EXHIBIT 99.1
News Release
Pioneer Natural Resources Reports
First Quarter 2011 Financial and Operating Results
Dallas, Texas, May 3, 2011 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended March 31, 2011.
Pioneer reported first quarter net income attributable to common stockholders of $349 million, or $2.96 per diluted share (see attached schedule for a description of the earnings per diluted share calculation). Net income included unrealized mark-to-market losses on derivatives of $164 million after tax, or $1.40 per diluted share. Without the effect of this item, adjusted income for the first quarter of 2011 would have been $513 million, or $4.36 per diluted share.
Also included in Pioneer’s first quarter results was income of $432 million after tax, or $3.68 per diluted share, related to unusual items. These unusual items included:
| · | income from discontinued operations of $415 million after tax ($3.53 per diluted share) that was primarily attributable to the gain recognized on the sale of Pioneer’s Tunisian subsidiaries, and |
| · | Alaska Petroleum Production Tax (PPT) credits of $17 million after tax ($0.15 per diluted share). |
First quarter and other recent highlights included:
| · | producing 111.2 thousand barrels oil equivalent per day (MBOEPD) from continuing operations, despite losing 2 MBOEPD attributable to severe weather downtime during February in Texas, Kansas and Colorado, and 1.5 MBOEPD of unplanned third-party downtime during the quarter in the Mid-Continent, Alaska and South Africa, |
| · | planning to accelerate the Spraberry drilling program from 32 rigs currently to 35 rigs by mid-year, operating 4 Spraberry fracture stimulation fleets, with plans to increase to 6 fleets in May and 7 fleets by year end, |
| · | downspacing to 20-acre wells in the Spraberry and delivering production in excess of expectations, |
| · | drilling deeper to the Strawn and Atoka intervals in the Spraberry field with early Strawn well results indicating up to a 20% increase in cumulative first-year production as compared to offset Wolfberry wells; currently completing Pioneer’s first 2 Atoka wells, |
| · | progressing horizontal pilot program in the Spraberry with 2 horizontal Wolfcamp wells producing; planning to drill 6 – 8 additional wells to test multiple formations, |
| · | operating 9 rigs in the Eagle Ford Shale; on track to increase to 12 rigs by mid-2011, |
| · | initiating 2 fracture stimulation fleets in the Eagle Ford Shale in May; expect to be at 3 fracture stimulation fleets by year end, |
| · | developing the Barnett Shale Combo play with 24 wells drilled and 5 wells currently on production; early well results consistent with expectations, |
| · | completing the sale of Pioneer’s Tunisian subsidiaries for $866 million and |
| · | decreasing net debt-to-book capitalization from 37% at year-end 2010 to 31% at the end of the first quarter of 2011. |
Scott Sheffield, Chairman and CEO, stated, “Despite having production curtailed in the first quarter due to the impacts of severe weather and unscheduled third-party downtime, we continue to expect to deliver full-year 2011 production growth for the Company ranging from 125 MBOEPD to 130 MBOEPD, an increase of 15% to 19% compared to 2010 (reflecting production from Tunisia as discontinued operations). Both the Spraberry and Eagle Ford Shale accelerated drilling programs are on track to deliver most of this growth, much of it during the second half of the year in response to increasing
fracture stimulation capacity. We expect to fund our accelerated drilling program for 2011 from forecasted operating cash flow of $1.5 billion and the redeployment of a portion of the proceeds from the sale of Tunisia. For the 2011 to 2013 period, we expect to deliver compound annual production growth for the Company of 18+% and expect operating cash flow to grow to $2.6 billion in 2013. Pioneer remains committed to maintaining our strong financial position.”
Operations Update and Drilling Program
In the Spraberry field in West Texas, Pioneer’s drilling program continues to ramp up, with 32 rigs currently operating, including 14 Company-owned rigs. As a result of the Tunisia sale, the Company is accelerating its planned drilling ramp-up in the field and expects to increase the rig count to 35 rigs by mid-2011 and 45 rigs by early 2012.
As Pioneer ramps up drilling in the Spraberry field, the Company continues to expand its integrated services to control drilling costs and support execution of its accelerated drilling program. Three Company-owned fracture stimulation fleets are currently operating. Two additional fleets are being added, with the first scheduled to be operational in May and the second during the fourth quarter of 2011. To support its growing operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks and fishing tools. In addition, the Company has contracted for its forecasted fracture stimulation sand supply requirements through 2015, its tubular and pumping unit requirements through 2012 and is planning to enter a contract with a third party to supply well cementing services through 2016.
Vertical integration in the Spraberry field is saving Pioneer up to $0.5 million per well compared to utilizing third-party services. Pioneer expects to meet approximately one third of its rig requirements and two thirds of its fracture stimulation requirements with its own equipment in 2011. As a result, the blended Pioneer and third-party 2011 well cost is expected to average $1.4 million to $1.5 million per well. Pioneer’s internal rate of return on its 2011 Spraberry drilling program is expected to be 50% before tax based on current NYMEX strip commodity prices and estimated future production costs.
The Company’s accelerated drilling program and increasing fracture stimulation capacity in the Spraberry field is expected to significantly increase wells on production during 2011, particularly in the second half of the year. As a result, quarterly production growth is forecast over the remainder of the year, with full-year production expected to average 43 MBOEPD to 46 MBOEPD, further increasing to 52 MBOEPD to 56 MBOEPD in 2012 and 66 MBOEPD to 70 MBOEPD in 2013.
The Company continues to test downspacing in the Spraberry field from 40 acres to 20 acres. Eighteen 20-acre wells were drilled in 2010, with 14 of these wells on production. These 20-acre wells are capturing pay from the Lower Wolfcamp, Strawn and shale/silt intervals. Early results indicate production from these wells is outperforming the previous 110 MBOE type curve for a traditional Spraberry/Dean well. Plans call for drilling twenty 20-acre downspaced wells in 2011.
During 2010, Pioneer successfully added incremental production and proved reserves from vertical completions in the deeper Lower Wolfcamp and shale/silt intervals. As a result, the Company increased the estimated ultimate recovery (EUR) of a vertical Spraberry well from 110 MBOE to 140 MBOE to reflect the incremental production and reserves being added from this deeper drilling. The deeper Strawn and Atoka intervals below the Wolfcamp are now being tested in certain areas of the field with the expectation that incremental production and reserves will be added.
Of the 78 Spraberry wells drilled to the Strawn since the testing program began in the first quarter of 2010, 38 wells have been completed in that interval. Early results suggest an increase of up to 20% in cumulative first-year production compared to production from offset Wolfberry wells over the same time period. The incremental cost per well for this deeper drilling and one additional frac stage is
approximately $60 thousand. Pioneer believes the Strawn interval is prospective in 40% of its Spraberry acreage and expects to target this interval in 50% of the wells in its 2011 drilling program.
The Company is currently completing its first two vertical Atoka wells. Plans are to test the Atoka interval for two months and then comingle this production with production from upper intervals in the Spraberry and Wolfcamp zones. The incremental cost to drill an Atoka well is estimated to be $500 thousand to $750 thousand, reflecting deeper drilling and adding an intermediate casing string and CO2 fracture stimulation. Plans call for testing 10 to 20 Atoka wells in 2011.
The Company has also commenced a pilot program to test horizontal drilling applications in multiple intervals of the Spraberry field. The first two wells in the program have been drilled and completed. Both wells had 4,000-foot laterals with 15-stage fracture stimulation completions.
The first horizontal well was drilled in a Wolfcamp carbonate interval. Microseismic indicated the completion did not effectively stimulate the targeted zone. As a result, the well had an initial production rate of approximately 100 barrels oil per day (BOPD), but production declined more quickly than expected. Given the ineffective stimulation, the Company does not view this well as a representative test of the potential for a horizontal well in this interval and plans to test additional horizontal wells in this interval.
The second horizontal well targeted the Lower Wolfcamp shale interval. It was completed in late April. Microseismic indicated the successful stimulation of the interval. The well is currently unloading the fracture stimulation water with strong flowing pressure. With 30% of the load water recovered, an early test rate of 150 BOPD has been recorded.
The pilot program calls for drilling six to eight more horizontal wells. These wells will target the Lower Wolfcamp shale, Tippett shale (Middle Wolfcamp), Wolfcamp carbonate and Jo Mill (Middle Spraberry) intervals.
Water injection was initiated in the third quarter of 2010 on the Company’s 7,000-acre waterflood project in the Upper Spraberry interval. Early results are encouraging, as the production decline from 110 producing wells in the surveillance area continues to flatten. Early production response has been observed in several wells and there has been no premature water breakthrough. Based on the results of historical waterflood projects, an ultimate 50% uptick in production from the flooded Upper Spraberry interval is expected.
In the highly prospective Eagle Ford Shale in South Texas, Pioneer and its joint venture partners have successfully drilled 50 horizontal wells through the end of the first quarter of 2011. Twenty-four of the wells are on production and performing as forecasted. Of the remaining 26 wells, 5 are completed and awaiting hookup. Completion of the remaining 21 wells has been slower than anticipated due to limited third-party fracture stimulation fleet availability.
Pioneer has 9 rigs currently running in the play and plans to increase to 12 rigs by mid-year, 14 rigs in early 2012 and 16 rigs in early 2013.
To improve the execution of its drilling and completions program and reduce costs, Pioneer has purchased two fracture stimulation fleets for its Eagle Ford Shale completions. One was placed in service in April and the other is expected to be operational during the fourth quarter of 2011. The Company also entered into a two-year contract for a dedicated third-party fracture stimulation fleet which commenced operating in April.
Five central gathering plants (CGPs) have been completed as part of the joint venture’s Eagle Ford Shale midstream business. Three additional CGPs are expected to be completed over the remainder of 2011.
Pioneer’s gross well cost in the Eagle Ford Shale ranges from $7 million to $8 million per well. Using this cost and current NYMEX strip commodity prices, and excluding the benefit of the joint-venture drilling carry, before tax internal rates of return are estimated at 110% for high condensate yield wells (200 barrels per million cubic feet) and 70% for low condensate yield wells (60 barrels per million cubic feet).
Based on the increasing rig count and fracture stimulation capacity in the Eagle Ford Shale, Pioneer expects to significantly increase the number of wells put on production during 2011, especially during the second half of the year. Average annual production in 2011 is expected to grow to 12 MBOEPD to 15 MBOEPD, with a further expected increase to 26 MBOEPD to 30 MBOEPD in 2012 and 40 MBOEPD to 45 MBOEPD in 2013.
Sufficient gas processing, fractionation and transportation capacity is in place with third-party midstream service providers to handle Pioneer’s growing Spraberry and Eagle Ford Shale production.
In the liquids-rich Barnett Shale Combo play, Pioneer has built a 70,000-acre position, representing more than 600 drilling locations. Drilling commenced in the play in the latter part of 2010, with 2 rigs currently operating. The Company has acquired 160 square miles of 3-D seismic covering its acreage and expects to increase this coverage to 200 square miles by year end. Twenty-four wells have been drilled to date, of which 10 have been completed and 5 are producing. Of the three most recent wells placed on production, the 5-day initial production rates have averaged 155 BOPD and 854 thousand cubic feet per day (MCFPD), or 356 barrels of oil equivalent per day including the incremental uplift from natural gas liquids (NGLs).
The Company expects to generate quarterly production growth over the remainder of 2011 and average 4 MBOEPD to 5 MBOEPD for the full year. Plans call for increasing the rig count from 2 rigs in 2011 to 4 rigs in 2012, which is expected to further increase production to 9 MBOEPD to 11 MBOEPD in 2012 and 16 MBOEPD to 20 MBOEPD in 2013. Assuming current NYMEX strip commodity prices, an average per well drilling cost of $3 million and a gross EUR of 320 MBOE, Pioneer’s internal rate of return in the Barnett Shale Combo play is expected to be 50% before tax. A Pioneer-owned frac fleet has been purchased for the Barnett Shale Combo play with delivery expected later in May.
On the North Slope of Alaska, Pioneer will continue to operate one rig during 2011. During the first quarter, the Company drilled its second well to test the Torok formation within the Moraine play. This well is currently being tested. The Company will also be performing well maintenance on 3 producing wells during the second quarter. After the completion of this maintenance activity, additional Kuparuk and Nuiqsut drilling is planned over the remainder of 2011.
2011 Capital Budget
Pioneer’s capital program for 2011 continues at $1.8 billion, consisting of $1.6 billion for drilling operations and $0.2 billion for vertical integration and facilities. The 2011 budget excludes acquisitions, asset retirement obligations, capitalized interest and geological and geophysical G&A.
The 2011 drilling capital of $1.6 billion continues to be focused on oil and liquids-rich drilling, with 75% of the capital allocated to the Spraberry and Eagle Ford Shale plays. The following provides a breakdown of the forecasted spending by asset:
| · | Spraberry - $1.1 billion |
| · | Eagle Ford Shale - $110 million (reflects 25% of anticipated 2011 drilling costs; remaining 75% covered by drilling carry from Reliance Industries Limited ) |
| · | Barnett Shale Combo play - $170 million |
| · | Other - approximately $120 million, including land capital for existing assets |
Funds for the expansion of Pioneer’s integrated well service operations in the Spraberry field, the establishment of similar services in the Eagle Ford Shale and Barnett Shale Combo plays, and the build-out of facilities to support vertical integration (yards, buildings and shops) are budgeted at $200 million in 2011 and will be recorded in Other Property and Equipment.
2011 Capital Budget Funding and Balance Sheet
The 2011 capital budget is expected to be funded from forecasted operating cash flow of $1.5 billion, assuming current NYMEX strip pricing, and by redeploying $0.3 billion from the proceeds attributable to the recent sale of Tunisia.
Pioneer’s net debt (reduced for cash on Pioneer’s balance sheet) at the end of the first quarter of 2011 was $2 billion, a reduction of $0.5 billion from year-end 2010. With Pioneer’s improving net debt position, net debt-to-book capitalization declined from 37% at year-end 2010 to 31% at the end of the first quarter of 2011. The Company is committed to keeping its net debt-to-book capitalization below 35% and net debt to operating cash flow below 1.75 times.
Eagle Ford Shale Midstream Operations
Pioneer’s share of its Eagle Ford Shale joint-venture midstream activities is conducted through a partially-owned, unconsolidated entity. After May 2011, the Company expects the funding for the ongoing midstream infrastructure build-out to be provided from external debt sources. Cash flow from the services provided by the midstream operations is not included in Pioneer’s forecasted operating cash flow of $1.5 billion in 2011.
First Quarter 2011 Financial Review
The following financial results for the first quarter of 2011 reflect continuing operations.
First quarter sales averaged 111 MBOEPD, consisting of oil sales averaging 34 MBOPD, NGL sales averaging 19 thousand barrels per day and gas sales averaging 349 MMCFPD.
The average reported first quarter price for oil was $95.62 per barrel and included $3.57 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded. The average reported price for NGLs was $42.17 per barrel. The average reported price for gas was $4.14 per thousand cubic feet.
First quarter production costs averaged $13.31 per barrel oil equivalent (BOE), an increase of $2.37 per BOE from the fourth quarter of 2010. This increase included the impact of repairs during the first quarter associated with the severe weather downtime and higher production taxes associated with rising oil prices. It also reflects a one-time processing fee recovery in the fourth quarter associated with the Company’s Oooguruk project in Alaska of $10 million and an ad valorem tax accrual reduction in the fourth quarter.
Depreciation, depletion and amortization (DD&A) expense averaged $14.02 per BOE for the first quarter. Exploration and abandonment costs were $18 million for the quarter and included $2 million of unsuccessful exploration costs and acreage abandonments and $16 million of geologic and geophysical expenses and personnel costs.
Second Quarter 2011 Financial Outlook
The Company’s second quarter 2011 outlook for certain operating and financial items is provided below.
Production is forecasted to average 116 MBOEPD to 121 MBOEPD.
Production costs are expected to average $12.00 to $14.00 per BOE, based on current NYMEX strip commodity prices. DD&A expense is expected to average $13.50 to $15.00 per BOE.
Total exploration and abandonment expense is forecasted to be $25 million to $35 million, primarily related to exploration wells, including related acreage costs, and seismic and personnel costs.
General and administrative expense is expected to be $45 million to $49 million, interest expense is expected to be $44 million to $47 million, and other expense is expected to be $20 million to $25 million. Accretion of discount on asset retirement obligations is expected to be $2 million to $4 million.
Noncontrolling interest in consolidated subsidiaries’ income, excluding unrealized derivative mark-to-market adjustments, is expected to be $9 million to $12 million, primarily reflecting the public ownership in Pioneer Southwest Energy Partners L.P.
The Company’s effective income tax rate is expected to range from 35% to 45% based on current capital spending plans and the assumption of no significant unrealized derivative mark-to-market changes in the Company’s derivative position. Current income taxes are expected to be $5 million to $10 million and are primarily attributable to South Africa.
The Company's financial and derivative mark-to-market results, open derivatives positions for oil, NGL and gas, amortization of net deferred gains on discontinued commodity hedges and future VPP amortization are outlined on the attached schedules.
Earnings Conference Call
On Wednesday, May 4, 2011, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended March 31, 2011, with an accompanying presentation. Instructions for listening to the call and viewing the accompanying presentation are shown below.
Internet: www.pxd.com
Select “Investors,” then “Earnings Calls & Webcasts” to listen to the discussion and view the presentation.
Telephone: Dial (800) 967-7137 confirmation code: 3709635 five minutes before the call. View the presentation via Pioneer’s internet address above.
A replay of the webcast will be archived on Pioneer’s website. A telephone replay will be available through May 28 by dialing (888) 203-1112 confirmation code: 3709635.
Pioneer is a large independent oil and gas exploration and production company, headquartered in Dallas, Texas, with operations primarily in the United States. For more information, visit Pioneer’s website at www.pxd.com.
Except for historical information contained herein, the statements in this news release are forward-looking statements that are made pursuant to the Safe Harbor Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer are subject to a number of risks and uncertainties that may cause Pioneer's actual results in future periods to differ materially from the forward-looking statements. These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other
government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services and personnel required to complete the Company’s operating activities, access to and availability of transportation, processing and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer’s credit facility and derivative contracts and the purchasers of Pioneer’s oil, NGL and gas production, uncertainties about estimates of reserves and resource potential and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, international operation and acts of war or terrorism. These and other risks are described in Pioneer's 10-K and 10-Q Reports and other filings with the Securities and Exchange Commission. In addition, Pioneer may be subject to currently unforeseen risks that may have a materially adverse impact on it. Pioneer undertakes no duty to publicly update these statements except as required by law.
Cautionary Note to U.S. Investors --The U.S. Securities and Exchange Commission (the "SEC") prohibits oil and gas companies, in their filings with the SEC, from disclosing estimates of oil or gas resources other than “reserves,” as that term is defined by the SEC. In this news release, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource potential,” “estimated ultimate recovery,” “EUR” or other descriptions of volumes of reserves, which terms include quantities of oil and gas that may not meet the SEC’s definitions of proved, probable and possible reserves, and which the SEC's guidelines strictly prohibit Pioneer from including in filings with the SEC. These estimates are by their nature more speculative than estimates of proved reserves and accordingly are subject to substantially greater risk of being recovered by Pioneer. U.S. investors are urged to consider closely the disclosures in the Company’s periodic filings with the SEC. Such filings are available from the Company at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039, Attention: Investor Relations, and the Company’s website at www.pxd.com. These filings also can be obtained from the SEC by calling 1-800-SEC-0330.
Pioneer Natural Resources Contacts:
Investors
Frank Hopkins – 972-969-4065
Brian Hansen – 972-969-4017
Eric Pregler – 972-969-5756
Media and Public Affairs
Susan Spratlen – 972-969-4018
Suzanne Hicks – 972-969-4020
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
| | | | | March 31,
2011 | | December 31,
2010 |
| ASSETS |
| Current assets: | | | | | |
| | Cash and cash equivalents | $ | 520,651 | | $ | 111,160 |
| | Accounts receivable, net | | 277,293 | | | 245,303 |
| | Income taxes receivable | | 30,900 | | | 30,901 |
| | Inventories | | 187,715 | | | 173,615 |
| | Prepaid expenses | | 10,010 | | | 11,441 |
| | Deferred income taxes | | 22,802 | | | 156,650 |
| | Discontinued operations held for sale | | - | | | 281,741 |
| | Derivatives | | 147,643 | | | 171,679 |
| | Other current assets, net | | 38,579 | | | 14,693 |
| | | | | | | | | |
| | | Total current assets | | 1,235,593 | | | 1,197,183 |
| | | | | | | | | |
| Property, plant and equipment, at cost: | | | | | |
| | Oil and gas properties, using the successful efforts method of accounting | | 11,269,772 | | | 10,930,226 |
| | Accumulated depletion, depreciation and amortization | | (3,495,838) | | | (3,366,440) |
| | | | | | | | | |
| | | Total property, plant and equipment | | 7,773,934 | | | 7,563,786 |
| | | | | | | | | |
| Goodwill | | 298,145 | | | 298,182 |
| Investment in unconsolidated affiliate | | 109,391 | | | 72,045 |
| Derivatives | | 106,210 | | | 151,011 |
| Other assets, net | | 502,713 | | | 396,895 |
| | | | | | | | | |
| | | | | $ | 10,025,986 | | $ | 9,679,102 |
| | | | | | | | | |
| LIABILITIES AND STOCKHOLDERS' EQUITY |
| Current liabilities: | | | | | |
| | Accounts payable | $ | 369,333 | | $ | 419,150 |
| | Interest payable | | 33,942 | | | 59,008 |
| | Income taxes payable | | 33,072 | | | 19,168 |
| | Deferred income taxes | | - | | | 1,144 |
| | Discontinued operations held for sale | | - | | | 108,592 |
| | Deferred revenue | | 44,327 | | | 44,951 |
| | Derivatives | | 173,628 | | | 80,997 |
| | Other current liabilities | | 41,562 | | | 36,210 |
| | | | | | | | | |
| | | Total current liabilities | | 695,864 | | | 769,220 |
| | | | | | | | | |
| Long-term debt | | 2,562,688 | | | 2,601,670 |
| Deferred income taxes | | 1,763,976 | | | 1,751,310 |
| Deferred revenue | | 31,610 | | | 42,069 |
| Derivatives | | 179,914 | | | 56,574 |
| Other liabilities | | 238,367 | | | 232,234 |
| Stockholders' equity | | 4,553,567 | | | 4,226,025 |
| | | | | | | | | |
| | | | | $ | 10,025,986 | | $ | 9,679,102 |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
| | | | Three Months Ended March 31, |
| | | | 2011 | | 2010 |
| Revenues and other income: | | | | | |
| | Oil and gas | $ | 497,130 | | $ | 472,045 |
| | Interest and other | | 32,687 | | | 18,008 |
| | Gain (loss) on disposition of assets, net | | (2,191) | | | 16,943 |
| | | | | 527,626 | | | 506,996 |
| Costs and expenses: | | | | | |
| | Oil and gas production | | 99,931 | | | 86,100 |
| | Production and ad valorem taxes | | 33,296 | | | 27,061 |
| | Depletion, depreciation and amortization | | 140,373 | | | 144,428 |
| | Exploration and abandonments | | 17,643 | | | 16,848 |
| | General and administrative | | 44,106 | | | 38,315 |
| | Accretion of discount on asset retirement obligations | | 2,655 | | | 2,859 |
| | Interest | | 45,227 | | | 47,523 |
| | Hurricane activity, net | | 71 | | | (7,410) |
| | Derivative (gains) losses, net | | 244,432 | | | (265,476) |
| | Other | | 17,881 | | | 15,946 |
| | | | | 645,615 | | | 106,194 |
| | | | | | | | |
| Income (loss) from continuing operations before income taxes | | (117,989) | | | 400,802 |
| Income tax benefit (provision) | | 47,151 | | | (144,007) |
| Income (loss) from continuing operations | | (70,838) | | | 256,795 |
| Income from discontinued operations, net of tax | | 414,642 | | | 3,811 |
| Net income | | 343,804 | | | 260,606 |
| | Net (income) loss attributable to the noncontrolling interests | | 4,790 | | | (15,352) |
| Net income attributable to common stockholders | $ | 348,594 | | $ | 245,254 |
| | | | | | | |
| Basic earnings per share: | | | | | |
| | Income (loss) from continuing operations attributable to common stockholders | $ | (0.57) | | $ | 2.06 |
| | Income from discontinued operations attributable to common stockholders | | 3.53 | | | 0.03 |
| | Income attributable to common stockholders | $ | 2.96 | | $ | 2.09 |
| | | | | | | | |
| Diluted earnings per share: | | | | | |
| | Income (loss) from continuing operations attributable to common stockholders | $ | (0.57) | | $ | 2.05 |
| | Income from discontinued operations attributable to common stockholders | | 3.53 | | | 0.03 |
| | Income attributable to common stockholders | $ | 2.96 | | $ | 2.08 |
| | | | | | | | |
| Weighted average shares outstanding: | | | | | |
| | Basic | | 115,869 | | | 114,655 |
| | Diluted | | 115,869 | | | 115,462 |
| | | | | | | | |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| | | | | | | | Three Months Ended March 31, |
| | | | | | | | 2011 | | | 2010 |
| Cash flows from operating activities: | | | | | |
| | Net income | $ | 343,804 | | $ | 260,606 |
| | | Adjustments to reconcile net income to net cash provided by | | | | |
| | | operating activities: | | | | | |
| | | | Depletion, depreciation and amortization | | 140,373 | | | 144,428 |
| | | | Exploration expenses, including dry holes | | 1,481 | | | 3,587 |
| | | | Deferred income taxes | | (55,868) | | | 141,545 |
| | | | (Gain) loss on disposition of assets, net | | 2,191 | | | (16,943) |
| | | | Accretion of discount on asset retirement obligations | | 2,655 | | | 2,859 |
| | | | Discontinued operations | | (408,065) | | | 21,558 |
| | | | Interest expense | | 7,637 | | | 7,408 |
| | | | Derivative related activity | | 276,683 | | | (281,871) |
| | | | Amortization of stock-based compensation | | 10,174 | | | 9,624 |
| | | | Amortization of deferred revenue | | (11,083) | | | (22,483) |
| | | | Other noncash items | | (20,488) | | | (403) |
| | Change in operating assets and liabilities: | | | | | |
| | | | Accounts receivable, net | | (25,270) | | | 48,080 |
| | | | Income taxes receivable | | 1 | | | 21,264 |
| | | | Inventories | | (29,319) | | | 17,429 |
| | | | Prepaid expenses | | 1,342 | | | 435 |
| | | | Other current assets | | 3,305 | | | 1,226 |
| | | | Accounts payable | | (89,980) | | | (34,296) |
| | | | Interest payable | | (25,066) | | | (13,314) |
| | | | Income taxes payable | | 15,354 | | | (1,536) |
| | | | Other current liabilities | | 3,353 | | | (9,840) |
| | | | | Net cash provided by operating activities | | 143,214 | | | 299,363 |
| Net cash provided by (used in) investing activities | | 334,168 | | | (166,543) |
| Net cash used in financing activities | | (67,891) | | | (125,648) |
| Net increase in cash and cash equivalents | | 409,491 | | | 7,172 |
| Cash and cash equivalents, beginning of period | | 111,160 | | | 27,368 |
| Cash and cash equivalents, end of period | $ | 520,651 | | $ | 34,540 |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
| | | | | Three Months Ended March 31, |
| | | | | 2011 | | 2010 |
| Average Daily Sales Volumes | | | | | | |
| | from Continuing Operations: | | | | | | |
| | | Oil (Bbls) - | U.S. | | 33,926 | | | 25,803 |
| | | | South Africa | | 526 | | | 1,111 |
| | | | Worldwide | | 34,452 | | | 26,914 |
| | | | | | | | | |
| | | Natural gas liquids (Bbls) - | U.S. | | 18,645 | | | 19,115 |
| | | | | | | | | |
| | | Gas (Mcf) - | U.S. | | 325,169 | | | 346,248 |
| | | | South Africa | | 23,537 | | | 31,033 |
| | | | Worldwide | | 348,706 | | | 377,281 |
| | | | | | | | | |
| | | Total (BOE) - | U.S. | | 106,766 | | | 102,627 |
| | | | South Africa | | 4,449 | | | 6,283 |
| | | | Worldwide | | 111,215 | | | 108,910 |
| Average Reported Prices (a): | | | | | | |
| | | Oil (per Bbl) - | U.S. | $ | 95.46 | | $ | 92.08 |
| | | | South Africa | $ | 106.38 | | $ | 77.58 |
| | | | Worldwide | $ | 95.62 | | $ | 91.48 |
| | | | | | | | | |
| | | Natural gas liquids (per Bbl) - | U.S. | $ | 42.17 | | $ | 41.82 |
| | | | | | | | | |
| | | Gas (per Mcf) - | U.S. | $ | 3.88 | | $ | 5.16 |
| | | | South Africa | $ | 7.73 | | $ | 6.31 |
| | | | Worldwide | $ | 4.14 | | $ | 5.26 |
| | | | | | | | | |
| | | Total (BOE) - | U.S. | $ | 49.51 | | $ | 48.36 |
| | | | South Africa | $ | 53.45 | | $ | 44.89 |
| | | | Worldwide | $ | 49.67 | | $ | 48.16 |
__________
| (a) | Average reported prices are attributable to continuing operations and include the results of hedging activities and amortization of VPP deferred revenue. |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY EARNINGS PER SHARE INFORMATION
The Company uses the two-class method of calculating basic and diluted earnings per share. Under the two-class method of calculating earnings per share, GAAP provides that share- and unit-based awards with guaranteed dividend or distribution participation rights qualify as "participating securities" during their vesting periods. The Company's basic net income per share attributable to common stockholders is computed as (i) net income attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income per share attributable to common stockholders is computed as (i) basic net income attributable to common stockholders, (ii) plus adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would be dilutive to loss per share; therefore, conversion into common stock is assumed not to occur.
The following table is a reconciliation of the Company's net income attributable to common stockholders to basic net income attributable to common stockholders and to diluted net income attributable to common stockholders for the three months ended March 31, 2011 and 2010:
| | | Three Months Ended March 31, |
| | | 2011 | | 2010 |
| | | (in thousands) |
| | | | | | | |
| Net income attributable to common stockholders | $ | 348,594 | | $ | 245,254 |
| | Participating basic distributed earnings | | (25) | | | - |
| | Participating basic undistributed earnings | | (6,115) | | | (5,337) |
| Basic net income attributable to common stockholders | | 342,454 | | | 239,917 |
| | Diluted adjustments to share- and unit-based earnings | | - | | | 51 |
| Diluted net income attributable to common stockholders | | | | | |
| | stockholders | $ | 342,454 | | $ | 239,968 |
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three months ended March 31, 2011 and 2010:
| | | | Three Months Ended March 31, |
| | | | 2011 | | 2010 |
| | | | (in thousands) |
| | | | | | |
| Weighted average common shares outstanding: | | | | |
| | Basic | | 115,869 | | 114,655 |
| | Dilutive common stock options | | - | | 224 |
| | Contingently issuable - performance shares | | - | | 583 |
| | | | | | |
| | Diluted | | 115,869 | | 115,462 |
| | | | | | |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES
(in thousands)
EBITDAX and discretionary cash flow ("DCF") (as defined below) are presented herein, and reconciled to the generally accepted accounting principle ("GAAP") measures of net income and net cash provided by operating activities because of their wide acceptance by the investment community as financial indicators of a company's ability to internally fund exploration and development activities and to service or incur debt. The Company also views the non-GAAP measures of EBITDAX and DCF as useful tools for comparisons of the Company's financial indicators with those of peer companies that follow the full cost method of accounting. EBITDAX and DCF should not be considered as alternatives to net income or net cash provided by operating activities, as defined by GAAP.
| | | | | Three Months Ended March 31, |
| | | | | 2011 | | | 2010 |
| | | | | | | | |
| Net income | $ | 343,804 | | $ | 260,606 |
| Depletion, depreciation and amortization | | 140,373 | | | 144,428 |
| Exploration and abandonments | | 17,643 | | | 16,848 |
| Hurricane activity, net | | 71 | | | (7,410) |
| Accretion of discount on asset retirement obligations | | 2,655 | | | 2,859 |
| Interest expense | | 45,227 | | | 47,523 |
| Income tax (benefit) provision | | (47,151) | | | 144,007 |
| (Gain) loss on disposition of assets, net | | 2,191 | | | (16,943) |
| Discontinued operations | | (414,642) | | | (3,811) |
| Derivative related activity | | 276,683 | | | (281,871) |
| Amortization of stock-based compensation | | 10,174 | | | 9,624 |
| Amortization of deferred revenue | | (11,084) | | | (22,483) |
| Other noncash items | | (20,487) | | | (403) |
| | | | | | | | |
| | EBITDAX (a) | | 345,457 | | | 292,974 |
| | | | | | | | |
| Cash interest expense | | (37,590) | | | (40,115) |
| Current income taxes | | (8,717) | | | (2,462) |
| | | | | | | | |
| | Discretionary cash flow (b) | | 299,150 | | | 250,397 |
| | | | | | | | |
| Cash hurricane activity | | (71) | | | 7,410 |
| Discontinued operations cash activity | | 6,577 | | | 25,369 |
| Cash exploration expense | | (16,162) | | | (13,261) |
| Changes in operating assets and liabilities | | (146,280) | | | 29,448 |
| | | | | | | | |
| | Net cash provided by operating activities | $ | 143,214 | | $ | 299,363 |
__________
| (a) | “EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; net hurricane activity; unrealized mark-to-market derivative activity; accretion of discount on asset retirement obligations; interest expense; income taxes; (gain) loss on the disposition of assets, net; discontinued operations; amortization of stock-based compensation; amortization of deferred revenue and other noncash items. |
| (b) | Discretionary cash flow equals cash flows from operating activities before changes in operating assets and liabilities, cash activity reflected in discontinued operations and hurricane activity, and cash exploration expense. |
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY NON-GAAP FINANCIAL MEASURES (continued)
(in millions, except per share data)
Income adjusted for unrealized mark-to-market ("MTM") derivative losses, and income adjusted for unrealized MTM derivative losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net income attributable to common stockholders that is determined in accordance with GAAP because Pioneer believes that these non-GAAP financial measures reflect an additional way of viewing aspects of Pioneer's business that, when viewed together with its financial results computed in accordance with GAAP, provide a more complete understanding of factors and trends affecting its historical financial performance and future operating results, greater transparency of underlying trends and greater comparability of results across periods. In addition, management believes that these non-GAAP measures may enhance investors' ability to assess Pioneer's historical and future financial performance. These non-GAAP financial measures are not intended to be substitutes for the comparable GAAP measures and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Unrealized MTM net derivative losses, Alaska petroleum production tax credit recoveries and net discontinued operations will recur in future periods; however, the amount and frequency of each item can vary significantly from period to period. The table below reconciles Pioneer's net income attributable to common stockholders for the three months ended March 31, 2011, as determined in accordance with GAAP, to income adjusted for unrealized MTM derivative losses, and income adjusted for unrealized MTM derivative losses and unusual items, for that quarter.
| | | | After-tax Amounts | | Diluted
Amounts
Per Share |
| | | | | | | | |
| Net income attributable to common stockholders | $ | 349 | | $ | 2.96 |
| | Unrealized MTM derivative losses ($276 before tax) | | 164 | | | 1.40 |
| Adjusted income excluding unrealized MTM derivative losses | | 513 | | | 4.36 |
| | | | | | | | |
| | Discontinued operations ($664 income before tax) | | (415) | | | (3.53) |
| | Alaska petroleum production tax credit recoveries ($27 before tax) | | (17) | | | (0.15) |
| Adjusted income excluding unrealized MTM derivative losses and unusual items | $ | 81 | | $ | 0.68 |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Open Commodity Derivative Positions as of May 2, 2011
(Volumes are average daily amounts)
| | | | | | 2011 | | | | | | | | | | | | |
| | | | | | Second Quarter | | Third Quarter | | Fourth Quarter | | 2012 | | 2013 | | 2014 | | 2015 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Average Daily Oil Production Associated | | | | | | | | | | | | | | | | | | | | |
| | with Derivatives (Bbls): | | | | | | | | | | | | | | | | | | | | |
| | | Swap Contracts: | | | | | | | | | | | | | | | | | | | | |
| | | | Volume | | 750 | | | 750 | | | 750 | | | 3,000 | | | 3,000 | | | - | | | - |
| | | | NYMEX price | $ | 77.25 | | $ | 77.25 | | $ | 77.25 | | $ | 79.32 | | $ | 81.02 | | $ | - | | $ | - |
| | | Collar Contracts: | | | | | | | | | | | | | | | | | | | | |
| | | | Volume | | 2,000 | | | 2,000 | | | 2,000 | | | 2,000 | | | - | | | - | | | - |
| | | | NYMEX price: | | | | | | | | | | | | | | | | | | | | |
| | | | | Ceiling | $ | 170.00 | | $ | 170.00 | | $ | 170.00 | | $ | 127.00 | | $ | - | | $ | - | | $ | - |
| | | | | Floor | $ | 115.00 | | $ | 115.00 | | $ | 115.00 | | $ | 90.00 | | $ | - | | $ | - | | $ | - |
| | | Collar Contracts with Short Puts: | | | | | | | | | | | | | | | | | | | | |
| | | | Volume | | 32,000 | | | 32,000 | | | 32,000 | | | 37,000 | | | 21,250 | | | 12,000 | | | - |
| | | | NYMEX Price: | | | | | | | | | | | | | | | | | | | | |
| | | | | Ceiling | $ | 99.33 | | $ | 99.33 | | $ | 99.33 | | $ | 118.34 | | $ | 117.38 | | $ | 128.16 | | $ | - |
| | | | | Floor | $ | 73.75 | | $ | 73.75 | | $ | 73.75 | | $ | 80.41 | | $ | 80.18 | | $ | 87.92 | | $ | - |
| | | | | Short Put | $ | 59.31 | | $ | 59.31 | | $ | 59.31 | | $ | 65.00 | | $ | 65.18 | | $ | 72.92 | | $ | - |
| | | Percent of total oil production (a) | | ~90% | | | ~85% | | | ~80% | | | ~75% | | | ~35% | | | ~15% | | | N/A |
| Average Daily NGL Production Associated | | | | | | | | | | | | | | | | | | | | |
| | with Derivatives (Bbls): | | | | | | | | | | | | | | | | | | | | |
| | | Swap Contracts: | | | | | | | | | | | | | | | | | | | | |
| | | | Volume | | 1,150 | | | 1,150 | | | 1,150 | | | 750 | | | - | | | - | | | - |
| | | | Blended index price (b) | $ | 51.38 | | $ | 51.50 | | $ | 51.50 | | $ | 35.03 | | $ | - | | $ | - | | $ | - |
| | | Collar Contracts: | | | | | | | | | | | | | | | | | | | | |
| | | | Volume | | 2,650 | | | 2,650 | | | 2,650 | | | - | | | - | | | - | | | - |
| | | | Index price (b): | | | | | | | | | | | | | | | | | | | | |
| | | | | Ceiling | $ | 64.23 | | $ | 64.23 | | $ | 64.23 | | $ | - | | $ | - | | $ | - | | $ | - |
| | | | | Floor | $ | 53.29 | | $ | 53.29 | | $ | 53.29 | | $ | - | | $ | - | | $ | - | | $ | - |
| | | Percent of total NGL production (a) | | ~15% | | | ~15% | | | ~15% | | | <5% | | | N/A | | | N/A | | | N/A |
| Average Daily Gas Production Associated | | | | | | | | | | | | | | | | | | | | |
| | with Derivatives (MMBtu): | | | | | | | | | | | | | | | | | | | | |
| | | Swap Contracts: | | | | | | | | | | | | | | | | | | | | |
| | | | Volume | | 117,500 | | | 117,500 | | | 117,500 | | | 105,000 | | | 67,500 | | | 50,000 | | | - |
| | | | NYMEX price (c) | $ | 6.13 | | $ | 6.13 | | $ | 6.13 | | $ | 5.82 | | $ | 6.11 | | $ | 6.05 | | $ | - |
| | | Collar Contracts: | | | | | | | | | | | | | | | | | | | | |
| | | | Volume | | - | | | - | | | - | | | 65,000 | | | 150,000 | | | 140,000 | | | 50,000 |
| | | | NYMEX price (c): | | | | | | | | | | | | | | | | | | | | |
| | | | | Ceiling | $ | - | | $ | - | | $ | - | | $ | 6.60 | | $ | 6.25 | | $ | 6.44 | | $ | 7.92 |
| | | | | Floor | $ | - | | $ | - | | $ | - | | $ | 5.00 | | $ | 5.00 | | $ | 5.00 | | $ | 5.00 |
| | | Collar Contracts with Short Puts: | | | | | | | | | | | | | | | | | | | | |
| | | | Volume | | 200,000 | | | 200,000 | | | 200,000 | | | 190,000 | | | 45,000 | | | 50,000 | | | - |
| | | | NYMEX price (c): | | | | | | | | | | | | | | | | | | | | |
| | | | | Ceiling | $ | 8.55 | | $ | 8.55 | | $ | 8.55 | | $ | 7.96 | | $ | 7.49 | | $ | 8.08 | | $ | - |
| | | | | Floor | $ | 6.32 | | $ | 6.32 | | $ | 6.32 | | $ | 6.12 | | $ | 6.00 | | $ | 6.00 | | $ | - |
| | | | | Short Put | $ | 4.88 | | $ | 4.88 | | $ | 4.88 | | $ | 4.55 | | $ | 4.50 | | $ | 4.50 | | $ | - |
| | | Percent of total gas production (a) | | ~90% | | | ~90% | | | ~85% | | | ~80% | | | ~50% | | | ~40% | | | ~5% |
| | | Basis Swap Contracts: | | | | | | | | | | | | | | | | | | | | |
| | | | Permian Basin Index Swaps volume - (d) | | 20,000 | | | 20,000 | | | 20,000 | | | 32,500 | | | 2,500 | | | - | | | - |
| | | | Price differential ($/MMBtu) | $ | (0.30) | | $ | (0.30) | | $ | (0.30) | | $ | (0.38) | | $ | (0.31) | | $ | - | | $ | - |
| | | | Mid-Continent Index Swaps volume - (d) | | 100,000 | | | 100,000 | | | 100,000 | | | 40,000 | | | 10,000 | | | - | | | - |
| | | | Price differential ($/MMBtu) | $ | (0.71) | | $ | (0.71) | | $ | (0.71) | | $ | (0.58) | | $ | (0.71) | | $ | - | | $ | - |
| | | | Gulf Coast Index Swaps volume - (d) | | 33,500 | | | 23,500 | | | 23,500 | | | 43,500 | | | 20,000 | | | 10,000 | | | - |
| | | | Price differential ($/MMBtu) | $ | (0.13) | | $ | (0.16) | | $ | (0.16) | | $ | (0.16) | | $ | (0.16) | | $ | (0.16) | | $ | - |
__________
| (a) | Represents an estimated percentage of forecasted production, which may differ from the percentage of actual production. |
| (b) | Represents weighted average index price per Bbl of each NGL component. |
| (c) | Represents the NYMEX Henry Hub index price or approximate NYMEX Henry Hub index price based on historical differentials to the index price on the derivative trade date. |
| (d) | Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin, Mid-Continent and Gulf Coast gas and the NYMEX Henry Hub index price used in gas swap contracts. |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Amortization of Deferred Revenue Associated with Volumetric Production Payments and Derivative Losses
as of March 31, 2011
(in thousands)
| | | 2011 | | | | | | |
| | | Second
Quarter | | Third
Quarter | | Fourth
Quarter | | 2012 | | Total |
| | | | | | | | | | | | | | | | |
| Total deferred revenues (a) | $ | 11,207 | | $ | 11,330 | | $ | 11,330 | | $ | 42,070 | | $ | 75,937 |
| Less derivative losses to be recognized in | | | | | | | | | | | | | | |
| | pretax earnings (b) | | (889) | | | (903) | | | (906) | | | (3,157) | | | (5,855) |
| | | | | | | | | | | | | | | | |
| Total VPP impact to pretax earnings | $ | 10,318 | | $ | 10,427 | | $ | 10,424 | | $ | 38,913 | | $ | 70,082 |
__________
| (a) | Deferred revenue will be amortized as increases to oil revenues during the indicated future periods. |
| (b) | Represents the remaining pretax earnings impact of the derivatives assigned in the VPPs. |
Deferred Gains on Discontinued Commodity Hedges as of March 31, 2011 (a)
(in thousands)
| | | 2011 |
| | | | Second
Quarter | | Third
Quarter | | Fourth
Quarter |
| | | | | | | | | | | |
| | | | | | | | | | | |
| Commodity hedge gains - oil (b) | | $ | 9,097 | | $ | 9,197 | | $ | 9,197 |
__________
| (a) | Excludes deferred hedge losses on terminated derivatives related to the VPPs. |
| (b) | Deferred commodity hedge gains will be realized as increases to oil revenues during the indicated future periods. |
PIONEER NATURAL RESOURCES COMPANY
SUPPLEMENTAL INFORMATION
Derivative Losses, Net
(in thousands)
| | | | | Three Months Ended March 31, 2011 |
| Unrealized mark-to-market changes in fair value: | | |
| | Oil derivative losses | $ | 212,951 |
| | NGL derivative losses | | 7,118 |
| | Gas derivative losses | | 48,560 |
| | Interest rate derivative losses | | 7,181 |
| | | Total unrealized mark-to-market derivative losses (a) | | 275,810 |
| | | | | | |
| Cash settled changes in fair value: | | |
| | Oil derivative losses | | 13,234 |
| | NGL derivative losses | | 2,696 |
| | Gas derivative gains | | (42,279) |
| | Interest rate derivative gains | | (5,029) |
| | | Total cash derivative gains, net | | (31,378) |
| | | | Total derivative losses, net | $ | 244,432 |
__________
| (a) | Total unrealized mark-to-market derivative losses includes $14.2 million of losses attributable to noncontrolling interests in consolidated subsidiaries during the three month period ending March 31, 2011. |
