Pogo's 2Q04 Revenues Up, Net Income Down From Year Ago

Pogo Producing Company (NYSE: PPP) recorded second quarter 2004 net income of $65,189,000, or $1.02 per share, on revenues of $326,893,000, compared to net income in the second quarter of 2003 totaling $79,719,000, or $1.29 per share, on revenues of $297,146,000. For the first half of 2004, Pogo's net income was $136,829,000, or $2.15 per share, on revenues of $634,775,000, compared to first half 2003 net income of $168,196,000, or $2.73 per share, on revenues of $609,819,000.

Discretionary cash flow in the second quarter and the first half of 2004 was $200,034,000 and $377,811,000, respectively, compared to discretionary cash flow of $160,561,000 in the second quarter and $355,902,000 in the first half of 2003. Net cash provided by operating activities during the second quarter and first half of 2004 was $127,188,000 and $348,257,000 respectively, compared to $168,249,000 and $392,224,000 for the same time periods in 2003.

Pogo's Chairman and Chief Executive Officer, Paul G. Van Wagenen, said, "Perhaps a keynote of Pogo's mid-year report is the marked acceleration of exploration activity planned for the balance of 2004. Of particular interest are a handful of deeper outercontinental shelf (OCS) wells scheduled for drilling late this year."

During the second quarter of 2004, Pogo's net income was reduced by $7,080,000, or $0.11 per share, due to the call premium associated with early redemption of all the company's outstanding 10 3/8% notes.

Mr. Van Wagenen said, "This action will save Pogo over $11,000,000 in annualized interest expense."

Pogo's Board of Directors today authorized a $150 million (36%) increase in the 2004 capital and exploration budget, bringing it to $565 million. Mr. Van Wagenen said, "Every operating division of the company will share in the added funding, however, a significant piece of the capital will be directed toward the drilling of at least five new high-potential Gulf of Mexico exploration prospects. Those leases were acquired, in most cases, in the federal OCS lease sale held in March, 2004."

Second quarter 2004 liquids production, including crude oil, condensate and plant products, dropped to an average of 58,423 barrels per day, compared to Pogo's all-time quarterly record volumes of 69,137 barrels per day produced in the second quarter of 2003. A part of the slippage reflects a change in the gas-to-oil ratio in several Benchamas field wells in the Gulf of Thailand, following a first quarter field shut-in for upgrades of the production facilities. Steps are underway to remedy that shortfall by completing or recompleting some additional high-concentration oil wells in Benchamas field, and by effecting some other helpful processing facility modifications. Another significant factor in the year-to-year drop in liquids production is the onset of natural declines in the flush 2003 production rates from Pogo's fine Main Pass Block 61/62 field. In order to alleviate that decline and improve ultimate reservoir drainage, an additional well at that field, the C-7, is presently drilling and a second well, C-8, is planned.

This decline in second quarter oil volumes was offset by increased natural gas production, averaging 338.1 million cubic feet per day (mmcf/d), up 12% from 301.7 mmcf/d produced in the same quarter one year ago.

Prices for both natural gas and oil were higher in the quarter just ended. Second quarter oil and condensate prices rose to $35.58 per barrel, from $27.45 per barrel recorded in the same quarter of 2003. Natural gas prices climbed to an average of $4.90 per thousand cubic feet (mcf) in the second quarter of 2004, up from $4.51/mcf during the same quarter last year.

The year 2003 marked the most ambitious drilling program in Pogo's 35-year history, with 248 gross wells drilled. The initial 2004 budget called for the drilling of some 300 gross wells. The capital budget increase approved today will allow Pogo to drill a total of 390 wells in 2004. Second quarter 2004 drilling is already at that pace, with 93 wells drilled, 86 of which were completed as producers.

The capital budget increase authorized by Pogo's Board of Directors today includes some $85 million earmarked for additional drilling on the OCS. That sum will call for the drilling, later this year, of at least five exploratory wells targeting deeper than usual depths, ranging between 14,000 and 21,000 feet subsea. These exploration prospects have been developed with 3-D seismic information. In such projects, both the target sizes and expected costs will be larger.

Mr. Van Wagenen noted, "We had planned to redouble our 2004 Gulf of Mexico exploratory budget from the very moment it was set last January, contingent upon award of the lease sale blocks by the Minerals Management Service, and a continuation of strong energy prices. Those conditions have been met and we are eager to begin drilling in the fourth quarter."

Eight development wells were drilled during the quarter on the Benchamas field "F" platform, averaging an impressive 220 feet of pay per well. The first three of ten Benchamas "L" development wells were also drilled during the quarter. Also successful was the Chaba "No. 3" exploration well, which logged some 42 feet of pay and significantly extended the known westward developable limits of the Chaba field. A second drilling rig is currently operating on Block B8/32, and has drilled the first four of eleven development wells planned for the North Jarmjuree production license area.

In Pogo's Permian Basin/San Juan region, 35 wells were drilled during the second quarter, every one of which was completed as a producer. Some 34 additional Permian Basin wells were in various stages of drilling, completing or testing as the second quarter ended. Important among those successes was the Eddy County, New Mexico, Patton 18 Fed. No. 1 well, 60% owned by Pogo, which encountered pay at several horizons. The initial completion in that Patton well is now producing 150 barrels per day and 200 mcf/d. Six more wells in that same Poker Lake/Sundance field area are budgeted for the remainder of 2004.

In the San Juan Basin Gardner field, the C-No. 1-A well, 50% owned by Pogo, was drilled and flow tested at a rate of about 4 mmcf/d. Five more wells are planned for the Gardner field in the second half of the year.

In South Texas, 14 successful wells were drilled, and five more wells were underway as the second quarter ended. Twelve of the 14 were located in Pogo's Zapata County, Texas, Los Mogotes field. The Haynes Nos. 114, 116 and 120 wells tested at daily rates between 4.6 and 6.1 mmcf/d per well. Two drilling rigs continue to run at Los Mogotes where Pogo generally owns about 70% interest. In the nearby 100% Pogo-owned South Hundido field, the Benevides No. 9 well tested at 5 mmcf/d.

Elsewhere in Pogo's Gulf Coast onshore region, the Parro No. 1 well in Thibodaux field, Lafourche Parish, Louisiana, tested at 2 mmcf/d.

In the Madden field in the Wind River Basin of central Wyoming, the operator drilled 18 second quarter Lower Fort Union wells, completing 16 as producers. Some 22 wells have been drilled this year in Madden field. Pogo's new budget envisions 32 more Madden field wells to be drilled during the second half of this year.

The drilling rig in Hungary moved as the quarter ended, from the Szolnok Orm-K-3 well location to the K-5 location on an untested portion of the Kenderes area. As announced on July 1, Pogo has taken a second quarter write- off of expenditures of approximately $17 million, relating to the four Kenderes wells drilled to date. Successful drilling results on the new K-5 well could lead to additional Kenderes area drilling in the second half of this year. Seismic data collection in the unexplored Koros region of Szolnok is set to begin in late July. If analysis of that new data indicates that it is justified, drilling at Koros could be scheduled for early next year.

The 40%-owned Fasan No. 1 exploratory well in the Denmark North Sea was drilled and plugged by the operator during the second quarter. No further plans for that block are presently contemplated.

New 3-D seismic acquisition covering more than 250,000 acres, is planned to begin in about December on Pogo's 1,014,000-acre New Zealand exploration license. When processed and reviewed, that new information should lead to exploration drilling in New Zealand by late 2005.

The Board of Directors today declared a dividend of $0.05 (five cents) per share of common stock to be paid August 15, 2004, to shareholders of record as of August 1, 2004.

                                      Three Months Ended    Six Months Ended
                                           June 30,              June 30,
                                       2004       2003       2004       2003
    Natural gas
        Price per Mcf              $    4.90  $    4.51  $    4.85  $    4.59
        Production (sales),
         Mcf per day                 338,104    301,704    318,868    303,219
    Crude Oil and Condensate
        Price per barrel           $   35.58  $   27.45  $   35.35  $   29.66
        Production, barrels per day   53,747     65,670     51,740     64,383
        Sales, barrels per day        51,147     66,744     51,572     63,444
    Total liquids
        Production, barrels per day   58,423     69,137     56,334     68,373
        Sales, barrels per day        55,823     70,211     56,166     67,434

     A summary of unaudited results
      follows, stated in thousands,
      except per share amounts

        Oil and gas                $ 326,659  $ 297,077  $ 633,986  $ 608,863
        Other                            234         69        789        956
                                   $ 326,893  $ 297,146  $ 634,775  $ 609,819

    Income before cumulative
     effect of change in
     accounting principle          $  65,189  $  79,719  $ 136,829  $ 172,362
    Cumulative effect of change
     in accounting principle             ---        ---        ---     (4,166)
    Net income                     $  65,189  $  79,719  $ 136,829  $ 168,196

    Earnings (loss) per share:
        Income before cumulative
         effect of change in
         accounting principle      $    1.02  $    1.29  $    2.15  $    2.80
        Cumulative effect of
         change in accounting
         principle                 $     ---  $     ---  $     ---  $   (0.07)
        Net Income                 $    1.02  $    1.29  $    2.15  $    2.73

        Income before cumulative
         effect of change in
         accounting principle      $    1.01  $    1.24  $    2.13  $    2.67
        Cumulative effect of
         change in accounting
         principle                 $     ---  $     ---  $     ---  $   (0.06)
        Net Income                 $    1.01  $    1.24  $    2.13  $    2.61

Discretionary cash flow is presented because of its wide acceptance as a financial indicator of a company's ability to internally fund exploration and development activities and to service or incur debt. This measure is widely used by investors and professional research analysts in the valuation, comparison, rating and investment recommendations of companies within the oil and gas exploration and production industry. Management also views the non-GAAP measure of discretionary cash flow as a useful tool for comparisons of the Company's financial indicators with those of peer companies that follow the full cost method of accounting. Discretionary cash flow is a financial measure that is not calculated in accordance with generally accepted accounting principles ("GAAP") and should not be considered as an alternative to net cash provided by operating activities, as defined by GAAP, or as a measure of financial performance or liquidity. The Company defines discretionary cash flow as net cash provided by operating activities before changes in operating assets and liabilities and exploration expenses. Other companies may define discretionary cash flow differently.

A reconciliation to net cash provided by operating activities is as follows

     Net cash provided by
      operating activities         $ 127,188  $ 168,249  $ 348,257  $ 392,224
         Remove changes in
          operating assets
          and liabilities             67,930     (9,515) $  16,167    (39,981)
         Add back exploration
          expenses                     4,916      1,827  $  13,387      3,659
     Discretionary cash flow       $ 200,034  $ 160,561  $ 377,811  $ 355,902

     Net cash used in
      investing activities         $(127,902) $ (75,575) $(242,167) $(157,818)
     Net cash used in
      financing activities         $  (7,540) $  (7,864) $(104,907) $(139,253)


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