Pioneer Natural Resources Posts 2Q Financial Results

Pioneer Natural Resources has announced financial and operating results for the quarter ended June 30, 2009.

Pioneer reported a second quarter net loss attributable to common stockholders of $92 million, or $.80 per diluted share. The loss included a noncash unrealized loss on commodity derivatives of $110 million after tax, or $.96 per diluted share. Without the effect of this item, adjusted income for the second quarter of 2009 would have been $18 million, or $.16 per diluted share.

Included in Pioneer’s second quarter results were unusual items that net to a gain of $31 million after tax, or $.26 per diluted share. These after-tax unusual items included:

  • Alaska Petroleum Production Tax credits of $55 million after tax ($.48 per diluted share),
  • hurricane-related charges covered by insurance of $10 million after tax ($.09 per diluted share) and
  • terminated and stacked rig charges of $14 million after tax ($.13 per diluted share).

Including discontinued operations, second quarter average daily oil and gas production grew by 3% from the prior year quarter to 117 thousand barrels oil equivalent per day (MBOEPD), consistent with second quarter guidance. Second quarter production was negatively impacted by the loss of approximately 2 MBOEPD of production that was shut in during the quarter as a result of unplanned third-party pipeline repairs in Alaska and the Mid-Continent area.

Production from continuing operations was 115 MBOEPD, reflecting Pioneer's agreement to sell its remaining Gulf of Mexico Shelf properties during the third quarter. Production attributable to these properties was approximately 1,400 barrels oil equivalent per day (BOEPD) during the second quarter.

Other highlights related to the quarter include:

  • Lease operating expenses (LOE) were reduced by 15% from the first quarter of 2009 in response to the Company’s aggressive cost reduction initiatives.
  • Debt was reduced by $97 million during the second quarter.
  • Oil derivatives were added for 2010 and 2011 with price upside, bringing forecasted oil production coverage to approximately 80% in 2010 and 65% in 2011.
  • Gas derivatives were added for 2010 and 2011 with price upside, bringing forecasted gas production coverage to approximately 80% in 2010 and 30% in 2011.
  • Two wells in Alaska were successfully fracture stimulated with a combined initial gross production rate of 5,400 barrels of oil per day (BOPD).
  • A Purchase and Sale Agreement was signed to sell Pioneer's remaining Gulf of Mexico Shelf properties; the transaction is expected to close during the third quarter.

Scott Sheffield, Chairman and CEO, stated, "We remain committed to a free cash flow model, with excess cash flow being used to reduce debt. Despite a significantly reduced capital program for 2009 of approximately $300 million, our high-quality assets delivered production growth of 9% during the first six months compared to last year, and we continue to expect full-year production growth of at least 5% per share.

"The improving outlook for oil prices, coupled with our strong derivative positions, provide confidence in achieving cash flow of approximately $1 billion in 2010. As a result, we are preparing to resume an oil-focused drilling program with strong returns in the Spraberry field and Tunisia at the beginning of 2010. Additionally, we will continue our successful oil development program in Alaska and actively assess the resource potential of the Eagle Ford Shale play. This drilling program and the expiration of our 5 MBOEPD volumetric production payment obligation at the end of 2009 are expected to once again generate a quarterly production growth profile starting in the first quarter of 2010."

Operations Update

In the Spraberry field, first half 2009 daily production increased 12% as compared to the first half of 2008, reflecting the success of the 2008 drilling program, improved well performance and sales of inventoried natural gas liquids (NGLs) that were not fractionated and sold in the fourth quarter of 2008 as a result of hurricane damage to third-party fractionation facilities. The Company had no rigs running in the Spraberry field during the second quarter but will resume drilling with one rig in August. With substantially reduced well costs and the strip price for oil exceeding $60 per barrel for 2010 and 2011, the Company is planning to have ten to twelve rigs running by January 2010, drilling approximately 250 wells during the year. The majority of these wells will include completions in additional zones, including the Wolfcamp and shale/silt intervals. Pioneer also plans to implement a full-scale waterflood project in 2010.

On the North Slope of Alaska, production from Pioneer's Oooguruk field averaged 4 thousand barrels of oil per day (MBOPD) during the first half 2009. Second quarter production from high-rate Kuparuk wells was curtailed by approximately 1 MBOPD due to constraints in the third-party water delivery system that provides water for reservoir pressure management. Sufficient water injection volumes are now available to meet current needs. Pioneer plans to drill a total of five horizontal Nuiqsut laterals during the second and third quarters, of which three will be fracture-stimulated production wells and two will be unstimulated water injection wells. The first unstimulated water injector has been producing oil at a stabilized rate of approximately 1 MBOPD and will be converted to injection during August. Early results from the first two fracture-stimulated production wells, which had a combined initial flow rate of 5,400 BOPD, suggest that stabilized production will be two to three times that of the unstimulated injector. Net production from Alaska for second half 2009 is forecast to average 6 MBOPD to 7 MBOPD.

In South Texas, Pioneer's first half 2009 daily production rose 16% versus the prior year period as a result of a strong drilling program in the Edwards Trend during 2008. The Company fracture stimulated its first horizontal well in the Eagle Ford Shale play where it holds 310,000 acres overlaying the Edwards Trend. The well incurred mechanical problems but still delivered an initial flow rate of 3.7 million cubic feet equivalent per day (MMCFEPD) with only two of five fracture stimulation stages contributing. The Company is implementing a multi-well drilling program beginning in the third quarter to delineate the play and assess its resource potential.

In the low-decline Raton and Mid-Continent areas where no drilling took place during the first half of 2009, production was down 4% and 8%, respectively, compared to last year. The reduction in Mid-Continent production included the curtailment of approximately 6 MMCFEPD during the second quarter of 2009 due to an unexpected third-party pipeline repair. The repair has now been completed and production is back to normal at approximately 110 MMCFEPD. Pioneer’s Mid-Continent production will increase by approximately 28 MMCFEPD on January 1, 2010 with the expiration of a volumetric production payment (VPP) obligation in the Hugoton field.

Daily production in Tunisia increased 29% compared to the first half of 2008. Drilling has been curtailed until early 2010 when new 3-D seismic will be fully processed.

In South Africa, first half 2009 daily production increased 51% compared to the same period in 2008 reflecting the commencement of production from the most prolific well in Pioneer's South Coast Gas project during fourth quarter 2008. Looking forward, a major maintenance shutdown is scheduled during the fourth quarter of 2009 at the Mossel Bay gas-to-liquids plant where the gas production is sold. As a result, fourth quarter forecasted production is expected to be curtailed from approximately 6 MBOEPD to 4 MBOEPD.

Pioneer and Pioneer Southwest (the master limited partnership in which Pioneer has a 68% interest) are evaluating the potential sale of certain developed and undeveloped oil and gas properties from Pioneer to Pioneer Southwest, which is dependent on market conditions, among other items.

Cost Reduction Initiatives

Pioneer's asset teams have continued to aggressively implement initiatives to reduce 2009 LOE. Second quarter LOE was 15% lower compared to the first quarter of 2009. The Company has achieved significant reductions in electricity, water disposal, well servicing, facilities and compression costs.

The Company is also continuing to work with service providers to reduce drilling and completion costs. Since the third quarter of 2008, when drilling and completion costs peaked, Pioneer has achieved a reduction of greater than 30% in the cost of drilling and completing a well for the majority of its domestic drilling inventory based on current market conditions.

General and administrative expenses were down 4% from the first quarter, again reflecting the Company’s focus on reducing costs.

Financial Review

Second quarter sales from continuing operations averaged 115,436 BOEPD, consisting of oil sales averaging 31,406 barrels per day (BPD), NGL sales averaging 18,921 BPD and gas sales averaging 391 million cubic feet per day (MMCFPD).

The reported second quarter average price for oil was $70.89 per barrel and included $8.62 per barrel related to deferred revenue from VPPs for which production was not recorded. The reported price for NGLs was $26.78 per barrel. The reported price for gas was $3.43 per thousand cubic feet (MCF) and included $.35 per MCF related to deferred revenue from VPPs for which production was not recorded.

Second quarter production costs averaged $10.33 per barrel oil equivalent (BOE), down $1.92 per BOE or 16%, from the first quarter of 2009, as a result of the Company’s cost reduction initiatives and reduced production taxes associated with lower commodity prices.

Depreciation, depletion and amortization (DD&A) expense averaged $15.80 per BOE for the second quarter. Exploration and abandonment costs were $22 million for the quarter and included $10 million of acreage and unsuccessful drilling costs and $12 million of geologic and geophysical expenses and personnel costs.

Cash flow from operating activities for the second quarter was $224 million.

Commodity Derivatives

Prior to February 1, 2009, Pioneer entered into and designated certain commodity and interest rate derivative instruments as cash flow hedges of commodity price risk and interest rate risk in accordance with generally accepted accounting principles in the United States (GAAP). Effective February 1, 2009, the Company discontinued hedge accounting on all of its existing derivative instruments and since that date has accounted for derivative instruments using the mark-to-market (MTM) accounting method.

On January 31, 2009, the Company determined the fair value of its derivative hedge instruments and adjusted the effective portion of its net hedge gains in accumulated other comprehensive income -- deferred hedge gains, net of tax (AOCI), in the equity portion of its consolidated balance sheet to $88 million. In accordance with GAAP, the Company transfers the net hedge gains included in AOCI to oil and gas revenues and interest expense in the same periods in which the transactions that they hedged are recognized in earnings. Excluding VPP hedge losses for the three and six month periods ended June 30, 2009, the Company transferred $29 million and $67 million of net gains from AOCI to oil and gas revenues, respectively, attributable to discontinued and terminated hedge derivatives.

Under the MTM accounting method, since February 1, 2009, the Company has accounted for all changes in the fair values of its derivative instruments as gains or losses in the earnings of the periods in which they occurred. The Company's MTM net derivative losses that were recorded to earnings for the three and six month periods ended June 30, 2009 and the scheduled amortization of net deferred gains on discontinued and terminated commodity hedges to oil and gas revenue are shown in the attached schedules.

Pioneer has increased its 2010 and 2011 oil and gas derivative positions to support the Company's free cash flow model and the resumption of oil drilling. In particular, the Company added 12,000 BPD of three-way oil collar derivatives in 2010 and 2011, with upside to approximately $90 per barrel and $100 per barrel, respectively. The Company also added 50,000 million British Thermal Units per day of three-way gas collar derivatives in 2011, with upside to $8.55 per million British Thermal Units. The new derivatives bring Pioneer's 2010 derivative coverage to 80% of forecasted production for both oil and gas, and 2011 coverage to 65% for oil and 35% for gas.

Financial Outlook

Third quarter 2009 guidance excludes discontinued operations related to the sale of Gulf of Mexico Shelf properties. The production and expense estimates below include amounts attributable to the public ownership in Pioneer Southwest.

Third quarter production is forecasted to average 110,000 BOEPD to 115,000 BOEPD.

Third quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $10.00 to $11.00 per BOE based on current NYMEX strip prices for oil and gas. DD&A expense is expected to average $15.50 to $16.50 per BOE, also based on current strip prices.

Total exploration and abandonment expense during the third quarter is expected to be $15 million to $25 million, primarily related to exploration wells, including related acreage costs, and seismic and personnel costs.

General and administrative expense is expected to be $33 million to $37 million. Interest expense is expected to be $42 million to $45 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.

Noncontrolling interest in consolidated subsidiaries' net income is expected to be $4 million to $7 million, primarily reflecting the public ownership in Pioneer Southwest.

The Company also expects to recognize $10 million to $15 million of charges in other expense associated with certain drilling rigs stacked as a result of the low price environment.

The Company's third quarter effective income tax rate is expected to range from 40% to 50% based on current capital spending plans, higher tax rates in Tunisia and no significant mark-to-market changes in the Company's derivative position. Cash taxes are expected to be $5 million to $10 million and are primarily attributable to Tunisia.

The Company's financial and MTM results, oil, NGL and gas derivatives, amortization of net deferred gains on discontinued and terminated commodity hedges and future VPP amortization are outlined on the attached schedules.