Pioneer reported net income for the quarter of $185.6 million, or $1.28 per diluted share, an increase of 166% over net income for the same period last year of $69.7 million, or $.58 per diluted share. Cash flow from operations for the second quarter was $332.6 million, an increase of 26% compared to $264.7 million for the same period in 2004. The significant increase in operating cash flow is attributable to higher realized prices for oil, gas and natural gas liquids offset partially by increases in costs. Cash flow from operations, proceeds from the Company's sale of its third volumetric production payment in April and proceeds from asset divestitures during the second quarter allowed Pioneer to reduce its long-term debt by $437 million and repurchase 2.1 million shares of its common stock during the quarter in addition to funding its second quarter capital program. At the end of the quarter, long-term debt was approximately $1.4 billion, or 35% of total capitalization, and shares outstanding totaled 141.9 million.
Net income for the quarter includes $44.1 million ($28.0 million net of tax) of other income which represents expected proceeds from business interruption insurance claims related to previously disclosed losses sustained as a result of Hurricane Ivan and a fire at one of Pioneer's domestic onshore gas plants. Second quarter net income was reduced by a $27.3 million reversal of the deferred tax benefit recorded in connection with the Company's decision to exit Gabon. The deferred tax benefit is being reversed as a result of Pioneer's agreement in June of 2005 to sell its interest in its Gabon subsidiary.
In May, the Company sold its interests in three non-core fields in Canada and has reflected the results of operations of these fields, the gain on the sale and the related tax effects as income from discontinued operations in the amount of $82.0 million. Income from continuing operations for the quarter was $103.5 million, or $.72 per diluted share, and compares to income from continuing operations of $64.2 million, or $.53 per diluted share, for the same period last year.
Second quarter oil and gas sales averaged 183,298 barrels oil equivalent per day (BOEPD) excluding approximately 2,100 BOEPD associated with discontinued operations. Second quarter oil sales averaged 44,882 barrels per day (BPD) and natural gas liquids sales averaged 17,466 BPD. Gas sales in the second quarter averaged 726 million cubic feet per day (MMcfpd). Second quarter realized prices for oil and natural gas liquids were $35.52 and $29.11 per barrel, respectively. The worldwide realized price for gas was $5.35 per thousand cubic feet (Mcf), including $.30 per Mcf associated with the VPP transactions. North American realized gas prices averaged $6.37 per Mcf, including $.37 per Mcf associated with the VPP transactions.
Second quarter production costs averaged $6.47 per barrel of oil equivalent (BOE). Exploration and abandonment costs were $52.4 million for the quarter and included $18.2 million of dry hole and abandonments associated with unsuccessful wells in the U.S., Argentina, Canada and Tunisia, $28.4 million of geologic and geophysical expenses including seismic costs and $5.8 million of delay rentals and unproved acreage abandonments. General and administrative costs for the quarter were $29.2 million.
For the same quarter last year, adjusted to exclude discontinued operations, Pioneer reported oil and gas sales of 180,404 BOEPD, including oil sales of 44,811 BPD, natural gas liquids sales of 21,708 BPD and gas sales of 683 MMcfpd. Realized prices for second quarter 2004 were $27.92 per barrel for oil, $22.73 per barrel for natural gas liquids and $4.28 per Mcf for gas. North American gas prices averaged $5.07 per Mcf.
Pioneer has increased its 2005 capital budget for development and exploratory activities and land additions by approximately $150 million to $1.1 billion. The increase encompasses expenditures related to Pioneer's success in extending its acreage positions in West Africa, the U.S. onshore Gulf Coast, the Rocky Mountains, Alaska and Canada, adding a 5-well Gulf of Mexico shallow shelf exploration program and an increase in drilling in the Spraberry field and the Horseshoe Canyon coalbed methane play in Canada. The increased budget also reflects the rising costs associated with drilling and completion activities given higher commodity prices. The capital budget excludes costs associated with recent acquisitions.
During the second quarter, Pioneer continued with the aggressive pace of development set earlier in the year. Currently, the Company has 16 onshore rigs running in the U.S., nine in Argentina and five in Canada.
In the Raton Basin, Pioneer has drilled 135 of the 300 wells planned by year end. The Company is scheduled to drill 30 to 40 wells per month through the end of the year given that each year's drilling schedule is back-end loaded to accommodate typical winter weather delays. During the second quarter, third-party pipeline capacity restraints began limiting Pioneer's production from the field and are expected to continue to have an impact until a pipeline expansion of approximately 35% is completed in October of 2005. As a result, Raton production in 2005 is now expected to be 5% to 7% above 2004 levels.
In the deepwater Gulf of Mexico, exploration drilling on Pioneer's Clipper prospect has resumed after having been suspended for severe weather and recurring loop currents. Pioneer also expects to use the rig that it has under contract on the Clipper prospect to drill its Paladin prospect later in the year. During the fourth quarter, an appraisal well is planned on the Thunder Hawk discovery.
The ramp-up of production from the Devils Tower field has also been impacted by severe weather. In addition, production from Devils Tower's deepest intervals is being extended, increasing recoverable reserves, but postponing access to shallower intervals that are expected to produce at higher rates. Plans for tying in two satellite fields, Triton and Goldfinger, are progressing toward completion during the fourth quarter.
In July, recoverable reserves from the Harrier field were fully produced, with ultimate recoverable reserves exceeding expectations. Pioneer has also been advised by the operator of the Canyon Express system that sidetrack operations planned for the Aconcagua field later this year will be postponed pending rig availability. The existing Aconcagua wells are expected to reach the end of their productive lives by the end of 2005 or early 2006; therefore, Pioneer now anticipates that the system will be shut-in once the Camden Hill recoverable reserves are fully produced during the first half of 2006 unless a rig becomes available to drill the Aconcagua sidetrack wells.
In Canada, Pioneer has drilled 30 wells in the Horseshoe Canyon coalbed methane play under a program to drill up to 100 wells during 2005. Initial stabilized flow rates have significantly exceeded expectations, and the Company is considering an expansion of this program. Two Manville coalbed methane pilots are also planned in the Bashaw area later this year.
The Company continues to expand its deepwater exploration program in West Africa. Pioneer was awarded exploration rights to acreage in Blocks 2 and 3 in the Joint Development Zone between Nigeria and Sao Tome and Principe through a consortium with ERHC Energy Inc. The consortium was awarded 65% interest in Block 2 and 25% interest in Block 3 subject to negotiating acceptable joint operating and production sharing agreements.
As announced yesterday, Pioneer is also expanding its portfolio in Alaska and has joined ConocoPhillips in the Cosmopolitan Unit located offshore in the Cook Inlet where three wells and a sidetrack have been drilled establishing a significant oil column. A new 3-D seismic survey is planned for later this year to refine the estimate of recoverable reserves.
Scott D. Sheffield, Chairman and CEO, stated, "Pioneer delivered another quarter of strong financial and operational performance, reflecting recent robust market conditions and our quality portfolio of producing assets. Since the beginning of this year, we have reduced long-term debt by $1 billion and substantially improved our financial flexibility. With this enhanced financial flexibility, we expect to continue to add net asset value and grow production on a per share basis through an aggressive development drilling program, the commercialization of several attractive discovered resources, core area acquisitions, further exploration success and additional share repurchases."
The following statements are estimates based on current expectations. These forward-looking statements are subject to a number of risks and uncertainties which may cause the Company's actual results to differ materially from the following statements. The last paragraph of this release addresses certain of the risks and uncertainties to which the Company is subject.
Full-year production is now expected to range from 63 MMBOE to 65 MMBOE for 2005, excluding production from discontinued operations. The new range reflects the production impact of closed and pending asset sales in Canada, East Texas and the inland waters of the Gulf of Mexico, the Company's third volumetric production payment transaction, production lost from the Devils Tower and West Panhandle fields which were covered by business interruption insurance, pipeline capacity limitations delaying the ramp up of production from the Raton Basin and the impact of weather and rig shortages in the deepwater Gulf of Mexico, most of which are discussed in the operations update above. The new range also reflects the impact of directives from the Minerals Management Service which required that uphole recompletions scheduled for Devils Tower wells be postponed to maximize the recovery of oil and gas from less prolific deeper zones.
Third quarter 2005 production is expected to average 160,000 to 175,000 BOEPD. This range is lower than the second quarter average and reflects the Harrier field having been fully produced, the resumption of production from the West Panhandle field in mid-July and the typical variability in the timing of oil cargo shipments in South Africa, Argentina and Tunisia.
Third quarter production costs (including production and ad valorem taxes) are expected to average $6.75 to $7.25 per BOE based on current NYMEX strip prices for oil and gas. The increase over the prior quarter is primarily the result of lower anticipated third quarter production from lower per unit cost Gulf of Mexico fields, higher commodity prices, and to a lesser extent, the retention of a full quarter of operating costs associated with the third VPP volumes sold in April. Depreciation, depletion and amortization expense is expected to average $8.75 to $9.25 per BOE.
Total exploration and abandonment expense is expected to be $40 million to $70 million and includes plans to drill two deepwater Gulf of Mexico exploration wells (Clipper and Paladin) and one well in the Anaguid Block in Tunisia and the acquisition of additional 3-D seismic data. General and administrative expense is expected to be $28 million to $30 million. Interest expense is expected to be $26 million to $29 million, and accretion of discount on asset retirement obligations is expected to be $2 million to $3 million.
The Company's third quarter effective income tax rate is expected to range from 36% to 39% based on current capital spending plans, including cash income taxes of $10 million to $20 million that are principally related to Argentine, Canadian and Tunisian income taxes and nominal alternative minimum tax in the U.S. Other than in Argentina, Canada and Tunisia, the Company continues to benefit from the carryforward of net operating losses and other positive tax attributes.
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