at March 31, 2005 and December 31, 2004, consists of the following (dollars expressed in thousands):

 

 

 

March 31,
2005

 

December 31,
2004

 

Senior debt -

 

 

 

 

 

Bank revolving credit agreement:

 

 

 

 

 

LIBOR based loans, borrowings at March 31, 2005 and December 31, 2004 at interest rates of 3.8105% and 3.665%, respectively

 

$

190,000

 

$

515,000

 

Prime based loans, borrowings at March 31, 2005 at an interest rate of 5.75%

 

50,000

 

 

 

LIBOR Rate Advances, borrowings at March 31, 2005 and December 31, 2004 at interest rates of 3.93% and 3.5275%, respectively

 

40,000

 

40,000

 

Total senior debt

 

280,000

 

555,000

 

Subordinated debt -

 

 

 

 

 

8 1/4% Senior subordinated notes, due 2011

 

200,000

 

200,000

 

6 5/8% Senior subordinated notes, due 2015

 

300,000

 

 

Total subordinated debt

 

500,000

 

200,000

 

Unamortized discount on 2015 Notes

 

(2,695

)

 

Total debt

 

777,305

 

755,000

 

Amount due within one year

 

 

 

Long-term debt

 

$

777,305

 

$

755,000

 

 

6



 

On March 29, 2005, the Company issued $300,000,000 principal amount of 2015 Notes at 99.101%. The proceeds from the sale of the 2015 Notes were used to pay down obligations under the Company’s bank credit facility.  The 2015 Notes bear interest at a rate of 6 5/8%, payable semi-annually in arrears on March 15 and September 15 of each year. The 2015 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company’s senior indebtedness, which currently includes the Company’s obligations under the Credit Facility and LIBOR advances.  The Company, at its option, may redeem the 2015 Notes in whole or in part, at any time on or after March 15, 2010, at a redemption price of 103.3125% of their principal value and decreasing percentages thereafter. The Company may also redeem a portion of the 2015 Notes prior to March 15, 2008 and some or all of the Notes prior to March 15, 2010, in each case by paying specified premiums.  The indenture governing the 2015 Notes also imposes certain covenants on the Company including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of assets sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and merger, consolidations and the sale of assets.

 

(4) INCOME TAXES –

 

On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the “Act”).  The Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividend received deduction for certain dividends from controlled foreign corporations.  The deduction is subject to a number of limitations and, as of May 4, 2005, uncertainty remains as to how to interpret numerous provisions of the Act.  As a result, the Company is not yet in a position to decide whether, and to what extent, it might repatriate foreign earnings that have not yet been remitted to the U.S. from its foreign subsidiaries.  If certain technical corrections to the Act are passed, the Company may consider repatriating an amount up to $212.5 million of the cash and cash equivalents held by international subsidiaries as of March 31, 2005, with an associated tax liability of approximately $11.2 million (assuming 15% of such cash is subject to tax at the U.S. statutory rate).

 

(5) 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 periods ended March 31, 2005 and 2004 is as follows (in thousands):

 < /font>

 

 

2005

 

2004

 

ARO as of January 1,

 

$

95,140

 

$

70,790

 

Liabilities incurred during the three months ended March 31,

 

3,226

 

12,249

 

Liabilities settled during the three months ended March 31,

 

(3,317

)

 

Accretion expense

 

1,625

 

1,306

 

Balance of ARO as of March 31,

 

$

96,674

 

$

84,345

 

Less: current portion of ARO

 

(3,545

)

 

Long-term ARO as of March 31,

 

$

93,129

 

$

84,345

 

 

For the three months ended March 31, 2005 and 2004 the Company recognized depreciation expense related to its ARC of $1,611,000 and $1,098,000, respectively.

 

(6) HEDGING ACTIVITIES -

 

As of March 31, 2005, the Company held various derivative instruments.  During 2004 and 2005, 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 has 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. 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-month period ended March 31, 2005, activity from the Company’s price hedge contracts had no effect on oil and gas revenues.  The Company did recognize a pre-tax loss of $1,156,000 due to ineffectiveness on these hedge contracts during the first quarter of 2005.  Net unrealized losses on derivative instruments of $12,117,000, net of deferred taxes of $6,523,000, have been reflected as a component of other comprehensive income for the three months ended March 31, 2005.  During the three-month period ended March 31, 2004, the Company held no derivative instruments and there were no hedging activities during the first quarter of 2004.  Based on the fair market value of the hedge contracts as of March 31, 2005, the Company would reclassify additional pre-tax losses of approximately

 

7



 

$14,663,000 (approximately $9,531,000 after taxes) from accumulated other comprehensive income (loss) (shareholders’ equity) to net income during the next twelve months.

 

The gas hedging transactions 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 hedging transactions are generally settled based on the average of the reporting 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 transactions 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, 2005 are as follows:

 

Contract Period and

 

 

 

NYMEX
Contract
Price

 

Fair Value
of

 

Type of Contract

 

Volume

 

Floor

 

Ceiling

 

Asset/(Liability)

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Contracts (MMBtu) (a)

 

 

 

 

 

 

 

 

 

Collar Contracts:

 

 

 

 

 

 

 

 

 

April 2005 - December 2005

 

4,125

 

$

5.50

 

$

8.00

 

$

(2,223,459

)

April 2005 - December 2005

 

1,375

 

$

6.00

 

$

9.30

 

$

(247,817

)

April 2005 - December 2005

 

1,375

 

$

6.00

 

$

9.25

 

$

(258,776

)

April 2005 - December 2005

 

2,750

 

$

6.00

 

$

9.25

 

$

(517,553

)

April 2005 - December 2005

 

1,375

 

$

6.00

 

$

10.25

 

$

(97,380

)

April 2005 - December 2005

 

2,750

 

$

6.00

 

$

10.30

 

$

(183,692

)

January 2006 - December 2006

 

5,475

 

$

5.00

 

$

7.50

 

$

(5,069,822

)

January 2006 - December 2006

 

3,650

 

$

5.50

 

$

8.25

 

$

(2,121,749

)

January 2006 - December 2006

 

3,650

 

$

5.75

 

$

8.27

 

$

(1,925,689

)

 

 

 

 

 

 

 

 

 

 

Crude Oil Contracts (Barrels)

 

 

 

 

 

 

 

 

 

Collar Contracts:

 

 

 

 

 

 

 

 

 

April 2005 - December 2005

 

2,750,000

 

$

40.00

 

$

62.50

 

$

(6,281,972

)

April 2005 - December 2005

 

137,500

 

$

43.50

 

$

72.00

 

$

(48,025

)

April 2005 - December 2005

 

550,000

 

$

43.50

 

$

72.50

 

$

(165,210

)

 


(a) MMBtu means million British Thermal Units.

 

(7) GEOGRAPHIC INFORMATION –

 

Financial information by geographic segment is presented below:

 

 

 

Three Months Ended
March 31,

 

 

 

2005

 

2004

 

 

 

(Expressed in thousands)

 

Revenues:

 

 

 

 

 

United States

 

$

267,152

 

$

235,133

 

Kingdom of Thailand

 

101,638

 

72,749

 

Other

 

 

 

Total

 

$

368,790

 

$

307,882

 

 

 

 

 

 

 

Operating Income (Loss):

 

 

 

 

 

United States

 

$

78,715

 

$

108,805

 

Kingdom of Thailand

 

50,103

 

34,762

 

Other

 

(8,432

)

(9,888

)

Total

 

$

120,386

 

$

133,679

 

 

8



 

(8) 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. The Company did not make a contribution to the plan during the first three months of 2005 and does not expect to make a contribution during the remainder of 2005.

 

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 thousands of dollars):

 

 

 

Retirement Plan

 

 

 

Three Months Ended
March 31,

 

 

 

2005

 

2004

 

 

 

 

 

 

 

Service cost

 

$

827

 

$

627

 

Interest cost

 

535

 

427

 

Expected return on plan assets

 

(655

)

(663

)

Amortization of prior service cost

 

22

 

12

 

Amortization of net loss

 

317

 

152

 

 

 

$

1,046

 

$

555

 

 

 

 

Post-Retirement Medical Plan

 

 

 

Three Months Ended
March 31,

 

 

 

2005

 

2004

 

 

 

 

 

 

 

Service cost

 

$

424

 

$

344

 

Interest cost

 

316

 

271

 

Amortization of transition obligation

 

76

 

76

 

Amortization of net loss

 

92

 

56

 

 

 

$

908

 

$

747

 

 

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, 2004.

 

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. In May 2004, the FASB issued Staff Position No. 106-2, “Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” (FSP No. 106-2), which addresses the accounting and disclosure requirements associated with the effects of the Act.

 

In 2004, the Company elected not to reflect changes in the Act in its financials since the Company concluded that the effects of the Act were not a significant event that called for remeasurement under FAS 106.  At this time, the Company has not remeasured the effects of the Act.

 

9



 

(9) 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” (“SFAS 148”) for all Stock Awards granted, modified or settled after January 1, 2003.  The Company granted Stock Awards covering 2,000 shares during the three-month period ended March 31, 2005.  The Company did not grant any Stock Awards during the three-month period ended March 31, 2004.

 

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, 2005 and 2004 (in thousands of dollars, except per share amounts):

 

 

 

Three Months Ended
March 31,

 

 

 

2005

 

2004

 

 

 

 

 

 

 

Net income, as reported

 

$

59,236

 

$

71,640

 

Add:

Employee stock-based compensation expense, net of related tax effects, included in net income, as reported

 

1,010

 

485

 

Deduct:

Total employee stock-based compensation expense, determined under fair value method for all awards, net of related tax effects

 

(1,622

)

(1,672

)

Net income, pro forma

 

$

58,624

 

$

70,453

 

 

 

 

 

 

 

Earnings per share:

 

 

 

 

 

Basic - as reported

 

$

0.93

 

$

1.13

 

Basic - pro forma

 

$

0.92

 

$

1.11

 

Diluted - as reported

 

$

0.93

 

$

1.12

 

Diluted - pro forma

 

$

0.92

 

$

1.10

 

 

(10) ACQUISITIONS –

 

In December 2004, the Company completed the acquisition of two privately held corporations for approximately $282.5 million in cash and a deferred payment of $26.4 million to be made in 2005 to the former owner of one of the corporations. The corporations have subsequently been named Pogo Producing (San Juan) Company and Pogo Producing (Texas Panhandle) Company (the “corporations”).  The transactions included properties located primarily in the San Juan basin of New Mexico and the Texas Panhandle. The Company acquired the corporations primarily to strengthen its position in domestic natural gas properties. The corporations had an estimated 133 billion cubic feet of gas equivalent proven reserves (Bcfe) as of the dates of acquisition. The Company recorded the estimated fair values of the assets acquired and the liabilities assumed at the closing date of the transactions, which primarily consisted of oil and gas properties of $423.7 million, long-term debt of $50.1 million and deferred tax liabilities of $67.4 million.  No goodwill was recorded for the transactions.

 

In 2004, the Company also completed six other producing property acquisitions for cash consideration totaling approximately $186 million. These acquisitions added approximately 119 Bcfe to the Company’s proved reserves.

 

Pro Forma Information

 

The following summary presents unaudited pro forma consolidated results of operations for the quarter ended March 31, 2004 as if the acquisitions had occurred as of January 1, 2004.  The pro forma results are for illustrative purposes only and include adjustments in addition to the pre-acquisition historical results of the corporations, such as increased depreciation, depletion and amortization expense resulting from the allocation of fair value to oil and gas properties acquired and increased interest expense on acquisition debt. The unaudited pro forma information (presented in thousands of dollars, except per share amounts) is not necessarily indicative of the operating results that would have occurred had the acquisitions been consummated at that date, nor are they necessarily indicative of future operating results.

 

10



 

Pro Forma:

 

Revenues

 

 

$

319,253

 

Net income

 

74,310

 

Earnings per share:

 

 

 

Basic -

 

$

1.17

 

Diluted -

 

$

1.16

 

 

11



 

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, 2004. 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, 2004, 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

 

Total revenue for the first quarter of 2005 was $368.7 million and net income totaled $59.2 million, or $0.93 per share.  Cash flow from operations totaled $263.7 million.

 

The Company continues to have a strong balance sheet.  During the first quarter, the Company issued $300 million of 6 5/8% Senior Subordinated Notes due 2015.  Proceeds from the offering were used to reduce outstanding senior indebtedness under the Company’s revolving credit facility.  Cash and current investments increased by $10 million to $231 million at March 31, 2005.

 

2005 Capital Budget

 

The Company has established a $345 million exploration and development budget (excluding property acquisitions). The Company expects to spend approximately $187 million on exploration and $158 million on development activities. The capital budget calls for the drilling of approximately 226 wells during 2005.

 

During the first quarter of 2005, the Company spent $146 million on exploratory and development activities and, as of March 31, 2005, had spent 42% of its 2005 capital budget.  During the first quarter of 2005, 88 wells were drilled with 80 successfully completed, a 91% success rate.

 

Thailand and Hungary Disposition

 

The Company announced during the first quarter of 2005 that it would consider the sale or swap of the Company’s operations in Thailand and Hungary and has retained Goldman, Sachs & Co. to advise it on the potential transactions. International asset sale proceeds could be favorably treated by the tax provisions of the “American Jobs Creation Act of 2004”, if completed by year-end 2005. Exploration activities in Thailand and development activities in both Thailand and Hungary will run concurrently with the Company’s consideration of the sale of its operations.

 

Hurricane Ivan Update

 

Company operated Gulf of Mexico platforms did not sustain major damage as a result of Hurricane Ivan.  However, damages to outside owned and operated platforms, pipelines and onshore terminals caused a meaningful component of the Company’s Gulf of Mexico production to be shut-in during the first quarter.  In order to protect its cash flow, the Company has business interruption insurance for certain of the blocks affected by the shut-in.  The majority of shut-in volumes were brought back online late in the first quarter.  The Company recorded $11.4 million in revenue related to the business interruption insurance claim, during the first quarter.

 

Share Repurchase

 

During the first quarter of 2005, the Company announced a share repurchase plan. The Company expects to expend not less than $275 million nor more than $375 million to effect the repurchases. Based on recent stock prices, the repurchase could represent approximately 9% to 12% of the shares outstanding at December 31, 2004.  As of May 2, 2005, the Company had repurchased 3.6 million shares for approximately $170 million.

 

2005 Production Outlook Update

 

The Company currently expects that 2005 equivalent hydrocarbon production should reach within 2% of the Company’s 2004 production levels, subject to changes in circumstances, acquisitions, divestitures and many other factors.

 

Results of Operations

 

Oil and Gas Revenues

 

The Company’s oil and gas revenues for the first quarter of 2005 were $355,700,000, an increase of approximately 16% from oil and gas revenues of $307,327,000 for the first quarter of 2004.  The following table reflects an analysis of variances in the Company’s oil and gas revenues (expressed in thousands) between 2005 and 2004.

 

12



 

 

 

1st Qtr 2005
Compared to
1st Qtr 2004

 

 

 

 

 

Increase (decrease) in oil and gas revenues resulting from variances in:

 

 

 

Natural gas -

 

 

 

Price

 

$

11,234

 

Production

 

15,039

 

 

 

26,273

 

Crude oil and condensate -

 

 

 

Price

 

47,402

 

Production

 

(25,136

)

 

 

22,266

 

 

 

 

 

Natural gas liquids

 

(166

)

Increase in oil and gas revenues

 

$

48,373

 

 

The increase in the Company’s oil and gas revenues in the first quarter of 2005, compared to the first quarter of 2004, is related to increases in the average prices that the Company received for its natural gas, crude oil and condensate and increases in natural gas production volumes, partially offset by a decrease in the Company’s crude oil and condensate production volumes.  The most significant cause for the reduction in crude oil and condensate production was the shut-in of several of the Company’s offshore fields due to the infrastructure damage caused by Hurricane Ivan in mid-September of 2004.  The majority of shut-in volumes were brought back online late in the first quarter.

 

Other Revenues

 

Other revenue is revenue derived from sources other than the current production of hydrocarbons.  This revenue includes, among other items, insurance proceeds (excluding those related to operating expenses, which are credited against the appropriate expense category), pipeline imbalance settlements and revenue from salt water disposal activities.  The increase in the Company’s other revenues in the first quarter of 2005, compared to the first quarter of 2004, is related primarily to $11.4 million of business interruption insurance recorded in 2005 with no comparable insurance claim in 2004.  The business interruption insurance claim relates to the shut-in of a significant portion of the Company’s Gulf of Mexico production during the first quarter of 2005 as a result of the infrastructure damage caused by Hurricane Ivan in 2004.

 

 

 

 

 

 

 

% Change

 

 

 

1st Quarter

 

2005 to

 

 

 

2005

 

2004

 

2004

 

Comparison of Increases in:

 

 

 

 

 

 

 

Natural Gas —

 

 

 

 

 

 

 

Average prices

 

 

 

 

 

 

 

United States (a)

 

$

5.97

 

$

5.48

 

9

%

Kingdom of Thailand (b)

 

$

2.61

 

$

2.50

 

4

%

Company-wide average price

 

$

5.20

 

$

4.79

 

9

%

Average daily production volumes
(MMcf per day):

 

 

 

 

 

 

 

United States (a)

 

258.9

 

230.5

 

12

%

Kingdom of Thailand

 

76.2

 

69.1

 

10

%

Company-wide average daily production

 

335.1

 

299.6

 

12

%

 


(a)   Price hedging activity had no effect on the average price of the Company’s United States natural gas production during the first quarter of 2005The Company had no price hedging activity during the first three months of 2004.   “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.

 

13



 

 

 

 

 

 

 

% Change

 

 

 

1st Quarter

 

2005 to

 

 

 

2005

 

2004

 

2004

 

Comparison of Increases (Decreases) in:

 

 

 

 

 

 

 

Crude Oil and Condensate —

 

 

 

 

 

 

 

Average prices (a)

 

 

 

 

 

 

 

United States

 

$

43.75

 

$

35.28

 

24

%

Kingdom of Thailand

 

$

47.02

 

$

34.86

 

35

%

Company-wide average price

 

$

45.15

 

$

35.13

 

29

%

Average daily production volumes
(Bbls per day):

 

 

 

 

 

 

 

United States (a)

 

26,600

 

34,049

 

(22

)%

Kingdom of Thailand (b)

 

18,168

 

15,684

 

16

%

Company-wide average daily production

 

44,768

 

49,733

 

(10

)%

 

 

 

 

 

 

 

 

Total Liquid Hydrocarbons —

 

 

 

 

 

 

 

Company-wide average daily
production (Bbls per day)(b)

 

48,767

 

54,245

 

(10

)%

 


(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.  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 2005.  The Company had no price hedging activity during the first three months of 2004.  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 146,000 barrels less than it sold in the first quarter of 2005 and 206,000 barrels more than it sold in the first quarter of 2004.

 

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.

 

Production.     The increase in the Company’s natural gas production during the first quarter of 2005, compared to the comparable 2004 period, was primarily related to the addition of production from fields purchased by the Company subsequent to the first quarter of 2004.  The Company also experienced increases in natural gas production volumes from the Los Mogotes field in South Texas, the Benchamas field in the Gulf of Thailand, at the Madden field in Wyoming and from the Company’s Main Pass Block 68 in the Gulf of Mexico.  These increases were partially offset by decreased production due to the effects of Hurricane Ivan and, to a lesser extent, natural production declines.

 

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.  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 either Malaysian TAPIS or Dated Brent 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 2005, compared to the first quarter of 2004, resulted primarily from the shut-in of Gulf of Mexico platforms due to the effects of Hurricane Ivan and, to a lesser extent, natural production declines.  These decreases were partially offset by increased crude oil and condensate production from the Company’s Kingdom of Thailand concession.  The increase in Thailand crude oil and condensate production during the first quarter of 2005, compared to the first quarter of 2004, primarily reflects the shut-in of production from the Benchamas field during the first quarter of 2004 to install additional production capacity for the field.

 

14



 

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, 2005, the Company had approximately 254,000 net barrels stored on board the FPSO and FSO.

 

Costs and Expenses

 

 

 

1st Quarter

 

% Change

 

 

 

2005

 

2004

 

2005 to 2004

 

Comparison of Increases (Decreases) in:

 

 

 

 

 

 

 

Lease Operating Expenses

 

 

 

 

 

 

 

United States

 

$

28,721,000

 

$

23,472,000

 

22

%

Kingdom of Thailand

 

$

11,528,000

 

$

11,403,000

 

1

%

Total Lease Operating Expenses

 

$

40,249,000

 

$

34,875,000

 

15

%

 

 

 

 

 

 

 

 

General and Administrative Expenses

 

$

20,727,000

 

$

17,232,000

 

20

%

Exploration Expenses

 

$

11,285,000

 

$

8,471,000

 

33

%

Dry Hole and Impairment Expenses

 

$

47,403,000

 

$

11,623,000

 

308

%

Depreciation, Depletion and
Amortization (DD&A) Expenses

 

$

100,645,000

 

$

87,339,000

 

15

%

DD&A rate

 

$

1.75

 

$

1.50

 

17

%

Mcfe sold (a)

 

57,366,000

 

58,121,000

 

(1

)%

Production and Other Taxes

 

$

21,799,000

 

$

9,538,000

 

129

%

Transportation and Other

 

$

6,296,000

 

$

5,125,000

 

23

%

Interest—

 

 

 

 

 

 

 

Charges

 

$

(10,211,000

)

$

(9,444,000

)

8

%

Capitalized Interest Expense

 

$

2,197,000

 

$

4,548,000

 

(52

)%

Income Tax Expense

 

$

(54,525,000

)

$

(57,551,000

)

(5

)%

 


(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 2005, compared to the first quarter of 2004, is related primarily to increased maintenance expenses on several of the Company’s significant offshore properties due to damage from Hurricane Ivan in the third quarter of 2004 and also to increased expenses incurred on onshore properties acquired by the Company in 2004.

 

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 $3.4 million (net to the Company’s interest) of the Company’s Thailand lease operating expenses for the first quarters of 2005 and 2004.  The Company currently expects these lease payments to remain relatively constant at approximately $14.5 million per year (net to the Company’s interest) for the next two years.

 

On a per unit of production basis, the Company’s total lease operating expenses have increased from an average of $0.61 per Mcfe for the first quarter of 2004 to $0.71 for the first quarter of 2005.   The per unit of production increase is primarily related to the shut-in of domestic production due to Hurricane Ivan during the first quarter of 2005, which both increased costs and lowered production volumes for the Company during the period.

 

General and Administrative Expenses

 

The increase in general and administrative expenses for the first quarter of 2005 compared with the respective 2004 period, is primarily related to increases in compensation and related benefit expense and to increased professional fees (due in part to compliance with Sarbanes-Oxley legislation and the related increased audit costs).  On a per unit of production basis, the Company’s general and administrative expenses increased to $0.37 per Mcfe in the first quarter of 2005 from $0.30 per Mcfe in the first quarter of 2004.

 

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 2005, compared to the first quarter of 2004, resulted primarily from the commencement of 3-D seismic activity over

 

15



 

prospective acreage in the Company’s New Zealand concession.  The Company incurred approximately $7.5 million of seismic costs in New Zealand during the first quarter of 2005.  No comparable expenses were incurred in New Zealand during the first quarter of 2004.

 

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 2005, compared to the first quarter of 2004, was primarily the result of costs related to unsuccessful domestic exploratory wells located primarily in the Gulf of Mexico, totaling approximately $42.5 million.  In the first quarter of 2004, the Company expensed costs related to unsuccessful exploratory wells in its Hungary concession totaling approximately $9.3 million.

 

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 properties 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 both 2005 and 2004, 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 2005 compared to the respective 2004 period resulted from an increase in the Company’s composite DD&A rate, which was only partially offset by a decrease in the Company’s equivalent hydrocarbon sales.

 

The increase in the composite DD&A rate for all of the Company’s producing fields for the first quarter of 2005, compared to the respective 2004 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 Main Pass Block 61/62 which was shut-in due to hurricane downtime) 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 domestic onshore properties recently acquired).

 

Production and Other Taxes

 

The increase in production and other taxes during the first quarter of 2005, compared to the respective 2004 period, relates primarily to Special Remuneration Benefit (SRB) taxes in the Kingdom of Thailand and to increased severance, property and franchise taxes in the United States resulting from the higher product prices received by the Company. The 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.  The Company recognized SRB obligations of $10,623,000 and $1,788,000 during the first quarters of 2005 and 2004, respectively.  Subject to the sale of its Thailand concession, 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 obligations, ineffectiveness on hedge contracts and various other operating expenses, none of which represents more than 10% of this expense category in either the first quarter of 2005 or the first quarter of 2004.  The increase in transportation and other expense for the first quarter of 2005, compared to the first quarter of 2004, relates primarily to hedge ineffectiveness incurred in 2005 with no comparable expense in 2004.  This was partially offset by a reduction in the Company’s transportation expenses between the comparative periods. The Company incurred transportation expense of $2,886,000 and $3,125,000 in the first quarters of 2005 and 2004, respectively.

 

Interest

 

Interest Charges.     The increase in the Company’s interest charges for the first quarter of 2005, compared to the first quarter of 2004, resulted from an increase in the average amount of the Company’s outstanding debt, which was partially offset by a reduction in the Company’s weighted average interest rate.

 

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 decrease in capitalized interest for the first quarter of 2005, compared to the comparable 2004 period, resulted primarily from a decrease in the amount of oil and gas projects in progress subject to interest capitalization during the first quarter of 2005 (approximately $169,000,000), compared to the first quarter of 2004 (approximately $216,000,000) in addition to a decrease in the weighted average interest rate on the Company’s outstanding

 

16



 

borrowings. The interest rates on borrowings repaid during the prior year were above the rates of the borrowings currently remaining, resulting in a lower weighted average rate to be applied to the cost of oil and gas projects in progress.

 

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 2005, compared to the first quarter of 2004, resulted from decreased pre-tax income during the 2005 period. The Company’s consolidated effective tax rate was 48% and 45% for the first quarters of 2005 and 2004, respectively.  The higher effective tax rate was the result of a higher percentage of the Company’s pre-tax income being derived from its Thailand operations during the 2005 period as compared to the 2004 period.  The Thailand income is taxed at a rate higher than the U.S. statutory rate.

 

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 2005 was $263,678,000 compared to cash flow from operating activities of $221,069,000 in the first quarter of 2004.  The increase is attributable primarily to higher oil and gas prices, partially offset by higher expenses (principally lease operating expenses and production and other taxes) discussed under “Results of Operations” above.  Cash flow from operating activities during the first quarter of 2005 was more than adequate to fund $191,189,000 in cash expenditures for capital and exploration projects for the quarter.  The Company also issued $300,000,000 principal amount of 2015 Notes (see description below) and repaid other debt obligations using cash of approximately $275,000,000 (net of borrowings).  The Company also paid $3,997,000 of dividends on its common stock during the first quarter of 2005.  As of March 31, 2005, the Company had cash and cash equivalents of $231,060,000 (including $212,513,000 in international subsidiaries which the Company intends to reinvest in its foreign operations subject to its evaluation of the new tax provisions of the American Jobs Creation Act of 2004, discussed below) and long-term debt obligations of $780,000,000 (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 25, 2005, the Company’s lenders redetermined the borrowing base under its Credit Agreement at $1,000,000,000.  As of May 2, 2005, the Company had an outstanding balance of $312,000,000 under its Credit Agreement.  As such, the available borrowing capacity under the Credit Agreement is currently $438,000,000.

 

2015 Notes

 

On March 29, 2005, the Company issued $300,000,000 principal amount of 2015 Notes at 99.101%. The proceeds from the sale of the 2015 Notes were used to pay down obligations under the Company’s bank credit facility.  The 2015 Notes bear interest at a rate of 6 5/8%, payable semi-annually in arrears on March 15 and September 15 of each year. The 2015 Notes are general unsecured senior subordinated obligations of the Company, are subordinated in right of payment to the Company’s senior indebtedness, which currently includes the Company’s obligations under the Credit Facility and LIBOR advances.  The Company, at its option, may redeem the 2015 Notes in whole or in part, at any time on or after March 15, 2010, at a redemption price of 103.3125% of their principal value and decreasing percentages thereafter. The Company may also redeem a portion of the 2015 Notes prior to March 15, 2008 and some or all of the Notes prior to March 15, 2010, in each case by paying specified premiums.  The indenture governing the 2015 Notes also imposes certain covenants on the Company including covenants limiting: incurrence of indebtedness including senior indebtedness; restricted payments; the issuance and sales of restricted subsidiary capital stock; transactions with affiliates; liens; disposition of proceeds of assets sales; non-guarantor restricted subsidiaries; dividends and other payment restrictions affecting restricted subsidiaries; and merger, consolidations and the sale of assets.

 

LIBOR Rate Advances

 

Under separate Promissory Note Agreements dated May 8, 2004 and September 13, 2004, two of the Company’s lenders make available to the Company LIBOR rate advances on an uncommitted basis up to $50,000,000.  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 reborrow such amounts under its Credit Agreement.  The Company’s 2011 Notes and 2015 Notes may restrict all or a portion of the amounts that may be borrowed under the Promissory Note Agreements as senior debt.  The Promissory Note Agreements permit either party to terminate the letter agreements at any time upon three-business days notice.  As of May 2, 2005, there was $40,000,000 outstanding under these agreements.

 

17



 

American Jobs Creation Act of 2004

 

On October 22, 2004, the President signed the American Jobs Creation Act of 2004 (the “Act”).  The Act creates a temporary incentive for U.S. corporations to repatriate accumulated income earned abroad by providing an 85% dividend received deduction for certain dividends from controlled foreign corporations.  The deduction is subject to a number of limitations and, as of May 4, 2005, uncertainty remains as to how to interpret numerous provisions of the Act.  As a result, the Company is not yet in a position to decide whether, and to what extent, it might repatriate foreign earnings that have not yet been remitted to the U.S., therefore if technical corrections to the Act are passed the Company may repatriate in 2005 an amount up to approximately $212.5 million of the cash and cash equivalents held by international subsidiaries discussed in “Liquidity and Capital Resources” above.  The repatriation would be subject to a tax liability of approximately $11.2 million (assuming 15% of such cash is subject to tax at the U.S. statutory rate).  This amount excludes any proceeds that may be realized from the potential sale of the Company’s Thailand and Hungarian operations

 

Future Capital and Other Expenditure Requirements

 

The Company’s capital and exploration budget for 2005, which does not include any amounts that may be expended for acquisitions or any interest which may be capitalized resulting from projects in progress, has been established by the Company’s Board of Directors at $345,000,000, of which approximately $146,400,000 was incurred in the three-months ended March 31, 2005.  The Company has included 226 gross wells in its 2005 capital and exploration budget (88 of which were drilled in the first quarter of 2005), including wells in the United States and the Kingdom of Thailand.  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, 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.

 

Stock Repurchase

 

On January 25, 2005, the Company announced a plan to repurchase, through open market or privately negotiated transactions, not less than $275 million nor more than $375 million of its common stock.  As of May 2, 2005, the Company had completed the purchase of  3,640,400 shares at a total cost of $170 million.

 

The following table sets forth certain information with respect to repurchases of the Company’s equity securities during the three months ended March 31, 2005.

 

 

Period

 

Total Number
of Shares
Purchased (a)

 

Average
Price Paid
Per Share

 

Maximum Dollar Value
of Shares that May
Yet Be Purchaseed
Under the Plan

 

 

 

 

 

 

 

 

 

January 26-31 2005

 

373,000

 

$

42.89

 

$

358,988,919

 

February 1-28 2005

 

517,200

 

$

44.70

 

$

335,852,282

 

March 1-31 2005

 

1,223,600

 

$

48.57

 

$

276,380,624

 

 

 

 

 

 

 

 

 

Total

 

2,113,800

 

 

 

 

 

 


(a)  All of these shares were purchased under the plan announced on January 25, 2005.

 

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.

 

18



 

Current Hedging Activity

 

As of March 31, 2005, 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 has 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. 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 hedging 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 hedging transactions are generally settled based on the average of the reporting 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 transactions 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, 2005 are as follows:

 

 

 

 

 

NYMEX

 

 

 

 

 

 

 

Contract

Fair Value

Contract Period and

 

 

 

Price

of

Type of Contract

 

Volume

 

Floor

 

Ceiling

Asset/(Liability)

 

 

 

 

 

 

 

 

 

 

Natural Gas Contracts (MMBtu) (a)

 

 

 

 

 

 

 

 

 

Collar Contracts:

 

 

 

 

 

 

 

 

 

April 2005 - December 2005

 

4,125

 

$

5.50

 

$

8.00

 

$

(2,223,459

)

April 2005 - December 2005

 

1,375

 

$

6.00

 

$

9.30

 

$

(247,817

)

April 2005 - December 2005

 

1,375

 

$

6.00

 

$

9.25

 

$

(258,776

)

April 2005 - December 2005

 

2,750

 

$

6.00

 

$

9.25

 

$

(517,553

)

April 2005 - December 2005

 

1,375

 

$

6.00

 

$

10.25

 

$

(97,380

)

April 2005 - December 2005

 

2,750

 

$

6.00

 

$

10.30

 

$

(183,692

)

January 2006 - December 2006

 

5,475

 

$

5.00

 

$

7.50

 

$

(5,069,822

)

January 2006 - December 2006

 

3,650

 

$

5.50

 

$

8.25

 

$

(2,121,749

)

January 2006 - December 2006

 

3,650

 

$

5.75

 

$

8.27

 

$

(1,925,689

)

 

 

 

 

 

 

 

 

 

 

Crude Oil Contracts (Barrels)

 

 

 

 

 

 

 

 

 

Collar Contracts:

 

 

 

 

 

 

 

 

 

April 2005 - December 2005

 

2,750,000

 

$

40.00

 

$

62.50

 

$

(6,281,972

)

April 2005 - December 2005

 

137,500

 

$

43.50

 

$

72.00

 

$

(48,025

)

April 2005 - December 2005

 

550,000

 

$

43.50

 

$

72.50

 

$

(165,210

)

 


(a) MMBtu means million British Thermal Units.

 

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 May 2, 2005, 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, 2005:

 

 

 

2005

 

2006

 

2007

 

2008

 

2009

 

Thereafter

 

Total

 

Fair Value

 

Long-Term Debt:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Variable Rate

 

$

0

 

$

0

 

$

0

 

$

0

 

$

280,000

 

$

0

 

$

280,000

 

$

280,000

 

Average Interest Rate

 

 

 

 

 

4.17

%

 

4.17

%

 

Fixed Rate

 

$

0

 

$

0

 

$

0

 

$

0

 

$

0

 

$

500,000

 

$

500,000

 

$

512,125

 

Average Interest Rate

 

 

 

 

 

 

7.28

%

7.28

%

 

 

19



 

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 6.  Exhibits

 

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).

 

 4.1          Indenture, dated as of March 29, 2005 between Pogo Producing Company and The Bank of New York Trust Company, N.A., as Trustee.

 

 4.2          Form of 6.625% Senior Subordinated Note (included as Exhibit A to Exhibit 4.1).

 

 4.3          Registration Rights Agreement dated March 29, 2005, by and among Pogo Producing Company and the parties thereto.

 

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.

 

20



 

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: May 4, 2005

 

 

 

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