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Pioneer Natural Resources Reports Fourth Quarter 2013 Financial and Operating Results and Announces 2014 Capital Budget

DALLAS--(BUSINESS WIRE)--Feb. 10, 2014-- Pioneer Natural Resources Company (NYSE:PXD) (“Pioneer” or “the Company”) today announced financial and operating results for the quarter ended December 31, 2013.

Pioneer reported a fourth quarter net loss attributable to common stockholders of $1.4 billion, or $9.82 per diluted share (see attached schedule for a description of the net loss per diluted share calculation). Without the effect of noncash derivative mark-to-market losses and other unusual noncash items, adjusted income for the fourth quarter was $140 million after tax, or $1.00 per diluted share.

Fourth quarter and other recent highlights included:

  • producing 164 thousand barrels oil equivalent per day (MBOEPD) from continuing operations in the fourth quarter (excludes the previously announced sale of Alaska assets and the plan to sell the Company’s Barnett Shale assets that is being announced today); fourth quarter production was curtailed by approximately 6 MBOEPD due to severe winter weather in Texas, primarily in the Spraberry/Wolfcamp play; fourth quarter production was 173 MBOEPD including Barnett Shale production, which is consistent with Pioneer’s news release on January 20, 2014;
  • producing 161 MBOEPD for full-year 2013 from continuing operations (excludes production from Alaska and Barnett Shale assets that is reflected in discontinued operations), an increase of 12% from a comparable full-year 2012; this strong production growth was primarily related to the Company’s successful Spraberry/Wolfcamp (+19%) and Eagle Ford Shale (+35%) drilling programs; Eagle Ford Shale achieved record production in the fourth quarter;
  • growing oil production from continuing operations by 22% in 2013 as compared to 2012;
  • delivering 211% drillbit reserve replacement by adding proved reserves of 141 million barrels oil equivalent (MMBOE) (excludes proved undeveloped reserves removed totaling 319 MMBOE and positive pricing revisions of 30 MMBOE) at a drillbit finding and development cost of $19.70 per barrel oil equivalent (BOE);
  • forecasting annual production growth from continuing operations of 14% to 19% from 2013 to 2014 based on planned drilling capital expenditures of $3.0 billion; production growth in 2014 will be second-half weighted as Pioneer ramps up its drilling program in the northern Spraberry/Wolfcamp from five rigs at year-end 2013 to 16 rigs by the end of the first quarter;
  • targeting compound annual production growth from continuing operations of 16% to 21% for 2014 to 2016 and expecting to more than double production by 2018 compared to 2013;
  • having derivative coverage for approximately 90% of forecasted 2014 oil production at $93 per barrel or higher;
  • completing the merger of Pioneer and Pioneer Southwest Energy Partners L.P.;
  • progressing asset divestitures that will allow Pioneer to reallocate capital to the Company’s higher-return Spraberry/Wolfcamp horizontal drilling program; these divestitures include (i) the previously-announced sale of Pioneer’s Alaska assets for reduced proceeds of $350 million (remains subject to receiving governmental and other third-party approvals), (ii) the plan to sell Pioneer’s Barnett Shale assets that is being announced today and (iii) the expected divestiture of other assets for anticipated proceeds of approximately $100 million;
  • maintaining a strong balance sheet with approximately $400 million of cash on hand at year-end 2013, a net debt-to-operating cash flow of 1.1 and a net debt-to-book capitalization of 25%;
  • concluding that production data from Pioneer’s first 10 Wolfcamp A, B and D interval wells on its northern Spraberry/Wolfcamp acreage supports estimated ultimate recoveries (EURs) for wells with 7,000-foot lateral lengths of:
    • 1 MMBOE for Wolfcamp B interval wells in Midland County with before tax returns of 100+%,
    • 800 thousand barrels oil equivalent (MBOE) for Wolfcamp A interval wells in Midland County and Wolfcamp B interval wells in Martin County with before tax returns of 100+% and
    • 650 MBOE to 800 MBOE for Wolfcamp D interval wells in Midland, Martin and Andrews counties with before tax returns ranging from 45% to 95%;
  • placing four additional Wolfcamp B interval wells on production in the fourth quarter (two were in Midland County with 24-hour peak initial production (IP) rates of 2,673 barrels oil equivalent per day (BOEPD) and 2,347 BOEPD and two were in Martin County with 24-hour peak IP rates of 1,606 BOEPD and 756 BOEPD); early production data from these wells also supports EURs for Wolfcamp B interval wells with 7,000-foot lateral lengths of 1 MMBOE in Midland County and 800 MBOE in Martin County;
  • placing first Wolfcamp B interval well in Glasscock County on production in early February with 24-hour peak IP rate of 1,460 BOEPD;
  • placing the Company’s first five Lower Spraberry Shale interval wells on production in the fourth quarter and early January in Andrews, Glasscock, Martin and Midland counties, with 24-hour peak IP rates ranging from 537 BOEPD to 1,660 BOEPD and an average oil content of 84%; early production data from these wells suggests that Lower Spraberry Shale EURs will range from 575 MBOE to 800 MBOE with before tax returns ranging from 45% to 100%;
  • continuing to test horizontal downspacing in the southern Wolfcamp joint venture area; six wells downspaced to 480 feet between wells continue to display similar production performance to six offset wells placed at 720 feet between wells;
  • testing of 300-foot downspaced and staggered horizontal wells in the liquids-rich areas of the Eagle Ford Shale continues; initial 300-foot and staggered test in the Lower Eagle Ford Shale indicates performance is consistent with offset 500-foot spaced wells;
  • announcing that Pioneer’s first successful Upper Eagle Ford Shale well continues to perform in line with offset Lower Eagle Ford Shale wells; 45 Upper Eagle Ford Shale wells are planned in 2014 as part of the downspacing program in this play;
  • optimizing completions in the Eagle Ford Shale, which is increasing EURs by 20% to 30% with a minimal increase in drilling and completion capital and generating before tax returns of 100% on the incremental capital spent; and
  • increasing Pioneer’s net recoverable resource potential from more than 8 billion barrels oil equivalent (BBOE) to more than 10 BBOE, primarily as a result of drilling and downspacing success in the Spraberry/Wolfcamp and Eagle Ford Shale plays; Pioneer’s total proved reserves and net recoverable resource potential exceeds 11 BBOE.

Scott D. Sheffield, Chairman and CEO, stated, “I consider 2013 to be the best year in Pioneer’s 17-year history. Our successful horizontal drilling programs in the Spraberry/Wolfcamp and Eagle Ford Shale plays contributed to another year of strong production growth and drillbit reserve additions. The successful closing of our joint venture with Sinochem in the southern Wolfcamp and our successful equity offering in February allowed us to accelerate horizontal development drilling in the southern Wolfcamp and to commence appraising six horizontal shale intervals across our extensive northern Spraberry/Wolfcamp acreage position. By demonstrating the horizontal prospectivity of Pioneer’s northern acreage and progressing successful downspacing programs in the Eagle Ford Shale and the Spraberry/Wolfcamp, we added substantial resource potential and net asset value to the Company. We are in the process of reallocating capital to higher-return Spraberry/Wolfcamp horizontal drilling by reducing our vertical drilling activity and divesting our Alaska and Barnett Shale assets. We accomplished all of this while maintaining a strong balance sheet and building one of the best oil and gas derivative positions in the industry. Pioneer’s stock price increased by 73% during 2013, and we were once again the top performing energy stock in the S&P 500.”

“Looking ahead to 2014, our main objective is to translate the resource growth we delivered in 2013 to strong production growth. To accomplish this, we are increasing our horizontal rig count in the northern Spraberry/Wolfcamp from five rigs at the end of 2013 to 16 rigs by the end of the first quarter. We will also continue an active drilling program in the southern Wolfcamp joint venture area and the Eagle Ford Shale. As a result, we expect a 14% to 19% increase in production in 2014 compared to 2013. Looking beyond 2014, we expect to continue to ramp up our horizontal rig count in the Spraberry/Wolfcamp, deliver compound annual production growth of 16% to 21% for the next three years and more than double production by 2018.”

Mark-To-Market Derivative Losses and Unusual Items Included in Fourth Quarter 2013 Earnings

Pioneer’s fourth quarter earnings included noncash mark-to-market losses on derivatives of $28 million after tax, or $0.20 per diluted share.

Fourth quarter earnings also included a loss of $1.5 billion after tax, or $10.62 per diluted share, related to the following unusual noncash items:

  • a loss of $507 million after tax, or $3.64 per diluted share, associated with discontinued operations and assets held for sale,
  • an impairment charge of $957 million after tax, or $6.87 per diluted share, to reduce the carrying value of the Company’s Raton proved gas properties as a result of the decline in long-term NYMEX strip gas prices and
  • an impairment charge of $15 million, or $0.11 per diluted share, associated with surplus vertical well-related inventory.

Operations Update and Drilling Program

Pioneer is the largest acreage holder in the Spraberry/Wolfcamp play, with more than 600,000 gross acres in the northern portion of the play and more than 200,000 gross acres in the southern Wolfcamp joint venture area. The Company believes it has 10 BBOE of net recoverable resource potential from horizontal drilling across its entire acreage position based on its extensive geologic data and successful drilling results to date.

The Company commenced an active horizontal drilling program in early 2013 to appraise six different “stacked” shale intervals across its northern acreage position. By mid-2013, five horizontal rigs were being operated, which resulted in 21 horizontal wells being placed on production during the year. These wells included:

  • nine Wolfcamp B interval wells with 24-hour peak IP rates averaging 1,850 BOEPD and peak 30-day average rates of 1,149 BOEPD,
  • one Wolfcamp A interval well with a 24-hour peak IP rate of 1,712 BOEPD and a peak 30-day average rate of 1,122 BOEPD,
  • four Wolfcamp D interval wells with 24-hour peak IP rates averaging 2,600 BOEPD and peak 30-day average rates of 938 BOEPD,
  • five Lower Spraberry Shale interval wells with 24-hour peak IP rates averaging 939 BOEPD (peak 30-day rate average not yet achieved for all five wells) and
  • two Jo Mill Shale interval wells with 24-hour peak IP rates averaging 486 BOEPD; however, these wells both incurred mechanical problems during completion and have subsequently been shut in pending remedial action.

Based on these production results and the extensive “science” (e.g. coring, open-hole logging, micro-seismic and 3-D seismic) that was performed on these wells, the Company’s geologic maps are being confirmed and four of the six “stacked” shale intervals are now considered successfully appraised. Appraisal of the Jo Mill Shale and Middle Spraberry Shale intervals is currently underway, with results expected later this year.

Pioneer has 10 horizontal oil wells that have been on production for an extended period of time in the Wolfcamp A, B and D intervals in the northern Spraberry/Wolfcamp. Production data from these wells supports EURs for wells with 7,000-foot lateral lengths of:

  • 1 MMBOE for Wolfcamp B wells and 800 MBOE for Wolfcamp A wells in Midland County,
  • 800 MBOE for Wolfcamp B wells in Martin County and
  • 650 MBOE to 800 MBOE for Wolfcamp D wells in Midland, Martin and Andrews counties.

Pioneer also placed the following four Wolfcamp B wells on production in the fourth quarter:

  • DL Hutt C #6H (7,382-foot lateral length) - 24-hour peak IP rate of 2,673 BOEPD (75% oil content) and 30-day IP rate of 1,369 BOEPD,
  • DL Hutt C #5H (7,331-foot lateral length) - 24-hour peak IP rate of 2,347 BOEPD (75% oil content) and 30-day peak IP rate of 1,300 BOEPD,
  • Mabee K #4H (9,542-foot lateral length) - 24-hour peak IP rate of 1,606 BOEPD (80% oil content) and 30-day IP rate of 955 BOEPD and
  • Scharbauer Ranch #203H (7,622-foot lateral length) - 24-hour peak IP rate of 756 BOEPD (70% oil content) and 30-day IP rate of 571 BOEPD.

Early production data from these wells also supports EURs for Wolfcamp B interval wells with lateral lengths of 7,000-feet of 1 MMBOE in Midland County and 800 MBOE in Martin County.

Pioneer also placed its first horizontal Wolfcamp B interval well on production in Glasscock County in early February. The Flanagan 14 Lloyd B #1H (9,542-foot lateral) had a 24-hour peak IP rate of 1,460 BOEPD (79% oil content).

The Company’s first five Lower Spraberry Shale interval wells were placed on production during the fourth quarter and early January in Andrews, Glasscock, Martin and Midland counties with the following 24-hour peak IP rates:

  • University 7-43 #16H (Andrews County) - 7,502-foot lateral length with a 24-hour peak IP rate of 1,660 BOEPD (84% oil content),
  • Flanagan 14 Lloyd A #21H (Glasscock County) - 7,212-foot lateral length with a 24-hour peak IP rate of 1,010 BOEPD (82% oil content),
  • Mabee K #10H (Martin County) - 4,982-foot lateral length with a 24-hour peak IP rate of 795 BOEPD (84% oil content),
  • Scharbauer Ranch #501H (Martin County) - 7,502-foot lateral length with a 24-hour peak IP rate of 691 BOEPD (83% oil content) and
  • Hutt C #21H (Midland County) - 6,662-foot lateral length with a 24-hour peak IP rate of 537 BOEPD (86% oil content).

The Lower Spraberry Shale interval is estimated to contain 40 million to 60 million barrels of oil per section on Pioneer’s acreage, which is one of the highest oil-in-place intervals in the Spraberry/Wolfcamp play. Pioneer’s first five Lower Spraberry Shale interval wells had an average oil content of 84%. Wells completed in this interval typically take 30 days to 60 days to flow back fracture stimulation water before reaching a 24-hour peak IP rate. Early production data from Pioneer’s first five wells suggests that Lower Spraberry Shale will decline slower than deeper Wolfcamp interval wells and deliver EURs that will range from 575 MBOE to 800 MBOE with before tax returns ranging from 45% to 100%.

Pioneer is transitioning from a horizontal appraisal program in 2013 to a horizontal development program across its northern acreage during 2014. The Company doubled its horizontal rig count from five rigs at year-end 2013 to 10 rigs at the end of January. A further increase to 16 rigs is expected by the end of the first quarter. The 16-rig program is expected to spud 140 wells during 2014 with an average lateral length of approximately 8,200 feet. Approximately 90% of the drilling program will be Wolfcamp A, B and D interval wells. The remaining 10% will be Spraberry Shale wells (Lower Spraberry Shale, Jo Mill Shale and Middle Spraberry Shale). This well mix could include more Spraberry Shale wells if the strong performance of the Lower Spraberry Shale interval wells continues and strong wells results are delivered from the Jo Mill and Middle Spraberry wells that are expected to be placed on production during the first half of the year. Three-well pads will be utilized to drill all of the wells in the 2014 program and “science” activity will be reduced from 2013 levels. The average drilling and completion cost for the 2014 program in the northern acreage is expected to be $8.5 million to $9.0 million per well.

Pioneer expects to spud approximately 115 horizontal wells in the southern Wolfcamp joint venture area in 2014 with an average lateral length of 9,400 feet, an increase of 13% from the average lateral length of 8,300 feet in 2013. Three-well pads will be utilized to drill all of the wells in the 2014 program. The 2014 drilling program will be focused on the higher return areas in northern Upton and Reagan counties (includes Giddings and University Block 2), with approximately two-thirds of the wells being completed in the Wolfcamp B interval and the remainder being a mix of Wolfcamp A, C and D interval wells. The average drilling and completion cost for the 2014 program in the joint venture area is expected to be approximately $8.0 million per well.

Pioneer is testing downspacing from 720-foot spacing between wells to 480-foot spacing between wells in the Giddings area. The initial test, which commenced in the third quarter, includes 12 wells that were drilled on three-well pads using zipper fracture stimulations. The wells all have approximately 6,200-foot perforated lateral lengths and were completed utilizing a 21-stage hybrid fracture stimulation. The wells were also staggered between the Upper Wolfcamp B and Lower Wolfcamp B intervals. All 12 wells are currently on production with similar performance. Pioneer is currently monitoring the performance of these wells and may test downspacing to 310 feet between wells in the future.

Pioneer is currently operating 11 vertical rigs in the Spraberry field that are expected to drill approximately 200 wells in 2014. These 11 rigs, which reflect a reduction of four vertical rigs from 2013, are required to meet continuous drilling obligations. Approximately 90% of the vertical wells in the 2014 drilling program are expected to be completed in the deeper Strawn and Atoka intervals. With only 11 rigs running, vertical production is expected to decline in 2014 by 10%. The Company expects to further reduce its vertical rig count going forward, allowing it to devote more of its capital to higher-rate-of-return horizontal drilling.

Fourth quarter production from the entire Spraberry/Wolfcamp area (northern acreage and southern Wolfcamp joint venture area) averaged 80 MBOEPD. This included horizontal production of 14 MBOEPD and vertical production of 66 MBOEPD. During the fourth quarter, the Company placed 34 horizontal wells on production, predominantly weighted toward the beginning of the quarter, and 56 vertical wells on production. Fourth quarter production was curtailed by approximately 5 MBOEPD due to severe winter weather. Heavy icing and low temperatures across Pioneer’s leasehold position in the Spraberry/Wolfcamp area resulted in extensive power outages, facility freeze-ups, trucking curtailments and limited access to production and drilling facilities. When the severe weather first occurred in late November, over 50% of Pioneer’s more than 7,000 wells in the Spraberry/Wolfcamp area were shut in. All of the affected wells were returned to production by mid-January, and the Company does not anticipate any adverse effects on future well performance due to the wells being shut-in. Drilling and completion operations returned to normal by the end of December.

Full-year 2013 production in the Spraberry/Wolfcamp averaged 79 MBOEPD (including the conveyance of 4 MBOEPD in May 2013 to Sinochem as part of the southern Wolfcamp joint venture transaction), an increase of 19% compared to 2012. For 2014, production is forecasted to grow to 95 MBOEPD to 100 MBOEPD, an increase of 21% to 27% compared to 2013. This growth will be second-half weighted, primarily as a result of moving to three-well pad drilling on Pioneer’s northern acreage and 11 horizontal rigs being added in this area during the first quarter. For the first quarter, Pioneer expects to place approximately 30 horizontal wells on production, predominately in the second half of the quarter and in the southern Wolfcamp joint venture area. The Company also expects to place 50 vertical wells on production during the quarter. Production from these wells will be mostly realized in the second quarter.

Pioneer previously announced that approximately 300 drilling locations were added in the liquids-rich area of the Eagle Ford Shale as a result of downspacing from 1,000 feet between wells to 500 feet between wells. Further downspacing and staggered testing to 175 feet between wells is underway in the liquids-rich areas where the 500-foot spacing was successful. Some areas will include testing of the Lower Eagle Ford Shale interval only, while others will include a combination of the Lower and Upper intervals. Early results from the initial 300-foot downspacing and staggered test in the Lower Eagle Ford Shale continue to be encouraging, with five downspaced wells performing consistent with offset 500-foot spaced wells. The potential exists to add 300 to 400 drilling locations from this program.

In the liquids-rich Eagle Ford Shale play in South Texas, results from Pioneer’s first Upper Eagle Ford Shale well continue to be encouraging, with production in line with offset Lower Eagle Ford Shale interval wells. As a result, the Company plans to drill 45 Upper Eagle Ford Shale wells as part of the downspacing program in 2014. Approximately 25% of Pioneer’s acreage is expected to be prospective for this interval.

Over the past two years, Pioneer has improved its Eagle Ford Shale completion design by reducing cluster spacing, increasing the pounds of white sand proppant pumped per foot, increasing the barrels of fracture stimulation fluid pumped per minute in each cluster (BPM) and utilizing combinations of the above. This optimization program is increasing EURs by 20% to 30% with only a minimal increase in drilling and completion capital and generating before tax returns of 100% on the incremental capital spent.

Pioneer’s fourth quarter production from the Eagle Ford Shale averaged a record 40 MBOEPD. Forty-one wells were placed on production during the quarter, predominately weighted toward the first half of the quarter. Full-year 2013 production averaged 38 MBOEPD, an increase of 35% compared to 2012.

For 2014, the Company expects to drill approximately 110 liquids-rich wells in the Eagle Ford Shale. Most of these wells will be drilled utilizing three-well and four-well pads. The 2014 program reflects longer lateral lengths and larger fracture stimulations compared to 2013. Full-year production is forecasted to range from 45 MBOEPD to 49 MBOEPD, an increase of 18% to 29% compared to full-year 2013. For the first quarter, Pioneer expects to place approximately 26 horizontal wells on production, predominately in the second half of the quarter. Production from these wells will be mostly realized in the second quarter.

2014 Capital Budget

Pioneer’s capital program for 2014 of $3.3 billion (excludes acquisitions, asset retirement obligations, capitalized interest, geological and geophysical G&A and capital expenditures associated with the Alaska and Barnett Shale assets prior to their sale) includes $3.0 billion for drilling and $0.3 billion for vertical integration and the construction of new field and office buildings.

The following provides a breakdown of the drilling capital by asset:

  • Northern Spraberry/Wolfcamp area - $2,165 million (includes $1,225 million for the horizontal drilling program, $440 million for the vertical drilling program, $400 million for infrastructure additions, land and science and $100 million for gas processing facilities)
  • Southern Wolfcamp joint venture area (net of carry) - $205 million (includes $140 million for the horizontal drilling program and $65 million for infrastructure additions, land and science)
  • Eagle Ford Shale - $545 million (includes $480 million for the horizontal drilling program and $65 million for infrastructure additions and land)
  • Other Assets - $100 million

The 2014 capital budget is expected to be funded from forecasted operating cash flow of $2.3 billion (assuming commodity prices of $90 per barrel for oil and $4.00 per thousand cubic feet (MCF) for gas), $0.4 billion from cash on the balance sheet and the proceeds from planned divestitures.

Pioneer’s year-end 2013 net debt was $2.3 billion with net debt-to-operating cash flow of 1.1 and net debt-to-book capitalization of 25%. The Company will continue to target a net debt-to-book capitalization below 35% and net debt-to-operating cash flow below 1.5.

Fourth Quarter 2013 Financial Review

Sales volumes from continuing operations for the fourth quarter of 2013 averaged 164 MBOEPD (excludes Alaska and Barnett Shale production, which is reflected in discontinued operations). Oil sales averaged 72 thousand barrels per day (MBPD), natural gas liquids (NGLs) sales averaged 34 MBPD and gas sales averaged 346 million cubic feet per day.

The average realized price for oil was $90.88 per barrel. The average realized price for NGLs was $30.71 per barrel and the average realized price for gas was $3.44 per MCF. These prices exclude derivatives.

Production costs from continuing operations averaged $13.36 per BOE. Depreciation, depletion and amortization (DD&A) expense averaged $16.13 per BOE. Exploration and abandonment costs were $32 million, principally comprised of $11 million associated with drilling and acreage abandonments, $4 million for seismic data and $17 million for personnel costs. General and administrative expense totaled $96 million, which included increases in performance-related compensation expenses for 2013. Interest expense was $45 million, and other expense was $72 million.

First Quarter 2014 Financial Outlook

The Company’s first quarter 2014 outlook for certain operating and financial items is provided below. This outlook excludes Alaska and Barnett Shale operations which will be reflected in discontinued operations until these assets are sold.

Production is forecasted to average 166 MBOEPD to 171 MBOEPD.

Production costs are expected to average $13.50 per BOE to $15.50 per BOE. DD&A expense is expected to average $13.50 per BOE to $15.50 per BOE. Total exploration and abandonment expense is forecasted to be $25 million to $35 million.

General and administrative expense is expected to be $70 million to $75 million, interest expense is expected to be $44 million to $49 million and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 million.

The Company’s effective income tax rate is expected to range from 35% to 40%. Current income taxes are expected to be $5 million to $10 million and are primarily attributable to federal alternative minimum tax and state taxes.

The Company’s financial and derivative mark-to-market results and open derivatives positions are outlined on the attached schedules.

Earnings Conference Call

On Tuesday, February 11, 2014, at 9:00 a.m. Central Time, Pioneer will discuss its financial and operating results for the quarter ended December 31, 2013, 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 & Webcasts” to listen to the discussion, view the presentation and see other related material.

Telephone: Dial (877) 419-6603 and confirmation code: 1922288 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 8, 2014, by dialing (888) 203-1112 and confirmation code: 1922288.

Pioneer is a large independent oil and gas exploration and production company, headquartered in Dallas, Texas, with operations 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, completion of planned divestitures, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to complete the Company's operating activities, access to and availability of transportation, processing, fractionation 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, the risks associated with the ownership and operation of the Company’s industrial sand mining and oilfield services businesses, 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.

An audit of proved reserves follows the general principles set forth in the standards pertaining to the estimating and auditing of oil and gas reserve information promulgated by the Society of Petroleum Engineers ("SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. Please see the Company's Annual Report on Form 10-K for a general description of the concepts included in the SPE's definition of a reserve audit.

"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 revisions of previous estimates (excluding PUDs removed and price revisions), discoveries and extensions and improved recovery. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included in costs incurred.

“Drillbit reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates (excluding PUDs removed and price revisions), discoveries and extensions and improved recovery divided by annual production of oil, NGLs and gas, on a BOE basis.

Cautionary Note to U.S. Investors -- 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,” “net recoverable resources 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 COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED BALANCE SHEETS
(in thousands)
 

December 31,
2013

December 31,
2012

ASSETS
Current assets:
Cash and cash equivalents $ 392,646 $ 229,396
Accounts receivable, net 433,485 320,153
Income taxes receivable 4,784 7,447
Inventories 220,125 197,056
Prepaid expenses 15,852 13,438
Assets held for sale 583,750
Derivatives 75,237 279,119
Other current assets, net   2,555     3,746  
Total current assets   1,728,434     1,050,355  
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting 13,529,517 14,491,263
Accumulated depletion, depreciation and amortization   (4,903,122 )   (4,412,913 )
Total property, plant and equipment   8,626,395     10,078,350  
Goodwill 274,329 298,142
Other property and equipment, net 1,224,153 1,217,694
Investment in unconsolidated affiliate 224,850 204,129
Derivatives 90,854 55,257
Other assets, net   123,773     165,103  
$ 12,292,788   $ 13,069,030  
 
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable $ 1,060,557 $ 826,877
Interest payable 62,374 68,083
Income taxes payable 165 208
Current deferred income taxes 19,169 86,481
Liabilities held for sale 38,562
Derivatives 11,626 13,416
Other current liabilities   57,653     39,725  
Total current liabilities   1,250,106     1,034,790  
Long-term debt 2,653,059 3,721,193
Deferred income taxes 1,472,717 2,140,416
Derivatives 9,933 12,307
Other liabilities 292,215 293,016
Equity   6,614,758     5,867,308  
 
$ 12,292,788   $ 13,069,030  
 
         
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
 

Three Months Ended
December 31,

Twelve Months Ended
December 31,

2013     2012 2013     2012
Revenues and other income:
Oil and gas $ 809,939 $ 674,379 $ 3,155,696 $ 2,575,311
Sales of purchased oil and gas 139,603 52,055 333,822 122,093
Interest and other 14,042 (16,657 ) 16,961 (1,032 )
Derivative gains, net 4,343 86,683 4,010 330,251
Gain on disposition of assets, net   2,856     503     209,021     45,898  
  970,783     796,963     3,719,510     3,072,521  
Costs and expenses:
Oil and gas production 155,169 150,643 614,676 558,045
Production and ad valorem taxes 46,819 45,224 201,186 178,723
Depletion, depreciation and amortization 243,678 198,258 907,077 708,270

Purchased oil and gas

139,599 55,918 335,734 120,408
Impairment of oil and gas properties 1,495,242 1,495,242
Exploration and abandonments 32,138 14,324 98,448 98,285
General and administrative 95,887 66,504 295,868 244,196
Accretion of discount on asset retirement obligations 2,983 2,189 11,862 8,677
Interest 45,072 53,915 183,750 204,222
Other   71,768     23,037     137,386     114,175  
  2,328,355     610,012     4,281,229     2,235,001  
Income (loss) from continuing operations before income taxes (1,357,572 ) 186,951 (561,719 ) 837,520
Income tax benefit (provision)   493,769     (57,807 )   211,775     (290,488 )
Income (loss) from continuing operations (863,803 ) 129,144 (349,944 ) 547,032
Loss from discontinued operations, net of tax   (494,502 )   (89,442 )   (449,605 )   (304,210 )
Net income (loss) (1,358,305 ) 39,702 (799,549 ) 242,822
Net income attributable to noncontrolling interests   (9,160 )   (10,868 )   (38,865 )   (50,537 )
Net income (loss) attributable to common stockholders $ (1,367,465 ) $ 28,834   $ (838,414 ) $ 192,285  
Basic earnings per share attributable to common stockholders:
Income (loss) from continuing operations $ (6.27 ) $ 0.98 $ (2.86 ) $ 4.02
Loss from discontinued operations   (3.55 )   (0.75 )   (3.30 )   (2.48 )
Net income (loss) $ (9.82 ) $ 0.23   $ (6.16 ) $ 1.54  
Diluted earnings per share attributable to common stockholders:
Income (loss) from continuing operations $ (6.27 ) $ 0.94 $ (2.86 ) $ 3.91
Loss from discontinued operations   (3.55 )   (0.72 )   (3.30 )   (2.41 )
Net income (loss) $ (9.82 ) $ 0.22   $ (6.16 ) $ 1.50  
Weighted average shares outstanding:
Basic   139,314     123,240     136,130     122,966  
Diluted   139,314     126,945     136,130     126,320  
 
         
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
 

Three Months Ended
December 31,

Twelve Months Ended
December 31,

2013     2012 2013     2012
Cash flows from operating activities:
Net income (loss) $ (1,358,305 ) $ 39,702 $ (799,549 ) $ 242,822
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization 243,678 198,258 907,077 708,270
Impairment of oil and gas properties 1,495,242 1,495,242
Impairment of inventory and other property and equipment 53,786 81 61,812 5,719
Exploration expenses, including dry holes 11,662 239 21,379 31,189
Deferred income taxes (499,022 ) 53,122 (222,374 ) 286,229
Gain on disposition of assets, net (2,856 ) (503 ) (209,021 ) (45,898 )
Accretion of discount on asset retirement obligations 2,983 2,189 11,862 8,677
Discontinued operations 513,770 134,055 612,880 497,579
Interest expense 4,186 8,752 17,225 35,563
Derivative related activity 42,053 (24,485 ) 164,121 68,604
Amortization of stock-based compensation 18,210 15,668 70,999 62,567
Amortization of deferred revenue (10,575 ) (42,069 )
Other noncash items 1,395 (13,884 ) (6,073 ) (45,293 )
Change in operating assets and liabilities, net of effects from acquisitions and dispositions:
Accounts receivable, net (33,921 ) (20,260 ) (122,914 ) (28,206 )
Income taxes receivable 5,384 2,679 2,663 (5,953 )
Inventories (11,047 ) 39,406 (39,062 ) 33,059
Prepaid expenses 6,758 8,219 (531 ) 1,447
Other current assets 2,186 6,393 3,964 14,291
Accounts payable 24,347 22,484 208,692 46,038
Interest payable 25,865 27,144 (5,709 ) 10,842
Income taxes payable 36 (14 ) (62 ) (9,580 )
Other current liabilities   (5,379 )   (8,563 )   (27,342 )   (38,320 )
Net cash provided by operating activities 541,011 480,107 2,145,279 1,837,577
Net cash used in investing activities (677,896 ) (740,321 ) (2,139,804 ) (3,256,410 )
Net cash provided by (used in) financing activities   (214,589 )   155,724     157,775     1,110,745  
Net increase (decrease) in cash and cash equivalents (351,474 ) (104,490 ) 163,250 (308,088 )
Cash and cash equivalents, beginning of period   744,120     333,886     229,396     537,484  
Cash and cash equivalents, end of period $ 392,646   $ 229,396   $ 392,646   $ 229,396  
 
           
PIONEER NATURAL RESOURCES COMPANY
 
UNAUDITED SUMMARY PRODUCTION AND PRICE DATA
 

Three Months Ended
December 31,

Twelve Months Ended
December 31,

2013     2012 2013     2012
Average Daily Sales Volumes from Continuing Operations:
Oil (Bbls) U.S. 72,129 61,394 69,527 57,165
Natural gas liquids ("NGL") (Bbls) U.S. 34,430 28,650 32,422 27,060
Gas (Mcf) U.S. 346,070 369,648 357,044 358,284
Total (BOE) U.S. 164,238 151,652 161,456 143,939
Average Daily Sales Volumes from Discontinued Operations:
Oil (Bbls) U.S. 5,764 5,676 5,693 5,480
South Africa         428
Total   5,764   5,676   5,693   5,908
 
NGL (Bbls) U.S. 3,191 3,289 3,193 2,756
 
Gas (Mcf) U.S. 24,177 25,168 23,443 20,085
South Africa         10,340
Total   24,177   25,168   23,443   30,425
 
Total (BOE) U.S. 12,985 13,160 12,793 11,583
South Africa         2,151
Total   12,985   13,160   12,793   13,734
Average Reported Prices from Continuing Operations (a):
Oil (per Bbl) U.S. $ 90.88 $ 85.52 $ 92.62 $ 90.67
NGL (per Bbl) U.S. $ 30.71 $ 31.13 $ 30.24 $ 34.04
Gas (per Mcf) U.S. $ 3.44 $ 3.21 $ 3.43 $ 2.60
Total (BOE) U.S. $ 53.60 $ 48.34 $ 53.55 $ 48.88

_____________

(a)   Average reported prices are attributable to continuing operations and, for 2012, include the results of hedging activities and amortization of volumetric production payment ("VPP") deferred revenue. During 2012, all remaining deferred hedge losses were transferred to earnings and, as of December 31, 2012, all VPP production volumes had been delivered and there were no further obligations under VPP contracts or 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, generally acceptable accounting principles ("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 the reallocation of participating 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 anti-dilutive; therefore, conversion into common stock is assumed not to occur.

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic net income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for the three and twelve months ended December 31, 2013 and 2012:

   

Three Months Ended
December 31,

     

Twelve Months Ended
December 31,

2013     2012 2013     2012
(in thousands)
Net income (loss) attributable to common stockholders $ (1,367,465 ) $ 28,834 $ (838,414 ) $ 192,285
Participating basic earnings   (69 )   (516 )   (130 )   (3,029 )
Basic net income (loss) attributable to common stockholders (1,367,534 ) 28,318 (838,544 ) 189,256
Reallocation of participating earnings       24         161  
Diluted net income (loss) attributable to common stockholders $ (1,367,534 ) $ 28,342   $ (838,544 ) $ 189,417  
 

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, 2013 and 2012:

   

Three Months Ended
December 31,

     

Twelve Months Ended
December 31,

2013 (a)     2012 2013 (b)     2012
(in thousands)
Weighted average common shares outstanding:
Basic 139,314 123,240 136,130 122,966
Dilutive common stock options (c) 143 183
Contingently issuable performance unit shares 196 180
Convertible senior notes dilution 3,366 2,991
Diluted 139,314 126,945 136,130 126,320

_____________

(a)  

The following common share equivalents were excluded from the weighted average diluted shares for the quarter ended December 31, 2013 because they would have been anti-dilutive: (i) 118,988 of outstanding options to purchase the Company's common stock and (ii) 250,145 of common shares attributable to unvested performance awards.

(b)

The following common share equivalents were excluded from the weighted average diluted shares for the year ended December 31, 2013 because they would have been anti-dilutive: (i) 135,190 of outstanding options to purchase the Company's common stock, (ii) 200,360 of common shares attributable to unvested performance awards and (iii) 1,087,401 common shares related to the 2013 redemption of the Convertible Senior Notes, representing the weighted average portion of the year that is not included in the basic weighted average common shares outstanding.

(c) Options to purchase 98,819 and 129,918 shares of the Company's common stock were excluded from the diluted income per share calculations for the quarter and year ended December 31, 2012, respectively, because they would have been anti-dilutive to the calculation.
 

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 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.

   

Three Months Ended
December 31,

     

Twelve Months Ended
December 31,

2013     2012 2013     2012
 
Net income (loss) $ (1,358,305 ) $ 39,702 $ (799,549 ) $ 242,822
Depletion, depreciation and amortization 243,678 198,258 907,077 708,270
Exploration and abandonments 32,138 14,324 98,448 98,285
Impairment of oil and gas properties 1,495,242 1,495,242
Impairment of inventory and other property and equipment 53,786 81 61,812 5,719
Accretion of discount on asset retirement obligations 2,983 2,189 11,862 8,677
Interest expense 45,072 53,915 183,750 204,222
Income tax (benefit) provision (493,769 ) 57,807 (211,775 ) 290,488
Gain on disposition of assets, net (2,856 ) (503 ) (209,021 ) (45,898 )
Loss from discontinued operations 494,502 89,442 449,605 304,210
Derivative related activity 42,053 (24,485 ) 164,121 68,604
Amortization of stock-based compensation 18,210 15,668 70,999 62,567
Amortization of deferred revenue (10,575 ) (42,069 )
Other noncash items   1,395     (13,884 )   (6,073 )   (45,293 )
 
EBITDAX (a) 574,129 421,939 2,216,498 1,860,604
 
Cash interest expense (40,886 ) (45,163 ) (166,525 ) (168,659 )
Current income tax provision   (5,253 )   (4,685 )   (10,599 )   (4,259 )
 
Discretionary cash flow (b) 527,990 372,091 2,039,374 1,687,686
 
Discontinued operations cash activity 19,268 44,613 163,275 193,369
Cash exploration expense (20,476 ) (14,085 ) (77,069 ) (67,096 )
Changes in operating assets and liabilities   14,229     77,488     19,699     23,618  
Net cash provided by operating activities $ 541,011   $ 480,107   $ 2,145,279   $ 1,837,577  

_____________

(a)  

“EBITDAX” represents earnings before depletion, depreciation and amortization expense; exploration and abandonments; impairment of oil and gas properties; impairment of inventory and other property and equipment; accretion of discount on asset retirement obligations; interest expense; income taxes; net gain on the disposition of assets; loss from discontinued operations; noncash derivative related activity; 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 and cash activity reflected in discontinued operations, and exploration expense.

 

PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTAL NON-GAAP FINANCIAL MEASURES (continued)
(in thousands, except per share data)

Loss adjusted for noncash mark-to-market ("MTM") derivative losses, and adjusted income excluding noncash MTM derivative losses and unusual items, as presented in this press release, are presented and reconciled to Pioneer's net loss attributable to common stockholders (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, provides 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 measure and should be read only in conjunction with Pioneer's consolidated financial statements prepared in accordance with GAAP. Noncash MTM derivative gains and losses and unusual items will recur in future periods; however, the amount and frequency can vary significantly from period to period. The tables below reconcile Pioneer's net loss attributable to common stockholders for the three months ended December 31, 2013, as determined in accordance with GAAP, to loss adjusted for noncash MTM derivative losses and adjusted income excluding noncash MTM derivative losses and unusual items for that quarter.

   

After-tax
Amounts

   

Amounts
Per Share

 
Net loss attributable to common stockholders $ (1,367,465 ) $ (9.82 )
Noncash MTM derivative losses   28,502     0.20  
Loss adjusted for noncash MTM derivative losses (1,338,963 ) (9.62 )

Loss from discontinued operations and assets held for sale

506,750 3.64

Impairment of Raton proved gas properties

956,955 6.87

Impairment of excess vertical well inventory

  14,853     0.11  
Adjusted income excluding noncash MTM derivative losses and unusual items $ 139,595   $ 1.00  
 
   
PIONEER NATURAL RESOURCES COMPANY
 
SUPPLEMENTAL INFORMATION
 
Open Commodity Derivative Positions as of February 7, 2014
(Volumes are average daily amounts)
 
Twelve Months Ending December 31,
2014     2015     2016
 
Average Daily Oil Production Associated with Derivatives (Bbls):
Collar contracts with short puts:
Volume 69,000 85,000 25,000
NYMEX price:
Ceiling $ 114.05 $ 98.98 $ 93.30
Floor $ 93.70 $ 88.06 $ 85.00
Short put $ 77.61 $ 73.06 $ 70.00
Swap contracts:
Volume 10,000
NYMEX price $ 93.87 $ $
Rollfactor swap contracts:
Volume 4,192 5,000
NYMEX roll price (a) $ 0.82 $ 0.60 $
Average Daily NGL Production Associated with Derivatives (Bbls):
Collar contracts with short puts (b):
Volume 1,000
Index price
Ceiling $ 109.50 $ $
Floor $ 95.00 $ $
Short put $ 80.00 $ $
Collar contracts (c):
Volume 3,000
Index price
Ceiling $ 13.72 $ $
Floor $ 10.78 $ $
Swap contracts (d):
Volume 2,011
Index price $ 48.12 $ $
Average Daily Gas Production Associated with Derivatives (MMBtu):
Collar contracts with short puts:
Volume 115,000 285,000 20,000
NYMEX price:
Ceiling $ 4.70 $ 5.07 $ 5.36
Floor $ 4.00 $ 4.00 $ 4.00
Short put $ 3.00 $ 3.00 $ 3.00
Swap contracts:
Volume 195,000 20,000
NYMEX price (e) $ 4.04 $ 4.31 $
Basis swap contracts:
Permian Basin index swap volume (f) 10,000 10,000
Price differential ($/MMBtu) $ (0.15 ) $ (0.13 ) $
Mid-Continent index swap volume (f) 101,452 20,000
Price differential ($/MMBtu) $ (0.22 ) $ (0.21 ) $

_____________

(a)   Represent swaps that fix the difference between (i) each day's price per Bbl of West Texas Intermediate oil "WTI" for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333.
(b) Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(c) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(d) Represent swap contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(e) Represents the NYMEX Henry Hub index price on the derivative trade date.
(f)

Represent swaps that fix the basis differentials between the indices price at which the Company sells its Permian Basin and Mid-Continent gas and the NYMEX Henry Hub index price used in gas swap and collar contracts with short puts.

 

Interest rate derivatives. As of February 7, 2014, the Company was a party to interest rate derivative contracts whereby the Company will receive a fixed forward annual interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an average rate of 1.11 percent on a notional amount of $400 million through July 15, 2022.

Marketing and basis transfer derivatives. Periodically, the Company enters into gas buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these gas marketing arrangements, the Company may enter into gas index swaps to mitigate price risk. The following table presents Pioneer’s open marketing derivative positions as of February 7, 2014:

 

Twelve Months Ending
December 31,

2014
 
Average Daily Gas Production Associated with Marketing Derivatives (MMBtu):
Basis swap contracts:
Index swap volume 16,767
Price differential ($/MMBtu) $ 0.27
 
       
Derivative Gains, Net
(in thousands)
 

Three Months Ended
December 31, 2013

Twelve Months Ended
December 31, 2013

Noncash changes in fair value:
Oil derivative gains (losses) $ 39,766 $ (18,855 )
NGL derivative losses (1,428 ) (616 )
Gas derivative losses (73,601 ) (153,993 )
Marketing derivative gains 22
Interest rate derivative gains (losses)   (6,790 )   9,321  
Total noncash derivative losses, net (a)   (42,053 )   (164,121 )
 
Net cash receipts (payments) on settled derivative instruments:
Oil derivative receipts 5,329 11,579
NGL derivative receipts 352 1,224
Gas derivative receipts 40,715 155,014
Marketing derivative payments (168 )
Interest rate derivative receipts       482  

Total cash receipts on settled derivative instruments, net

  46,396     168,131  
Total derivative gains, net $ 4,343   $ 4,010  

_____________

(a)  

Total net noncash derivative losses includes $2.5 million and $5.0 million of net gains attributable to noncontrolling interests in consolidated subsidiaries during the three and twelve months ended December 31, 2013, respectively.

   
PIONEER NATURAL RESOURCES COMPANY
 
Selected Quarterly Financial Results
 
Quarter
First     Second     Third     Fourth
(in thousands, except per share data)
Year Ended December 31, 2013:
Oil and gas revenues:
As reported $ 787,855 $ 845,136 $ 908,757 $ 809,939
Adjustment for discontinued operations   (59,354 )   (63,938 )   (72,699 )    
As Adjusted $ 728,501   $ 781,198   $ 836,058   $ 809,939  
Total revenues and other income: (a)
As reported $ 831,587 $ 1,181,727 $ 826,822 $ 970,783
Adjustment for derivative losses, net (42,243 )
Adjustment for sales of purchased oil and gas (b) 55,905 56,076 82,238
Adjustment for discontinued operations   (78,936 )   (78,589 )   (85,860 )    
As Adjusted $ 766,313   $ 1,159,214   $ 823,200   $ 970,783  
Total costs and expenses: (c)
As reported $ 663,058 $ 638,224 $ 670,042 $ 2,328,355
Adjustment for derivative losses, net (42,243 )
Adjustment for purchased oil and gas (b) 55,727 54,984 85,424
Adjustment to other expense (b) 178 1,092 (3,186 )
Adjustment for discontinued operations   (53,222 )   (58,621 )   (58,583 )    
As Adjusted $ 623,498   $ 635,679   $ 693,697     2,328,355  
Net income (loss) $ 108,735 $ 351,474 $ 98,547 $ (1,358,305 )
Net income (loss) attributable to common stockholders $ 100,663 $ 337,263 $ 91,125 $ (1,367,465 )
Net income (loss) attributable to common stockholders per share:
Basic $ 0.77 $ 2.42 $ 0.65 $ (9.82 )
Diluted $ 0.75 $ 2.40 $ 0.65 $ (9.82 )
Year Ended December 31, 2012:
Oil and gas revenues:
As reported $ 718,956 $ 641,737 $ 716,327 $ 734,640
Adjustment for discontinued operations   (54,908 )   (61,719 )   (59,461 )   (60,261 )
As Adjusted $ 664,048   $ 580,018   $ 656,866   $ 674,379  
Total revenues and other income: (a)
As reported $ 784,460 $ 917,975 $ 615,437 $ 818,686
Adjustment for derivative gains, net 91,750
Adjustment for sales of purchased oil and gas (b) 20,052 20,095 29,891 52,055
Adjustment for discontinued operations   (66,753 )   (61,719 )   (75,630 )   (73,778 )
As Adjusted $ 829,509   $ 876,351   $ 569,698   $ 796,963  
Total costs and expenses:
As reported $ 456,494 $ 1,014,615 $ 615,419 $ 769,973
Adjustment for derivative gains, net 91,750
Adjustment for purchased oil and gas (b) 19,168 20,294 29,687 51,259
Adjustment to other expense (b) 884 (199 ) 204 796
Adjustment for discontinued operations   (71,473 )   (507,161 )   (44,693 )   (212,016 )
As Adjusted $ 496,823   $ 527,549   $ 600,617   $ 610,012  
Net income (loss) $ 220,958 $ (39,537 ) $ 21,699 $ 39,702
Net income (loss) attributable to common stockholders $ 214,619 $ (70,392 ) $ 19,224 $ 28,834
Net income (loss) attributable to common stockholders per share:
Basic $ 1.73 $ (0.57 ) $ 0.15 $ 0.23
Diluted $ 1.68 $ (0.57 ) $ 0.15 $ 0.22

_____________

(a)  

The Company's total revenues and other income include net derivative gains of $144.4 million and $4.3 million during the second and fourth quarters of 2013, respectively, and net derivative losses of $42.2 million and $102.5 million during the first and third quarters of 2013, respectively. During 2012, the Company's total revenues included net derivative gains of $91.8 million, $275.8 million and $86.7 million during the first, second and fourth quarters, respectively, and net derivative losses of $124.0 million during the third quarter.

(b) Includes the revision of net margins on purchases and sales of third-party oil and gas from other expense to gross sales of purchased oil and gas and costs of purchased oil and gas. Revenues and costs from the purchase and sale transactions are presented on a gross basis as the Company acts as a principal in the transactions by assuming the risks and rewards of ownership, including credit risk, of the oil and gas purchased and assumes responsibility for the delivery of the oil and gas volumes sold.
(c)

During the fourth quarter of 2013, the Company's total costs and expenses include (i) charges of $1.5 billion to impair the carrying value of proved gas properties in the Raton field and (ii) charges of $48.7 million to impair the carrying value of excess materials inventory and other property and equipment held for sale.

Source: Pioneer Natural Resources Company

Pioneer Natural Resources
Investors
Frank Hopkins, 972-969-4065
or
Josh Jones, 972-969-5822
or
Mike Bandy, 972-969-4513
or
Media and Public Affairs
Susan Spratlen, 972-969-4018
or
Suzanne Hicks, 972-969-4020

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