EXHIBIT 99.1
News Release
Pioneer Natural Resources Reports
Fourth Quarter 2010 Financial and Operating Results
Dallas, Texas, February 7, 2011 -- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended December 31, 2010.
Pioneer reported fourth quarter net income attributable to common stockholders of $80 million, or $.67 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 $85 million after tax, or $.71 per diluted share. Without the effect of this item, adjusted income for the fourth quarter of 2010 would have been $165 million, or $1.38 per diluted share.
Also included in Pioneer’s fourth quarter results was a net gain of $106 million after tax, or $.87 per diluted share, related to unusual items. These unusual items included:
| · | a net gain of $84 million after tax ($.70 per diluted share) related to the settlement of an insurance claim for the reclamation and abandonment of the Company’s East Cameron 322 facility in the Gulf of Mexico that was destroyed by Hurricane Rita in 2005, |
| · | earnings from discontinued operations that are not attributable to Tunisia’s results of operations for the fourth quarter of $51 million ($.42 per diluted share), principally related to the recognition of future foreign tax credit net benefits associated with the Tunisian divestiture, |
| · | a benefit of $14 million ($.11 per diluted share) from adjusting state tax apportionment factors to reflect that a larger percentage of Pioneer’s future business activities will occur in Texas, which has a lower state tax rate than the other states where Pioneer operates, |
| · | the recovery of a processing fee in Alaska of $11 million after tax ($.09 per diluted share), |
| · | a foreign tax credit of $8 million ($.06 per diluted share) related to the repatriation of earnings from South Africa, and |
| · | a noncash exploration and abandonment charge of $62 million after tax ($.51 per diluted share) associated with the decision to abandon the Cosmopolitan project in Alaska. |
Fourth quarter and other recent highlights included:
| · | producing 117 thousand barrels oil equivalent per day (MBOEPD), including volumes reflected in discontinued operations associated with the sale of Tunisia (111 MBOEPD excluding volumes reflected in discontinued operations), |
| · | achieving the Company’s production growth target of 10% from the fourth quarter of 2009 to the fourth quarter of 2010, including volumes reflected in discontinued operations (+11% excluding volumes reflected in discontinued operations), |
| · | Spraberry production growth exceeding forecast due to improved well performance associated with deeper drilling, |
| · | ramping up Spraberry drilling to 30 rigs at year-end 2010, with an acceleration to 35 rigs expected by mid-year 2011, |
| · | increasing the estimated ultimate recovery for a 40-acre Spraberry well from 110 thousand barrels oil equivalent (MBOE) to 140 MBOE as a result of successful deeper drilling to the Lower Wolfcamp and completions in the shale/silt intervals, |
| · | ramping up Eagle Ford Shale production as expected; exited 2010 at net 5 MBOEPD; currently running 7 rigs and expect to increase to 12 rigs by mid-2011, |
| · | installing central gathering plants (CGPs) in the Eagle Ford Shale – 3 CGPs online, 2 additional CGPs expected by March and 3 more CGPs by year-end 2011, |
| · | expanding vertical integration, particularly fracture stimulation capabilities in Spraberry, Eagle Ford Shale and the Barnett Shale Combo play, |
| · | adding proved reserves during 2010 totaling 163 million barrels oil equivalent (MMBOE), or 363% of full-year production, |
| · | reporting 2010 drillbit finding and development cost of $9.96 per barrel oil equivalent (BOE) excluding price revisions, |
| · | decreasing debt to book capitalization from 43% at year-end 2009 to 37% at year-end 2010, and |
| · | announcing an agreement to sell Pioneer’s Tunisia subsidiaries for $866 million, with proceeds to be redeployed to the Company’s core U.S. assets. |
Scott Sheffield, Chairman and CEO, stated, “In 2010, we ramped up drilling in the Spraberry field and the Eagle Ford Shale faster than originally planned and delivered production growth from these assets in excess of our initial targets, while continuing to spend within cash flow. For 2011, we are further accelerating drilling in these two core plays and expect to deliver production growth for the Company ranging from 15% to 19% compared to 2010 (reflecting production from Tunisia as discontinued operations). The accelerated drilling program will be funded from forecasted operating cash flow of approximately $1.4 billion and the redeployment of a portion of the proceeds from the pending sale of T unisia. For the 2011 to 2013 period, we are increasing our compound annual production growth rate target for the Company from 15+% to 18+% and expect operating cash flow to grow from $1.0 billion in 2010 to approximately $2.3 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 30 rigs currently operating. As a result of the Tunisia sale, the Company expects to accelerate its planned drilling ramp-up in the field and increase the rig count to 35 rigs by mid-2011 and to 40 or more rigs in 2012.
As forecasted, the drilling program generated quarter-to-quarter Spraberry production growth during 2010. Fourth quarter production was 38 MBOEPD, up 9% from the third quarter of 2010. The fourth quarter production level exceeded Pioneer’s forecast for the quarter by 2 MBOEPD due to improved well performance associated with deeper drilling in the field. Production is expected to increase further to an average of 42 MBOEPD to 46 MBOEPD in 2011.
The 2010 drilling program added incremental production and proved reserves from vertical completions in the Lower Wolfcamp and shale/silt intervals. Initial cumulative production from all wells drilled to these intervals in 2010 with at least four months of production history averaged 30+% more cumulative production than that of a traditional Spraberry/Dean/Upper Wolfcamp well. As a result, the Company is increasing the estimated ultimate recovery (EUR) of a vertical Spraberry well from 110 MBOE to 140 MBOE to reflect the incremental production and reserves that are expected to be added from the deeper drilling into the Lower Wolfcamp and shale/silt intervals. Potential additional production and reserves from drilling to the Strawn and Atoka intervals below the Wolfcamp are not included in the Company’s increased EUR for a vertical Spraberry well.
Based on the planned drilling ramp-up and incremental production generated from drilling to deeper intervals, Spraberry field production is expected to double from 34 MBOEPD in 2010 to 66 to 70 MBOEPD in 2013, reflecting a compound annual production growth rate of more than 25%.
The Company has a two-well program underway to test horizontal drilling in the Wolfcamp. Both wells will be 4,000-foot laterals with 15-stage fracture stimulation completions. The first well is being drilled in
the Middle Wolfcamp carbonate section and is currently being completed. The second is targeting the Lower Wolfcamp shale section and is expected to be completed during March.
Water injection was initiated in August 2009 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 is beginning to flatten. Based on the results of historical waterflood projects, an ultimate uptick in production of 50% from the flooded Upper Spraberry interval is expected.
As Pioneer ramps up drilling in the Spraberry field, the Company continues to expand its integrated services to control drilling costs and ensure execution of its accelerated drilling program. A third Company-owned fracture stimulation fleet has recently commenced operating in the field. Two additional fleets are being built, with one scheduled for delivery in the second quarter of 2011 and the second in the fourth quarter of 2011. To support its fracture stimulation operations, Pioneer has sand supply in place to cover its forecasted requirements through 2015. Tubular and pumping unit requirements have been contracted through 2012. In addition, the Company owns 12 dril ling rigs that are currently operating. The Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks and fishing tools, to support its growing operations.
Vertical integration in the Spraberry field is saving Pioneer up to $500 thousand per well compared to utilizing third-party services. Pioneer expects to meet approximately 30% of its rig requirements and 60% 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 approximately 45% before tax based on current NYMEX strip commodity prices and estimated future production costs.
In the highly prospective Eagle Ford Shale in South Texas, Pioneer and its joint venture partners have successfully drilled 41 horizontal wells to date. Twenty-one of the wells are on production, with most of the production from these wells flowing through three CGPs that were constructed as part of the Company’s midstream business. Performance from these 21 wells continues as expected. Of the remaining 20 wells, three have been completed and are awaiting hookup. Completion of the remaining 17 wells has been slower than anticipated due to limited third-party fracture stimulation fleet availability.
To improve the execution of its drilling and completions program and reduce costs, Pioneer has purchased two fracture stimulation fleets, with one expected to be in service during the second quarter of 2011 and the other during the fourth quarter of 2011. The Company has also entered into a two-year contract for a dedicated third-party fracture stimulation fleet beginning later this quarter and is pursuing opportunities to contract additional third-party equipment.
Pioneer has seven rigs running in the play. The initial joint-venture development plan called for an increase to 10 rigs by the end of 2011, 14 rigs by the end of 2012 and remaining at this level thereafter. An accelerated plan for 2011 has been approved by the joint-venture partners and now reflects increasing to 12 rigs by the middle of 2011. The rig count is expected to increase to 14 rigs in 2012 and 16 rigs in 2013.
Initiatives to control drilling, completion and production costs in the play continue despite significant service cost inflation. Drilling times have been reduced and completion techniques continue to be optimized. Agreements have also been executed with third parties to process, fractionate and transport gas and oil production.
As a result of these initiatives, Pioneer expects gross well costs in the Eagle Ford Shale to range 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
approximately 100% for high condensate yield wells (200 barrels per million cubic feet) and 50% for low condensate yield wells (60 barrels per million cubic feet).
As forecasted, Pioneer exited 2010 in the Eagle Ford Shale at a net production rate of 5 MBOEPD. Based on the accelerated joint-venture development plan, average annual production in 2011 is expected to grow to an average of 12 MBOEPD to 15 MBOEPD, with a further increase to 26 MBOEPD to 30 MBOEPD in 2012 and 40 MBOEPD to 45 MBOEPD in 2013.
Plans for the Eagle Ford Shale midstream business call for five additional CGPs to be completed during 2011, with the first two online in March.
Pioneer continues to acquire acreage in the liquids-rich Barnett Shale Combo play, where the Company has 65,000 net acres under lease, representing more than 600 drilling locations. The Company commenced drilling in the play in the latter part of 2010 and currently has 2 rigs operating in Montague County. The Company has acquired 110 square miles of 3-D seismic covering its acreage and expects to increase this coverage to approximately 200 square miles by year end. Thirteen wells have been drilled to date, of which three have been completed. First production is expected during February. Assuming current NYMEX strip commodity prices, an average per well drilling cost of $2.8 million and a gross EUR of 320 MBOE, Pioneer’s internal rate of return in the Barnett Shale Combo play is expected to be approximately 45% before tax. A Pioneer-owned frac fleet has been ordered for the Barnett Shale Combo play with delivery expected in the second quarter of 2011.
On the North Slope of Alaska, Pioneer will continue to operate one rig during 2011. A key element of the 2011 drilling program will be the further testing of the Torok formation within the Moraine play. The Company is currently drilling its first of two Torok wells. Additional Kuparuk and Nuiqsut drilling is also planned for later in the year. Production in Alaska was 6 thousand barrels oil per day (MBOPD) during the fourth quarter, down approximately 1 MBOPD compared to the third quarter as production was limited by unplanned third-party service disruptions (compressor outages and interruptions to the supply of gas and injection water for reservoir pressure maintenance) and well maintenanc e. Production will continue to be limited in the first quarter of 2011 due to outages on the Trans Alaska Pipeline and continuing unplanned third-party service disruptions.
In the Mid-Continent area (Panhandle of Texas and Western Kansas), fourth quarter 2010 production was 20 MBOEPD, down approximately 500 barrels oil equivalent per day (BOEPD) from the third quarter of 2010 due to unscheduled pipeline downtime. In the Raton Basin (Southeastern Colorado) and the Edwards Trend (South Texas), where gas drilling has been curtailed since the beginning of 2009 due to low gas prices, fourth quarter 2010 production was 169 million cubic feet per day (MMCFPD) and 51 MMCFPD, respectively. These rates were essentially flat with production rates in the third quarter of 2010.
2011 Capital Budget
Pioneer’s capital program for 2011 totals $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 approximately $1.4 billion, assuming current NYMEX strip pricing, and by redeploying approximately $0.4 billion from the pending sale of Tunisia.
Pioneer’s year-end 2010 net debt (reduced for cash on Pioneer’s balance sheet) was $2.5 billion, a reduction of $0.2 billion from year-end 2009. With Pioneer’s improving net debt position, net debt-to-book capitalization declined from 43% at year-end 2009 to 37% at year-end 2010 and is forecasted to further decline to approximately 30% by year-end 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 non-consolidated entity. For 2011, the Company expects the majority of the funding for the ongoing midstream infrastructure build-out to be provided from external debt sources. Cash flow from this activity is not included in Pioneer’s forecasted operating cash flow of $1.4 billion in 2011.
Fourth Quarter 2010 Financial Review
The following financial results for the fourth quarter of 2010 reflect continuing operations.
Fourth quarter sales averaged 111 MBOEPD, consisting of oil sales averaging 31 MBOPD, NGL sales averaging 20 thousand barrels per day and gas sales averaging 361 MMCFPD.
The average reported fourth quarter price for oil was $94.38 per barrel and included $7.90 per barrel related to deferred revenue from volumetric production payments (VPPs) for which production was not recorded. The average reported price for NGLs was $42.03 per barrel. The average reported price for gas was $3.79 per thousand cubic feet.
Fourth quarter production costs averaged $10.94 per BOE, a decrease of $2.33 per BOE from the third quarter. This decrease included recognizing a processing fee recovery associated with the Company’s Oooguruk project in Alaska of $10 million ($1.02 per BOE). The processing fee recovery represents that portion of recovery that is attributable to the first nine months of 2010. The production cost decrease also included reduced workover activity during the fourth quarter ($.35 per BOE) and a $.43 per BOE ad valorem tax accrual reduction after receiving actual invoices for the full year.
Depreciation, depletion and amortization (DD&A) expense averaged $13.53 per BOE for the fourth quarter, benefiting from the proved reserve additions attributable to the Company’s successful drilling program and positive price and technical revisions. Exploration and abandonment costs were $129 million for the quarter and included $97 million related to the abandonment of the Cosmopolitan project, $18 million of unsuccessful exploration costs and acreage abandonments, and $14 million of geologic and geophysical expenses and personnel costs.
Cash flow from operating activities for the fourth quarter was $383 million.
First Quarter 2011 Financial Outlook
The Company’s first quarter 2011 outlook for certain operating and financial items is provided below. This outlook does not reflect potential impacts of anticipated weather-related downtime and associated repairs in several of Pioneer’s operating areas.
Production is forecasted to average 114 MBOEPD to 118 MBOEPD.
Production costs are expected to average $11.75 to $13.75 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. Cash 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 Tuesday, February 8, 2011, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended December 31, 2010, 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 (877) 718-5098 confirmation code: 2034800 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 March 4 by dialing (888) 203-1112 confirmation code: 2034800.
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, international operations and associated international political and economic instability, 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 re fining 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, 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 Pion eer 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.
"Drillbit finding and development cost per BOE," or "drillbit F&D cost per BOE," means the summation of exploration and development costs incurred divided by the summation of annual proved reserves, on a BOE basis, attributable to technical revisions of previous estimates, discoveries and extensions and improved recovery. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.
"Reserve replacement" is the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates, purchases of minerals-in-place, discoveries and extensions and improved recovery divided by annual production of oil, NGLs and gas, on a BOE basis.
Pioneer Natural Resources Contacts:
Investors
Frank Hopkins – 972-969-4065
Brian Hansen – 972-969-4017
Media and Public Affairs
Susan Spratlen – 972-969-4018
Suzanne Hicks – 972-969-4020
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 (loss) per share attributable to common stockholders is computed as (i) net income (loss) 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 (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus adjustments t o 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 not be dilutive to loss per share and conversion into common stock is assumed not to occur.
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the three and twelve months ended December 31, 2010 and 2009:
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 (loss) 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 (loss) or net cash provided by operating activities, as defined by GAAP.
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 e nhance 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, net hurricane related credits 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 December 31, 2010, 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.
