PXD-2014.12.31-10K
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ý
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2014
or
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                  to                 
Commission File Number: 1-13245
Pioneer Natural Resources Company
(Exact name of registrant as specified in its charter)
Delaware
 
75-2702753
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
 
5205 N. O'Connor Blvd., Suite 200, Irving, Texas
 
75039
(Address of principal executive offices)
 
(Zip Code)
Registrant's telephone number, including area code: (972) 444-9001
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, par value $.01
 
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes  ý    No  ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    Yes  ¨    No  ý
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ý    No  ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  ý    No  ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.    ý
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
ý
  
Accelerated filer
o
 
 
 
 
 
Non-accelerated filer
o  (Do not check if a smaller reporting company)
  
Smaller reporting company
o
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).     Yes   ¨     No   ý
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant's most recently completed second fiscal quarter
$
32,612,539,563

 
 
Number of shares of Common Stock outstanding as of February 13, 2015
148,963,753

DOCUMENTS INCORPORATED BY REFERENCE:
(1)
Portions of the Definitive Proxy Statement for the Company's Annual Meeting of Shareholders to be held during May 2015 are incorporated into Part III of this report.

Table of Contents
TABLE OF CONTENTS

 
 
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Item 1.
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
 
 
 
 
Item 3.
Item 4.
Item 5.
 
Item 6.
Item 7.
 
 
 
 
 
 
 
 
 
 
Item 7A.
 
 
Item 8.
 
 
 
 
 
Item 9.
Item 9A.
 
 
Item 9B.


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Item 10.
Item 11.
Item 12.
 
Item 13.
Item 14.
Item 15.


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Definitions of Certain Terms and Conventions Used Herein
Within this Report, the following terms and conventions have specific meanings:
•
"Bbl" means a standard barrel containing 42 United States gallons.
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"Bcf" means one billion cubic feet.
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"BOE" means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six thousand cubic feet of gas to one Bbl of oil or natural gas liquid.
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"BOEPD" means BOE per day.
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"Btu" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.
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"CBM" means coal bed methane.
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"Conway" means the daily average natural gas liquids components as priced in Oil Price Information Services ("OPIS") in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.
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"DD&A" means depletion, depreciation and amortization.
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"Field fuel" means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.
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"GAAP" means accounting principles that are generally accepted in the United States of America.
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"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.
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"MBbl" means one thousand Bbls.
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"MBOE" means one thousand BOEs.
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"Mcf" means one thousand cubic feet and is a measure of gas volume.
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"MMBbl" means one million Bbls.
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"MMBOE" means one million BOEs.
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"MMBtu" means one million Btus.
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"MMcf" means one million cubic feet.
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"Mont Belvieu" means the daily average natural gas liquids components as priced in OPIS in the table "U.S. and Canada LP – Gas Weekly Averages" at Mont Belvieu, Texas.
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"NGL" means natural gas liquid.
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"NYMEX" means the New York Mercantile Exchange.
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"NYSE" means the New York Stock Exchange.
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"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.
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"Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. and its subsidiaries.
•
"Proved developed reserves" mean reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.
•
"Proved reserves" mean those quantities of oil and gas, which, by analysis of geosciences and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons ("LKH") as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.

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(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.
(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.
•
"Proved undeveloped reserves" means reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.
(ii) Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.
•
"SEC" means the United States Securities and Exchange Commission.
•
"Standardized Measure" means the after-tax present value of estimated future net cash flows of proved reserves, determined in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved reserves and a ten percent discount rate.
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"U.S." means United States.
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"VPP" means volumetric production payment.
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"WTI" means West Texas intermediate, a light, sweet blend of oil produced from fields in western Texas.
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With respect to information on the working interest in wells, drilling locations and acreage, "net" wells, drilling locations and acres are determined by multiplying "gross" wells, drilling locations and acres by the Company's working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.
•
Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (this "Report") contains forward-looking statements that involve risks and uncertainties. When used in this document, the words "believes," "plans," "expects," "anticipates," "forecasts," "intends," "continue," "may," "will," "could," "should," "future," "potential," "estimate," or the negative of such terms and similar expressions as they relate to the Company are intended to identify forward-looking statements, which are generally not historical in nature. The forward-looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to predict and, in many cases, beyond the Company's control. In addition, the Company may be subject to currently unforeseen risks that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will not be materially different from the anticipated results described in the forward-looking statements. See "Item 1. Business — Competition, Markets and Regulations," "Item 1A. Risk Factors," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for a description of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date hereof. The Company undertakes no duty to publicly update these statements except as required by law.



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PIONEER NATURAL RESOURCES COMPANY

PART I
 
ITEM 1.
BUSINESS
General
The Company is a large independent oil and gas exploration and production company with operations in the United States. Pioneer is a holding company whose assets consist of direct and indirect ownership interests in, and whose business is conducted substantially through, its subsidiaries. Pioneer's common stock is listed and traded on the NYSE under the ticker symbol "PXD."
The Company is a Delaware corporation formed in 1997. The Company's executive offices are located at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039. The Company's telephone number is (972) 444-9001. The Company maintains other offices in Denver, Colorado and Midland, Texas. At December 31, 2014, the Company had 4,075 employees, 1,795 of whom were employed in field and plant operations and 848 of whom were employed in vertical integration activities.
Available Information
Pioneer files or furnishes annual, quarterly and current reports, proxy statements and other documents with the SEC under the Securities Exchange Act of 1934 (the "Exchange Act"). The public may read and copy any materials that Pioneer files with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website that contains reports, proxy and information statements, and other information regarding issuers, including Pioneer, that file electronically with the SEC. The public can obtain any documents that Pioneer files with the SEC at http://www.sec.gov.
The Company also makes available free of charge through its Internet website (www.pxd.com) its Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files such material with, or furnishes it to, the SEC. In addition to the reports filed or furnished with the SEC, Pioneer publicly discloses material information from time to time in its press releases, at annual meetings of stockholders, in publicly accessible conferences and investor presentations, and through its website (principally in the Investors pages).
Mission and Strategies
The Company's mission is to enhance shareholder investment returns through strategies that maximize Pioneer's long-term profitability and net asset value. The strategies employed to achieve this mission are predicated on maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions. These strategies are anchored by the Company's interests in the long-lived Spraberry/Wolfcamp oil field; the liquid-rich Eagle Ford Shale play; the West Panhandle gas and liquids field; and the Raton gas field; which together have an estimated remaining productive life in excess of 40 years. Underlying these fields are 98 percent of the Company's total proved oil and gas reserves as of December 31, 2014.
Business Activities
The Company is an independent oil and gas exploration and production company. Pioneer's purpose is to competitively and profitably explore for, develop and produce oil and gas reserves. In so doing, the Company sells homogenous oil, NGL and gas units that, except for geographic and relatively minor quality differences, cannot be significantly differentiated from units offered for sale by the Company's competitors. Competitive advantage is gained in the oil and gas exploration and development industry by employing well-trained and experienced personnel who make prudent capital investment decisions based on management direction, embrace technological innovation and are focused on price and cost management.
Petroleum industry. North American oil prices had been fairly stable during the past three years despite the significant increase in United States oil production from unconventional shale plays. During such time, the growth in North American oil production had been offset by reduced oil imports, keeping supply and demand fairly balanced in the United States. On an international level, the geopolitical factors negatively impacting international oil supplies were offset by the decline in United States imports, resulting in generally stable world oil prices. During the second half of 2014, however, as United States production continued to surge, worldwide demand was sluggish, reflecting the decline in the Chinese growth rate, the lingering recession in Europe and weaker economic performance in other regions, resulting in a worldwide oversupply of oil and oil price weakness. During the fourth quarter of 2014, members of the Organization of Petroleum Exporting Countries ("OPEC") decided to maintain production quotas at current levels despite production outpacing demand. This caused oil prices, which had already been declining, to decrease significantly in December 2014. The market oversupply of oil is expected to continue in 2015, with oil prices expected to remain under pressure. The growth of unconventional shale drilling has also substantially increased the supply of NGLs, resulting

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in a significant decline in NGL component prices as the supply of such products has grown. While more export facilities have been built and NGL exports are increasing, the overall United States demand for NGL products has not kept pace with the supply of such products; consequently, prices for NGL products have generally declined over the past three years. North American gas prices have remained volatile and they trended lower from 2009 through 2012, but improved steadily throughout 2013 and 2014 before dropping significantly in the fourth quarter of 2014. The decline in North American gas prices from 2009 through 2012 was primarily a result of significant discoveries of gas and associated gas reserves in United States gas, oil and liquid-rich shale plays, combined with the warmer than normal winters, which resulted in gas storage levels being at historically high levels, and minimal economic demand growth in the United States. The increases in gas prices during the latter part of 2013 and the majority of 2014 were primarily related to reduced drilling activity in gas shale plays and demand increases as a result of colder late 2013 and early 2014 winter weather, which reduced storage levels. The recent gas price decrease during the fourth quarter of 2014 reflects expectations for a warmer than normal winter, which is expected to result in gas storage levels being higher than normal at the end of the winter draw season and an expectation that there will be an oversupply of gas during 2015.
Oil prices continue to be primarily driven by world supply and demand fundamentals. Recent increases in United States oil, NGL and gas production volumes from the Permian Basin, Eagle Ford, Bakken, Marcellus and Utica areas have been met with lower demand, the decades-old ban on oil exports, higher storage levels and pipeline, gas plant and NGL fractionation infrastructure capacity limitations. These factors have led to a reduction in United States NYMEX oil, NGL and gas prices compared to international prices for similar commodities, including Brent oil prices.
 Since 2010, the economies in the United States and certain other countries have continued to stabilize with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain European and Asian nations, continue to face economic struggles or slowing economic growth. While the outlook for a continued worldwide economic recovery remains cautiously optimistic, its timing and strength is still uncertain; therefore, the likelihood of a sustained recovery in worldwide demand for energy is difficult to predict. As a result, the Company believes it is likely that commodity prices will continue to be volatile during 2015.
Significant factors that will affect 2015 commodity prices include: the impact of announced capital spending decreases on forecasted United States oil, NGL and gas supplies; the ongoing effect of economic stimulus initiatives; fiscal challenges facing the United States federal government and potential changes to the tax laws in the United States; continuing economic struggles in European and Asian nations; political and economic developments in North Africa and the Middle East; demand from Asian and European markets; the extent to which members of OPEC and other oil exporting nations are able to manage oil supply through export quotas; the capacity of United States refiners to absorb increasing domestic supplies of oil and condensate; potential export regulatory changes in the United States; the supply and demand fundamentals for NGLs in the United States and the pace at which export capacity grows; and overall North American gas supply and demand fundamentals, including gas storage levels that are anticipated to be higher than normal at the end of the winter draw season.
Pioneer uses commodity derivative contracts to mitigate the effect of commodity price volatility on the Company's net cash provided by operating activities and its net asset value. Although the Company has entered into commodity derivative contracts for a large portion of its forecasted production through 2015, a sustained lower commodity price environment would result in lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts on additional volumes in the future. As a result, the Company's internal cash flows would be reduced for affected periods. A sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively affect the Company's liquidity, financial position and future results of operations. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's open derivative positions as of December 31, 2014, and subsequent changes to these positions.
The Company. The Company's growth plan is primarily anchored by horizontal drilling in the Spraberry/Wolfcamp oil field located in West Texas and the liquid-rich Eagle Ford Shale field located in South Texas. Complementing these growth areas, the Company has oil and gas production activities and development opportunities in the Raton gas field located in southern Colorado, the West Panhandle gas and liquids field located in the Texas Panhandle and the Edwards gas field located in South Texas. Combined, these assets create a portfolio of resources and opportunities that are well balanced and diversified among oil, NGL and gas, and that are also well balanced among long-lived, dependable production and lower-risk exploration and development opportunities. The Company has a team of dedicated employees who represent the professional disciplines and sciences that the Company believes are necessary to allow Pioneer to maximize the long-term profitability and net asset value inherent in its physical assets.
Production. The Company focuses its efforts towards maximizing its average daily production of oil, NGLs and gas through development drilling, production enhancement activities and acquisitions of producing properties, while minimizing the controllable costs associated with the production activities. For the year ended December 31, 2014, the Company's production

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from continuing operations of 67 MMBOE, excluding field fuel usage, represented an 18 percent increase over production from continuing operations during 2013. Production, price and cost information with respect to the Company's properties for 2014, 2013 and 2012 is set forth in "Item 2. Properties — Selected Oil and Gas Information — Production, price and cost data."
Development activities. The Company seeks to increase its proved oil and gas reserves, production and cash flow through development drilling and by conducting other production enhancement activities, such as well recompletions. During the three years ended December 31, 2014, the Company drilled 1,423 gross (1,242 net) development wells, 99 percent of which were successfully completed as productive wells, at a total drilling cost (net to the Company's interest) of $4.9 billion.
The Company believes that its current property base provides a substantial inventory of prospects for future reserve, production and cash flow growth. The Company's proved reserves as of December 31, 2014 include proved undeveloped reserves and proved developed reserves that are behind pipe of 89 MMBbls of oil, 42 MMBbls of NGLs and 317 Bcf of gas. The Company believes that its proved reserves represent a significant portfolio of development opportunities. The timing of the development of these reserves will be dependent upon commodity prices, drilling and operating costs and the Company's expected operating cash flows and financial condition.
Exploratory activities. The Company has devoted significant efforts and resources to hiring and developing a highly skilled geoscience staff as well as acquiring a significant portfolio of lower-risk exploration opportunities that are expected to be evaluated and tested over the next decade and beyond. Exploratory and extension drilling involve greater risks of dry holes or failure to find commercial quantities of hydrocarbons than development drilling or enhanced recovery activities. See "Item 1A. Risk Factors — Exploration and development drilling may not result in commercially productive reserves" below.
Integrated services. The Company continues to benefit from its integrated services to control drilling and operating costs and support the execution of its drilling program and operating activities. The Company has Company-owned fracture stimulation fleets totaling approximately 360,000 horsepower supporting drilling operations in the Spraberry/Wolfcamp and Eagle Ford Shale areas. The Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In April 2012, Pioneer acquired a large U.S. industrial sands company, which was renamed Premier Silica (see Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the acquisition of Premier Silica). That acquisition secured a high-quality, low-cost and logistically advantaged brown sand supply for Pioneer to use for its growing fracture stimulation requirements in the Spraberry/Wolfcamp field.
Acquisition activities. The Company regularly seeks to acquire properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. In addition, the Company pursues strategic acquisitions that will allow the Company to expand into new geographical areas that provide future exploration/exploitation opportunities. During 2014, 2013 and 2012, the Company spent $104 million, $76 million and $158 million, respectively, to purchase primarily undeveloped acreage for future exploitation and exploration activities.
In December 2014, the Company acquired the remaining limited partner interests in five affiliated partnerships for $54 million and caused the partnerships to be merged with and into the Company. In addition, in December 2013, the Company completed the acquisition of all of the outstanding common units of Pioneer Southwest not already owned by the Company in exchange for 3.96 million shares of the Company's common stock through a merger of a wholly-owned subsidiary of the Company into Pioneer Southwest, the result of which was that Pioneer Southwest became a wholly-owned subsidiary of the Company. The 2014 and 2013 mergers enhance the Company's (i) ability to fully and optimally develop the Company's Spraberry/Wolfcamp properties in the Midland Basin in West Texas utilizing horizontal drilling and (ii) organizational, operational and administrative efficiencies.
The Company periodically evaluates and pursues acquisition opportunities (including opportunities to acquire particular oil and gas assets or entities owning oil and gas assets and opportunities to engage in mergers, consolidations or other business combinations with such entities) and at any given time may be in various stages of evaluating such opportunities. Such stages may take the form of internal financial analyses, oil and gas reserve analyses, due diligence, the submission of indications of interest, preliminary negotiations, negotiation of letters of intent or negotiation of definitive agreements. The success of any acquisition is uncertain and depends on a number of factors, some of which are outside the Company's control. See "Item 1A. Risk Factors — The Company may be unable to make attractive acquisitions and any acquisition it completes is subject to substantial risks that could adversely affect its business."
Asset divestitures and discontinued operations. The Company regularly reviews its asset base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. While the Company generally does not dispose of assets solely for the purpose of reducing debt, such dispositions can have the result of furthering the Company's objective of increasing financial flexibility through reduced debt levels.

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EFS Midstream. In November 2014, the Company announced that it is pursuing the divestment of its 50.1 percent share of EFS Midstream LLC ("EFS Midstream"). The Company is marketing its equity investment in EFS Midstream and no assurance can be given that a sale will be completed in accordance with the Company's plans or on terms and at a price acceptable to the Company.
Hugoton. In September 2014, the Company completed the sale of its net assets in the Hugoton field in southwest Kansas for cash proceeds of $328 million, including normal closing adjustments.
Barnett Shale. During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. In September 2014, the Company completed the sale of its Barnett Shale net assets for cash proceeds of $150 million, including normal closing adjustments.
Alaska. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in Pioneer's Alaska subsidiary ("Pioneer Alaska"). In April 2014, the Company completed the sale of Pioneer Alaska for cash proceeds of $267 million, including normal closing and other adjustments.
South Africa. During the first quarter of 2012, the Company agreed to sell its net assets in South Africa ("Pioneer South Africa"), effective January 1, 2012, for $60 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for cash proceeds of $16 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale.
The Company has reflected its Hugoton, Barnett Shale, Pioneer Alaska and Pioneer South Africa results of operations as discontinued operations in the accompanying consolidated statements of operations.
Sendero. During December 2013, the Company committed to a plan to sell the Company's majority interest in Sendero Drilling Company, LLC ("Sendero") to Sendero's minority interest owner. At December 31, 2013, the assets and liabilities of Sendero were classified as held for sale at their estimated fair value. In March 2014, the Company completed the sale of Sendero for cash proceeds of $31 million. As part of the sales agreement, the Company committed to lease from Sendero 12 vertical rigs through December 31, 2015 and eight vertical rigs in 2016.
Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem") to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas for consideration of $1.8 billion. In May 2013, the Company completed the sale for cash proceeds of $624 million, which resulted in a gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the southern portion of the horizontal Wolfcamp Shale play. At December 31, 2014, the unused carry balance totaled $575 million.
The Company anticipates that it will continue to sell nonstrategic properties or other assets from time to time to increase capital resources available for other activities, to achieve operating and administrative efficiencies and to improve profitability. See Notes C and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding the Company's asset divestitures, impairments and discontinued operations. Also see "Item 1A. Risk Factors - The Company's ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond its control, and in certain cases the Company may be required to retain liabilities for certain matters" for discussion of risk factors associated with the completion of divestitures.
Marketing of Production
General. Production from the Company's properties is marketed using methods that are consistent with industry practices. Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand conditions. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional discussion of operations and price risk.
Significant purchasers. During 2014, the Company's significant purchasers of oil, NGLs and gas were Plains Marketing LP (24 percent), Occidental Energy Marketing Inc. (13 percent), Enterprise Products Partners L.P. (11 percent) and Valero Marketing and Supply Company (10 percent). The Company believes the loss of a significant purchaser or an inability to secure adequate pipeline, gas plant and NGL fractionation infrastructure in its key producing areas could have a material adverse effect on its ability to sell its oil, NGL and gas production. See "Item 1A. Risk Factors" and Note L of Notes to Consolidated Financial Statements

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included in "Item 8. Financial Statements and Supplementary Data" for more information about significant customer and infrastructure capacity risks.
Derivative risk management activities. The Company primarily utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate derivative contracts to reduce the effect of interest rate volatility on the Company's indebtedness. The Company accounts for its derivative contracts using the mark-to-market ("MTM") method of accounting. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of the Company's derivative risk management activities, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information about the impact of commodity derivative activities on oil, NGL and gas revenues and net derivative gains and losses during 2014, 2013 and 2012, as well as the Company's open commodity derivative positions at December 31, 2014, and subsequent changes to these positions.
Competition, Markets and Regulations
Competition. The oil and gas industry is highly competitive. A large number of companies, including major integrated and other independent companies, and individuals engage in the exploration for and development of oil and gas properties, and there is a high degree of competition for oil and gas properties suitable for development or exploration. Acquisitions of oil and gas properties have been an important element of the Company's growth. The Company intends to continue acquiring oil and gas properties that complement its operations, provide exploration and development opportunities and potentially provide superior returns on investment. The principal competitive factors in the acquisition of oil and gas properties include the staff and data necessary to identify, evaluate and acquire such properties and the financial resources necessary to acquire and develop the properties. Some of the Company's competitors are substantially larger and have financial and other resources greater than those of the Company.
Markets. The Company's ability to produce and market oil, NGLs and gas profitably depends on numerous factors beyond the Company's control. The effect of these factors cannot be accurately predicted or anticipated. Although the Company cannot predict the occurrence of events that may affect these commodity prices or the degree to which these prices will be affected, the prices for any commodity that the Company produces will generally approximate current market prices in the geographic region of the production.
Securities regulations. Enterprises that sell securities in public markets are subject to regulatory oversight by agencies such as the SEC and the NYSE. This regulatory oversight imposes on the Company the responsibility for establishing and maintaining disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial statements and other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the rules and regulations of the SEC could subject the Company to litigation from public or private plaintiffs. Failure to comply with the rules of the NYSE could result in the de-listing of the Company's common stock, which would have an adverse effect on the market price and liquidity of the Company's common stock. Compliance with some of these rules and regulations is costly, and regulations are subject to change or reinterpretation.
 Environmental and occupational health and safety matters. The Company's operations are subject to stringent and complex federal, state and local laws and regulations governing worker health and safety, the discharge of materials into the environment and environmental protection. Numerous governmental entities, including the U.S. Environmental Protection Agency (the "EPA") and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions to achieve and maintain compliance and imposing sanctions, including administrative, civil and criminal penalties, for any failure to comply.
These laws and regulations may, among other things:
•
require the acquisition of various permits before drilling or other regulated activity commences;
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enjoin some or all of the operations of facilities deemed in noncompliance with permits;
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restrict the types, quantities and concentration of various substances that may be released into the environment in connection with oil and gas drilling, production and transportation activities;
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limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
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impose specific criteria addressing worker protection;
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require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and

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•
impose substantial liabilities for pollution resulting from operations.
These laws and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, the U.S. Congress, state legislatures and federal and state regulatory agencies frequently revise environmental laws and regulations, and the trend in environmental regulation is to place more restrictions and limitations on activities that may adversely affect the environment. Any changes that result in more stringent and costly drilling, completion, construction or water management activities, or waste handling, disposal and cleanup requirements for the oil and gas industry could have a significant effect on the Company's capital and operating costs.
The following is a summary of some of the more significant laws and regulations to which the Company's business operations are or may be subject. These laws may be amended from time to time.
Waste handling. The federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. While drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of oil or gas are currently regulated under RCRA's non-hazardous waste provisions, it is possible that such exploration and production wastes may, in the future, be classified as hazardous wastes. Any such change could result in an increase in the Company's costs to manage and dispose of wastes, which could have a material adverse effect on the Company's results of operations and financial position. In the course of its operations, the Company generates some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes.
Wastes containing naturally occurring radioactive materials ("NORM") may also be generated in connection with the Company's operations. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling and management activities are governed by regulations promulgated by the federal Occupational Safety and Health Administration ("OSHA"). These state and OSHA regulations impose certain requirements concerning worker protection, with respect to NORM, the treatment, storage and disposal of NORM waste, the management of waste piles, containers and tanks containing NORM and restrictions on the uses of land with NORM contamination.
Comprehensive Environmental Response, Compensation, and Liability Act. The federal Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the Superfund law, and analogous state laws impose joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment.
The Company currently owns or leases numerous properties that have been used for oil and gas exploration and production for many years. Although the Company believes it has used operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on or under the properties owned or leased by the Company, or on or under other locations, including off-site locations, where such substances have been taken for treatment or disposal. In addition, some of the Company's properties have been operated by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under the Company's control. Certain of these properties have had historical petroleum spills or releases. All of such properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination. If a surface spill or release were to occur, the Company expects that it would be controlled, contained and remediated in accordance with the applicable requirements of state oil and gas commissions and by using the Company's spill prevention, control and countermeasure ("SPCC") plans or other spill or emergency contingency plans that it maintains in accordance with EPA requirements.
Water discharges and use. The federal Water Pollution Control Act, also known as the Clean Water Act (the "CWA"), and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States and state waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations

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implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. SPCC planning requirements of federal laws require appropriate containment berms and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations.
The primary federal law imposing liability for oil spills is the Oil Pollution Act ("OPA"), which amends the CWA and sets minimum standards for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities and onshore facilities, including exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. If an oil spill subject to the requirements of OPA were to occur at a Company property, the Company expects that it would be controlled, contained and remediated in accordance with the applicable requirements of OPA and by using the Company's OPA spill response plan together with the assistance of trained first responders and any oil spill response contractor that the Company would have engaged pursuant to OPA to address such oil spills.
Fluids associated with oil and gas production, consisting primarily of salt water, result from operations on the Company's properties and are disposed by injection in underground disposal wells. These disposal wells are regulated pursuant to the Underground Injection Control ("UIC") program established under the federal Safe Drinking Water Act ("SDWA") and analogous state and local laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of the Company's disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. Currently, the Company believes that disposal well operations on the Company's properties substantially comply with all applicable requirements under the SDWA. However, a change in the regulations or the inability to obtain permits for new disposal wells in the future may affect the Company's ability to dispose of produced waters and ultimately increase the cost of the Company's operations. For example, there exists a growing concern that the injection of salt water and other fluids into underground disposal wells triggers seismic activity in certain areas, including in some parts of Texas, where the Company operates. In response to these concerns, in October 2014, the Texas Railroad Commission (the "TRC") published a final rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant of a disposal well permit fails to demonstrate that the injected fluids are confined to the disposal zone or if scientific data indicates such a disposal well is likely to be or determined to be contributing to seismic activity, then the TRC may deny, modify, suspend or terminate the permit application or existing operating permit for that well. These new seismic permitting requirements applicable to disposal wells impose more stringent permitting requirements and are likely to result in added costs to comply or perhaps may require alternative methods of disposing of salt water and other fluids, which could delay production schedules and also result in increased costs.
The Company also uses hydraulic fracturing techniques in virtually all of its drilling and completion programs, and development of its properties is dependent on the Company's ability to hydraulically fracture the producing formations. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final Clean Air Act regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the federal Bureau of Land Management (the "BLM") issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands, and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015.
From time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In addition to any actions by the U.S. Congress, certain states in which the Company operates, including Colorado and Texas, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure and well-construction requirements on hydraulic fracturing operations. States could elect to prohibit hydraulic fracturing altogether, as Governor Andrew Cuomo of the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. For example, in response to concerns regarding hydraulic fracturing, the city of Denton, Texas issued a moratorium on the issuance of new drilling permits inside the Denton city limits.The Company believes that it follows applicable standard industry practices and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, in the event federal, state or local restrictions are adopted in areas where the Company is currently conducting, or in the future plans to conduct operations, the

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Company may incur additional costs to comply with such requirements that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development or production activities, and be limited or precluded in the drilling of wells or in the amounts that the Company is ultimately able to produce from its reserves.
Certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Also, the EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and a draft report is expected to be available for public comments and peer review in the first half of 2015. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing.
The water produced by the Company's CBM operations also may be subject to the state laws and regulations of regulatory bodies regarding the ownership and use of water. For example, in connection with the Company's CBM operations in the Raton Basin in Colorado, water is removed from coal seams to reduce pressure and allow the methane to be recovered. Historically, these operations have been regulated by the state agency responsible for regulating oil and gas activity in the state. Nevertheless, in 2009, the Colorado Supreme Court affirmed a state court holding that water produced in connection with the CBM operations should be subject to state water-use regulations administered by a different agency that regulates other uses of water in the state, including requirements to obtain permits for diversion and use of surface and subsurface water, an evaluation of potential competing uses of the water, and a possible requirement to provide mitigation water for other water users. The Colorado legislature and state agency adopted laws and regulations in response to this ruling. These and other resulting changes in the regulation of water produced from CBM operations may have an adverse effect on the costs of doing business and the ability to expand operations by the Company or other CBM producers.
Air emissions. The Clean Air Act (the "CAA") and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain or strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions of certain air pollutants. Moreover, states may impose their own air emissions limitations, which may be more stringent than the federal standards imposed by the EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for noncompliance with air permits or other requirements of the CAA and associated state laws and regulations. The adoption of laws, regulations, orders or other legally enforceable mandates governing oil and gas drilling and operating activities in the areas where the Company conducts business that result in more stringent emissions standards could increase the Company's costs or reduce its volume of production, which could have a material adverse effect on the Company's results of operations and cash flows.
Moreover, permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling air emissions in regional non-attainment areas, may require the Company to incur future capital expenditures in connection with the addition or modification of existing air emission control equipment and strategies for oil and gas exploration and production operations. For example, in 2012, the EPA published final rules under the CAA that subject oil and gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards for Hazardous Air Pollutants programs. With regard to production activities, these final rules require, among other things, the reduction of volatile organic compound emissions from certain fractured and refractured gas wells by using reduced emission completions, also known as "green completions," after January 1, 2015. These regulations also establish specific new requirements regarding emissions from certain production-related wet seal and reciprocating compressors, pneumatic controllers and storage vessels. Compliance with these requirements could increase the Company's costs of development and production, which costs could be significant.
Endangered species. The federal Endangered Species Act (the "ESA") and analogous state laws regulate activities that could have an adverse effect on species listed as threatened or endangered under the ESA. Some of the Company's operations are conducted in areas where protected species or their habitats are known to exist. In these areas, the Company may be obligated to develop and implement plans to avoid potential adverse effects to protected species and their habitats, and the Company may be prohibited from conducting operations in certain locations or during certain seasons, such as breeding and nesting seasons, when the Company's operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where the Company performs activities could result in increased costs or limitations on the Company's ability to perform operations and thus have an adverse effect on the Company's business.
Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service (the "FWS") is required to make a determination on the potential listing of numerous species as endangered or threatened under the ESA before completion of the agency's 2017 fiscal year. The designation of previously

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unprotected species as threatened or endangered in areas where the Company operates could cause the Company to incur increased costs arising from species protection measures or could result in limitations on the Company's drilling and production activities that could have an adverse effect on the Company's ability to develop and produce its reserves. For example, on March 27, 2014, the FWS announced the listing of the lesser prairie chicken, whose habitat is over a five-state region, including Texas and Colorado, where the Company conducts operations, as a threatened species under the ESA. However, the FWS also announced a final rule that will limit regulatory impacts on landowners and businesses from the listing if those landowners and businesses have entered into certain range-wide conservation planning agreements, such as those developed by the Western Association of Fish and Wildlife Agencies ("WAFWA"), pursuant to which such parties, including the Company, agreed to take steps to protect the lesser prairie chicken's habitat and to pay a mitigation fee if its actions harm the lesser prairie chicken's habitat. The listing of the lesser prairie chicken as a threatened species or, alternatively, entry into certain range-wide conservation planning agreements such as WAFWA, could result in increased costs to the Company from species protection measures, time delays or limitations on the Company's activities, which costs, delays or limitations may be significant to the Company's business.
Activities on federal lands. Oil and gas exploration, development and production activities on federal lands, including Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act ("NEPA"). NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Currently, the Company has minimal exploration and production activities on federal lands. However, for those current activities as well as for future or proposed exploration and development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are required. This process has the potential to delay or limit, or increase the cost of, the development of oil and gas projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.
Occupational health and safety. The Company's operations are subject to the requirements of OSHA and comparable state statutes. These laws and the related regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statues require that the Company organize or disclose information about hazardous materials used or produced in the Company's operations. In addition, the Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment and other matters. The Company believes that it is in substantial compliance with these applicable standards and with OSHA and comparable requirements.
Climate change. In 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under the CAA that, among other things, establish certain permits and construction reviews designed to allow operations while ensuring the Prevention of Significant Deterioration ("PSD") of air quality by GHG emissions from large stationary sources that already may be potential sources of other regulated pollutant emissions. The Company could become subject to these permitting requirements and be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that the Company may seek to construct in the future if they would otherwise emit large volumes of GHGs from such sources. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including certain oil and gas production facilities, which includes certain of the Company's facilities. The Company is monitoring GHG emissions from its operations in accordance with these GHG emissions reporting rules and believes its monitoring activities are in substantial compliance with applicable reporting obligations.
While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs.
The adoption of any legislation or regulations that require reporting of GHGs or otherwise restrict emissions of GHGs from the Company's equipment and operations could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements including the imposition of a carbon tax. For example, pursuant to President Obama's Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015 that the EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and gas processing and transmission facilities as part of the Administration's efforts to reduce methane emissions from the oil and gas sector by up

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to 45 percent from 2012 levels by 2025. Any such legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company's business, financial condition and results of operations. Finally, some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other climatic events. If any such effects were to occur, they could have an adverse effect on the Company's financial condition and results of operations.
Other regulation of the oil and gas industry. The oil and gas industry is regulated by numerous federal, state and local authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous federal and state departments and agencies are authorized by statute to issue rules and regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and gas industry may increase the Company's cost of doing business by increasing the cost of production, the Company believes that these burdens generally do not affect the Company any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.
Development and production. Development and production operations are subject to various types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds in connection with various types of activities and filing reports concerning operations. Most states, and some counties and municipalities, in which the Company operates also regulate one or more of the following:
•
the location of wells;
•
the method of drilling and casing wells;
•
the method and ability to fracture stimulate wells;
•
the surface use and restoration of properties upon which wells are drilled;
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the plugging and abandoning of wells; and
•
notice to surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas properties. Some states allow forced pooling or integration of tracts to facilitate development while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce the Company's interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and gas the Company can produce from the Company's wells or limit the number of wells or the locations at which the Company can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGL and gas within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and gas that may be produced from the Company's wells, negatively affect the economics of production from these wells, or limit the number of locations the Company can drill.
Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of gas. Federal and state regulations govern the price and terms for access to gas pipeline transportation. Intrastate gas pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies. The interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission ("FERC"). FERC endeavors to make gas transportation more accessible to gas buyers and sellers on an open-access and non-discriminatory basis.
Pursuant to the Energy Policy Act of 2005 ("EPAct 2005") it is unlawful for "any entity," including producers such as the Company, that are otherwise not subject to FERC's jurisdiction under the Natural Gas Act (the "NGA"), to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC's rules implementing this provision make it unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives FERC authority to impose civil penalties of up to $1.0 million per day for each violation of the NGA or the Natural Gas Policy Act of 1978. The anti-manipulation rule applies to activities of entities not otherwise subject to FERC's jurisdiction to the extent the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which includes the annual reporting requirements under Order 704 (defined below).

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In December 2007, FERC issued a final rule on the annual gas transaction reporting requirements, as amended by subsequent orders on rehearing ("Order 704"). Under Order 704, any market participant, including a producer such as the Company, that engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBtus of physical gas in the previous calendar year must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains aggregate volumes of gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual transactions should be reported based on the guidance of Order 704. Order 704 is intended to increase the transparency of the wholesale gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.
Additional proposals and proceedings that might affect the gas industry are considered from time to time by the U.S. Congress, FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become effective or their effect, if any, on its operations. The Company does not believe that it will be affected by any action taken in a materially different way than other gas producers, gatherers and marketers with which it competes.
Natural gas processing. The Company's gas processing operations are not subject to FERC or state regulation. There can be no assurance that the Company's processing operations will continue to be exempt from regulation in the future. However, although the processing facilities may not be directly related, other laws and regulations may affect the availability of gas for processing, such as state regulation of production rates and maximum daily production allowable from gas wells, which could impact the Company's processing business.
Gas gathering. Section 1(b) of the NGA exempts gas gathering facilities from FERC's jurisdiction. The Company believes that its gathering facilities meet the traditional tests FERC has used to establish a pipeline system's status as a non-jurisdictional gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation from time to time, so the classification and regulation of some of the Company's gathering facilities may be subject to change based on future determinations by FERC and the courts. Thus, the Company cannot guarantee that the jurisdictional status of its gas gathering facilities will remain unchanged.
While the Company owns or operates some gas gathering facilities, the Company also depends on gathering facilities owned and operated by third parties to gather production from its properties, and therefore the Company is affected by the rates charged by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates charged for gathering services, the Company also may be affected by these changes. Accordingly, the Company does not anticipate that the Company would be affected any differently than similarly situated gas producers.
Regulation of transportation and sale of oil and NGLs. The liquids industry is also extensively regulated by numerous federal, state and local authorities. In a number of instances, the ability to transport and sell such products on interstate pipelines is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate Commerce Act (the "ICA"). The Company does not believe these regulations affect it any differently than other producers.
The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service on interstate common carrier pipelines be "just and reasonable." Such pipelines must also provide jurisdictional service in a manner that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms and conditions of service before FERC.
Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-year period beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 2.65 percent. This adjustment is subject to review every five years. Under FERC's regulations, a liquids pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation rates may result in lower revenue and cash flows for the Company.
In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers in an equitable manner in the event there are nominations in excess of capacity by current shippers or capacity requests are received from a new shipper. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to the Company. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that the Company relies upon for liquids transportation could have a material adverse effect on its business, financial condition, results of operations and cash flows. However, the Company believes that access to liquids pipeline transportation services generally will be available to it to the same extent as to its similarly-situated competitors.

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Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates, varies from state to state. The Company believes that the regulation of liquids pipeline transportation rates will not affect its operations in any way that is materially different from the effects on its similarly-situated competitors.
In November 2009, the Federal Trade Commission (the "FTC") issued regulations pursuant to the Energy Independence and Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil penalties of up to $1.0 million per violation per day. In July 2010, the U.S. Congress passed the Dodd-Frank Wall Street Reform and Consumer Protection Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission (the "CFTC") to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to oil swaps and futures contracts, is similar to the anti-manipulation authority granted to the FERC with respect to anti-manipulation in the gas industry and the FTC with respect to oil purchases and sales, as described above. In July 2011, the CFTC issued final rules to implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1.0 million or triple the monetary gain to the person for each violation.
Energy commodity prices. Sales prices of oil, condensate, NGLs and gas are not currently regulated and are made at market prices. Although prices of these energy commodities are currently unregulated, the U.S. Congress historically has been active in their regulation. The Company cannot predict whether new legislation to regulate oil and gas might actually be enacted by the U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on the Company's operations.
Transportation of hazardous materials. The federal Department of Transportation has adopted regulations requiring that certain entities transporting designated hazardous materials develop plans to address security risks related to the transportation of hazardous materials. The Company does not believe that these requirements will have an adverse effect on the Company or its operations. The Company cannot provide any assurance that the security plans required under these regulations would protect against all security risks and prevent an attack or other incident related to the Company's transportation of hazardous materials.
ITEM 1A.
RISK FACTORS
The nature of the business activities conducted by the Company subjects it to certain hazards and risks. The following is a summary of some of the material risks relating to the Company's business activities. Other risks are described in "Item 1. Business — Competition, Markets and Regulations," "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." These risks are not the only risks facing the Company. The Company's business could also be affected by additional risks and uncertainties not currently known to the Company or that it currently deems to be immaterial. If any of these risks actually occurs, it could materially harm the Company's business, financial condition or results of operations and impair the Company's ability to implement business plans or complete development activities as scheduled. In that case, the market price of the Company's common stock could decline.
The prices of oil, NGLs and gas are highly volatile. A sustained decline in these commodity prices could adversely affect the Company's business, financial condition and results of operations.
The Company's revenues, profitability, cash flow and future rate of growth are highly dependent on commodity prices. Commodity prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGLs and gas, market uncertainty and a variety of additional factors that are beyond the Company's control, such as:
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domestic and worldwide supply of and demand for oil, NGLs and gas;
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inventory levels at Cushing, Oklahoma, the benchmark for WTI oil prices, and the United States Gulf Coast;
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oil, NGL and gas inventory levels in the United States;
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the capacity of U.S. refiners to absorb increasing domestic supplies of oil and condensate;
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weather conditions;
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overall domestic and global political and economic conditions, including laws, regulations and administrative policies that restrict the export of the Company's products;
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actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
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the effect of liquefied natural gas deliveries to and exports from the United States;
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technological advances affecting energy consumption and energy supply;
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domestic and foreign governmental regulations and taxation;
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the effect of energy conservation efforts;
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the proximity, capacity, cost and availability of pipelines and other transportation facilities; and
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the price and availability of alternative fuels.

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In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For the five years ended December 31, 2014, oil prices fluctuated from a high of $113.93 per Bbl in 2011 to a low of $53.27 per Bbl in 2014, while gas prices fluctuated from a low of $1.91 per Mcf in 2012 to a high of $6.15 per Mcf in 2014. Recently, commodity prices have declined significantly. Through February 13, 2015, oil prices have declined from a high of $107.26 per Bbl on June 20, 2014 to $44.45 per Bbl on January 28, 2015, and gas prices have declined from a high of $6.15 per Mcf on February 19, 2014 to a low of $2.58 per Mcf on February 6, 2015. Likewise, NGLs have suffered significant recent declines. NGLs are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics. A further or extended decline in commodity prices could materially and adversely affect the Company's future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures. The Company makes price assumptions that are used for planning purposes, and a significant portion of the Company's cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, the Company's financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
Significant or extended price declines could also adversely affect the amount of oil, NGLs and gas that the Company can produce economically, which may result in the Company having to make significant downward adjustments to its estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require the Company to reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively affect the Company's ability to replace its production and its future rate of growth.
The Company could experience periods of higher costs if commodity prices rise. These increases could reduce the Company's profitability, cash flow and ability to complete development activities as planned.
Historically, the Company's capital and operating costs have risen during periods of increasing oil, NGL and gas prices. These cost increases result from a variety of factors beyond the Company's control, such as increases in the cost of electricity, steel and other raw materials that the Company and its vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Increased levels of drilling activity in the oil and gas industry in recent periods have led to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in the Company's revenue, thereby negatively impacting the Company's profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that the Company's ability to participate in the commodity price increases is limited by its derivative risk management activities.
The Company's derivative risk management activities could result in financial losses.
To mitigate the effect of commodity price volatility on the Company's net cash provided by operating activities, support the Company's annual capital budgeting and expenditure plans and reduce commodity price risk associated with certain capital projects, the Company's strategy is to enter into derivative arrangements covering a portion of its oil, NGL and gas production. These derivative arrangements are subject to MTM accounting treatment, and the changes in fair market value of the contracts are reported in the Company's statements of operations each quarter, which may result in significant noncash gains or losses. These derivative contracts may also expose the Company to risk of financial loss in certain circumstances, including when:
•
production is less than the contracted derivative volumes;
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the counterparty to the derivative contract defaults on its contract obligations; or
•
the derivative contracts limit the benefit the Company would otherwise receive from increases in commodity prices.
On the other hand, failure to protect against declines in commodity prices exposes the Company to reduced liquidity when prices decline.
The failure by counterparties to the Company's derivative risk management activities to perform their obligations could have a material adverse effect on the Company's results of operations.
The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the financial terms of such transactions. If any of these counterparties were to default on its obligations under the Company's derivative arrangements, such a default could have a material adverse effect on the Company's results of operations, and could result in a larger percentage of the Company's future production being subject to commodity price changes.

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 Exploration and development drilling may not result in commercially productive reserves.
Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered. The cost of drilling, completing and operating wells is often uncertain and drilling operations may be curtailed, delayed or canceled, or become costlier, as a result of a variety of factors, including:
•
unexpected drilling conditions;
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unexpected pressure or irregularities in formations;
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equipment failures or accidents;
•
fracture stimulation accidents or failures;
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adverse weather conditions;
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restricted access to land for drilling or laying pipelines; and
•
access to, and the cost and availability of, the equipment, services, resources and personnel required to complete the Company's drilling, completion and operating activities.
The Company's future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse effect on the Company's future results of operations and financial condition. While all drilling, whether developmental, extension or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to find commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and abandonment expense in 2015.
Future price declines could result in a reduction in the carrying value of the Company's proved oil and gas properties, which could adversely affect the Company's results of operations.
Recently, commodity prices have declined significantly. Through February 13, 2015, oil prices have declined from a high of $107.26 per Bbl on June 20, 2014 to $44.45 per Bbl on January 28, 2015, and gas prices have declined from a high of $6.15 per Mcf on February 19, 2014 to a low of $2.58 per Mcf on February 6, 2015. Likewise, NGLs have suffered significant recent declines. NGLs are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics. As stated above, price declines, as have occurred recently, could result in the Company having to make downward adjustments to its estimated proved reserves. It is possible that prices could decline further, or the Company's estimates of production or other economic factors could change to such an extent that the Company may be required to impair, as a noncash charge to earnings, the carrying value of the Company's oil and gas properties. The Company is required to perform impairment tests on proved oil and gas properties whenever events or changes in circumstances indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company's oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their fair value. See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for specific information regarding the Company's impairments. The Company may incur impairment charges in the future, which could materially affect the Company's results of operations in the period incurred.
The Company periodically evaluates its unproved oil and gas properties and could be required to recognize noncash charges in the earnings of future periods.
At December 31, 2014, the Company carried unproved oil and gas property costs of $159 million. GAAP requires periodic evaluation of these costs on a project-by-project basis. These evaluations are affected by the results of exploration activities, commodity price outlooks, planned future sales or expiration of all or a portion of the leases, and contracts and permits appurtenant to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost invested in each project, the Company will recognize noncash charges in the earnings of future periods.
The Company periodically evaluates its goodwill for impairment and could be required to recognize noncash charges in the earnings of future periods.
At December 31, 2014, the Company carried goodwill of $272 million. Goodwill is assessed for impairment annually during the third quarter and whenever facts or circumstances indicate that the carrying value of the Company's goodwill may be impaired, which may require an estimate of the fair values of the reporting unit's assets and liabilities. Those assessments may be affected by (a) additional reserve adjustments both positive and negative, (b) results of drilling activities, (c) management's outlook for commodity prices and costs and expenses, (d) changes in the Company's market capitalization, (e) changes in the Company's weighted average cost of capital and (f) changes in income taxes. If the fair value of the reporting unit's net assets is not sufficient to fully support the goodwill balance in the future, the Company will reduce the carrying value of goodwill for the impaired value, with a corresponding noncash charge to earnings in the period in which goodwill is determined to be impaired.

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The Company may be unable to make attractive acquisitions, and any acquisition it completes is subject to substantial risks that could adversely affect its business.
Acquisitions of producing oil and gas properties have from time to time contributed to the Company's growth. The Company's growth following the full development of its existing property base could be impeded if it is unable to acquire additional oil and gas reserves on a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive, which can increase the cost of, or cause the Company to refrain from, completing acquisitions. The success of any acquisition will depend on a number of factors and involves potential risks, including among other things:
•
the inability to estimate accurately the costs to develop the reserves, the recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves;
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the assumption of unknown liabilities, including environmental liabilities, and losses or costs for which the Company is not indemnified or for which the indemnity the Company receives is inadequate;
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the validity of assumptions about costs, including synergies;
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the effect on the Company's liquidity or financial leverage of using available cash or debt to finance acquisitions;
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the diversion of management's attention from other business concerns; and
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an inability to hire, train or retain qualified personnel to manage and operate the Company's growing business and assets.
All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return on investment. Even though the Company performs a review of the properties it seeks to acquire that it believes is consistent with industry practices, such reviews are often limited in scope. As a result, among other risks, the Company's initial estimates of reserves may be subject to revision following an acquisition, which may materially and adversely affect the desired benefits of the acquisition.
The Company's ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond its control, and in certain cases the Company may be required to retain liabilities for certain matters.
From time to time, the Company sells an interest in a strategic asset for the purpose of assisting or accelerating the asset's development. In addition, the Company regularly reviews its property base for the purpose of identifying nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational and operational efficiencies. Various factors could materially affect the ability of the Company to dispose of such interests or nonstrategic assets or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to the Company.
Sellers typically retain certain liabilities or indemnify buyers for certain matters. The magnitude of any such retained liability or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, the Company may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
The Company's gas processing operations are subject to operational risks, which could result in significant damages and the loss of revenue.
As of December 31, 2014, the Company owned interests in six gas processing plants and eight treating facilities. The Company is the operator of one of the gas processing plants and all eight of the treating facilities. There are significant risks associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens. Damage to or improper operation of a gas processing plant or facility could result in an explosion or the discharge of toxic gases, which could result in significant damage claims in addition to interrupting a revenue source.
 The Company's operations involve many operational risks, some of which could result in unforeseen interruptions to the Company's operations and substantial losses to the Company for which the Company may not be adequately insured.
The Company's operations, including well stimulation and completion activities, such as hydraulic fracturing, are subject to all the risks normally incident to the oil and gas development and production business, including:
•
blowouts, cratering, explosions and fires;
•
adverse weather effects;
•
environmental hazards, such as gas leaks, oil spills, pipeline and vessel ruptures, encountering NORM, and unauthorized discharges of toxic gases, brine, well stimulation and completion fluids or other pollutants into the surface and subsurface environment;

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•
high costs, shortages or delivery delays of equipment, labor or other services or water and sand for hydraulic fracturing;
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facility or equipment malfunctions, failures or accidents;
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title problems;
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pipe or cement failures or casing collapses;
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compliance with environmental and other governmental requirements;
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lost or damaged oilfield workover and service tools;
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unusual or unexpected geological formations or pressure or irregularities in formations; and
•
natural disasters.
The Company's overall exposure to operational risks may increase as its drilling activity expands and as it seeks to directly provide fracture stimulation, water distribution and disposal and other services internally. Any of these risks could result in substantial losses to the Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up responsibilities, regulatory investigations and penalties and suspension of operations.
The Company is not fully insured against certain of the risks described above, either because such insurance is not available or because of the high premium costs and deductibles associated with obtaining such insurance. Additionally, the Company relies to a large extent on facilities owned and operated by third-parties, and damage to or destruction of those third-party facilities could affect the ability of the Company to produce, transport and sell its hydrocarbons.
Part of the Company's strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
The Company's operations involve utilizing some of the latest drilling and completion techniques as developed by it and its service providers. Risks that the Company faces while drilling horizontal wells include, but are not limited to, the following:
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landing the wellbore in the desired drilling zone;
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staying in the desired drilling zone while drilling horizontally through the formation;
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running casing the entire length of the wellbore; and
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being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that the Company faces while completing wells include, but are not limited to, the following:
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the ability to fracture stimulate the planned number of stages;
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the ability to run tools the entire length of the wellbore during completion operations; and
•
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
The results of drilling in emerging areas are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. New discoveries and emerging formations have limited or no production history and, consequently, the Company is more limited in assessing future drilling results in these areas. If the Company's drilling results are worse than anticipated, the return on investment for a particular project may not be as attractive as anticipated and the Company may recognize noncash impairment charges to reduce the carrying value of its unproved properties.
The Company's expectations for future drilling activities will be realized over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of such activities.
The Company has identified drilling locations and prospects for future drilling opportunities, including development, exploratory and infill drilling activities. These drilling locations and prospects represent a significant part of the Company's future drilling plans. For example, the Company's proved reserves as of December 31, 2014 include proved undeveloped reserves and proved developed reserves that are behind pipe of 89 MMBbls of oil, 42 MMBbls of NGLs and 317 Bcf of gas. The Company's ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. Changes in the laws or regulations on which the Company relies in planning and executing its drilling programs could adversely impact the Company's ability to successfully complete those programs. For example, under current Texas laws and regulations the Company may receive permits to drill, and may drill and complete, certain horizontal wells that traverse one or more units and/or leases; a change in those laws or regulations could adversely impact the Company's ability to drill those wells. Because of these uncertainties, the Company cannot give any assurance as to the timing of these activities or that they will ultimately result in the realization of proved reserves or meet the Company's expectations for success. As such, the Company's actual drilling activities may materially differ from the Company's current expectations, which could have a significant adverse effect on the Company's proved reserves, financial condition and results of operations.

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The Company may not be able to obtain access on commercially reasonable terms or otherwise to pipelines and storage facilities, gas gathering systems and other transportation, processing, fractionation and refining facilities to market its oil, NGL and gas production; the Company relies on a limited number of purchasers for a majority of its products.
The marketing of oil, NGLs and gas production depends in large part on the availability, proximity and capacity of pipelines and storage facilities, gas gathering systems and other transportation, processing, fractionation and refining facilities, as well as the existence of adequate markets. If there were insufficient capacity available on these systems, if these systems were unavailable to the Company, or if access to these systems were to become commercially unreasonable, the price offered for the Company's production could be significantly depressed, or the Company could be forced to shut in some production or delay or discontinue drilling plans and commercial production following a discovery of hydrocarbons while it constructs its own facility or awaits the availability of third party facilities. The Company also relies (and expects to rely in the future) on facilities developed and owned by third parties in order to store, process, transport, fractionate and sell its oil, NGL and gas production. The Company's plans to develop and sell its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties to provide sufficient transportation, storage or processing and fractionation facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist.
For example, following Hurricanes Gustav and Ike in 2008, certain Permian Basin gas processors were forced to shut down their plants due to the shutdown of the Texas Gulf Coast NGL fractionators. The Company was able to produce its oil wells and vent or flare the associated gas; however, there is no certainty the Company will be able to vent or flare gas in the future due to potential changes in regulations. The amount of oil and gas that can be produced is subject to limitation in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, transportation, refining or processing facilities, or lack of capacity on such facilities. The Company has periodically experienced high line pressure at its tank batteries, which has occasionally led to the flaring of gas due to the inability of the gas gathering systems in the areas to support the increased gas production. The curtailments arising from these and similar circumstances may last from a few days to several months, and in many cases, the Company may be provided only limited, if any, notice as to when these circumstances will arise and their duration.
To the extent that the Company enters into transportation contracts with gas pipelines that are subject to FERC regulation, the Company is subject to FERC requirements related to use of such capacity. Any failure on the Company's part to comply with FERC's regulations and policies or with an interstate pipeline's tariff could result in the imposition of civil and criminal penalties.
A limited number of companies purchase a majority of the Company's oil, NGLs and gas. The loss of a significant purchaser could have a material adverse effect on the Company's ability to sell its production.
The Company's operations and drilling activity are concentrated in areas of high industry activity, which may affect its ability to obtain the personnel, equipment, services, resources and facilities access needed to complete its development activities as planned or result in increased costs.
The Company's operations and drilling activity are concentrated in areas in which industry activity had increased rapidly, particularly in the Spraberry field in West Texas and the Eagle Ford Shale play in South Texas. As a result, demand for personnel, equipment, power, services and resources, as well as access to transportation, processing and refining facilities in these areas, had increased, as did the costs for those items. In addition, hydraulic fracturing and other operations require significant quantities of water, which supply may be affected by drought conditions. In late 2014, commodity prices began to decline and the demand for goods and services has subsided due to reduced activity in these areas. To the extent that commodity prices improve in the future, any delay or inability to secure the personnel, equipment, power, services, resources and facilities access necessary for the Company to resume or increase its development activities, including the result of any changes in laws or regulations applicable to the Company's operations relating to water usage, could result in oil and gas production volumes being below the Company's forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on the Company's cash flow and profitability.
The refining industry may be unable to absorb rising U.S. oil and condensate production; in such a case, the resulting surplus could depress prices and restrict the availability of markets, which could adversely affect the Company's results of operations.
Under U.S. law and regulations, the export of oil and certain condensates is restricted. Absent a change in this law or an expansion of U.S. refining capacity, rising U.S. production of oil and condensates could result in a surplus of these products, which would likely cause prices for these commodities to fall and markets to constrict. In such circumstances, the returns on the Company's capital projects would decline, possibly to levels that would make execution of the Company's drilling plans uneconomical, and a lack of market for the Company's products could require that the Company shut in some portion of its production. If this were to occur, the Company's production and cash flow could decrease, or could increase less than forecasted, which could have a material adverse effect on the Company's cash flow and profitability.

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The nature of the Company's assets and production operations exposes it to significant costs and liabilities with respect to environmental and occupational health and safety matters.
The oil and gas business involves the production, handling, sale and disposal of environmentally sensitive materials and is subject to environmental hazards, such as oil spills, produced water spills, gas leaks, pipeline and vessel ruptures and unauthorized discharges of substances or gases, that could expose the Company to substantial liability due to pollution and other environmental damage. Pollution and similar environmental risks generally are not fully insurable either because such insurance is not available or because of the high premium costs and deductible associated with obtaining such insurance. A variety of federal, state and local laws and regulations govern the environmental aspects of the oil and gas business. Noncompliance with these laws and regulations may subject the Company to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other liabilities, and compliance with these laws and regulations may increase the cost of the Company's operations. Such laws and regulations may also affect the costs of acquisitions. See "Item 1. Business — Competition, Markets and Regulations — Environmental and occupational health and safety matters" above for additional discussion related to environmental risks.
Environmental laws and regulations are subject to amendment or replacement by more stringent laws and regulations and no assurance can be given that continued compliance with existing or future environmental laws and regulations will not result in a curtailment of production or processing activities, result in a material increase in the costs of production, development, exploration or processing operations or adversely affect the Company's future operations and financial condition.
The Company could incur significant costs and liabilities in responding to contamination that occurs at its properties or as a result of its operations.
There is inherent risk of incurring significant environmental costs and liabilities in the Company's operations due to its handling of petroleum hydrocarbons and wastes, the risk of air emissions and water discharges related to its operations, and operations and waste disposal practices by prior owners and operators. The Company currently owns, leases or operates properties that for many years have been used for oil and gas exploration and production activities, and petroleum hydrocarbons, hazardous substances and wastes may have been released on or under such properties and could be released during future operations. Joint and several strict liabilities may be incurred in connection with such releases of petroleum hydrocarbons and wastes on, under or from the Company's properties. Private parties, including lessors of properties on which the Company operates and the owners or operators of properties adjacent to the Company's operations and facilities where the Company's petroleum hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance as well as seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage. The Company may not be able to recover some or any of these costs from insurance or other sources of contractual indemnity.
The Company's credit facility and debt instruments have substantial restrictions and financial covenants that may restrict its business and financing activities.
The Company is a borrower under fixed rate senior notes and maintains a credit facility that is currently undrawn. The terms of the Company's borrowings specify scheduled debt repayments and require the Company to comply with certain associated covenants and restrictions. The Company's ability to comply with the debt repayment terms, associated covenants and restrictions is dependent on, among other things, factors outside the Company's direct control, such as commodity prices and interest rates. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's outstanding debt as of December 31, 2014 and the terms associated therewith.
The Company's ability to obtain additional financing is also affected by the Company's debt credit ratings and competition for available debt financing.
 The Company faces significant competition, and some of its competitors have resources in excess of the Company's available resources.
The oil and gas industry is highly competitive. The Company competes with a large number of companies, producers and operators in a number of areas such as:
•
seeking to acquire oil and gas properties suitable for development or exploration;
•
marketing oil, NGL and gas production; and
•
seeking to acquire the equipment and expertise, including trained personnel, necessary to evaluate, operate and develop its properties.
Some of the Company's competitors are larger and have substantially greater financial and other resources than the Company. See "Item 1. Business — Competition, Markets and Regulations" for additional discussion regarding competition.

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The Company is subject to regulations that may cause it to incur substantial costs.
The Company's operations are subject to stringent and complex federal, state and local laws and regulations governing, among other things, worker health and safety, the discharge of materials into the environment and environmental protection that may cause it to incur substantial costs. For example, in connection with the Company's CBM operations in the Raton Basin in Colorado, the Colorado Supreme Court affirmed a state water court holding that water produced in connection with CBM operations should be subject to state water-use regulations, including regulations requiring permits for diversion and use of surface and subsurface water, an evaluation of potential competing permits, possible uses of the water and a possible requirement to provide augmentation water supplies for water rights owners with more senior rights. As another example, the underground injection well program under the SDWA requires permits from the EPA or an analogous state agency for the Company's disposal wells, establishes minimum standards for injection well operations, and restricts the types and quantities of fluids that may be injected. In some areas of Texas, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing Texas regulatory agency is reviewing the data to determine whether any action is necessary to address this issue. If the Texas state agency were to decline to issue permits for, or limit the volumes of, new injection wells into the formations currently utilized by the Company, the Company may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase its costs. There can be no assurance that present or future regulations will not adversely affect the Company's business and operations, including that the Company may be required to suspend drilling operations or shut in production pending compliance. See "Item 1. Business — Competition, Markets and Regulations" for additional discussion regarding government regulation.
The Company's sales of oil, NGLs, gas or other energy commodities, and any derivative activities related to such energy commodities, expose the Company to potential regulatory risks.
FERC, the FTC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy commodities markets relevant to the Company's business. These agencies have imposed broad regulations prohibiting fraud and manipulation of such markets. With regard to the Company's physical sales of oil, NGLs, gas or other energy commodities, and any derivative activities related to these energy commodities, the Company is required to observe the market-related regulations enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted and enforced, could materially and adversely affect the Company's results of operations and financial condition.
Estimates of proved reserves and future net cash flows are not precise. The actual quantities and net cash flows of the Company's proved reserves may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. The estimates of proved reserves and related future net cash flows set forth in this Report are based on various assumptions, which may ultimately prove to be inaccurate.
Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and gas reserves and estimates of future net cash flows depend upon a number of variable factors and assumptions, including the following:
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historical production from the area compared with production from other producing areas;
•
the quality and quantity of available data;
•
the interpretation of that data;
•
the assumed effects of regulations by governmental agencies;
•
assumptions concerning future commodity prices; and
•
assumptions concerning future operating costs, severance, ad valorem and excise taxes, development costs, transportation costs and workover and remedial costs.
Because all proved reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating proved reserves:
•
the quantities of oil and gas that are ultimately recovered;
•
the production costs incurred to recover the reserves;
•
the amount and timing of future development expenditures; and
•
future commodity prices.
Furthermore, different reserve engineers may make different estimates of proved reserves and cash flows based on the same available data. The Company's actual production, revenues and expenditures with respect to proved reserves will likely be different from estimates, and the differences may be material.

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As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on average prices preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
•
the amount and timing of actual production;
•
levels of future capital spending;
•
increases or decreases in the supply of or demand for oil, NGLs and gas; and
•
changes in governmental regulations or taxation.
Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject to the rules and regulations of the SEC. In general, it requires the use of commodity prices that are based upon a 12-month unweighted average, as well as operating and development costs being incurred at the end of the reporting period. Consequently, it may not reflect the prices ordinarily received or that will be received for oil and gas production because of seasonal price fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general. Therefore, the estimates of discounted future net cash flows or Standardized Measure in this Report should not be construed as accurate estimates of the current market value of the Company's proved reserves.
The Company's actual production could differ materially from its forecasts.
From time to time, the Company provides forecasts of expected quantities of future oil and gas production. These forecasts are based on a number of estimates, including expectations of production from existing wells and the outcome of future drilling activity. Should these estimates prove inaccurate, actual production could be adversely affected. In addition, the Company's forecasts assume that none of the risks associated with the Company's oil and gas operations summarized in this "Item 1A. Risk Factors" occur, such as facility or equipment malfunctions, adverse weather effects, or downturns in commodity prices or significant increases in costs, which could make certain drilling activities or production uneconomical.
The Company's business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.
As an oil and gas producer, the Company faces various security threats, including cybersecurity threats to gain unauthorized access to sensitive information or to render data or systems unusable; threats to the security of the Company's facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts. The potential for such security threats has subjected the Company's operations to increased risks that could have a material adverse effect on the Company's business. In particular, the Company's implementation of various procedures and controls to monitor and mitigate security threats and to increase security for the Company's information, facilities and infrastructure may result in increased capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information, critical infrastructure or capabilities essential to the Company's operations and could have a material adverse effect on the Company's reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, and corruption of data. These events could damage the Company's reputation and lead to financial losses from remedial actions, loss of business or potential liability.
 A failure by purchasers of the Company's production to satisfy their obligations to the Company could require the Company to recognize a pre-tax charge in earnings and have a material adverse effect on the Company's results of operation.
The Company relies on a limited number of purchasers to purchase a majority of its products. To the extent that purchasers of the Company's production rely on access to the credit or equity markets to fund their operations, there is a risk that those purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or equity markets for an extended period of time. If for any reason the Company were to determine that it was probable that some or all of the accounts receivable from any one or more of the purchasers of the Company's production were uncollectible, the Company would recognize a pre-tax charge in the earnings of that period for the probable loss.

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Declining general economic, business or industry conditions could have a material adverse effect on the Company's results of operations.
Since 2010, the economies in the United States and certain other countries have continued to stabilize with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain European and Asian nations, continue to face economic struggles or slowing economic growth and, should these conditions worsen, there could be a significant adverse effect on global financial markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate, demand for petroleum products could diminish, which could depress the prices at which the Company could sell its oil, NGLs and gas and ultimately decrease the Company's net revenue and profitability.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may be eliminated as a result of future legislation.
In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws, including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas companies. Such tax legislation changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties, (ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, and any such change could have an adverse effect on the Company's financial position, results of operations and cash flows.
Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil, NGLs and gas the Company produces.
In 2009, the EPA published its findings that emissions of GHGs present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. Based on these findings, the EPA has adopted regulations under the CAA that, among other things, establish certain permits and construction reviews designed to allow operations while ensuring the PSD of air quality by GHG emissions from large stationary sources that already may be potential sources of other regulated pollutant emissions. The Company could become subject to these permitting requirements and be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that the Company may seek to construct in the future if they would otherwise emit large volumes of GHGs from such sources. The EPA has also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States, including certain oil and gas production facilities, which include certain of the Company's facilities. While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. The adoption of any legislation or regulations that requires reporting of GHGs or otherwise restricts emissions of GHGs from the Company's equipment and operations could require the Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. For example, pursuant to President Obama's Strategy to Reduce Methane Emissions, the Obama Administration announced on January 14, 2015, that EPA is expected to propose in the summer of 2015 and finalize in 2016 new regulations that will set methane emission standards for new and modified oil and gas production and gas processing and transmission facilities as part of the Administration's efforts to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025. Any such legislation or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on the Company's business, financial condition and results of operations. See "Item 1. Business - Competition, Markets and Regulations - Environmental and occupational health and safety matters - Climate change" for additional discussion relating to climate change.
The enactment of derivatives legislation could have an adverse effect on the Company's ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with its business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") enacted on July 21, 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations for its

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implementation. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the United States District Court for the District of Columbia in September 2012. However, in November 2013, the CFTC proposed new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical commodities, subject to exceptions for certain bona fide derivative transactions. As these new position limit rules are not yet final, the impact of those provisions on the Company is uncertain at this time. The CFTC has designated certain interest rate swaps and credit default swaps for mandatory clearing and the associated rules also will require the Company, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although the Company believes it qualifies for the end-user exception from the mandatory clearing requirements for swaps entered to mitigate its commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the Company's derivatives. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished or what the effect of any such regulations will be on the Company. For example, for uncleared swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial and variation margin. Posting of collateral could impact liquidity and reduce cash available to the Company for capital expenditures, therefore reducing its ability to execute derivatives to reduce risk and protect cash flows. The proposed margin rules are not yet final, and therefore the impact of those provisions to the Company is uncertain at this time. The full impact of the Dodd-Frank Act and related regulatory requirements upon the Company's business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters and reduce the Company's ability to monetize or restructure its existing derivative contracts. If the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, the Company's results of operations may become more volatile and its cash flows may be less predictable, which could adversely affect the Company's ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and gas. The Company's revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the Company, its financial condition and its results of operations. In addition, the European Union and other non-U.S. jurisdictions are implementing regulations with respect to the derivatives market. To the extent the Company transacts with counterparties in foreign jurisdictions, it may become subject to such regulations. At this time, the impact of such regulations is not clear.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect the Company's production.
Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations. The Company routinely utilizes hydraulic fracturing techniques in the majority of its drilling and completion programs. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and gas production. The process is typically regulated by state oil and gas commissions, but several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has issued final CAA regulations governing performance standards, including standards for the capture of air emissions released during hydraulic fracturing; announced its intent to propose in the first half of 2015 effluent limit guidelines that wastewater from shale gas extraction operations must meet before discharging to a treatment plant; and issued in May 2014 a prepublication of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in May 2013, the BLM issued a revised proposed rule containing disclosure requirements and other mandates for hydraulic fracturing on federal lands and the agency is now analyzing comments to the proposed rulemaking and is expected to promulgate a final rule in the first half of 2015.
From time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. In addition, certain states in which the Company operates, including Colorado and Texas have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, and well-construction requirements on hydraulic-fracturing operations. States could elect to prohibit hydraulic fracturing altogether, as Governor Andrew Cuomo of the State of New York announced in December 2014 with regard to fracturing activities in New York. Also, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. For example, in response to concerns regarding hydraulic fracturing, the city of Denton, Texas issued a moratorium on the issuance of new drilling permits inside the Denton city limits. In the event federal, state or local restrictions are adopted in areas where the Company is currently conducting, or in the future plan to conduct operations, the Company may incur additional costs to comply with such requirements that may

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be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that the Company is ultimately able to produce from its reserves.
Certain governmental reviews are underway that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and a draft report is expected to be available for public comment and peer review in the first half of 2015. These existing or any future studies, depending on their degree of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing. See "Item 1. Business - Competition, Markets and Regulations - Environmental and occupational health and safety matters" for additional discussion related to environmental risks associated with the Company's hydraulic fracturing activities.
Laws and regulations pertaining to threatened and endangered species could delay or restrict the Company's operations and cause it to incur substantial costs.
Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, the CWA, OPA and CERCLA. The FWS may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. For example, on March 27, 2014, the FWS announced the listing of the lesser prairie chicken as a threatened species under the ESA. The lesser prairies chicken's habitat is over a five-state region, including Texas and Colorado, where we conduct operations. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the FWS is required to make a determination on the listing of numerous species as endangered or threatened under the ESA before completion of the agency's 2017 fiscal year. The designation of previously unprotected species as threatened or endangered in areas where the Company conducts operations could cause the Company to incur increased costs arising from species protection measures or could result in delays or limitations on its development and production activities that could have an adverse effect on the Company's ability to develop and produce reserves.
Provisions of the Company's charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for the Company's common stock.
Provisions in the Company's certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which the Company is not the surviving company and may otherwise prevent or slow changes in the Company's board of directors and management. In addition, because the Company is incorporated in Delaware, it is governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for the Company's common stock.
The Company's sand mining operations are subject to operating risks that are often beyond the Company's control, and such risks may not be covered by insurance.
Ownership of industrial sand mining operations is subject to risks, many of which are beyond the Company's control. These risks include:
•
unusual or unexpected geological formations or pressures;
•
cave-ins, pit wall failures or rock falls;
•
unanticipated ground, grade or water conditions;
•
inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;
•
environmental hazards, such as unauthorized spills, releases and discharges of wastes, vessel ruptures and emission of unpermitted levels of pollutants;
•
changes in laws and regulations;
•
inability to acquire or maintain necessary permits or mining or water rights;
•
restrictions on blasting operations;
•
inability to obtain necessary production equipment or replacement parts;
•
reduction in the amount of water available for processing;
•
technical difficulties or failures;

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•
labor disputes;
•
late delivery of supplies;
•
fires, explosions or other accidents; and
•
facility interruptions or shutdowns in response to environmental regulatory actions.
Any of these risks could result in damage to, or destruction of, the Company's mining properties or production facilities, personal injury, environmental damage, delays in mining or processing, losses or possible legal liability. Not all of these risks are insurable, and the Company's insurance coverage contains limits, deductibles, exclusions and endorsements. The Company's insurance coverage may not be sufficient to meet its needs in the event of loss and any such loss may have a material adverse effect on the Company.
The Company's estimates of sand reserves and resource deposits are imprecise and actual reserves could be less than estimated.
The Company bases its sand reserve and resource estimates on engineering, economic and geological data assembled and analyzed by engineers and geologists, which are periodically reviewed by outside firms. However, commercial sand reserve estimates are necessarily imprecise and depend to some extent on statistical inferences drawn from available drilling data, which may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of commercial sand reserves and costs to mine recoverable reserves, including many factors beyond the Company's control. Estimates of economically recoverable commercial sand reserves necessarily depend on a number of factors and assumptions, all of which may vary considerably from actual results, such as:
•
geological and mining conditions or effects from prior mining that may not be fully identified by available data or that may differ from experience;
•
assumptions concerning future prices of commercial sand products, operating costs, mining technology improvements, development costs and reclamation costs; and
•
assumptions concerning future effects of regulation, including the issuance of required permits and taxes by governmental agencies.
The Company's sand mining operations are subject to extensive environmental and occupational health and safety regulations that impose significant costs and potential liabilities.
The Company's sand mining operations are subject to a variety of federal, state and local environmental requirements affecting the mining and mineral processing industry, including, among others, those relating to employee health and safety, environmental permitting and licensing, air emissions and water discharges, GHG emissions, water pollution, waste management and disposal, remediation of soil and groundwater contamination, land use restrictions, reclamation and restoration of properties, hazardous materials and natural resources. Some environmental laws impose substantial penalties for noncompliance, and others, such as the CERCLA, impose strict, retroactive and joint and several liability for the remediation of releases of hazardous substances. Failure to properly handle, transport, store or dispose of hazardous materials or otherwise conduct the Company's sand mining operations in compliance with environmental laws could expose the Company to liability for governmental penalties, cleanup costs and civil or criminal liability associated with releases of such materials into the environment, damages to property or natural resources and other damages, as well as potentially impair the Company's ability to conduct its sand mining operations. In addition, environmental laws and regulations are subject to amendment, replacement or interpretation by more stringent and comprehensive legal requirements. The Company's continued compliance with existing or future laws and regulations could restrict the Company's ability to expand its facilities or extract mineral deposits or could require the Company to acquire costly equipment or to incur other significant expenses in connection with its sand mining operations, which restrictions or costs could have a material adverse effect on the Company's sand mining operations.
Any failure by the Company to comply with applicable environmental laws and regulations in connection with its sand mining operations may cause governmental authorities to take actions that could adversely affect the Company, including:
•
issuance of administrative, civil and criminal penalties;
•
denial, modification or revocation of permits or other authorizations;
•
imposition of injunctive obligations or other limitations on the Company's operations, including interruptions or cessation of operations; and
•
requirements to perform site investigatory, remedial or other corrective actions.
In addition to environmental regulation, the Company's sand mining operations are subject to laws and regulations relating to worker health and safety, including such matters as human exposure to crystalline silica dust. Several federal and state regulatory authorities, including the U.S. Mining Safety and Health Administration, may continue to propose changes in their regulations regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective equipment.

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The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent health and safety standards on numerous aspects of the Company's sand mining operations.
The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating equipment and other matters. The Company's failure to comply with such standards, or changes in such standards or the interpretation or enforcement thereof, could have a material adverse effect on the Company's sand mining operations or otherwise impose significant restrictions on the Company's ability to conduct mineral extraction and processing operations.
The Company's sand mining operations are subject to extensive other regulations that impose significant costs and liabilities.
In addition to the environmental and occupational health and safety regulation discussed above, the Company's sand mining operations are also subject to extensive governmental regulation on matters such as permitting and licensing requirements, reclamation and restoration of mining properties after mining is completed, and the effects that mining have on groundwater quality and availability. Also, the Company's sand mining operations require numerous governmental, environmental, mining and other permits, water rights and approvals authorizing operations at each sand mining facility.
In order to obtain permits and renewals of permits in the future for its sand mining operations, the Company may be required to prepare and present data to governmental authorities pertaining to the effect that any such activities may have on the environment. Obtaining or renewing required permits may be delayed or prevented due to opposition by neighboring property owners, members of the public or other third parties and other factors beyond the Company's control. A decision by a governmental agency or other third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit or approval, could have a material adverse effect on the Company's sand mining operations at the affected facility. Current or future regulations could have a material adverse effect on the Company's sand mining operations and the Company may not be able to renew or obtain permits in the future.
The Company's sand mining operations and hydraulic fracturing may result in silica-related health issues and litigation that could have a material adverse effect on the Company.
The inhalation of respirable crystalline silica dust is associated with the lung disease silicosis. There is evidence of an association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including immune system disorders, such as scleroderma. These health risks have been a significant issue confronting the commercial sand industry. The actual or perceived health risks of mining, processing and handling sand could materially and adversely affect the Company through the threat of product liability or personal injury lawsuits and increased scrutiny by federal, state and local regulatory authorities.
Premier Silica is named as a defendant, usually among many defendants, in numerous products liability lawsuits brought by or on behalf of current or former employees of Premier Silica's commercial customers alleging damages caused by silica exposure. As of December 31, 2014, Premier Silica was the subject of silica exposure claims from approximately 575 plaintiffs, the great majority of which claims have been inactive for many years due to the plaintiffs' failure to meet specific legal requirements to advance their claims. Almost all of the claims pending against Premier Silica arise out of the alleged use of Premier Silica's sand products in foundries or as an abrasive blast media and have been filed in the states of Texas and Missouri, although some cases have been brought in many other jurisdictions over the years.
It is possible that Premier Silica will have additional silica-related claims filed against it, including claims that allege silica exposure for periods for which there is not insurance coverage. In addition, it is possible that similar claims could be asserted arising out of the Company's other operations, including it hydraulic fracturing operations. Any pending or future claims or inadequacies of insurance coverage or contractual indemnification could have a material adverse effect on the Company's results of operations.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
None. 


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ITEM 2.
PROPERTIES
Reserve Estimation Procedures and Audits
The information included in this Report about the Company's proved reserves as of December 31, 2014, 2013 and 2012 is based on evaluations prepared by the Company's engineers and (i) audited by Netherland, Sewell & Associates, Inc. ("NSAI"), with respect to the Company's major properties for all periods, and (ii) audited by Ryder Scott Company, L.P. ("RSC"), with respect to the Company's Oooguruk field properties in Alaska as of December 31, 2012. The Company has no oil and gas reserves from non-traditional sources. Additionally, the Company does not provide optional disclosure of probable or possible reserves.
Reserve estimation procedures. The Company has established internal controls over reserve estimation processes and procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC and GAAP requirements. These controls include oversight of the reserves estimation reporting processes by Pioneer's Corporate Reserves Group ("Corporate Reserves"), and annual external audits of substantial portions of the Company's proved reserves by NSAI.
Individual asset teams are responsible for the day-to-day management of the oil and gas activities in each of the Company's Permian Basin, Rockies, Mid-Continent and South Texas asset areas (the "Asset Teams"). The Company's Asset Teams are each staffed with reservoir engineers and geoscientists who prepare reserve estimates at the end of each calendar quarter for the assets that they manage, using reservoir engineering information technology. There is shared oversight of the Asset Teams' reservoir engineers by the Asset Teams' managers and the Vice President of Corporate Reserves, each of whom is in turn subject to direct or indirect oversight by the Company's management committee ("MC"). The Company's MC is comprised of its Chief Executive Officer, Chief Operating Officer, Chief Financial Officer and other Executive Vice Presidents. The Asset Teams' reserve estimates are reviewed by the Asset Team reservoir engineers before being submitted to Corporate Reserves for further review.
The reserve estimates are summarized in reserve reconciliations that quantify reserve changes since the previous year end as revisions of previous estimates, purchases of minerals-in-place, improved recovery, extensions and discoveries, production and sales of minerals-in-place. All reserve estimates, material assumptions and inputs used in reserve estimates and significant changes in reserve estimates are reviewed for engineering and financial appropriateness and compliance with SEC and GAAP standards by Corporate Reserves, in consultation with the Company's accounting and financial management personnel. Annually, the MC reviews the reserve estimates and any differences with the reserve auditors (for the portion of the reserves audited by NSAI or RSC) on a consolidated basis before these estimates are approved. The engineers and geoscientists who participate in the reserve estimation and disclosure process periodically attend training provided by external consultants and/or through internal Pioneer programs. Additionally, Corporate Reserves has prepared and maintains written policies and guidelines for the Asset Teams to reference on reserve estimation and preparation to promote objectivity in the preparation of the Company's reserve estimates and SEC and GAAP compliance in the reserve estimation and reporting process.
Proved reserves audits. The proved reserve audits performed by NSAI for the years ended December 31, 2014, 2013 and 2012, and by RSC for 2012, in the aggregate, represented 80 percent, 94 percent and 95 percent of the Company's year-end 2014, 2013 and 2012 proved reserves, respectively; and 91 percent, 92 percent and 99 percent of the Company's year-end 2014, 2013 and 2012 associated pre-tax present value of proved reserves discounted at ten percent, respectively.
NSAI 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 (the "SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE's definition of a reserve audit includes the following concepts:
•
A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with the 2007 SPE publication entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information."
•
The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable.
•
The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare their own estimates of reserve information for the audited properties.

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In conjunction with the audit of the Company's proved reserves and associated pre-tax present value discounted at ten percent, Pioneer provided to NSAI its external and internal engineering and geoscience technical data and analyses. Following NSAI's review of that data, it had the option of honoring Pioneer's interpretations, or making its own interpretations. No data was withheld from NSAI. NSAI accepted without independent verification the accuracy and completeness of the historical information and data furnished by Pioneer with respect to ownership interest, oil and gas production, well test data, commodity prices, operating and development costs, and any agreements relating to current and future operations of the properties and sales of production. However, if in the course of its evaluations something came to its attention that brought into question the validity or sufficiency of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data.
In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of the Company's proved reserves and the pre-tax present values of such reserves discounted at ten percent. NSAI reviewed its audit differences with the Company, and, in a number of cases, held meetings with the Company to review additional reserves work performed by the Company's technical teams and any updated performance data related to the proved reserve differences. Such data was incorporated, as appropriate, by both parties into the proved reserve estimates. NSAI's estimates, including any adjustments resulting from additional data, of those proved reserves and the pre-tax present value of such reserves discounted at ten percent did not differ from Pioneer's estimates by more than ten percent in the aggregate. However, when compared on a lease-by-lease, field-by-field or area-by-area basis, some of the Company's estimates were greater than those of the reserve auditors and some were less than the estimates of the reserve auditors. When such differences do not exceed ten percent in the aggregate and NSAI is satisfied that the proved reserves and pre-tax present values of such reserves discounted at ten percent are reasonable and that its audit objectives have been met, NSAI will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited cost benefit of continuing such analyses by the Company and the reserve auditors. At the conclusion of the audit process, it was NSAI's opinion, as set forth in its audit letter, which is included as an exhibit to this Report, that Pioneer's estimates of the Company's proved oil and gas reserves and associated pre-tax present values discounted at ten percent are, in the aggregate, reasonable and have been prepared in accordance with the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the SPE.
See "Item 1A. Risk Factors," "Critical Accounting Estimates" in "Item 7. Management's Discussion and Analysis and Results of Operations" and "Item 8. Financial Statements and Supplementary Data" for additional discussions regarding proved reserves and their related cash flows.
Qualifications of proved reserves preparers and auditors. Corporate Reserves is staffed by petroleum engineers with extensive industry experience and is managed by the Vice President of Corporate Reserves, the technical person that is primarily responsible for overseeing the Company's reserves estimates. These individuals meet the professional qualifications of reserves estimators and reserves auditors as defined by the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information," promulgated by the SPE. The qualifications of the Vice President of Corporate Reserves include 37 years of experience as a petroleum engineer, with 30 years focused on reserves reporting for independent oil and gas companies, including Pioneer. His educational background includes an undergraduate degree in Chemical Engineering and a Masters of Business Administration degree in Finance. He is also a Chartered Financial Analyst Charterholder.
NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. The technical person primarily responsible for auditing the Company's reserves estimates has been a practicing consulting petroleum engineer at NSAI since 1983 and has over 36 years of practical experience in petroleum engineering, including over 34 years of experience in the estimation and evaluation of proved reserves. He graduated with a Bachelor of Science degree in Chemical Engineering in 1978 and meets or exceeds the education, training and experience requirements set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the board of directors of the SPE.
RSC provides worldwide petroleum property analysis services for energy clients, financial organizations and government agencies. RSC was founded in 1937 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-1580. The technical person primarily responsible for auditing the Company's Alaska reserves estimates in 2012 was a practicing consulting petroleum engineer at RSC since 2000 with over 28 years of practical experience in petroleum engineering. He graduated with a Bachelor of Science degree in Petroleum Engineering and a Master of Business Administration degree and at the time of the reserves audit he met or exceeded the education, training and experience requirements set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the board of directors of the SPE.
Technologies used in proved reserves estimates. Proved undeveloped reserves include those reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for

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PIONEER NATURAL RESOURCES COMPANY

completion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic producibility. Undrilled locations may be classified as having undeveloped proved reserves only if an ability and intent has been established to drill the reserves within five years, unless specific circumstances justify a longer time period.
In the context of reserves estimations, reasonable certainty means a high degree of confidence that the quantities will be recovered and reliable technology means a grouping of one or more technologies (including computational methods) that has been field-tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. In estimating proved reserves, the Company uses several different traditional methods such as performance-based methods, volumetric-based methods and analogy with similar properties. In addition, the Company utilizes additional technical analysis such as seismic interpretation, wireline formation tests, geophysical logs and core data to provide incremental support for more complex reservoirs. Information from this incremental support is combined with the traditional technologies outlined above to enhance the certainty of the Company's proved reserve estimates.
Proved Reserves
As of December 31, 2014, 2013 and 2012, the Company's oil and gas proved reserves are located entirely in the United States. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional details of the Company's discontinued operations. The following table provides information regarding the Company's proved reserves as of December 31, 2014, 2013 and 2012:
 
 
Summary of Oil and Gas Reserves as of Fiscal Year-End
Based on Average Fiscal-Year Prices
 
Reserve Volumes
 
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Gas
(MMcf) (a)
 
Total (MBOE)
 
%
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2014:
 
 
 
 
 
 
 
 
 
 
Developed
267,193

 
130,206

 
1,486,289

 
645,113

 
81
%
 
Undeveloped
84,891

 
39,038

 
182,583

 
154,360

 
19
%
 
Total proved reserves
352,084

 
169,244

 
1,668,872

 
799,473

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2013:
 
 
 
 
 
 
 
 
 
 
Developed
256,638

 
148,161

 
1,703,667

 
688,743

 
81
%
 
Undeveloped
85,467

 
37,261

 
202,674

 
156,507

 
19
%
 
Total proved reserves
342,105

 
185,422

 
1,906,341

 
845,250

 
100
%
 
Less proved reserves associated with discontinued operations
24,128

 
27,733

 
287,606

 
99,795

 
12
%
 
Total proved reserves associated with continuing operations
317,977

 
157,689

 
1,618,735

 
745,455

 
88
%
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2012:
 
 
 
 
 
 
 
 
 
 
Developed
230,700

 
134,637

 
1,605,209

 
632,872

 
58
%
 
Undeveloped
256,138

 
97,939

 
592,271

 
452,789

 
42
%
 
Total proved reserves
486,838

 
232,576

 
2,197,480

 
1,085,661

 
100
%
 
Less proved reserves associated with discontinued operations
48,274

 
42,331

 
383,931

 
154,594

 
14
%
 
Total proved reserves associated with continuing operations
438,564

 
190,245

 
1,813,549

 
931,067

 
86
%
 
 ______________________
(a)
Total proved gas reserves contain 191,932 MMcf, 240,093 MMcf and 280,344 MMcf of gas that the Company expected to be produced and used as field fuel (primarily for compressors) before the gas is delivered to a sales point, as of December 31, 2014, 2013 and 2012, respectively.
The Company's Standardized Measure of total proved reserves as of December 31, 2014 was $7.8 billion, including $6.4 billion and $1.4 billion related to proved developed and proved undeveloped reserves, respectively. The Company's Standardized Measure of total proved reserves as of December 31, 2013 was $7.3 billion, including $6.3 billion and $1.0 billion related to proved developed and proved undeveloped reserves, respectively. The Company's Standardized Measure of total proved reserves as of December 31, 2012 was $6.4 billion, including $5.0 billion and $1.4 billion related to proved developed and proved undeveloped reserves, respectively.

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See the "Unaudited Supplementary Information" section included in "Item 8. Financial Statements and Supplementary Data" for additional details of the estimated quantities of the Company's proved reserves, including explanations for material changes in proved developed and proved undeveloped reserves.
Description of Properties
The following tables summarize the Company's development and exploration/extension drilling activities during 2014:
 
 
Development Drilling
 
Beginning
Wells In Progress
 
Wells
Spud
 
Successful
Wells
 
Wells
Sold
 
Ending
Wells In
Progress
Permian Basin
59

 
257

 
271

 
4

 
41

South Texas—Eagle Ford Shale
16

 
34

 
37

 
—

 
13

Total continuing operations
75

 
291

 
308

 
4

 
54

Barnett Shale
1

 
—

 
1

 
—

 
—

Alaska
4

 
1

 
—

 
5

 
—

Total including discontinued operations
80

 
292

 
309

 
9

 
54

 
 
Exploration/Extension Drilling
 
Beginning
Wells In Progress
 
Wells
Spud
 
Successful
Wells
 
Unsuccessful
Wells
 
Wells
Sold
 
Ending
Wells In
Progress
Permian Basin
31

 
228

 
183

 
—

 
1

 
75

South Texas—Eagle Ford Shale
24

 
93

 
87

 
—

 
—

 
30

South Texas—Other
—

 
8

 
8

 
—

 
—

 
—

Other
3

 
3

 
—

 
5

 
—

 
1

Total continuing operations
58

 
332

 
278

 
5

 
1

 
106

Barnett Shale
17

 
42

 
52

 
—

 
7

 
—

Alaska
2

 
—

 
—

 
—

 
2

 
—

Total including discontinued operations
77

 
374

 
330

 
5

 
10

 
106

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during 2014:
 
 
Oil (Bbls)
 
NGLs (Bbls)
 
Gas (Mcf) (a)
 
Total (BOE)
Permian Basin
64,984

 
20,873

 
83,664

 
99,801

South Texas—Eagle Ford Shale
17,802

 
13,530

 
89,679

 
46,279

Raton Basin
—

 
—

 
124,310

 
20,718

West Panhandle
2,865

 
4,140

 
14,188

 
9,370

South Texas—Other
1,379

 
101

 
27,435

 
6,052

Other
4

 
2

 
65

 
17

Total continuing operations
87,034

 
38,646

 
339,341

 
182,237

Barnett Shale
1,604

 
2,867

 
21,453

 
8,047

Hugoton
—

 
1,668

 
16,428

 
4,405

Alaska
1,001

 
—

 
—

 
1,001

Total including discontinued operations
89,639

 
43,181

 
377,222

 
195,690

 _____________________
(a)
Gas production excludes gas produced and used as field fuel.

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The following table summarizes the Company's costs incurred by asset area during 2014:
 
 
Property
Acquisition Costs
 
Exploration Costs
 
Development Costs
 
Asset
Retirement Obligations
 
 
 
Proved
 
Unproved
 
 
 
 
Total
 
(in millions)
Permian Basin
$
14

 
$
78

 
$
1,409

 
$
1,194

 
$
7

 
$
2,702

South Texas—Eagle Ford Shale
—

 
—

 
348

 
219

 
1

 
568

Raton Basin
—

 
—

 
3

 
24

 
(10
)
 
17

West Panhandle
—

 
—

 
2

 
11

 
2

 
15

South Texas—Other
—

 
—

 
19

 
12

 
3

 
34

Other
—

 
2

 
30

 
—

 
—

 
32

Total continuing operations
$
14

 
$
80

 
$
1,811

 
$
1,460

 
$
3

 
$
3,368

Barnett Shale
5

 
5

 
128

 
22

 
—

 
160

Hugoton
—

 
—

 
2

 
1

 
—

 
3

Alaska
—

 
—

 
(1
)
 
48

(a)
4

 
51

Total including discontinued operations
$
19

 
$
85

 
$
1,940

 
$
1,531

 
$
7

 
$
3,582

 ____________________
(a)
Includes $2 million of capitalized interest associated with the Oooguruk development project prior to its divestiture.

Permian Basin
The Spraberry field was discovered in 1949, encompasses eight counties in West Texas and the Company believes it is the largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content of 1,400 Btu. The oil and gas are produced primarily from six formations, the upper and lower Spraberry, the Dean, the Wolfcamp, the Strawn and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. The Company believes that it has significant resource potential within its Spraberry and Wolfcamp formation acreage, based on its extensive geologic data covering the Spraberry and Wolfcamp A, B, C and D intervals and its drilling results to date. The Company expects to improve the incremental recovery rates in the Spraberry field through horizontal drilling while containing operating expenses and drilling costs through economies of scale and vertical integration of field services.
During 2014, the Company drilled 454 wells in the Spraberry field and its total acreage position now approximates 785,000 gross acres (692,000 net acres). During 2014, the Company placed on production 97 horizontal wells in the northern portion of the play, 113 horizontal wells in the southern portion of the play, where the Company has its joint venture with Sinochem, and 262 vertical wells. Three-well pads were utilized to drill most of the horizontal wells in the 2014 program. In the northern portion of the play, approximately 80 percent of the wells placed on production were Wolfcamp A, B and D interval wells and the remaining 20 percent were Spraberry Shale wells (Lower Spraberry Shale, Jo Mill Shale and Middle Spraberry Shale). In the southern portion of the play, approximately two-thirds of the wells placed on production were Wolfcamp B interval wells, with the remainder being a mix of Wolfcamp A, C and D interval wells.
The Company continued to shift its drilling activity in the Spraberry field from vertical drilling to horizontal drilling during 2014. The Company believes that replacing vertical drilling with horizontal drilling will enhance ultimate resource recoveries and improve rates of return per dollar invested. As a result, Pioneer no longer expects to drill any additional vertical locations in the Spraberry field in 2015 and has extended leases with continuous drilling obligations to allow the Company to drill those locations in the future with higher returning horizontal wells.
As a result of the significant decrease in oil prices, the Company is reducing its rig count for 2015 and expects to be at its planned 10 rig drilling program in the Spraberry field by the end of February 2015, all of which are drilling horizontal wells. During 2015, the Company expects to drill approximately four vertical wells and 105 horizontal wells (60 horizontal wells in the northern portion of the play and 45 horizontal wells in the southern portion of the play), with the horizontal wells being predominantly drilled in the Wolfcamp B horizon. The Company expects to spend $1.17 billion of drilling capital in the Spraberry field during 2015.
In January 2013, the Company signed an agreement with Sinochem, an unaffiliated third party, to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for consideration of $1.8 billion. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $624 million, resulting in a 2013 gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem is

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paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play. At December 31, 2014, the unused carry balance totaled $575 million. Associated with the closing of the joint venture transaction, the Company conveyed a 40 percent interest in the producing horizontal Wolfcamp Shale wells in the joint venture area.
Sinochem also elected to participate in certain vertical wells that were drilled in the joint interest area after the December 1, 2012 effective date and received its share of production and costs from the Wolfcamp and deeper horizons based on the reserve contribution from the Wolfcamp and deeper intervals relative to reserves from all completed intervals. Pioneer's and Sinochem's participation in vertical wells is based on each party's interest without any drilling carry applied. Pioneer retained 100 percent of its vertical production in the joint interest area for wells drilled before the December 1, 2012 effective date. Pioneer also retained its current working interests in all horizons shallower than the Wolfcamp horizon and continues as operator of the properties in the joint interest area.
The Company continues to benefit from its integrated services to control drilling and operating costs and support the execution of its drilling and production activities in the Spraberry field. The Company is currently utilizing six Company-owned fracture stimulation fleets totaling approximately 250,000 horsepower in the Spraberry field. To support its operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, Premier Silica (the Company's wholly-owned sand mining subsidiary) is supplying brown sand for proppant, which is being used to fracture stimulate vertical and horizontal wells in the Spraberry and Wolfcamp Shale intervals.
The Company's long-term growth plan continues to be focused on optimizing the development of the field and identifying the future requirements for water, field infrastructure, gas processing, sand, pipeline takeaway, oilfield services, tubulars, electricity, systems, buildings and roads. However, much of the Company's front-end loaded infrastructure plans, which were expected to provide significant future cost savings and support the Company's long-term growth plan in the Spraberry/Wolfcamp area, have been deferred given the significant decline in oil prices. The Company plans to re-evaluate its infrastructure plans for a field-wide water distribution network, additional gas processing facilities, continued build-out of horizontal tank batteries and expansion of Premier Silica's Brady sand mine when oil prices recover and/or costs improve.
South Texas Eagle Ford Shale
The Company's drilling activities in the South Texas area during 2014 continued to be primarily focused on development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2014 drilling program was focused on liquids-rich drilling, with no wells drilled in its dry gas acreage. During 2014, the Company also received confirmation from the U.S. Department of Commerce that condensate processed through distillation units, such as those located at several of Pioneer's Eagle Ford Shale central gathering plants in South Texas, is a petroleum product that may be exported without a license.
The Company completed 124 horizontal Eagle Ford Shale wells during 2014, all of which were successful, with average lateral lengths of 5,719 feet and, on average, 20-stage fracture stimulations. The Company placed 50 upper target Eagle Ford Shale wells on production and estimates that approximately 25 percent of the Company's acreage is prospective for this interval in the Eagle Ford Shale play. The Company plans to spend $390 million of capital in 2015 to drill approximately 83 Eagle Ford Shale wells. The Company is operating two Pioneer-owned fracture stimulation fleets in the play.
In 2013, the Company added approximately 300 drilling locations in the liquids-rich area of the play as a result of downspacing from 1,000 feet between wells (120-acre spacing) to 500 feet (60-acre spacing) between wells. Further downspacing and staggered testing to a range of 175 feet to 300 feet between staggered 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 lower and upper targets within the Eagle Ford Shale. Results from the downspacing and staggered tests in the Eagle Ford Shale continue to be encouraging.
The Company's drilling operations in the Eagle Ford Shale continue to focus on improving drilling efficiencies. During 2014, most Eagle Ford Shale wells were drilled utilizing three-well and four-well pads. Pad drilling saves the Company a significant amount of capital costs per well, as compared to drilling single-well locations.
The Company owns a 50.1 percent member interest in EFS Midstream, an entity formed by the Company to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play. The Company does not have control of EFS Midstream and accounts for its investment in EFS Midstream under the equity method of accounting for investments in unconsolidated affiliates. EFS Midstream is obligated to construct midstream assets in the Eagle Ford Shale area. The majority of the construction of the midstream assets has been completed. Eleven of the 13 planned central gathering plants were completed as of December 31, 2014. EFS Midstream is providing gathering, treating and transportation services for the Company during a 20-year contractual term.

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PIONEER NATURAL RESOURCES COMPANY

During November 2014, the Company announced that it is pursuing the divestment of its 50.1 percent share of EFS Midstream. The Company is marketing its equity investment in EFS Midstream and no assurance can be given that a sale will be completed in accordance with the Company's plans or on terms and at a price acceptable to the Company.
Raton Basin
The Raton Basin properties are located in the southeast portion of Colorado. The Company owns approximately 194,000 gross acres (174,000 net acres) in the center of the Raton Basin and produces CBM gas from the coal seams in the Vermejo and Raton formations from approximately 2,300 wells. See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the impairment charge recorded during 2013 to reduce the carrying value of the Company's gas properties in the Raton field.
West Panhandle
The West Panhandle properties are located in the panhandle region of Texas. These stable, long-lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no greater than 3,500 feet. The Company's gas has an average energy content of 1,400 Btu and is produced from approximately 700 wells on more than 246,000 gross acres (239,000 net acres) covering over 375 square miles. The Company controls 100 percent of the wells, production equipment, gathering system and the Fain gas processing plant for the field. As this field is characterized by very low reservoir pressure, Pioneer continually works to improve compressor and gathering system efficiency.
Divestitures Recorded as Discontinued Operations
Domestic. The Company completed the divestitures of its net assets in the Hugoton field in southwest Kansas, its net assets in the Barnett Shale field in North Texas and 100 percent of the capital stock in Pioneer Alaska in September 2014, September 2014 and April 2014, respectively.
The Company has reflected its Hugoton, Barnett Shale and Pioneer Alaska results of operations as discontinued operations in the accompanying consolidated statements of operations. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's divestitures of its Hugoton and Barnett Shale field assets and Pioneer Alaska.
International. During August 2012, the Company completed the sale of Pioneer South Africa to an unaffiliated third party. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the sale of Pioneer South Africa. As a result of this sale, the Company no longer has operations outside the United States.
Selected Oil and Gas Information
The following tables set forth selected oil and gas information for the Company as of and for each of the years ended December 31, 2014, 2013 and 2012. Because of normal production declines, increased or decreased drilling activities and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.
Production, price and cost data. The price that the Company receives for the oil and gas it produces is largely a function of market supply and demand. Demand is affected by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or gas can result in substantial price volatility. Historically, commodity prices have been volatile and the Company expects that volatility to continue in the future. If the recent decline in oil and gas prices were to persist, or if such prices were to decline further, or if the Company experienced poor drilling results, it could have a material adverse effect on the Company's financial position, results of operations, cash flows, quantities of oil and gas reserves that may be economically produced and the Company's ability to access capital markets.
The following tables set forth production, price and cost data with respect to the Company's properties for 2014, 2013 and 2012. These amounts represent the Company's historical results from operations without making pro forma adjustments for any acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not match the proved reserve volume tables in the "Unaudited Supplementary Information" section included in "Item 8. Financial Statements and Supplementary Data" because field fuel volumes are included in the proved reserve volume tables.
 

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PRODUCTION, PRICE AND COST DATA
 
Year Ended December 31, 2014
 
Included in
Continuing Operations
 
Included in
Discontinued Operations
 
Total
 
Spraberry
Field
 
Eagle Ford Shale Field
 
Raton
Field
 
Total Company Fields
 
United States
 
 
Production information:
 
 
 
 
 
 
 
 
 
 
 
Annual sales volumes:
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
23,701

 
6,498

 
—

 
31,767

 
951

 
32,718

NGLs (MBbls)
7,504

 
4,939

 
—

 
14,106

 
1,655

 
15,761

Gas (MMcf)
29,608

 
32,733

 
45,373

 
123,860

 
13,826

 
137,686

Total (MBOE)
36,139

 
16,892

 
7,562

 
66,516

 
4,911

 
71,427

Average daily sales volumes:
 
 
 
 
 
 
 
 
 
 
 
Oil (Bbls)
64,935

 
17,802

 
—

 
87,034

 
2,605

 
89,639

NGLs (Bbls)
20,558

 
13,530

 
—

 
38,646

 
4,535

 
43,181

Gas (Mcf)
81,117

 
89,679

 
124,310

 
339,341

 
37,881

 
377,222

Total (BOE)
99,012

 
46,279

 
20,718

 
182,237

 
13,453

 
195,690

Average prices:
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
86.51

 
$
81.84

 
$
—

 
$
85.29

 
$
93.10

 
$
85.51

NGL (per Bbl)
$
27.06

 
$
25.49

 
$
—

 
$
27.06

 
$
30.30

 
$
27.40

Gas (per Mcf)
$
3.81

 
$
4.35

 
$
4.05

 
$
4.10

 
$
4.30

 
$
4.12

Revenue (per BOE)
$
65.48

 
$
47.36

 
$
24.30

 
$
54.11

 
$
40.36

 
$
53.17

Average costs (per BOE):
 
 
 
 
 
 
 
 
 
 
 
Production costs:
 
 
 
 
 
 
 
 
 
 
 
Lease operating
$
11.42

 
$
2.68

 
$
6.72

 
$
8.27

 
$
8.54

 
$
8.29

Third-party transportation charges
0.40

 
3.88

 
3.41

 
1.68

 
2.33

 
1.73

Net natural gas plant/gathering
(1.23
)
 
0.03

 
2.25

 
(0.20
)
 
0.88

 
(0.12
)
Workover
0.94

 
0.33

 
—

 
0.65

 
0.40

 
0.64

Total
$
11.53

 
$
6.92

 
$
12.38

 
$
10.40

 
$
12.15

 
$
10.54

Production and ad valorem taxes:
 
 
 
 
 
 
 
 
 
 
 
Ad valorem
$
1.43

 
$
0.83

 
$
0.73

 
$
1.13

 
$
1.25

 
$
1.14

Production
3.18

 
1.22

 
0.36

 
2.18

 
1.11

 
2.11

Total
$
4.61

 
$
2.05

 
$
1.09

 
$
3.31

 
$
2.36

 
$
3.25

Depletion expense
$
20.41

 
$
11.49

 
$
4.48

 
$
15.19

 
$
2.10

 
$
14.29



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PRODUCTION, PRICE AND COST DATA - (continued)
 
 
Year Ended December 31, 2013
 
Included in
Continuing Operations
 
Included in
Discontinued Operations
 
 
 
Spraberry
Field
 
Eagle Ford Shale Field
 
Raton
Field
 
Total Company Fields
 
United States
 
Total
Production information:
 
 
 
 
 
 
 
 
 
 
 
Annual sales volumes:
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
19,176

 
5,014

 
—

 
25,377

 
2,078

 
27,455

NGLs (MBbls)
5,410

 
3,804

 
—

 
10,917

 
2,082

 
12,999

Gas (MMcf)
24,679

 
29,367

 
49,126

 
120,816

 
18,062

 
138,878

Total (MBOE)
28,699

 
13,712

 
8,188

 
56,431

 
7,170

 
63,601

Average daily sales volumes:
 
 
 
 
 
 
 
 
 
 
 
Oil (Bbls)
52,537

 
13,737

 
—

 
69,527

 
5,693

 
75,220

NGLs (Bbls)
14,822

 
10,421

 
—

 
29,910

 
5,705

 
35,615

Gas (Mcf)
67,614

 
80,458

 
134,591

 
331,003

 
49,484

 
380,487

Total (BOE)
78,627

 
37,568

 
22,432

 
154,604

 
19,645

 
174,249

Average prices:
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
93.30

 
$
91.74

 
$
—

 
$
92.62

 
$
98.81

 
$
93.09

NGL (per Bbl)
$
30.34

 
$
26.72

 
$
—

 
$
29.99

 
$
28.76

 
$
29.79

Gas (per Mcf)
$
3.23

 
$
3.63

 
$
3.27

 
$
3.39

 
$
3.53

 
$
3.41

Revenue (per BOE)
$
70.84

 
$
48.73

 
$
19.61

 
$
54.71

 
$
45.88

 
$
53.71

Average costs (per BOE):
 
 
 
 
 
 
 
 
 
 
 
Production costs:
 
 
 
 
 
 
 
 
 
 
 
Lease operating
$
11.38

 
$
3.23

 
$
6.25

 
$
8.19

 
$
11.64

 
$
8.58

Third-party transportation charges
0.24

 
3.86

 
3.02

 
1.59

 
1.43

 
1.57

Net natural gas plant/gathering
(1.11
)
 
0.01

 
1.90

 
(0.16
)
 
1.45

 
0.02

Workover
1.45

 
0.20

 
—

 
0.80

 
1.76

 
0.91

Total
$
11.96

 
$
7.30

 
$
11.17

 
$
10.42

 
$
16.28

 
$
11.08

Production and ad valorem taxes:
 
 
 
 
 
 
 
 
 
 
 
Ad valorem
$
1.70

 
$
0.65

 
$
0.42

 
$
1.15

 
$
2.01

 
$
1.25

Production
3.45

 
1.31

 
0.35

 
2.25

 
0.67

 
2.07

Total
$
5.15

 
$
1.96

 
$
0.77

 
$
3.40

 
$
2.68

 
$
3.32

Depletion expense
$
18.47

 
$
8.80

 
$
18.97

 
$
15.05

 
$
16.47

 
$
15.20



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PIONEER NATURAL RESOURCES COMPANY


PRODUCTION, PRICE AND COST DATA - (continued)
 
  
Year Ended December 31, 2012
 
Included in
Continuing Operations
 
Included in
Discontinued Operations
 
 
  
Spraberry
Field
 
Eagle Ford Shale Field
 
Raton
Field
 
Total Company Fields
 
United States
 
South Africa
 
Total
Production information:
 
 
 
 
 
 
 
 
 
 
 
 
 
Annual sales volumes:
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (MBbls)
16,096

 
3,613

 
—

 
20,922

 
2,006

 
157

 
23,085

NGLs (MBbls)
4,451

 
2,683

 
—

 
8,988

 
1,925

 
—

 
10,913

Gas (MMcf)
21,345

 
23,182

 
54,822

 
120,497

 
17,986

 
3,784

 
142,267

Total (MBOE)
24,104

 
10,160

 
9,137

 
49,993

 
6,928

 
787

 
57,708

Average daily sales volumes:
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (Bbls)
43,978

 
9,871

 
—

 
57,165

 
5,480

 
428

 
63,073

NGLs (Bbls)
12,160

 
7,332

 
—

 
24,557

 
5,259

 
—

 
29,816

Gas (Mcf)
58,319

 
63,338

 
149,787

 
329,228

 
49,141

 
10,340

 
388,709

Total (BOE)
65,858

 
27,759

 
24,965

 
136,593

 
18,929

 
2,151

 
157,673

Average prices, including hedge results and amortization of deferred VPP revenue (a):
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
90.57

 
$
93.84

 
$
—

 
$
90.67

 
$
93.20

 
$
108.62

 
$
91.01

NGL (per Bbl)
$
32.23

 
$
31.81

 
$
—

 
$
34.08

 
$
32.22

 
$
—

 
$
33.75

Gas (per Mcf)
$
2.58

 
$
2.81

 
$
2.41

 
$
2.56

 
$
2.84

 
$
8.50

 
$
2.75

Revenue (per BOE)
$
68.72

 
$
48.18

 
$
14.48

 
$
50.24

 
$
43.31

 
$
62.48

 
$
49.57

Average prices, excluding hedge results and amortization of deferred VPP revenue (a):
 
 
 
 
 
 
 
 
 
 
 
 
 
Oil (per Bbl)
$
87.95

 
$
93.84

 
$
—

 
$
88.81

 
$
93.20

 
$
108.62

 
$
89.32

NGL (per Bbl)
$
32.23

 
$
31.81

 
$
—

 
$
34.08

 
$
32.22

 
$
—

 
$
33.75

Gas (per Mcf)
$
2.58

 
$
2.81

 
$
2.41

 
$
2.56

 
$
2.84

 
$
8.50

 
$
2.75

Revenue (per BOE)
$
66.97

 
$
48.18

 
$
14.48

 
$
49.46

 
$
43.31

 
$
62.48

 
$
48.90

Average costs (per BOE):
 
 
 
 
 
 
 
 
 
 
 
 
 
Production costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
Lease operating
$
11.33

 
$
3.21

 
$
6.47

 
$
8.15

 
$
11.36

 
$
2.86

 
$
8.46

Third-party transportation charges
0.17

 
3.00

 
3.12

 
1.33

 
1.15

 
—

 
1.29

Net natural gas plant/gathering
(0.49
)
 
—

 
1.82

 
0.27

 
1.93

 
—

 
0.47

Workover
1.71

 
0.08

 
—

 
0.87

 
0.69

 
—

 
0.84

Total
$
12.72

 
$
6.29

 
$
11.41

 
$
10.62

 
$
15.13

 
$
2.86

 
$
11.06

Production and ad valorem taxes:
 
 
 
 
 
 
 
 
 
 
 
 
 
Ad valorem
$
1.78

 
$
0.71

 
$
0.17

 
$
1.13

 
$
2.16

 
$
—

 
$
1.24

Production
3.47

 
2.00

 
0.11

 
2.25

 
0.53

 
—

 
2.01

Total
$
5.25

 
$
2.71

 
$
0.28

 
$
3.38

 
$
2.69

 
$
—

 
$
3.25

Depletion expense
$
15.58

 
$
5.51

 
$
19.52

 
$
13.14

 
$
17.03

 
$
—

 
$
13.42

 _____________________
(a)
The Company recorded the amortization of deferred VPP revenue at a field level but did not record the results of its hedging activities at a field level. As of December 31, 2012, the Company had no further obligation to deliver oil under the VPP and did not have any hedging activities.

 

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PIONEER NATURAL RESOURCES COMPANY

Productive wells. Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. One or more completions in the same well bore are counted as one well. Any well in which one of the multiple completions is an oil completion is classified as an oil well.
The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of December 31, 2014:
PRODUCTIVE WELLS
 
Gross Productive Wells
 
Net Productive Wells
Oil
 
Gas
 
Total
 
Oil
 
Gas
 
Total
7,132

 
3,706

 
10,838

 
6,318

 
3,351

 
9,669

Leasehold acreage. The following table sets forth information about the Company's developed, undeveloped and royalty leasehold acreage as of December 31, 2014:
LEASEHOLD ACREAGE
 
Developed Acreage
 
Undeveloped Acreage
 
Royalty Acreage
Gross Acres
 
Net Acres
 
Gross Acres
 
Net Acres
 
1,321,885

 
1,114,056

 
1,020,417

 
753,603

 
244,615

 
The following table sets forth the expiration dates of the leases on the Company's gross and net undeveloped acres as of December 31, 2014:
 
 
Acres Expiring (a)
 
Gross
 
Net
2015
94,708

 
70,523

2016
711,401

 
501,741

2017
105,736

 
76,772

2018
78,328

 
77,761

2019
4,421

 
3,595

Thereafter
25,823

 
23,211

Total
1,020,417

 
753,603

 _____________________
(a)
Acres expiring are based on contractual lease maturities.

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PIONEER NATURAL RESOURCES COMPANY

Drilling and other exploratory and development activities. The following table sets forth the number of gross and net wells drilled by the Company during 2014, 2013 and 2012 that were productive or dry holes. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells compared to the costs of dry holes.
DRILLING ACTIVITIES
 
 
Gross Wells
 
Net Wells
 
Year Ended December 31,
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
2014
 
2013
 
2012
Productive wells:
 
 
 
 
 
 
 
 
 
 
 
Development
309

 
444

 
659

 
258

 
382

 
595

Exploratory
330

 
244

 
223

 
239

 
164

 
144

Dry holes:
 
 
 
 
 
 
 
 
 
 
 
Development
—

 
1

 
10

 
—

 
1

 
6

Exploratory
5

 
9

 
6

 
5

 
6

 
6

Total
644

 
698

 
898

 
502

 
553

 
751

Success ratio (a)
99
%
 
99
%
 
98
%
 
99
%
 
99
%
 
98
%
 ______________________
(a)
Represents the ratio of those wells that were successfully completed as producing wells or wells capable of producing to total wells drilled and evaluated.
 
Present activities. The following table sets forth information about the Company's wells that were in process of being drilled as of December 31, 2014:
 
 
Gross Wells
 
Net Wells
Development
54

 
39

Exploratory
106

 
76

Total
160

 
115

 
ITEM 3.
LEGAL PROCEEDINGS
The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding legal proceedings involving the Company.
ITEM 4.
MINE SAFETY DISCLOSURES
The Company's sand mines are subject to regulation by the Federal Mine Safety and Health Administration under the Federal Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006. Information concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report filed on Form 10-K.  

 

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PIONEER NATURAL RESOURCES COMPANY

PART II

ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
The Company's common stock is listed and traded on the NYSE under the symbol "PXD." The Company's board of directors (the "Board") declared dividends to the holders of the Company's common stock of $0.04 per share during each of the first and third quarters of the years ended December 31, 2014 and 2013. The Board intends to consider the payment of dividends to the holders of the Company's common stock in the future. The declaration and payment of future dividends, however, will be at the discretion of the Board and will depend on, among other things, the Company's earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the Board deems relevant.
The following table sets forth quarterly high and low prices of the Company's common stock and dividends declared per share for the years ended December 31, 2014 and 2013:
 
 
High
 
Low
 
Dividends
Declared
Per Share
Year ended December 31, 2014
 
 
 
 
 
Fourth quarter
$
199.56

 
$
127.31

 
$
—

Third quarter
$
234.60

 
$
193.03

 
$
0.04

Second quarter
$
234.20

 
$
177.53

 
$
—

First quarter
$
205.89

 
$
163.90

 
$
0.04

Year ended December 31, 2013
 
 
 
 
 
Fourth quarter
$
227.42

 
$
172.60

 
$
—

Third quarter
$
190.15

 
$
146.19

 
$
0.04

Second quarter
$
157.81

 
$
109.19

 
$
—

First quarter
$
133.68

 
$
107.29

 
$
0.04

On February 13, 2015, the last reported sales price of the Company's common stock, as reported in the NYSE composite transactions, was $157.85 per share.
As of February 13, 2015, the Company's common stock was held by 12,827 holders of record.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes the Company's purchases of its common stock during the three months ended December 31, 2014:
 
Period
Total Number of
Shares (or Units)
Purchased (a)
 
Average Price
Paid per Share
(or Unit)
 
Total Number of 
Shares (or Units) Purchased as
Part of Publicly
Announced Plans
or Programs
 
Approximate Dollar
Amount of Shares
that May Yet Be
Purchased under
Plans or Programs
October 2014
965

 
$
181.31

 
—

 
—

November 2014
55

 
$
179.63

 
—

 
—

December 2014
2,977

 
$
148.07

 
—

 
—

Total
3,997

 
$
156.53

 
—

 
$
—

 ______________________
(a)
Consists of shares purchased from employees in order for the employees to satisfy tax withholding payments related to share-based awards that vested during the period.
 

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PIONEER NATURAL RESOURCES COMPANY

ITEM 6.
SELECTED FINANCIAL DATA
The following selected consolidated financial data of the Company as of and for each of the five years ended December 31, 2014 should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Item 8. Financial Statements and Supplementary Data."
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
2011
 
2010
 
(in millions, except per share data)
Statements of Operations Data:
 
 
 
 
 
 
 
 
 
Oil and gas revenues
$
3,599

 
$
3,088

 
$
2,512

 
$
1,985

 
$
1,432

Total revenues and other income (a)
$
5,055

 
$
3,652

 
$
3,009

 
$
2,418

 
$
2,047

Total costs and expenses (a)(b)
$
3,458

 
$
4,226

 
$
2,177

 
$
1,863

 
$
1,277

Income (loss) from continuing operations
$
1,041

 
$
(361
)
 
$
544

 
$
380

 
$
514

Income (loss) from discontinued operations, net of tax (c)
$
(111
)
 
$
(438
)
 
$
(301
)
 
$
501

 
$
132

Net income (loss) attributable to common stockholders
$
930

 
$
(838
)
 
$
192

 
$
834

 
$
605

Income (loss) from continuing operations attributable to common stockholders per share:
 
 
 
 
 
 
 
 
 
Basic
$
7.17

 
$
(2.94
)
 
$
3.99

 
$
2.80

 
$
4.02

Diluted
$
7.15

 
$
(2.94
)
 
$
3.88

 
$
2.74

 
$
3.97

Net income (loss) attributable to common stockholders per share:
 
 
 
 
 
 
 
 
 
Basic
$
6.40

 
$
(6.16
)
 
$
1.54

 
$
7.01

 
$
5.14

Diluted
$
6.38

 
$
(6.16
)
 
$
1.50

 
$
6.88

 
$
5.08

Dividends declared per share
$
0.08

 
$
0.08

 
$
0.08

 
$
0.08

 
$
0.08

Balance Sheet Data (as of December 31):
 
 
 
 
 
 
 
 
 
Total assets
$
14,926

 
$
12,294

 
$
13,069

 
$
11,447

 
$
9,679

Long-term obligations
$
4,757

 
$
4,429

 
$
6,167

 
$
4,727

 
$
4,684

Total stockholders' equity
$
8,589

 
$
6,615

 
$
5,867

 
$
5,651

 
$
4,226

 ______________________
(a)
The Company recognized revenues from the sale of purchased oil and gas of $726 million, $334 million and $122 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company also recognized expenses related to purchased oil and gas of $703 million, $336 million and $120 million for the years ended December 31, 2014, 2013 and 2012, respectively. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's revenues and expenses from these transactions.
(b)
During 2013 and 2011, the Company recognized impairment charges of $1.5 billion related to dry gas properties in the Raton field and $354 million related to its Edwards and Austin Chalk net assets in South Texas, respectively. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's impairment charges.
(c)
The Company recognized impairment charges of (i) $305 million attributable to the Hugoton assets, Pioneer Alaska and the Barnett Shale assets in 2014, (ii) $729 million attributable to Pioneer Alaska and the Barnett Shale assets in 2013 and (iii) $533 million attributable to the Barnett Shale assets in 2012. During 2011, the Company recognized a gain on the sale of Pioneer Tunisia of $645 million. The results of these operations are classified as discontinued operations in accordance with GAAP. See Notes C and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's discontinued operations and related impairment charges.

 

44
Table of Contents
PIONEER NATURAL RESOURCES COMPANY

ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Financial and Operating Performance
Pioneer's financial and operating performance for 2014 included the following highlights:
•
Net income attributable to common stockholders was $930 million ($6.38 per diluted share) for the year ended December 31, 2014, as compared to net loss attributable to common stockholders of $838 million ($6.16 per diluted share) in 2013. The $1.8 billion increase in net income attributable to common stockholders is primarily comprised of a $1.4 billion increase in income from continuing operations and a $327 million decrease in loss from discontinued operations, net of tax.
The primary components of the increase in net income from continuing operations include:
•
a $708 million increase in net derivative gains, primarily as a result of changes in forward commodity prices and changes in the Company's portfolio of derivatives;
•
a $511 million increase in oil and gas revenues as a result of an 18 percent increase in total sales volumes, partially offset by a one percent decrease in average commodity prices received per BOE;
•
a $1.5 billion decrease in impairment charges related to the 2013 impairment recorded to reduce the carrying value of the Company's Raton gas field assets based on reductions in management's long-term gas price outlook (see Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Results of Operations" below); and
•
a $48 million decrease in other expense, primarily due to decreases in impairment of inventory and other assets; partially offset by
•
a $769 million increase in income taxes due to the increase in income from continuing operations before income taxes;
•
a $200 million decrease in gain on disposition of assets, primarily due to the gain recorded in 2013 on the Company's sale of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas to Sinochem;
•
a $158 million increase in DD&A expense, primarily attributable to the 18 percent increase in sales volumes, partially offset by the aforementioned impairment of proved properties in the Raton field during the fourth quarter of 2013, which reduced the Raton field's carrying value by $1.5 billion;
•
a $133 million increase in total oil and gas production costs and production and ad valorem taxes, primarily due to an 18 percent increase in sales volumes; and
•
a $37 million increase in general and administrative expenses primarily due to increases in contract labor and information technology related to process improvement initiatives and an increase in employee benefit costs.
The primary components of the decrease in the loss from discontinued operations, net of tax, include:
•
a $424 million decrease in impairment provisions associated with the sales of Pioneer Alaska and the Company's Barnett Shale field and Hugoton field assets ($305 million) as compared to the 2013 impairments of Pioneer Alaska and the Company's Barnett Shale field assets included in discontinued operations ($729 million); partially offset by
•
a $138 million decrease in revenues and other income, primarily due to the sale of Pioneer Alaska in April 2014 and the Hugoton field assets and Barnett Shale field assets in September 2014.
•
Daily sales volumes from continuing operations increased on a BOE basis by 18 percent to 182,237 BOEPD during 2014, as compared to 154,604 BOEPD during 2013, primarily due to the success of the Company's drilling programs;
•
Average reported oil and NGL prices from continuing operations decreased during 2014 to $85.29 per Bbl and $27.06 per Bbl, respectively, as compared to respective average reported prices of $92.62 per Bbl and $29.99 per Bbl during 2013. Average reported gas prices from continuing operations increased during 2014 to $4.10 per Mcf, as compared to an average reported price of $3.39 per Mcf during 2013;
•
Net cash provided by operating activities increased by 10 percent to $2.4 billion for 2014, as compared to $2.1 billion during 2013, primarily due to the increases in oil, NGL and gas sales volumes, partially offset by a $65 million decrease in cash receipts on settled derivative instruments; and
•
As of December 31, 2014, the Company's net debt to book capitalization declined to 16 percent, as compared to 25 percent as of December 31, 2013, primarily due to (i) the April 2014 completion of the sale of Pioneer Alaska for $267 million of cash proceeds, (ii) the September 2014 completion of the sales of the Company's Hugoton and Barnett Shale net assets for cash proceeds of $328 million and $150 million, respectively, and (iii) the November 2014 issuance of 5.75 million shares of the Company's common stock for $980 million of cash proceeds, net of associated underwriting and offering expenses.

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PIONEER NATURAL RESOURCES COMPANY

Significant Events
Commodity prices.  North American oil prices had been fairly stable during the past three years despite the significant increase in United States oil production from unconventional shale plays. The growth in North American oil production had been offset by reduced oil imports, keeping supply and demand fairly balanced in the United States. On an international level, the geopolitical factors negatively impacting international oil supplies were offset by the decline in United States imports, resulting in generally stable world oil prices. During the second half of 2014, however, as United States production continued to surge, worldwide demand was sluggish, reflecting the decline in the Chinese growth rate, the lingering recession in Europe and weaker economic performance in other regions, resulting in a worldwide oversupply and oil price weakness. During the fourth quarter of 2014, members of the OPEC decided to maintain production quotas at current levels despite production outpacing demand. This caused oil prices, which had already been declining, to decrease significantly in December 2014. The market oversupply of oil is expected to continue in 2015, with oil prices expected to remain under pressure. The growth of unconventional shale drilling has also substantially increased the supply of NGLs, resulting in a significant decline in NGL component prices as the supply of such products has grown. While more export facilities have been built and NGL exports are increasing, the overall United States demand for NGL products has not kept pace with the supply of such products; consequently, prices for NGL products have generally declined over the past three years. North American gas prices have remained volatile and they trended lower from 2009 through 2012, but improved steadily throughout 2013 and 2014 before dropping significantly in the fourth quarter of 2014. The decline in North American gas prices from 2009 through 2012 was primarily a result of significant discoveries of gas and associated gas reserves in United States gas, oil and liquid-rich shale plays, combined with the warmer than normal winters, which resulted in gas storage levels being at historically high levels, and minimal economic demand growth in the United States. The increases in gas prices during the latter part of 2013 and the majority of 2014 were primarily related to reduced drilling activity in gas shale plays and demand increases as a result of colder late 2013 and early 2014 winter weather, which reduced storage levels. The recent gas price decrease during the fourth quarter of 2014 reflects expectations for a warmer than normal winter, which is expected to result in gas storage levels being higher than normal at the end of the winter draw season and an expectation that there will be an oversupply of gas during 2015.
These circumstances have led to a dramatic decrease in drilling activity in the industry and have reduced the demand for drilling rigs, oilfield supplies, drill pipe and utilities, for which prices had reached very high levels during a period of high utilization in 2014. Although these costs have begun to decline, their declines significantly lag behind the declines in oil, NGL and gas prices. As a result of these circumstances, the Company experienced significant operating margin deterioration during the fourth quarter of 2014 and such deterioration has continued into 2015. The duration and magnitude of the commodity price declines and the timing and amount of cost reductions cannot be predicted.
 Low price environment initiatives. As a result of the significant drop in commodity prices, the Company has implemented initiatives to reduce capital spending, operating costs and general and administrative expenses to minimize spending in excess of estimated cash flows for 2015 and to maintain significant financial flexibility. This plan includes reducing drilling and infrastructure development activities until margins improve as a result of (i) increased commodity prices and/or (ii) decreased well costs.
 Pioneer is in the process of reducing its rig activity to 16 horizontal rigs drilling by the end of February 2015. The Company is continuing to work with drilling and service providers to reduce drilling and completion costs. To date, Pioneer has achieved reductions of approximately ten percent in drilling and completion costs, as compared to 2014 average well costs, and is targeting an additional ten percent reduction. Rigs have been terminated or stacked in the Spraberry/Wolfcamp and the Eagle Ford Shale areas. The Company's asset teams are also implementing initiatives to reduce controllable production costs, including costs associated with fuel surcharges, electricity supply, water disposal and compression rental.
In addition to the cost initiatives, the Company is also implementing the following initiatives to gain operating efficiencies:
•
completion optimization in the Spraberry/Wolfcamp area where the testing of increased clusters per stage and optimized fluid chemistry and proppant concentrations continue to be encouraging;
•
modified three-string and two-string casing design in the Upper Wolfcamp B and Wolfcamp A intervals; and
•
dissolvable plug technologies in the Spraberry/Wolfcamp and Eagle Ford Shale areas to reduce or eliminate coil tubing drillouts after fracture stimulations.
 In 2015, the Company expects capital spending for drilling operations to total $1.6 billion (excluding acquisitions, effects of asset retirement obligations, capitalized interest and geological and geophysical general and administrative costs). Approximately 75 percent of this amount is for horizontal drilling, primarily in the Spraberry/Wolfcamp and Eagle Ford Shale areas. The Company also expects to spend $250 million on other property and equipment in 2015, principally related to water infrastructure, vertical integration and facilities.

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First Quarter 2015 Outlook
Based on current estimates, the Company expects that first quarter 2015 production will average 192,000 to 197,000 BOEPD. First quarter guidance reflects an estimated production loss of 3,000 BOEPD in the Spraberry/Wolfcamp area due heavy icing and low temperatures during January that resulted in extensive power outages, facility freeze-ups, trucking curtailments and limited access to production and drilling facilities. In addition, the forecasted production for the quarter reflects reduced NGL production volumes of approximately 4,000 BOEPD due to not recovering ethane since it has a higher value if left in the gas stream.
First quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average $13.25 to $15.25 per BOE, based on current NYMEX strip prices for oil and gas. DD&A expense is expected to average $16.00 to $18.00 per BOE.
Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and administrative expense is expected to be $78 million to $83 million. Interest expense is expected to be $45 million to $50 million, and other expense is expected to be $30 million to $40 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 million.
The Company's first quarter effective income tax rate is expected to range from 35 percent to 40 percent, assuming current capital spending plans and no significant derivative MTM changes in the Company's derivative position. Cash income taxes are expected to be $1 million to $5 million and are primarily attributable to state taxes.
2015 Capital Budget
Pioneer's capital program for 2015 totals $1.85 billion, consisting of $1.6 billion for drilling operations, including budgeted land capital for existing assets, and $250 million for other property and equipment. The 2015 budget excludes acquisitions, asset retirement obligations, capitalized interest, and geological and geophysical general and administrative expense.
The 2015 drilling capital of $1.6 billion continues to be focused on oil- and liquids-rich drilling, with substantially all of the capital allocated to the Spraberry field and the Eagle Ford Shale play. The following is the forecasted spending by asset area:
•
Spraberry field - $1.17 billion, including (i) $1.05 billion of capital in the northern Spraberry/Wolfcamp acreage, which includes $735 million of horizontal drilling capital, $20 million of vertical drilling capital and $295 million for infrastructure, gas processing facilities and land and (ii) $120 million for drilling and facilities capital in the southern Wolfcamp joint interest area;
•
Eagle Ford Shale - $390 million, including $335 million of horizontal drilling capital and $55 million for facilities and land; and
•
Other spending - $40 million for other existing assets.
Pioneer's budgeted expenditures for other property and equipment in 2015 include:
•
Vertical integration capital - $185 million;
•
Buildings and other facilities - $50 million; and
•
Vehicles and other equipment - $15 million.

The 2015 capital budget is expected to be funded from a combination of operating cash flow, cash and cash equivalents on hand, and, if necessary, borrowings under the Company's credit facility or proceeds from planned divestitures.
Acquisitions
During 2014, 2013 and 2012, the Company spent $104 million, $76 million and $158 million, respectively, to acquire primarily undeveloped acreage for future exploitation and exploration activities. The 2014, 2013 and 2012 acquisitions primarily increased the Company's acreage positions in the West Texas Spraberry field. During 2013, the Company completed the acquisition of all of the outstanding common units of Pioneer Southwest not already owned by the Company in exchange for 0.2325 of a share of common stock of the Company per Pioneer Southwest common unit. Additionally, in 2012, the Company acquired Premier Silica for $297 million. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's acquisitions.
Divestitures and Discontinued Operations
Hugoton. In September 2014, the Company completed the sale of its net assets in the Hugoton field in southwest Kansas for cash proceeds of $328 million, including normal closing adjustments.

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Barnett Shale. During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. In September 2014, the Company completed the sale of its Barnett Shale net assets for cash proceeds of $150 million, including normal closing adjustments.
Pioneer Alaska. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in Pioneer Alaska. In April 2014, the Company completed the sale of Pioneer Alaska for cash proceeds of $267 million, including normal closing and other adjustments.
Pioneer South Africa. During the first quarter of 2012, the Company agreed to sell its net assets in Pioneer South Africa to an unaffiliated third party, effective January 1, 2012, for $60 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for cash proceeds of $16 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale.
The Company has reflected its Hugoton, Barnett Shale, Pioneer Alaska and Pioneer South Africa results of operations as discontinued operations in the accompanying consolidated statements of operations.
Sendero. During December 2013, the Company committed to a plan to sell the Company's majority interest in Sendero to Sendero's minority interest owner. At December 31, 2013, the assets and liabilities of Sendero were classified as held for sale at their estimated fair value. In March 2014, the Company completed the sale of Sendero for cash proceeds of $31 million. As part of the sales agreement, the Company committed to lease from Sendero 12 vertical rigs through December 31, 2015 and eight vertical rigs in 2016.
Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for total consideration of $1.8 billion. In May 2013, the Company completed the sale for net cash proceeds of $624 million, resulting in a gain of $181 million. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play. At December 31, 2014, the unused carry balance totaled $575 million.
See Notes C and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's divestitures, impairments and discontinued operations.

Results of Operations
Oil and gas revenues. Oil and gas revenues from continuing operations totaled $3.6 billion, $3.1 billion and $2.5 billion during 2014, 2013 and 2012, respectively.
The increase in 2014 oil and gas revenues relative to 2013 is reflective of 25 percent, 29 percent and three percent increases in oil, NGL and gas sales volumes, respectively, and a 21 percent increase in average reported gas prices. Partially offsetting the effects of these increases were declines of eight percent and 10 percent in average reported oil and NGL prices, respectively.
The increase in 2013 oil and gas revenues relative to 2012 is reflective of 22 percent, 22 percent and one percent increases in oil, NGL, and gas sales volumes, respectively, and two percent and 32 percent increases in average reported oil and gas prices, respectively. Partially offsetting the effects of these increases was a decline of 12 percent in average reported NGL prices.
The following table provides average daily sales volumes from continuing operations for 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Oil (Bbls)
87,034

 
69,527

 
57,165

NGLs (Bbls)
38,646

 
29,910

 
24,557

Gas (Mcf)
339,341

 
331,003

 
329,228

Total (BOE)
182,237

 
154,604

 
136,593

Average daily BOE sales volumes from continuing operations in 2014 and 2013 increased by 18 percent and 13 percent, respectively, as compared to the daily sales volumes in the respective prior years, principally due to the Company's successful drilling programs.

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Production for the year ended December 31, 2013 was negatively impacted by approximately 600 BOEPD related to gas processing capacity limitations that were resolved in mid-April and by approximately 1,500 BOEPD related to severe winter weather during the fourth quarter.
The following table provides average daily sales volumes from discontinued operations by geographic area and in total during 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Oil (Bbls):
 
 
 
 
 
United States
2,605

 
5,693

 
5,480

South Africa
—

 
—

 
428

Worldwide
2,605

 
5,693

 
5,908

NGL (Bbls):
 
 
 
 
 
United States
4,535

 
5,705

 
5,259

Gas (Mcf):
 
 
 
 
 
United States
37,881

 
49,484

 
49,141

South Africa
—

 
—

 
10,340

Worldwide
37,881

 
49,484

 
59,481

Total (BOE):
 
 
 
 
 
United States
13,453

 
19,645

 
18,929

South Africa
—

 
—

 
2,151

Worldwide
13,453

 
19,645

 
21,080


The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities. The following table provides the Company's average prices from continuing operations for 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012 (a)
Oil (per Bbl)
$
85.29

 
$
92.62

 
$
90.67

NGL (per Bbl)
$
27.06

 
$
29.99

 
$
34.08

Gas (per Mcf)
$
4.10

 
$
3.39

 
$
2.56

Total (per BOE)
$
54.11

 
$
54.71

 
$
50.24

 ____________________
(a)
For the year ended December 31, 2012, the Company's average realized oil price per Bbl was $88.81 and the average realized total price per BOE was $49.46. The average realized price does not include the impact of transfers of the Company's deferred hedge gains and losses from Accumulated Other Comprehensive Income ("AOCI-Hedging") and the amortization of deferred VPP revenue. During the year ended December 31, 2012, the Company transferred $3 million of deferred oil hedge losses from AOCI-Hedging to oil revenue. The transfer represented all of the remaining AOCI-Hedging transfers to earnings. Amortization of deferred VPP revenue increased oil revenues by $42 million during the year ended December 31, 2012. As of December 31, 2012, all VPP production volumes had been delivered and there are no further obligations under VPP contracts.
Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company's areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming responsibility to deliver the commodities sold. Deficiency payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for further information on transportation commitment charges.
Interest and other income. The Company's interest and other income from continuing operations was $9 million and $17 million during 2014 and 2013, respectively, and a loss of $1 million in 2012. The $8 million decrease during 2014, as compared

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to 2013, is primarily attributable to an $11 million increase between periods in the loss attributable to vertical integration services provided to third-party working interest owners in wells owned and operated by the Company and a $3 million decrease in deferred compensation plan income, partially offset by a $6 million increase in equity in earnings of EFS Midstream. The $18 million increase during 2013, as compared to 2012, was primarily attributable to a $7 million reduction in losses from vertical integration services, a $5 million increase in equity in earnings of EFS Midstream and a $4 million increase in deferred compensation plan income. See Note M of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's interest and other income.
Derivative gains, net. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts in order to (i) reduce the effect of price volatility on the commodities the Company produces, sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. In 2009, the Company discontinued hedge accounting on all of its then-existing derivative contracts. Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge accounting were recorded as a component of AOCI-Hedging in the equity section of the Company's consolidated balance sheets, and were transferred to earnings during the same periods in which the hedged transactions were recognized in the Company's earnings. Since 2009, the Company has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur. All deferred oil hedge losses were transferred from AOCI-Hedging to earnings during the year ended December 31, 2012. Transfers of deferred hedge gains and losses associated with oil cash flow hedges from AOCI-Hedging to oil revenues for the year ended December 31, 2012 resulted in a decrease of $3 million to oil revenue.
The following table summarizes the Company's net derivative gains or losses for the years ending December 31, 2014, 2013 and 2012 (in millions):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Noncash changes in fair value:
 
 
 
 
 
Oil derivative gains (losses)
$
514

 
$
(19
)
 
$
218

NGL derivative gains (losses)
4

 
(1
)
 
1

Gas derivative gains (losses)
91

 
(154
)
 
(290
)
Marketing derivative gains
3

 
—

 
—

Interest rate derivative gains (losses)
(3
)
 
10

 
6

Total noncash derivative gains (losses), net
609

 
(164
)
 
(65
)
Net cash receipts (payments) on settled derivative instruments:
 
 
 
 
 
Oil derivative receipts
104

 
12

 
4

NGL derivative receipts
8

 
1

 
13

Gas derivative receipts (payments)
(27
)
 
155

 
403

Diesel derivative receipts
—

 
—

 
3

Interest rate derivative receipts (payments)
18

 
—

 
(28
)
Total cash receipts on settled derivative instruments, net
103

 
168

 
395

Total derivative gains, net
$
712

 
$
4

 
$
330

The Company's open derivative contracts are subject to continuing market risk. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's derivative contracts.
Gain on disposition of assets, net. The Company recorded net gains on the disposition of assets of $9 million, $209 million and $46 million during 2014, 2013 and 2012, respectively.
During 2013, the Company's gains on disposition of assets included a $181 million gain on the sale of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas to Sinochem and a gain of $22 million on the sale of the Company's interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations. During 2012, the Company recorded a $43 million gain on the sale of a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale field.
Oil and gas production costs. The Company's oil and gas production costs from continuing operations totaled $693 million, $588 million and $532 million during 2014, 2013 and 2012, respectively. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while third-

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party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from gathering and processing of third party gas in Company-owned facilities.
Total oil and gas production costs per BOE for the year ended December 31, 2014 did not substantially change as compared to 2013. During 2013, total production costs per BOE decreased by two percent as compared to 2012. The decrease in production costs per BOE during 2013 was primarily reflective of a $0.43 per BOE decrease in net natural gas plant charges as a result of higher gas prices being realized on third-party volumes that are retained as processing fees in Company-owned facilities. Partially offsetting the decrease in per BOE net natural gas plant charges was a $0.26 per BOE increase in third-party transportation charges, primarily associated with increasing Eagle Ford Shale sales volumes.
The following table provides the components of the Company's total production costs per BOE for 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Lease operating expenses
$
8.27

 
$
8.19

 
$
8.15

Third-party transportation charges
1.68

 
1.59

 
1.33

Net natural gas plant/gathering charges
(0.20
)
 
(0.16
)
 
0.27

Workover costs
0.65

 
0.80

 
0.87

Total production costs
$
10.40

 
$
10.42

 
$
10.62

Production and ad valorem taxes. The Company recorded production and ad valorem taxes from continuing operations of $220 million during 2014, as compared to $192 million and $169 million for 2013 and 2012, respectively. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices. Production and ad valorem taxes on a per BOE basis have been relatively stable since 2012.
The following table provides the Company's production and ad valorem taxes per BOE from continuing operations and total production and ad valorem taxes per BOE from continuing operations for 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Production taxes
$
2.18

 
$
2.25

 
$
2.25

Ad valorem taxes
1.13

 
1.15

 
1.13

Total ad valorem and production taxes
$
3.31

 
$
3.40

 
$
3.38

 Depletion, depreciation and amortization expense. The Company's total DD&A expense from continuing operations was $1.0 billion ($15.75 per BOE), $889 million ($15.75 per BOE), and $689 million ($13.78 per BOE) for 2014, 2013 and 2012, respectively. Depletion expense on oil and gas properties, the largest component of DD&A expense, was $15.19, $15.05 and $13.14 per BOE during 2014, 2013 and 2012, respectively.
During 2014, the one percent increase in per BOE depletion expense, as compared to that of 2013, is primarily due to (i) a decline in proved undeveloped reserves due to negative revisions of previous estimates during the fourth quarter of each of 2014 and 2013 (39 MMBOE and 231 MMBOE, respectively) to remove undeveloped vertical well locations that were no longer expected to be drilled as a result of the Company shifting its planned capital expenditures to higher-rate-of-return horizontal drilling, offset by (ii) the impairment of proved properties in the Raton field during the fourth quarter of 2013, which reduced the Raton field's carrying value by $1.5 billion.
During 2013, the 15 percent increase in per BOE depletion expense was primarily due to (i) capital expenditures to develop proved undeveloped locations, primarily in the Company's successful Spraberry and Eagle Ford Shale fields programs and (ii) a 22 percent decline in total proved reserves. The decline in total proved reserves is primarily comprised of the aforementioned negative revisions of previous estimates to remove undeveloped vertical well locations that were no longer expected to be drilled as the Company shifted its planned capital expenditures to higher-rate-of-return horizontal drilling, partially offset by a nine percent increase in proved developed reserves.
Impairment of oil and gas properties and other long-lived assets. The Company recorded impairment expense in continuing operations to reduce the carrying values of oil and gas properties by $1.5 billion during the year ended December 31, 2013. For the year ended December 31, 2014 and 2012, the Company did not have any impairment expense in continuing operations.

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The Company performs assessments of its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying values of those assets may not be recoverable. In order to perform these assessments, management uses various observable and unobservable inputs, including management's outlooks for (i) commodity prices, (ii) production costs, (iii) capital expenditures and (iv) production, based upon current estimates of proved reserves and risk-adjusted probable and possible reserves.
Management's commodity price outlooks represent longer-term outlooks that are developed based on third-party longer-term commodity futures price outlooks as of a measurement date ("Management's Price Outlooks"). During 2013 and 2012, declines in Management's Price Outlooks for gas provided indications of possible impairment of the Company's predominantly dry gas properties in the Raton field in southeastern Colorado and the Barnett Shale field in North Texas (classified as held for sale as of December 31, 2013), respectively. During the years ended December 31, 2014 and 2013, Management's Price Outlook for gas declined by six percent and 10 percent, respectively, and Management's Price Outlook for oil declined by 15 percent and seven percent, respectively. The trend of Management's Price Outlooks by year is as follows:
 
December 31, 2014
 
December 31, 2013
 
December 31, 2012
Management's gas outlook
$4.16
 
$4.43
 
$4.92
Management's oil outlook
$68.64
 
$80.40
 
$86.40
As a result of management's assessments, during 2013 and 2012, the Company recognized noncash impairment charges of $1.5 billion and $533 million to reduce the carrying values of the Company's Raton field assets and the Company's Barnett Shale field assets (which are classified as discontinued operations in the accompanying statements of operations), respectively, to their estimated fair values.
It is reasonably possible that the estimate of undiscounted future net cash flows may change in the future resulting in the need to impair the carrying values of the Company's properties. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves (ii) results of future drilling activities, (iii) Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields.
See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's impairment assessments.
Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expense and leasehold abandonments and other exploration expense from continuing operations for 2014, 2013 and 2012 (in millions):
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Geological and geophysical
$
86

 
$
76

 
$
66

Exploratory dry holes
27

 
6

 
9

Leasehold abandonments and other
64

 
15

 
22

 
$
177

 
$
97

 
$
97

During 2014, the Company's exploration and abandonment expense is primarily attributable to $86 million of geological and geophysical costs, of which $59 million is geological and geophysical administrative costs; $27 million of dry hole provisions, primarily associated with the Company's unproved acreage position in southeast Colorado; and $64 million of leasehold abandonment expense, which includes $50 million associated with the Company's unproved acreage position in southeast Colorado. During 2014, the Company completed and evaluated 335 exploration/extension wells, 330 of which were successfully completed as discoveries.
During 2013, the Company's exploration and abandonment expense was primarily attributable to $76 million of geological and geophysical costs, of which $57 million was geological and geophysical administrative costs; $6 million of dry hole provisions; and $15 million of leasehold abandonment expense, which included $14 million associated with the Company's unproved dry gas properties in the Eagle Ford Shale and other unproved property abandonments. During 2013, the Company completed and evaluated 253 exploration/extension wells, 244 of which were successfully completed as discoveries.

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During 2012, the Company's exploration and abandonment expense was primarily attributable to $66 million of geological and geophysical costs, of which $41 million was geological and geophysical administrative costs; $9 million of dry hole provisions; and $22 million of leasehold abandonment expense. The significant components of the Company's 2012 leasehold abandonment expense included $10 million in the Eagle Ford Shale area, $5 million in the Rockies area and $5 million in the Permian Basin. During 2012, the Company completed and evaluated 229 exploration/extension wells, 223 of which were successfully completed as discoveries.
General and administrative expense. General and administrative expense from continuing operations totaled $333 million, $296 million and $244 million during 2014, 2013 and 2012, respectively. The increase in 2014, as compared to 2013, is primarily due to increases of $7 million and $5 million in contract labor and information technology, respectively, related to process improvement initiatives and a $5 million increase in employee benefit costs.
The increase in general and administrative expense during 2013, as compared to 2012, was also primarily due to increases of $43 million and $3 million in compensation and occupancy expenses, respectively, related to staffing increases in support of the Company's capital expansion and integrated services initiatives. The $43 million increase in compensation expense included an $8 million increase in stock-based compensation expense associated with stock-based compensation liability awards ("Liability Awards") that are expected to be settled in cash on their vesting dates, primarily due to increases in the market value of the Company's common stock during 2013, and an $19 million increase in cash bonus expense payable to employees as a result of the accomplishments of the Company during 2013.
Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations from continuing operations was $12 million, $12 million and $8 million during 2014, 2013 and 2012, respectively. The 50 percent increase in accretion of discount on asset retirement obligations during 2013 was primarily due to additional well completions resulting from the Company's drilling activities. See Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's asset retirement obligations.
Interest expense. Interest expense was $184 million, $184 million and $204 million during 2014, 2013 and 2012, respectively. The weighted average interest rate on the Company's indebtedness for the year ended December 31, 2014 was 6.4 percent, as compared to 6.5 percent and 6.0 percent for the years ended December 31, 2013 and 2012, respectively.
The $20 million decrease in interest expense during 2013, as compared to 2012, was primarily due to a decrease of $19 million in noncash amortization of financing fees, debt issuance discounts and deferred hedge losses.
See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's long-term debt and interest expense.
Other expenses. Other expenses from continuing operations were $89 million during 2014, as compared to $137 million during 2013 and $114 million during 2012. The $48 million decrease in other expense during 2014, as compared to 2013, is primarily associated with (i) a $28 million decrease in inventory valuation allowances, (ii) a $25 million decrease in other property impairments, which in 2013 was associated with the planned sale of the Company's majority interest in Sendero and (iii) a $9 million decrease in contingency and environmental accrual adjustments, partially offset by (iv) a $8 million increase in terminated drilling rig contract charges and (v) a $7 million increase in firm transportation payments on excess pipeline capacity commitments.
The $23 million increase in other expense during 2013, as compared to 2012, was primarily associated with the aforementioned (i) $25 million impairment associated with the planned sale of the Company's majority interest in Sendero, (ii) a $31 million increase in inventory valuation allowances and (iii) a $9 million increase in contingency and environmental accrual adjustments, partially offset by (iv) a $23 million decrease in above market and idle drilling and well service equipment charges and (v) a $15 million decrease in terminated drilling rig contract charges.
See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's other expenses.
Income tax provision. The Company recognized an income tax provision attributable to earnings from continuing operations of $556 million during 2014, as compared to an income tax benefit of $213 million during 2013 and an income tax provision of $288 million during 2012. The Company's effective tax rates on earnings from continuing operations, excluding income from noncontrolling interest, for 2014, 2013 and 2012 were 35 percent, 35 percent and 37 percent, respectively, as compared to the combined United States federal and state statutory rates of approximately 36 percent.
See "Critical Accounting Estimates" below and Note O of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's income tax rates and attributes.

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Loss from discontinued operations, net of tax. The Company recognized losses from discontinued operations, net of tax, of $111 million, $438 million and $301 million in 2014, 2013 and 2012, respectively. Loss from discontinued operations, net of tax, includes the results of operations of the following divestitures prior to their sale:

•
The Hugoton field assets, which were placed into assets held for sale and discontinued operations in July 2014;
•
Pioneer Alaska, which was placed into assets held for sale and discontinued operations in December 2013;
•
The Barnett Shale field assets, which were placed into assets held for sale and discontinued operations in December 2013; and
•
Pioneer South Africa, which was placed into assets held for sale and discontinued operations in December 2011.
The changes between years in the losses recognized from discontinued operations, net of tax, are primarily due to the impairment charges recognized each year offset by the corresponding deferred tax benefit recognized associated with the impairment. The Company recognized impairment charges of (i) $305 million attributable to the Hugoton assets, Pioneer Alaska and the Barnett Shale assets in 2014, (ii) $729 million attributable to Pioneer Alaska and the Barnett Shale assets in 2013 and (iii) $533 million attributable to the Barnett Shale assets in 2012.
See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's discontinued operations.
Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interests was nominal in 2014, as compared to $39 million and $51 million for 2013 and 2012, respectively. In 2012 and 2013, the Company's net income attributable to noncontrolling interest was primarily associated with the net income of Pioneer Southwest. The decrease in net income attributable to noncontrolling interest in 2014, as compared to 2013, is due to the Company's acquisition of all outstanding common units of Pioneer Southwest not owned by the Company in December 2013.
The $12 million decrease in net income attributable to noncontrolling interest in 2013, as compared to 2012, was primarily due to decreases in Pioneer Southwest's noncash derivative gains, higher production costs and higher depletion expense, partially offset by increased revenues.
See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding Pioneer Southwest and the Company's noncontrolling interest in consolidated subsidiaries' net income.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas properties and related vertical integration assets and facilities, payments of contractual obligations, dividends and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, cash and cash equivalents on hand, proceeds from divestitures or external financing sources as discussed in "Capital resources" below. During 2015, the Company expects that it will be able to fund its needs for cash (excluding acquisitions, if any) with a combination of internally generated cash flows, cash and cash equivalents on hand and, if necessary, availability under the Company's credit facility or proceeds from the Company's planned divestiture of EFS Midstream, if successful. Although the Company expects that these sources of funding will be adequate to fund capital expenditures and dividend payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company's future needs or that planned divestitures will be completed in accordance with the Company's plans or on terms and at a price acceptable to the Company.
During 2015, the Company plans to continue to focus its capital spending primarily on liquids-rich drilling activities. The Company's 2015 capital budget totals $1.85 billion (excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs), consisting of $1.6 billion for drilling operations and $250 million for vertical integration, buildings and other plant and equipment additions. Based on the Company's current Management Price Outlooks, Pioneer expects its net cash flows from operating activities, cash and cash equivalents on hand and, if necessary, availability under the Company's credit facility or proceeds from the Company's planned divestiture of EFS Midstream, if successful, to be sufficient to fund its planned capital expenditures and contractual obligations.
Investing activities. Net cash used in investing activities during 2014 was $2.7 billion, as compared to net cash used in investing activities of $2.1 billion and $3.3 billion during 2013 and 2012, respectively. The increase in net cash flow used in investing activities during 2014, as compared to 2013, is primarily due to (i) a $604 million increase in additions to oil and gas properties, (ii) a $96 million increase in additions to other assets and other property and equipment and (iii) a $25 million decrease in distributions from EFS Midstream recognized as investing activities, partially offset by (iv) a $166 million increase in proceeds

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from disposition of assets, primarily due to $745 million of net cash proceeds from the 2014 divestitures of the Hugoton field assets, the Barnett Shale field assets and Pioneer Alaska, compared to $624 million of net cash proceeds from the May 2013 sale to Sinochem of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas. In addition to the aforementioned proceeds from disposition of assets, the Company's investing activities during the year ended December 31, 2014 were funded by net cash provided by operating activities and proceeds from the issuance of shares of its common stock.
The decrease in net cash flow used in investing activities during 2013, as compared to 2012, was primarily due to (i) a $615 million increase in proceeds from disposition of assets, which resulted from $624 million of net cash proceeds from the aforementioned sale to Sinochem (ii) a $297 million decrease in payments for acquisitions due to the acquisition of Premier Silica during 2012, (iii) a $119 million decrease in additions to oil and gas properties, partially due to the drilling carry being paid by Sinochem in the southern portion of the horizontal Wolfcamp Shale play, (iv) a $60 million decrease in additions to other assets and other property and equipment and (v) a $25 million distribution from EFS Midstream during December 2013. See "Results of Operations" above and Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding asset divestitures.
Dividends/distributions. During each of the years ended December 31, 2014, 2013 and 2012, the Board declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $12 million, $11 million and $10 million, respectively, of aggregate dividends. Future dividends are at the discretion of the Board, and, if declared, the Board may change the dividend amount based on the Company's liquidity and capital resources at the time.
During January, April, July and October of 2013 and 2012, the board of directors of the general partner of Pioneer Southwest declared quarterly distributions aggregating annually to $2.08 and $2.07 per limited partner unit, respectively. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $35 million during each of the years ended December 31, 2013 and 2012.
Off-balance sheet arrangements. From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2014, the material off-balance sheet arrangements and transactions that the Company has entered into include (i) operating lease agreements, (ii) drilling commitments (iii) firm purchase, transportation and fractionation commitments, (iv) open purchase commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, processing (primarily treating and fractionation) and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. See "Contractual obligations" below and Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information regarding the Company's off-balance sheet arrangements.
Contractual obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments (including commitments to pay day rates for drilling rigs), capital funding obligations, derivative obligations, firm transportation and fractionation commitments, minimum annual gathering, processing and transportation commitments and other liabilities (including postretirement benefit obligations). Other joint owners in the properties operated by the Company will incur portions of the costs represented by these commitments.

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The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2014:
 
 
Payments Due by Year
 
2015
 
2016 and 2017
 
2018 and 2019
 
Thereafter
 
(in millions)
Long-term debt (a)
$
—

 
$
940

 
$
450

 
$
1,300

Operating leases (b)
30

 
42

 
38

 
27

Drilling commitments (c)
303

 
310

 
34

 
—

Derivative obligations (d)
3

 
2

 
—

 
—

Purchase commitments (e)
263

 
—

 
—

 
—

Other liabilities (f)
42

 
56

 
50

 
144

Firm purchase, gathering, processing, transportation and fractionation commitments (g)
455

 
850

 
657

 
1,011

 
$
1,096

 
$
2,200

 
$
1,229

 
$
2,482

 _____________________
(a)
See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for information regarding estimated future interest payment obligations under long-term debt obligations. The amounts included in the table above represent principal maturities only.
(b)
See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's operating leases.
(c)
Drilling commitments represent future minimum expenditure commitments for drilling rig services and well commitments under contracts to which the Company was a party on December 31, 2014.
(d)
Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity and interest rate derivatives that were valued as of December 31, 2014. The ultimate settlement amounts of the Company's derivative obligations are unknown because they are subject to continuing market risk. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's derivative obligations.
(e)
Open purchase commitments primarily represent expenditure commitments for inventory, materials and other property and equipment ordered, but not received, as of December 31, 2014.
(f)
The Company's other liabilities represent current and noncurrent other liabilities that are comprised of postretirement benefit obligations, litigation and environmental contingencies, asset retirement obligations and other obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See Notes H, I and J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's postretirement benefit obligations, asset retirement obligations and litigation and environmental contingencies, respectively.
(g)
Firm purchase, gathering, processing, transportation and fractionation commitments represent take-or-pay agreements, which include contractual commitments to purchase sand and water to accommodate the Company's drilling operations and estimated fees on production throughput commitments and demand fees associated with volume delivery commitments, principally comprised of approximately 50,000 Bbls per day through August 2017 related to the Company's Permian Basin operations. The Company does not expect to be able to fulfill all of its short-term and long-term delivery obligations from projected production of available reserves; consequently, the Company plans to purchase third party volumes to satisfy its commitments if it is economic to do so; otherwise, it will pay demand fees for commitment shortfalls. See "Item 2. Properties" and Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's firm purchase, gathering, processing, transportation and fractionation commitments.
Capital resources. The Company's primary capital resources are cash and cash equivalents, net cash provided by operating activities, proceeds from divestitures and proceeds from financing activities (principally borrowings under the Company's credit facility or issuances of debt or equity securities). If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, and/or fund a portion of its capital expenditures using availability under the Company's credit facility, issue debt or equity securities or obtain capital from other sources, such as through sales of nonstrategic assets.
Operating activities. Net cash provided by operating activities for the years ended December 31, 2014, 2013 and 2012 was $2.4 billion, $2.1 billion and $1.8 billion, respectively. The increases in net cash flow provided by operating activities in both 2014

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and 2013 were primarily due to increases in oil and gas sales, partially offset by decreases in net cash receipts from derivative settlements.
Asset divestitures. During 2014, the Company's major asset sales included the sale of (i) the Company's Barnett Shale field net assets for cash proceeds of $150 million, (ii) the Company's Hugoton field net assets for cash proceeds of $328 million, (iii) Pioneer Alaska for cash proceeds of $267 million, (iv) Sendero for cash proceeds of $31 million (Sendero had $14 million of cash on hand at the time of the sale) and (v) proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million.
In January 2013, the Company signed an agreement with Sinochem to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for consideration of $1.8 billion. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $624 million, resulting in a gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play. During 2013, the Company also completed a sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38 million, which resulted in a gain of $22 million.
In January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale play to unaffiliated third parties for cash proceeds of $55 million, which resulted in a gain of $43 million. In addition, during the first quarter of 2012, the Company agreed to sell Pioneer South Africa to an unaffiliated third party for $60 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $16 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale, resulting in a gain of $29 million.
See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information regarding the Company's divestitures.
Financing activities. Net cash provided by financing activities during 2014 was $965 million, as compared to net cash provided by financing activities during 2013 and 2012 of $158 million and $1.1 billion, respectively. During 2014, the significant component of financing activities was the completion of an offering of 5.75 million shares of the Company's common stock at a per-share price, after underwriter and offering expenses, of $170.50 for a total of $980 million of realized net proceeds. During 2013, the significant components of financing activities included $1.1 billion of net payments on long-term debt, the Company's completion of an offering of 10.35 million shares of its common stock in February 2013 at a per-share price, after underwriting and offering expenses, of $123.76 for a total of $1.3 billion of realized net proceeds and $47 million of dividend payments and distributions to noncontrolling interests. During 2012, the significant components of financing activities included $1.2 billion of net borrowings on long-term debt and $46 million of dividend payments and distributions to noncontrolling interests.
The following provides a description of the Company's significant financing activities during 2014, 2013 and 2012:
•
During November 2014, the Company completed the sale of 5.75 million shares of its common stock for $980 million of net cash proceeds;
•
During December 2012 and March 2013, the Company's stock price met the price threshold that caused the Convertible Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued. On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six months ended June 30, 2013, holders of $479 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $1 million in principal and interest to redeem all Convertible Senior Notes that remained outstanding;
•
During February 2013, the Company completed the sale of 10.35 million shares of its common stock for $1.3 billion of net cash proceeds;
•
During December 2012, the Company amended its credit facility with a syndicate of financial institutions to increase the aggregate loan commitments to $1.5 billion from $1.25 billion and extend its maturity to December 2017; and
•
During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of $8 million of offering discounts and costs, of $592 million.

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See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the significant financing activities.
As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company cannot predict the timing or ultimate outcome of any such actions as they are subject to market conditions, among other factors. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.
Liquidity. The Company's principal sources of short-term liquidity are cash and cash equivalents and unused borrowing capacity under the Company's credit facility. As of December 31, 2014, the Company had no outstanding borrowings under the credit facility, leaving $1.5 billion of unused borrowing capacity. The Company was in compliance with all of its debt covenants. The Company's credit facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments, not to exceed .60 to 1.0, which is above the Company's December 31, 2014 ratio of .21 to 1.0. The Company also had cash on hand of $1.0 billion as of December 31, 2014. If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under the Company's credit facility, issuances of debt or equity securities or other sources, such as sales of nonstrategic assets. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that the combination of internal operating cash flows, cash and cash equivalents on hand and, if necessary, available capacity under the Company's credit facility or proceeds from the Company's planned divestiture of EFS Midstream, if successful, will be adequate to fund 2015 capital expenditures and dividend payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company's future needs or that planned divestitures will be completed in accordance with the Company's plans or on terms and at a price acceptable to the Company.
Debt ratings. The Company is rated as investment grade by three credit rating agencies. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies considers many factors in determining the Company's ratings, including: production growth opportunities, liquidity, debt levels, asset composition and proved reserve mix. A reduction in the Company's debt ratings could increase the interest rates that the Company incurs on credit facility borrowings and could negatively affect the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.
Book capitalization and current ratio. The Company's net book capitalization at December 31, 2014 was $10.2 billion, consisting of $1.0 billion of cash and cash equivalents, debt of $2.7 billion and stockholders' equity of $8.6 billion. The Company's debt to book capitalization decreased to 16 percent at December 31, 2014 from 25 percent at December 31, 2013, primarily due to an increase in cash and cash equivalents of $632 million. The Company's ratio of current assets to current liabilities increased to 1.49 to 1.00 at December 31, 2014, as compared to 1.38 to 1.00 at December 31, 2013, primarily due to the increases in cash on hand and derivative assets, partially offset by the decrease in net assets held for sale due to the sale of the Company's Barnett Shale assets in September 2014 and Pioneer Alaska in April 2014. 
Critical Accounting Estimates
The Company prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a comprehensive discussion of the Company's significant accounting policies. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of the Company's most critical accounting estimates, judgments and uncertainties that are inherent in the Company's application of GAAP.
Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore the land at the end of oil and gas production operations. The Company's removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a

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corresponding adjustment is generally made to the oil and gas property balance. See Notes B and I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's asset retirement obligations.
Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for oil and gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing activities than under the full cost method, particularly during periods of active exploration. The critical difference between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense. During 2014, 2013 and 2012, the Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of $177 million, $97 million and $97 million, respectively. During 2014, 2013 and 2012, the Company recognized exploration, abandonment, geological and geophysical expense from discontinued operations of $4 million, $54 million and $109 million, respectively, under the successful efforts method.
Proved reserve estimates. Estimates of the Company's proved reserves included in this Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:
•
the quality and quantity of available data;
•
the interpretation of that data;
•
the accuracy of various mandated economic assumptions; and
•
the judgment of the persons preparing the estimate.
The Company's proved reserve information included in this Report as of December 31, 2014, 2013 and 2012 was prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major properties. Estimates prepared by third parties may be higher or lower than those included herein.
Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.
It should not be assumed that the Standardized Measure included in this Report as of December 31, 2014 is the current market value of the Company's estimated proved reserves. In accordance with SEC requirements, the Company based the 2014 Standardized Measure on a twelve month average of commodity prices on the first day of the month and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See "Item 1A. Risk Factors," "Item 2. Properties" and Supplementary Information included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding estimates of proved reserves.
The Company's estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company's assessment of its proved properties and goodwill for impairment.
Impairment of proved oil and gas properties. The Company reviews its proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future recoverable proved and risk-adjusted probable and possible reserves, Management's Price Outlooks, production and capital costs expected to be incurred to recover the reserves; discount rates commensurate with the nature of the properties and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's impairment assessments.
Impairment of unproved oil and gas properties. At December 31, 2014, the Company carried unproved property costs of $159 million. Management assesses unproved oil and gas properties for impairment on a project-by-project basis. Management's impairment assessments include evaluating the results of exploration activities, Management's Price Outlooks and planned future sales or expiration of all or a portion of such projects.

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Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.
The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:
(i)
The well has found a sufficient quantity of reserves to justify its completion as a producing well.
(ii)
The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves to sanction the project or is noncommercial and is impaired. See Note F of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's suspended exploratory well costs.
Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets, if any, will be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and reassesses the likelihood that the Company's net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurance that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period.
Goodwill impairment. The Company reviews its goodwill for impairment at least annually. During the third and fourth quarters of 2014 and 2013, the Company performed qualitative assessments of goodwill to assess whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount as a basis for determining whether it was necessary to perform the two-step goodwill impairment test. The Company determined that it was not likely that the Company's goodwill was impaired. There is considerable judgment involved in estimating fair values, particularly in determining the valuation methodologies to utilize, the estimation of proved reserves as described above and the weighting of different valuation methodologies applied. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding goodwill and assessments of goodwill for impairment.
Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's commitments and contingencies.
Valuation of stock-based compensation. The Company calculates the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The Company utilizes (a) the Black-Scholes option pricing model to measure the fair value of stock options, (b) the closing stock price on the day prior to the date of grant for the fair value of restricted stock awards, (c) the closing stock price at the balance sheet date for restricted stock awards that are expected to be settled wholly or partially in cash on their vesting date and (d) the Monte Carlo simulation method for the fair value of performance unit awards. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's stock-based compensation.
Valuation of other assets and liabilities at fair value. The Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities that the Company periodically measures and records at fair value include trading securities, commodity derivative contracts and interest rate contracts. The Company also measures and discloses certain financial assets and liabilities at fair value, such as long-term debt. The valuation methods used by the Company to measure the fair values

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of these assets and liabilities require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the methods used by management to estimate the fair values of these assets and liabilities.
New Accounting Pronouncements
The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data."
 

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ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about financial instruments to which the Company was a party as of December 31, 2014, and from which the Company may incur future gains or losses from changes in commodity prices or interest rates.
The fair values of the Company's long-term debt and derivative contracts are determined based on observable inputs and utilizing the Company's valuation models and applications. As of December 31, 2014, the Company was a party to commodity swap contracts, interest rate swap contracts, commodity collar contracts and commodity collar contracts with short put options. See Notes D and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's fair value measurements and derivative contracts. The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during 2014:
 
 
Derivative Contract Net Assets (Liabilities)
 
Commodities
 
Interest Rate
 
Total
 
(in millions)
Fair value of contracts outstanding as of December 31, 2013
$
145

 
$
—

 
$
145

Changes in contract fair values
697

 
15

 
712

Contract maturities
(87
)
 
(4
)
 
(91
)
Contract terminations
2

 
(14
)
 
(12
)
Fair value of contracts outstanding as of December 31, 2014
$
757

 
$
(3
)
 
$
754

 
Quantitative Disclosures
Interest rate sensitivity. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and Capital Commitments, Capital Resources and Liquidity included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding the Company's outstanding debt and debt transactions.
The following table provides information about financial instruments to which the Company was a party as of December 31, 2014 and that are sensitive to changes in interest rates. The table presents debt maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions, and the aggregate estimated fair value of the Company's outstanding debt. For fixed rate debt, the weighted average interest rates represent the contractual fixed rates that the Company was obligated to periodically pay on the debt as of December 31, 2014. Although the Company had no outstanding variable rate debt as of December 31, 2014, the average variable contractual rates for its credit facility projected forward proportionate to the forward yield curve for LIBOR on February 13, 2015 is presented in the table below.
 
INTEREST RATE SENSITIVITY
DEBT OBLIGATIONS AND DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2014
 
 
Year Ending December 31,
 
 
 
 
 
Liability Fair
Value at
December 31,
 
2015
 
2016
 
2017
 
2018
 
2019
 
Thereafter
 
Total
 
2014
Total Debt:
(dollars in millions)
Fixed rate principal maturities (a)
$
—

 
$
455

 
$
485

 
$
450

 
$
—

 
$
1,300

 
$
2,690

 
$
2,938

Weighted average fixed interest rate
6.15
%
 
6.17
%
 
6.11
%
 
5.91
%
 
5.80
%
 
5.81
%
 
 
 
 
Weighted average variable interest rate
2.04
%
 
2.88
%
 
3.50
%
 
—
%
 
—
%
 
—
%
 
 
 
 
Interest Rate Swaps (b):
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Notional debt amount
$
300

 
$
—

 
$
—

 
$
—

 
$
—

 
$
—

 

 
$
3

Weighted average fixed rate payable (%)
2.44
%
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 _______________________

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(a)
Represents maturities of principal amounts excluding debt issuance discounts and net deferred fair value hedge losses.
(b)
As of December 31, 2014, the Company was a party to interest rate derivative contracts whereby the Company will receive the 10-year Treasury rate in exchange for paying a weighted average fixed rate of 2.43 percent on a notional amount of $200 million on June 30, 2015 and 2.46 percent on a notional amount of $100 million on September 15, 2015. During the period from January 1, 2015 through February 13, 2015, the Company entered into additional interest rate derivative contracts that expire on September 15, 2015 for a notional amount of $50 million with an average fixed rate payable of 2.20 percent in exchange for receiving the 10-year Treasury rate as of the expiration date.
Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of December 31, 2014. Although mitigated by the Company's derivative activities, declines in oil, NGL and gas prices would reduce the Company's revenues.
The Company manages commodity price risk with derivative contracts, such as swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum ("floor" or "long put") and maximum ("ceiling") prices on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company's realized price will exceed the variable market prices by the long put-to-short put price differential.
See Notes B, D and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of the accounting procedures followed by the Company relative to its derivative financial instruments and for specific information regarding the terms of the Company's derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.
 

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DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2014

 
Year Ending December 31,
 
Asset
Fair Value at
December 31,
 
2015
 
2016
 
2017
 
2014 (a)
 
 
 
 
 
 
 
(in millions)
Oil Derivatives:
 
 
 
 
 
 
 
Average daily notional Bbl volumes:
 
 
 
 
 
 
 
Swap contracts
82,000

 
—

 
—

 
$
430

Weighted average fixed price per Bbl
$
71.18

 
$
—

 
$
—

 
 
Collar contracts with short puts (b)(c)
13,767

 
73,000

 
—

 
$
204

Weighted average ceiling price per Bbl
$
101.36

 
$
96.46

 
$
—

 
 
Weighted average floor price per Bbl
$
86.82

 
$
85.47

 
$
—

 
 
Weighted average short put price per Bbl
$
75.73

 
$
74.35

 
$
—

 
 
Average forward NYMEX oil prices (d)
$
57.57

 
$
63.40

 
$
—

 
 
Rollfactor swap contracts (e)
36,575

 
—

 
—

 
$
11

Weighted average fixed price per Bbl
$
0.06

 
$
—

 
$
—

 
 
Average forward NYMEX rollfactor prices (d)
$
(1.17
)
 
$
—

 
$
—

 
 
NGL Derivatives:
 
 
 
 
 
 
 
Average daily notional Bbl volumes:
 
 
 
 
 
 
 
Swap contracts (f)(g)
—

 
4,000

 
—

 
$
5

Weighted average fixed price per Bbl
$
—

 
$
12.29

 
$
—

 
 
Average forward NGL prices (h)
$
—

 
$
9.21

 
$
—

 
 
Gas Derivatives:
 
 
 
 
 
 
 
Average daily notional MMBtu volumes:
 
 
 
 
 
 
 
Swap contracts
20,000

 
70,000

 
—

 
$
24

Weighted average fixed price per MMBtu
$
4.31

 
$
4.06

 
$
—

 
 
Collar contracts with short puts
285,000

 
20,000

 
—

 
$
79

Weighted average ceiling price per MMBtu
$
5.07

 
$
5.36

 
$
—

 
 
Weighted average floor price per MMBtu
$
4.00

 
$
4.00

 
$
—

 
 
Weighted average short put price per MMBtu
$
3.00

 
$
3.00

 
$
—

 
 
Average forward NYMEX gas prices (d)
$
2.95

 
$
3.30

 
$
—

 
 
Basis swap contracts (i)
125,000

 
15,000

 
30,000

 
$
1

Weighted average fixed price per MMBTU
(0.19
)
 
(0.32
)
 
(0.34
)
 
 
Average forward basis differential prices (j)
$
(0.27
)
 
$
(0.36
)
 
$
(0.34
)
 
 
 _____________________
(a)
In accordance with Financial Accounting Standards Board Accounting Standards Codification ("ASC") 210-20 and ASC 815-10, the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, as the case may be. The net asset and liability amounts shown above have been provided on a commodity contract-type basis, which may differ from their master netting arrangements classifications.
(b)
Counterparties have the option to extend for an additional year 5,000 Bbls per day of 2015 collar contracts with short puts with a ceiling price of $100.08 per Bbl, a floor price of $90.00 per Bbl and a short put price of $80.00 per Bbl. The option to extend is exercisable on December 31, 2015. These contracts give the counterparties the option to extend the contracts under the same terms for an additional year if the option to extend is exercised by the counterparties on December 31, 2015.
(c)
During the period from January 1, 2015 through February 13, 2015, the Company converted (i) 3,000 Bbls per day of 2015 collar contracts with short puts into new 2015 collar contract with short puts with a ceiling price of $78.33 per Bbl, a floor price of $66.50 per Bbl and a short put price of $40.00 per Bbl and (ii) 55,000 Bbls per day of 2016 collar contracts with short puts into new 2016 collar contracts with short puts with a ceiling price of $77.41 per Bbl, a floor price of $66.58 per Bbl and a short put price of $41.55 per Bbl.
(d)
The average forward NYMEX oil, gas and rollfactor prices are based on February 13, 2015 market quotes.
(e)
Represents swaps that fix the difference between (i) each day's price per Bbl of WTI for the first nearby month less (ii) the

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PIONEER NATURAL RESOURCES COMPANY

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.
(f)
Represent contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.
(g)
During the period from January 1, 2015 through February 13, 2015, the Company entered into (i) 5,000 Bbls per day of ethane swap contracts for February through December 2015 with a fixed price of $7.83 per Bbl, (ii) 500 Bbls per day of ethane swap contracts for March through December 2015 with a fixed price of $7.56 per Bbl, (iii) 8,500 Bbls per day of propane swap contracts for February through December 2015 with a fixed price of $21.48 per Bbl and (iv) 2,000 Bbls per day of propane swap contracts for 2016 with a fixed price of $21.63 per Bbl.
(h)
Forward component NGL prices are derived from respective active-market NGL component price quotes on February 13, 2015.
(i)
Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast, Mid-Continent and Permian Basin gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts.
(j)
The average forward basis differential prices are based on February 13, 2015 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.
Marketing and basis differential derivatives. The Company periodically enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of December 31, 2014, the Company had oil index swap contracts totaling 10,000 Bbls per day for 2015 with a price differential of $2.99 per Bbl between Cushing WTI and LLS. As of December 31, 2014, these positions had an asset fair value of $3 million. Based on February 13, 2015 market quotes, the average forward basis differential price was $2.80 per Bbl between the relevant quoted forward oil index prices.


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Qualitative Disclosures
The Company's primary market risk exposures are to changes in commodity prices and interest rates. These risks did not change materially from December 31, 2013 to December 31, 2014.
Non-derivative financial instruments. The Company is a borrower under fixed rate debt instruments and, from time to time, under a variable rate debt instrument that gives rise to interest rate risk. The Company's objective in borrowing under fixed or variable rate debt is to satisfy capital requirements while minimizing the Company's costs of capital. The Company also enters into oil and gas purchase and sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a discussion of the Company's debt instruments.
Derivative financial instruments. The Company, from time to time, utilizes commodity price and interest rate derivative contracts to mitigate commodity price and interest rate risks in accordance with policies and guidelines approved by the Board. In accordance with those policies and guidelines, the Company's executive management determines the appropriate timing and extent of derivative transactions.

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ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
 
 
Page
Consolidated Financial Statements of Pioneer Natural Resources Company:
 
 
 


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REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The Board of Directors and Stockholders of
Pioneer Natural Resources Company
We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company (the "Company") as of December 31, 2014 and 2013, and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2014. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pioneer Natural Resources Company at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2014, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pioneer Natural Resources Company's internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 19, 2015 expressed an unqualified opinion thereon.
 
 
/s/ Ernst & Young LLP
Dallas, Texas
February 19, 2015
 

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CONSOLIDATED BALANCE SHEETS
(in millions)
 
 
December 31,
 
2014
 
2013
ASSETS
Current assets:
 
 
 
Cash and cash equivalents
$
1,025

 
$
393

Accounts receivable:
 
 
 
Trade, net
436

 
431

Due from affiliates
4

 
3

Income taxes receivable
23

 
5

Inventories
241

 
220

Prepaid expenses
15

 
16

Assets held for sale
—

 
584

Other current assets:
 
 
 
Derivatives
578

 
76

Other
37

 
2

Total current assets
2,359

 
1,730

Property, plant and equipment, at cost:
 
 
 
Oil and gas properties, using the successful efforts method of accounting:
 
 
 
Proved properties
15,662

 
13,406

Unproved properties
159

 
123

Accumulated depletion, depreciation and amortization
(5,431
)
 
(4,903
)
Total property, plant and equipment
10,390

 
8,626

Goodwill
272

 
274

Other property and equipment, net
1,391

 
1,224

Other assets:
 
 
 
Investment in unconsolidated affiliate
239

 
225

Derivatives
181

 
91

Other, net
94

 
124

 
$
14,926

 
$
12,294











The accompanying notes are an integral part of these consolidated financial statements.
 

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CONSOLIDATED BALANCE SHEETS (continued)
(in millions)
 
 
December 31,
 
2014
 
2013
LIABILITIES AND EQUITY
Current liabilities:
 
 
 
Accounts payable:
 
 
 
Trade
$
1,197

 
$
910

Due to affiliates
123

 
150

Interest payable
40

 
62

Income taxes payable
1

 
—

Deferred income taxes
161

 
19

Liabilities held for sale
—

 
39

Other current liabilities:
 
 
 
Derivatives
3

 
12

Other
55

 
58

Total current liabilities
1,580

 
1,250

Long-term debt
2,665

 
2,653

Derivatives
2

 
10

Deferred income taxes
1,803

 
1,473

Other liabilities
287

 
293

Equity:
 
 
 
Common stock, $.01 par value; 500 million shares authorized; 152 million and 146 million shares issued as of December 31, 2014 and 2013, respectively
2

 
1

Additional paid-in capital
6,167

 
5,080

Treasury stock, at cost: 3 million shares as of December 31, 2014 and 2013, respectively
(171
)
 
(144
)
Retained earnings
2,583

 
1,665

Total equity attributable to common stockholders
8,581

 
6,602

Noncontrolling interest in consolidated subsidiaries
8

 
13

Total equity
8,589

 
6,615

Commitments and contingencies
 
 
 
 
$
14,926

 
$
12,294









The accompanying notes are an integral part of these consolidated financial statements.

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CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Revenues and other income:
 
 
 
 
 
Oil and gas
$
3,599

 
$
3,088

 
$
2,512

Sales of purchased oil and gas
726

 
334

 
122

Interest and other
9

 
17

 
(1
)
Derivative gains, net
712

 
4

 
330

Gain on disposition of assets, net
9

 
209

 
46

 
5,055

 
3,652

 
3,009

Costs and expenses:
 
 
 
 
 
Oil and gas production
693

 
588

 
532

Production and ad valorem taxes
220

 
192

 
169

Depletion, depreciation and amortization
1,047

 
889

 
689

Purchased oil and gas
703

 
336

 
120

Impairment of oil and gas properties
—

 
1,495

 
—

Exploration and abandonments
177

 
97

 
97

General and administrative
333

 
296

 
244

Accretion of discount on asset retirement obligations
12

 
12

 
8

Interest
184

 
184

 
204

Other
89

 
137

 
114

 
3,458

 
4,226

 
2,177

Income (loss) from continuing operations before income taxes
1,597

 
(574
)
 
832

Income tax benefit (provision)
(556
)
 
213

 
(288
)
Income (loss) from continuing operations
1,041

 
(361
)
 
544

Loss from discontinued operations, net of tax
(111
)
 
(438
)
 
(301
)
Net income (loss)
930

 
(799
)
 
243

Net (income) loss attributable to noncontrolling interests
—

 
(39
)
 
(51
)
Net income (loss) attributable to common stockholders
$
930

 
$
(838
)
 
$
192

Basic earnings per share attributable to common stockholders:
 
 
 
 
 
Income (loss) from continuing operations
$
7.17

 
$
(2.94
)
 
$
3.99

Loss from discontinued operations
(0.77
)
 
(3.22
)
 
(2.45
)
Net income (loss)
$
6.40

 
$
(6.16
)
 
$
1.54

Diluted earnings per share attributable to common stockholders:
 
 
 
 
 
Income (loss) from continuing operations
$
7.15

 
$
(2.94
)
 
$
3.88

Loss from discontinued operations
(0.77
)
 
(3.22
)
 
(2.38
)
Net income (loss)
$
6.38

 
$
(6.16
)
 
$
1.50

Weighted average shares outstanding:
 
 
 
 
 
Basic
144

 
136

 
123

Diluted
144

 
136

 
126

Amounts attributable to common stockholders:
 
 
 
 
 
Income (loss) from continuing operations
$
1,041

 
$
(400
)
 
$
493

Loss from discontinued operations, net of tax
(111
)
 
(438
)
 
(301
)
Net income (loss)
$
930

 
$
(838
)
 
$
192


The accompanying notes are an integral part of these consolidated financial statements.

 

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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in millions)
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Net income (loss)
$
930

 
$
(799
)
 
$
243

Other comprehensive activity:
 
 
 
 
 
Net hedge losses included in continuing operations
—

 
—

 
5

Income tax benefit
—

 
—

 
(2
)
Other comprehensive activity
—

 
—

 
3

Comprehensive income (loss)
930

 
(799
)
 
246

Net (income) loss attributable to noncontrolling interests
—

 
(39
)
 
(51
)
Comprehensive income (loss) attributable to common stockholders
$
930

 
$
(838
)
 
$
195
























The accompanying notes are an integral part of these consolidated financial statements.


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CONSOLIDATED STATEMENTS OF EQUITY
(in millions, except dividends per share)
 
 
 
Equity Attributable to Common Stockholders
 
 
 
 
 
Shares
Outstanding
 
Common
Stock
 
Additional
Paid-in
Capital
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Income (Loss)
 
Noncontrolling
Interests
 
Total
Equity
Balance as of December 31, 2011
122

 
$
1

 
$
3,614

 
$
(458
)
 
$
2,335

 
$
(3
)
 
$
162

 
$
5,651

Dividends declared ($0.08 per share)
—

 
—

 
—

 
—

 
(10
)
 
—

 
—

 
(10
)
Exercise of long-term incentive plan stock options and employee stock purchases
—

 
—

 
(1
)
 
11

 
(3
)
 
—

 
—

 
7

Purchase of treasury stock
(1
)
 
—

 
—

 
(63
)
 
—

 
—

 
—

 
(63
)
Tax benefits related to stock-based compensation
—

 
—

 
58

 
—

 
—

 
—

 
—

 
58

Deferred tax provision attributable to 2008 Pioneer Southwest initial public offering
—

 
—

 
(49
)
 
—

 
—

 
—

 
—

 
(49
)
Compensation costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vested compensation awards, net
2

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Compensation costs included in net income
—

 
—

 
62

 
—

 
—

 
—

 
1

 
63

Distributions to noncontrolling interests
—

 
—

 
—

 
—

 
—

 
—

 
(36
)
 
(36
)
Net income
—

 
—

 
—

 
—

 
192

 
—

 
51

 
243

Net hedge losses included in continuing operations
—

 
—

 
—

 
—

 
—

 
3

 
—

 
3

Balance as of December 31, 2012
123

 
$
1

 
$
3,684

 
$
(510
)
 
$
2,514

 
$
—

 
$
178

 
$
5,867

Issuance of common stock
10

 
—

 
1,281

 
—

 
—

 
—

 
—

 
1,281

Dividends declared ($0.08 per share)
—

0.000001

—

 
—

 
—

 
(11
)
 
—

 
—

 
(11
)
Exercise of long-term incentive plan stock options and employee stock purchases
—

 
—

 
—

 
10

 
—

 
—

 
—

 
10

Purchase of treasury stock
—

 
—

 
—

 
(20
)
 
—

 
—

 
—

 
(20
)
Conversion of 2.875% convertible senior notes
5

 
—

 
(197
)
 
197

 
—

 
—

 
—

 
—

Deferred tax benefit related to conversion of 2.875% senior convertible notes
—

 
—

 
38

 
—

 
—

 
—

 
—

 
38

Tax benefits related to stock-based compensation
—

 
—

 
18

 
—

 
—

 
—

 
—

 
18

Pioneer Southwest merger:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Issuance of treasury stock to acquire outstanding PSE units
4

 
—

 
(179
)
 
179

 
—

 
—

 
—

 
—

Pioneer Southwest merger transaction costs
—

 
—

 
(4
)
 
—

 
—

 
—

 
—

 
(4
)
Pioneer Southwest noncontrolling interest transferred to APIC
—

 
—

 
169

 
—

 
—

 
—

 
(169
)
 
—

Deferred tax benefit associated with the Pioneer Southwest merger
—

 
—

 
200

 
—

 
—

 
—

 
—

 
200

Compensation costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
 

Vested compensation awards, net
1

 
—

 
—

 
—

 
—

 
—

 
—

 
—

Compensation costs included in net income
—

 
—

 
70

 
—

 
—

 
—

 
1

 
71

Distributions to noncontrolling interests
—

 
—

 
—

 
—

 
—

 
—

 
(36
)
 
(36
)
Net income (loss)
—

 
—

 
—

 
—

 
(838
)
 
—

 
39

 
(799
)
Balance as of December 31, 2013
143

 
$
1

 
$
5,080

 
$
(144
)
 
$
1,665

 
$
—

 
$
13

 
$
6,615


 The accompanying notes are an integral part of these consolidated financial statements.



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PIONEER NATURAL RESOURCES COMPANY


CONSOLIDATED STATEMENTS OF EQUITY (continued)
(in millions, except dividends per share)
 
 
 
 
Equity Attributable to Common Stockholders
 
 
 
 
 
Shares
Outstanding
 
Common
Stock
 
Additional
Paid-in
Capital
 
Treasury
Stock
 
Retained
Earnings
 
Noncontrolling
Interests
 
Total
Equity
Balance as of December 31, 2013
143

 
$
1

 
$
5,080

 
$
(144
)
 
$
1,665

 
$
13

 
$
6,615

Issuance of common stock
6

 
1

 
979

 
—

 
—

 
—

 
980

Dividends declared ($0.08 per share)
—

 
—

 
—

 
—

 
(12
)
 
—

 
(12
)
Exercise of long-term incentive plan stock options and employee stock purchases
—

 
—

 
6

 
7

 
—

 
—

 
13

Purchase of treasury stock
—

 
—

 
—

 
(34
)
 
—

 
—

 
(34
)
Sendero divestiture
—

 
—

 
—

 
—

 
—

 
(4
)
 
(4
)
Tax benefits related to stock-based compensation
—

 
—

 
19

 
—

 
—

 
—

 
19

Pioneer Southwest merger transaction costs
—

 
—

 
(1
)
 
—

 
—

 
—

 
(1
)
Compensation costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
Vested compensation awards, net
—

 
—

 
—

 
—

 
—

 
—

 
—

Compensation costs included in net income
—

 
—

 
84

 
—

 
—

 
—

 
84

Distributions to noncontrolling interests
—

 
—

 
—

 
—

 
—

 
(1
)
 
(1
)
Net income
—

 
—

 
—

 
—

 
930

 
—

 
930

Balance as of December 31, 2014
149

 
$
2

 
$
6,167

 
$
(171
)
 
$
2,583

 
$
8

 
$
8,589









The accompanying notes are an integral part of these consolidated financial statements.

 

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
 
Year Ended December 31,
 
2014
 
2013
 
2012
Cash flows from operating activities:
 
 
 
 
 
Net income (loss)
$
930

 
$
(799
)
 
$
243

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
 
Depletion, depreciation and amortization
1,047

 
889

 
689

Impairment of oil and gas properties
—

 
1,495

 
—

Impairment of inventory and other property and equipment
8

 
62

 
6

Exploration expenses, including dry holes
90

 
21

 
31

Deferred income taxes
552

 
(224
)
 
284

Gain on disposition of assets, net
(9
)
 
(209
)
 
(46
)
Accretion of discount on asset retirement obligations
12

 
12

 
8

Discontinued operations
251

 
633

 
520

Interest expense
17

 
17

 
36

Derivative related activity
(609
)
 
164

 
69

Amortization of stock-based compensation
84

 
71

 
63

Amortization of deferred revenue
—

 
—

 
(42
)
Other
34

 
(6
)
 
(47
)
Change in operating assets and liabilities
 
 
 
 
 
Accounts receivable, net
(29
)
 
(123
)
 
(28
)
Income taxes receivable
(18
)
 
3

 
(6
)
Inventories
(37
)
 
(39
)
 
33

Prepaid expenses
(3
)
 
(1
)
 
1

Other current assets
1

 
4

 
14

Accounts payable
104

 
209

 
46

Interest payable
(22
)
 
(6
)
 
11

Income taxes payable
1

 
—

 
(10
)
Other current liabilities
(38
)
 
(27
)
 
(38
)
Net cash provided by operating activities
2,366

 
2,146

 
1,837

Cash flows from investing activities:
 
 
 
 
 
Proceeds from disposition of assets, net of cash sold
877

 
711

 
96

Payments for acquisition, net of cash acquired
—

 
—

 
(297
)
Distribution from unconsolidated subsidiary
—

 
25

 
—

Additions to oil and gas properties
(3,243
)
 
(2,639
)
 
(2,758
)
Additions to other assets and other property and equipment, net
(333
)
 
(237
)
 
(297
)
Net cash used in investing activities
(2,699
)
 
(2,140
)
 
(3,256
)
Cash flows from financing activities:
 
 
 
 
 
Borrowings under long-term debt
523

 
467

 
1,777

Principal payments on long-term debt
(523
)
 
(1,547
)
 
(612
)
Proceeds from issuance of common stock, net of issuance costs
980

 
1,281

 
—

Distributions to noncontrolling interests
(1
)
 
(36
)
 
(36
)
Payments of other liabilities
—

 
(4
)
 
(1
)
Exercise of long-term incentive plan stock options and employee stock purchases
13

 
10

 
7

Purchase of treasury stock
(34
)
 
(20
)
 
(63
)
Excess tax benefits from stock-based payment arrangements
19

 
18

 
58

Payment of financing fees
—

 
—

 
(9
)
Dividends paid
(12
)
 
(11
)
 
(10
)
Net cash provided by financing activities
965

 
158

 
1,111

Net increase (decrease) in cash and cash equivalents
632

 
164

 
(308
)
Cash and cash equivalents, beginning of period
393

 
229

 
537

Cash and cash equivalents, end of period
$
1,025

 
$
393

 
$
229


The accompanying notes are an integral part of these consolidated financial statements.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013 and 2012
NOTE A.    Organization and Nature of Operations
Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company in the United States, with operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeastern Colorado and the West Panhandle field in the Texas Panhandle. The Company's objective is to maximize shareholder investment returns by maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions.
NOTE B.    Summary of Significant Accounting Policies
Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated.
Certain reclassifications have been made to the 2013 and 2012 financial statement and footnote amounts in order to conform them to the 2014 presentations.
Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.
Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less.
Accounts receivable. As of December 31, 2014 and 2013, the Company had accounts receivable – trade, net of allowances for bad debts, of $436 million and $431 million, respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security.
As of both December 31, 2014 and 2013, the Company's allowances for doubtful accounts totaled $1 million. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable. 
Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company's consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations.
Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, natural gas liquids ("NGLs") and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

The following table presents the Company's materials and supplies and commodity inventories as of December 31, 2014 and 2013:
 
 
As of December 31,
 
 
2014
 
2013
 
 
(in millions)
Materials and supplies (a)
 
$
223

 
$
211

Commodities
 
18

 
13

Less: Noncurrent materials and supplies (b)
 
—

 
(4
)
 
 
$
241

 
$
220

____________________
(a)
As of December 31, 2014 and 2013, the Company's materials and supplies inventories were net of valuation allowances of $22 million and $32 million, respectively. See Note D for additional information regarding inventory impairments.
(b)
Included in other noncurrent assets in the Company's accompanying consolidated balance sheet.
Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use.
The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:
(i)
The well has found a sufficient quantity of reserves to justify its completion as a producing well.
(ii)
The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.
Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs.
The Company owns interests in six gas processing plants and eight treating facilities. The Company is the operator of one of the gas processing plants and all eight of the treating facilities. The Company's ownership interests in the gas processing plants and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities in continuing operations for the years ended December 31, 2014, 2013 and 2012 were $56 million, $53 million and $31 million, respectively. Third party expenses attributable to the processing plants and treating facilities in continuing operations for the same respective periods were $24 million, $21 million and $19 million. The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service.
The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.
The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than the carrying amount of the assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's impairment of proved oil and gas properties.
Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time.
Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced for the impaired value with a corresponding charge to earnings in the period in which it is determined to be impaired. During the third quarter of 2014, the Company performed its annual qualitative assessment of goodwill to determine whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount as a basis for determining whether it was necessary to perform the two-step goodwill impairment test. The Company reevaluated this assessment during the fourth quarter of 2014 due to reductions in (i) management's longer-term commodity price outlooks ("Management's Price Outlooks") and (ii) the Company's common stock price. Based upon the results of the assessments, the Company determined that it was not likely that the Company's goodwill was impaired.
The Company reduced the carrying value of goodwill by $2 million and $24 million during the years ended December 31, 2014 and 2013, respectively, reflecting the portion of the Company's goodwill related to assets sold or included in assets held for sale. During 2014, the reduction of goodwill primarily reflected the Company's goodwill related to the Hugoton field assets sold in September 2014, while the 2013 reduction was primarily associated with the sale of 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas, and the planned sales of the Company's Alaska subsidiary and Barnett Shale net assets that were subsequently completed during 2014. See Note C for additional information regarding the Company's divestitures.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2014 and 2013, respectively, the net carrying value of other property and equipment consisted of the following:
 
 
As of December 31,
 
 
2014 (a)
 
2013 (a)
 
 
(in millions)
Proved and unproved sand properties (b)
 
$
469

 
$
451

Land and buildings
 
440

 
345

Equipment and rigs (c)
 
348

 
313

Transportation equipment
 
35

 
41

Furniture and fixtures
 
70

 
48

Leasehold improvements
 
29

 
26

 
 
$
1,391

 
$
1,224

____________________
(a)
At December 31, 2014 and 2013, other property and equipment was net of accumulated depreciation of $563 million and $458 million, respectively.
(b)
Includes sand mines, facilities and unproved leaseholds that primarily provide the Company and other unrelated customers with proppant used in the fracture stimulation of oil and gas wells.
(c)
Includes well servicing rigs and equipment and fracture stimulation equipment including assets owned by subsidiaries that provide pumping and well services on Company-operated properties. As of December 31, 2014, the Company owned eight fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools.
The primary purposes of the Company's sand mines and pumping and well services operations are to accommodate the Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. All intercompany gains or losses of the Company's sand mines and pumping and well services operations are eliminated.
Earnings from sales of proppant to third-party customers and from providing pumping and well services to working interest owners in Company-operated properties are included in interest and other income in the accompanying consolidated statements of operations.
The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Equipment items are generally depreciated by individual component on a straight line basis over their economic useful lives, which are generally from two to 12 years. Leasehold improvements are amortized over the lesser of their economic useful lives or the underlying terms of the associated leases.
The Company evaluates other property and equipment for potential impairment whenever indicators of impairment are present. Circumstances that could indicate potential impairment include: significant adverse changes in industry trends and the economic outlook; legal actions; regulatory changes; and significant declines in utilization rates or oil and gas prices. If it is determined that other property and equipment is potentially impaired, the Company performs an impairment evaluation by estimating the future undiscounted net cash flow from the use and eventual disposition of other property and equipment grouped at the lowest level that cash flows can be identified. If the sum of the future undiscounted net cash flows is less than the net book value of the property, an impairment loss is recognized for the excess, if any, of the assets' net book value over its estimated fair value.
Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party for $46 million of cash proceeds. Associated therewith, the Company recorded a deferred gain that is being amortized as a reduction in production costs over a 20 year period, representing the term of a continuing commitment of Pioneer to deliver production volumes through EFS Midstream handling and gathering facilities. As of December 31, 2014, the deferred gain totaled $39 million and is included in other current and noncurrent liabilities in the Company's accompanying consolidated balance sheet.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

The Company does not have control of EFS Midstream. Consequently, the Company accounts for this investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company's investment in unconsolidated affiliates is increased for investments made and the investor's share of the investee's net income, and decreased for distributions received, the carrying value of member interests sold and the investor's share of the investee's net losses.
The Company's equity interest in the net income or loss of EFS Midstream is recorded in interest and other income, net of eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS Midstream, in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the net income of EFS Midstream for the years ended December 31, 2014, 2013 and 2012.
During November 2014, the Company announced that it is pursuing the divestment of its 50.1 percent share of EFS Midstream. The Company is marketing its equity investment in EFS Midstream and no assurance can be given that a sale will be completed in accordance with the Company's plans or on terms and at a price acceptable to the Company.
Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated.
The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations.
Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.
Issuance of common stock. In November 2014 and February 2013, the Company issued 5.75 million shares and 10.35 million shares of its common stock, respectively, and realized cash proceeds of $980 million and $1.3 billion, respectively, net of associated underwriting and offering expenses.
Noncontrolling interest in consolidated subsidiaries. The Company owns the majority interests in certain subsidiaries with operations in the United States. Prior to December 17, 2013, the Company owned a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest") and consolidated the financial position, results of operations and cash flows of Pioneer Southwest with those of Pioneer. Pioneer Southwest owned proved and unproved oil and gas properties in the Spraberry field in the Permian Basin of West Texas. On December 17, 2013, the holders of a majority of the outstanding common units of Pioneer Southwest approved an amended agreement and plan of merger, pursuant to which (i) all of the then outstanding common units of Pioneer Southwest were canceled and converted into the right to receive 0.2325 of a share of common stock of the Company and (ii) Pioneer Southwest became a wholly-owned subsidiary of the Company. The changes in the Company's ownership of Pioneer Southwest were accounted for by eliminating the noncontrolling interest attributable to Pioneer Southwest. See Note C for additional information about Pioneer Southwest and the amended agreement and plan of merger.
Noncontrolling interests in the net assets of consolidated subsidiaries totaled $8 million and $13 million as of December 31, 2014 and 2013, respectively. For the year ended December 31, 2014, the Company recorded a nominal net loss attributable to the noncontrolling interests, as compared to $39 million and $51 million of net income attributable to the noncontrolling interests for the years ended December 31, 2013 and 2012, respectively. The decrease in income attributable to noncontrolling interests for the year ended December 31, 2014, as compared to 2013 and 2012, is due to the Company's acquisition of all of the outstanding common units of Pioneer Southwest not owned by the Company in December 2013.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

In accordance with GAAP, the Company records transfers of any gains or losses, net of taxes, from noncontrolling interests in consolidated subsidiaries to additional paid in capital proportionate to the ownership after giving effect to the purchase or sale of common units. The following table presents the Company's net income or loss attributable to common stockholders adjusted for changes in equity as a result of transactions that changed the Company's ownership interest in Pioneer Southwest:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Net income (loss) attributable to common stockholders
$
930

 
$
(838
)
 
$
192

Transfers from the noncontrolling interest in consolidated subsidiaries:
 
 
 
 
 
Decrease in additional paid-in capital for deferred taxes recognized attributable to Pioneer Southwest's 2008 initial public offering of 9.5 million common units
—

 
—

 
(49
)
Increase in additional paid-in capital from Pioneer Southwest merger
—

 
169

 
—

Increase in additional paid-in capital from deferred taxes recognized attributable to Pioneer Southwest merger
—

 
200

 
—

Decrease in additional paid-in capital from Pioneer Southwest merger transaction costs
(1
)
 
(4
)
 
—

Net increase (decrease) in equity from transactions with noncontrolling interests
(1
)
 
365

 
(49
)
Net income (loss) attributable to common stockholders and changes in equity from transactions with noncontrolling interests
$
929

 
$
(473
)
 
$
143

Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.
The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2014 or 2013.

The Company enters into purchase transactions with third parties and separate sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming responsibility to deliver the commodities sold. Deficiency payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. See Note N for further information on transportation commitment charges.
Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. Effective February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. The effective portions of the discontinued deferred hedges as of February 1, 2009 were included in accumulated other comprehensive income (loss) ("AOCI - Hedging") and were transferred to earnings during the same periods in which the forecasted hedged transactions were recognized in the Company's earnings. During 2012, the remaining AOCI - Hedging losses were transferred to earnings. Since discontinuing hedge accounting, the Company has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.
The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. See Note E for additional information about the Company's derivative instruments.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs.
Stock-based compensation. Stock-based compensation expense is being recognized on restricted stock, restricted stock units, performance units and stock option awards that are expected to be settled in the Company's common stock ("Equity Awards") in the Company's financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant or modification, as applicable. Stock-based compensation awards generally vest over a period of three years. The amount of stock-based compensation expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested at that date.
Stock-based compensation liability awards ("Liability Awards") are restricted stock awards that are expected to be settled in cash on their vesting dates, rather than in common stock. Liability Awards are recorded as accounts payable—affiliates based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to stock-based compensation expense.
The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair value of Equity Awards and Liability Awards and (iii) the Monte Carlo simulation method for the fair value of performance unit awards.
Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.
Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.
Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell.
In addition, after determining that held for sale criteria has been met, the Company considers whether the assets held for sale meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued operations, the Company classifies the results of operations from the assets held for sale as income or loss from discontinued operations, net of tax in the accompanying consolidated statements of operations for the current period and all prior periods. See Note C for additional information about the Company's divestitures.
New accounting pronouncements. In February 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis." ASU 2015-02 affects reporting entities that are required to evaluate whether they should consolidate certain legal entities. ASU 2015-02 is effective for periods beginning after December 15, 2015 with early adoption permitted. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements.
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within

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December 31, 2014, 2013, and 2012

the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2016 for public companies. Early adoption is not permitted. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.
In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 prospectively changes the criteria for reporting discontinued operations while enhancing disclosures around disposals of assets whether or not the disposal meets the definition of a discontinued operation. ASU 2014-08 is effective for annual and interim periods beginning after December 31, 2014 with early adoption permitted but only for disposals that have not been reported in financial statements previously issued. The impact of this guidance on the Company's consolidated financial statements will depend on the size and nature of the Company's disposal transactions in the future, which the Company cannot accurately predict. Several of the Company's past dispositions that were treated as discontinued operations may not have been classified as such had the new guidance been in effect.
NOTE C. Acquisitions and Divestitures
Divestitures Recorded in Continuing Operations
The Company recorded net gains on the disposition of assets in continuing operations of $9 million, $209 million and $46 million during the years ended December 31, 2014, 2013 and 2012, respectively. The following describes the significant divestitures included in continuing operations:
•
Vertical drilling rigs. During December 2013, the Company committed to a plan to sell the Company's majority interest in Sendero Drilling Company, LLC ("Sendero") to Sendero's minority interest owner. At December 31, 2013, the assets and liabilities of Sendero were classified as held for sale at their estimated fair value. In March 2014, the Company completed the sale of Sendero for cash proceeds of $31 million . As part of the sales agreement, the Company committed to lease from Sendero 12 vertical rigs through December 31, 2015 and eight vertical rigs in 2016. See Note D for information about impairment charges related to Sendero.
•
Permian Basin. During February 2014, the Company completed the sale of proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million, which resulted in a gain of $2 million on the unproved property sold.
•
Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem") to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas for total consideration of $1.8 billion. In May 2013, the Company completed the sale for cash proceeds of $624 million, which resulted in a gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the southern portion of the horizontal Wolfcamp Shale play. At December 31, 2014, the unused carry balance totaled $575 million.
•
West Panhandle. During the first quarter of 2013, the Company completed a sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38 million, which resulted in a gain of $22 million.
•
Eagle Ford Shale. In January 2012, the Company sold a portion of its interest in an unproved oil and gas property in the Eagle Ford Shale play to unaffiliated third parties for cash proceeds of $55 million, which resulted in a gain of $43 million.
•
Other. During 2014, 2013 and 2012, the Company sold other proved and unproved properties, inventory and other property and equipment and recorded net gains of $4 million, $5 million and $3 million, respectively.
Divestitures Recorded in Discontinued Operations
The Company has reflected its Hugoton, Barnett Shale, Pioneer Alaska and Pioneer South Africa results of operations as discontinued operations in the accompanying consolidated statements of operations.
Hugoton. In September 2014, the Company completed the sale of its net assets in the Hugoton field in southwest Kansas for cash proceeds of $328 million, including normal closing adjustments. See Note D for information about impairment charges on the Hugoton assets.

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December 31, 2014, 2013, and 2012

Barnett Shale. During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in North Texas. In September 2014, the Company completed the sale of its Barnett Shale net assets for cash proceeds of $150 million, including normal closing adjustments. See Note D for information about impairment charges on the Barnett Shale assets. Also included in discontinued operations in 2013 is the sale of the Company's interest in certain proved and unproved oil and gas properties in the Barnett Shale field for net cash proceeds of $34 million, which resulted in a gain of $9 million on the unproved properties sold.
Alaska. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in Pioneer's Alaska subsidiary ("Pioneer Alaska"). In April 2014, the Company completed the sale of Pioneer Alaska for cash proceeds of $267 million, including normal closing and other adjustments. See Note D for information about impairment charges on Pioneer Alaska. The recasting of Pioneer Alaska results to income (loss) from discontinued operations includes the sale of the Company's interest in the Cosmopolitan Unit in the Cook Inlet of Alaska in August 2012 for cash proceeds of $10 million, which, together with certain Company obligations assumed by the purchasers, resulted in a gain of $13 million.
South Africa. During the first quarter of 2012, the Company agreed to sell its net assets in South Africa ("Pioneer South Africa"), effective January 1, 2012, for $60 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for cash proceeds of $16 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale, resulting in a gain of $29 million.
  

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December 31, 2014, 2013, and 2012

The following table represents the components of the Company's discontinued operations for the years ended December 31, 2014, 2013 and 2012: 
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
 
 
(in millions)
Revenues and other income:
 
 
 
 
 
 
Oil and gas
 
$
198

 
$
329

 
$
349

Interest and other (a)
 
31

 
38

 
29

Gain on disposition of assets, net
 
9

 
9

 
41

 
 
238

 
376

 
419

Costs and expenses:
 
 
 
 
 
 
Oil and gas production
 
60

 
117

 
107

Production and ad valorem taxes
 
12

 
19

 
19

Depletion, depreciation and amortization
 
11

 
122

 
121

Impairment of oil and gas properties (b)
 
305

 
729

 
533

Exploration and abandonments
 
4

 
54

 
109

General and administrative
 
3

 
12

 
6

Accretion of discount on asset retirement obligations
 
1

 
1

 
3

Other
 
13

 
9

 
3

 
 
409

 
1,063

 
901

Loss from discontinued operations before income taxes
 
(171
)
 
(687
)
 
(482
)
Current tax provision
 
—

 
(6
)
 
(10
)
Deferred tax benefit
 
60

 
255

 
191

Loss from discontinued operations
 
$
(111
)
 
$
(438
)
 
$
(301
)
 ____________________
(a)
Primarily comprised of Alaskan Petroleum Production Tax credits on qualifying capital expenditures.
(b)
Represents noncash impairment charges of $97 million and $539 million on Pioneer Alaska net assets during the years ended December 31, 2014 and 2013, respectively, noncash impairment charges of $174 million, $190 million and $533 million on the Company's net assets in the Barnett Shale field during the years ended December 31, 2014, 2013 and 2012, respectively, and a noncash impairment charge of $34 million on the Company's net assets in the Hugoton field during the year ended December 31, 2014. See Note D for additional information regarding the noncash impairment charges.

As of December 31, 2013, the carrying values of the Company's ownership in Pioneer Alaska, the Barnett Shale field and Sendero were included in assets and liabilities held for sale in the accompanying consolidated balance sheet and were comprised of the following (the Company had no assets held for sale as of December 31, 2014):
 
 
December 31, 2013
 
 
(in millions)
Composition of assets included in assets held for sale:
 
 
Current assets (excluding cash and cash equivalents)
 
$
58

Property, plant and equipment
 
526

Total assets
 
$
584

 
 
 
Composition of liabilities included in liabilities held for sale:
 
 
Current liabilities
 
$
29

Other liabilities
 
10

Total liabilities
 
$
39


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December 31, 2014, 2013, and 2012

Acquisitions
Affiliated Partnerships. In December 2014, the Company acquired the remaining limited partner interests in five affiliated partnerships for $54 million and caused the partnerships to be merged with and into a wholly-owned subsidiary of the Company.
Pioneer Southwest Merger Transaction. In December 2013, the Company completed the acquisition of all of the outstanding common units of Pioneer Southwest not already owned by the Company, through a merger of a wholly-owned subsidiary of the Company into Pioneer Southwest, the result of which was that Pioneer Southwest became a wholly-owned subsidiary of the Company. All of the common units outstanding as of the closing of the merger, except for the common units owned by the Company, were canceled and converted into the right to receive 0.2325 of a share of common stock of the Company per common unit (the "Conversion Ratio"). Consequently, in December 2013, the Company issued an aggregate of 3.96 million shares of its common stock to Pioneer Southwest unitholders.
The Company subsequently caused Pioneer Southwest, its general partner and all of Pioneer Southwest's subsidiaries to be merged with and into a wholly-owned subsidiary of the Company, the result of which was that all common units of Pioneer Southwest were canceled and the Company no longer holds any common units.
Premier Silica Business Combination. In April 2012, a wholly-owned subsidiary of the Company acquired an industrial sand mining business that is now named Premier Silica LLC ("Premier Silica"). Premier Silica's primary mine operations are in Brady, Texas. The Brady mine facilities primarily produce, process and provide sand to the Company for use as proppant in its fracture stimulation of oil and gas wells in Texas. Premier Silica's sand production that is in excess of the Company's sand needs for fracture stimulation and sand production that is not usable for fracture stimulation is primarily sold to third parties for industrial and recreational purposes. The aggregate purchase price of Premier Silica was $297 million, including closing adjustments.
NOTE D.    Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:
•
Level 1 – quoted prices for identical assets or liabilities in active markets.
•
Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.
•
Level 3 – unobservable inputs for the asset or liability.
Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

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December 31, 2014, 2013, and 2012

The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2014 and 2013 for each of the fair value hierarchy levels:
 
 
Fair Value Measurements at December 31, 2014 Using
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Fair Value at December 31, 2014
 
(in millions)
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$
—

 
$
759

 
$
—

 
$
759

Deferred compensation plan assets
70

 
—

 
—

 
70

Total assets
70

 
759

 
—

 
829

Liabilities:
 
 
 
 
 
 
 
Commodity derivatives
—

 
2

 
—

 
2

Interest rate derivatives
—

 
3

 
—

 
3

Total liabilities
—

 
5

 
—

 
5

Total recurring fair value measurements
$
70

 
$
754

 
$
—

 
$
824

 
 
 
 
 
 
 
 
 
Fair Value Measurements at December 31, 2013 Using
 
 
 
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Fair Value at December 31, 2013
 
(in millions)
Assets:
 
 
 
 
 
 
 
Commodity derivatives
$
—

 
$
157

 
$
—

 
$
157

Interest rate derivatives
—

 
10

 
—

 
10

Deferred compensation plan assets
64

 
—

 
—

 
64

Total assets
64

 
167

 
—

 
231

Liabilities:
 
 
 
 
 
 
 
Commodity derivatives
—

 
12

 
—

 
12

Interest rate derivatives
—

 
10

 
—

 
10

Total liabilities
—

 
22

 
—

 
22

Total recurring fair value measurements
$
64

 
$
145

 
$
—

 
$
209

Commodity derivatives. The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represent Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.
The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs which include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and collar contracts with short puts, which is based on active and independent market-quoted volatility factors.
Deferred compensation plan assets. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of December 31, 2014 and 2013, the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs.

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December 31, 2014, 2013, and 2012

Interest rate derivatives. The Company's interest rate derivative assets and liabilities as of December 31, 2014 and 2013 represent Treasury rate swap contracts and interest rate swap contracts, respectively. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts as of December 31, 2014 and 2013 are based on (i) the contracted notional amounts, (ii) London Interbank Offered Rate ("LIBOR") yield curves provided by counterparties and corroborated with forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative asset and liability measurements represent Level 2 inputs in the hierarchy priority.
Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale.
Inventories. During the years ended December 31, 2014 and 2013, the Company recognized impairment charges of $8 million and $23 million, respectively, primarily to reduce the carrying value of its excess well pipe inventory. The Company calculated the estimated fair value of the inventory using significant Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment charges are included in other expense in the Company's accompanying consolidated statements of operations.
Proved oil and gas properties. During 2013 and 2012, reductions in Management's Price Outlooks provided indications of possible impairment of the Company's predominately dry gas properties in the Raton field in southeastern Colorado and the Barnett Shale field in North Texas. As a result of management's assessments, during the years ended December 31, 2013 and 2012, the Company recognized impairment charges to reduce the carrying values of the Raton field and the Barnett Shale field, respectively, to their estimated fair values. The impairment charge associated with the Barnett Shale field is reported in loss from discontinued operations, net of tax in the accompanying consolidated statements of operations.
The Company calculated the fair values of the Raton field and the Barnett Shale field proved properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included Management's Price Outlooks and management's outlooks for (i) production costs, (ii) capital expenditures, (iii) production and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party longer-term commodity futures price outlooks as of each measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value.
The following table presents the fair value and fair value adjustments (in millions) for the Company's 2013 and 2012 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in respective Management's Price Outlooks:
 
 
Year ended
 
Fair
 
Fair Value
 
Management's Price Outlooks
 
 
December 31,
 
Value

Adjustment
 
Oil
 
Gas
Barnett Shale
 
2012
 
$
185

 
$
(533
)
 
$
87.09

 
$
4.78

Raton
 
2013
 
$
534

 
$
(1,495
)
 
$
80.40

 
$
4.43

It is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future adjustments, both positive and negative, to proved and appropriate risk-adjusted probable and possible oil and gas reserves, (ii) results of future drilling activities, (iii) Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

Assets associated with divestitures. Long-lived assets that are classified as held for sale are recorded at the lower of the asset's net carrying amount or estimated fair value less costs to sell. At December 31, 2013, the Sendero assets, Pioneer Alaska and the Barnett Shale field assets were classified as held for sale and carried as such until their divestitures in March 2014, April 2014 and September 2014, respectively. Beginning in the third quarter of 2014, the Hugoton field assets were classified as held for sale until their divestiture in September 2014. At December 31, 2013, the fair value of the Barnett Shale field assets was based upon a weighted average calculation that utilized management inputs for both an estimated sales price and a discounted cash flow model for the proved properties using Level 3 assumptions as discussed in the proved oil and gas properties section above, while Sendero and Pioneer Alaska fair values were each based solely on estimated sales prices, less costs to sell. During 2014, the fair value measurements of all assets classified as held for sale were based on their sales prices, less costs to sell. See Note C for additional information regarding the Company's divestitures.
The following table presents the fair value adjustments made by the Company during the years ended December 31, 2014 and 2013 related to assets associated with divestitures:
 
 
 
 
Year Ended December 31, 2014
 
Year Ended December 31, 2013
 
 
Classification
 
Estimated Fair Value Less Costs to Sell
 
Fair Value Adjustment
 
Estimated Fair Value Less Costs to Sell
 
Fair Value Adjustment
 
 
 
 
(in millions)
Sendero
 
Continuing operations
 
 
 
 
 
$
31

 
$
(25
)
Pioneer Alaska
 
Discontinued operations
 
$
253

 
$
(97
)
 
$
351

 
$
(539
)
Barnett Shale field
 
Discontinued operations
 
$
149

 
$
(174
)
 
$
180

 
$
(190
)
Hugoton field
 
Discontinued operations
 
$
328

 
$
(34
)
 
 
 
 
Unproved oil and gas properties. During December 2014 and 2012, the Company recorded impairment charges of $50 million and $72 million to reduce the carrying value of unproved properties in southeast Colorado (reported in exploration and abandonments in the accompanying consolidated statements of operations) and the Barnett Shale field (reported in loss from discontinued operations, net of tax in the accompanying consolidated statements of operations), respectively. The Company calculated the estimated fair values of the unproved acreage in southeast Colorado and in the Barnett Shale field using significant Level 3 assumptions based on average lease bonuses per acre for its prospective acreage. No value was allocated to acreage that the Company does not plan to develop in southeast Colorado and in the Barnett Shale field.
Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheet as of December 31, 2014 and 2013 are as follows: 

 
 
December 31, 2014
 
December 31, 2013
 
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
 
(in millions)
Long-term debt
 
$
2,665

 
$
2,938

 
$
2,653

 
$
3,019

Long-term debt includes the Company's credit facility and the Company's senior notes. The fair value of debt is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.
Credit facilities. The fair values of the Company's credit facility is calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rates and (iii) the applicable credit-adjustments.
Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.
The Company has other financial instruments consisting primarily of cash equivalents, receivables, prepaid expenses, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively

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December 31, 2014, 2013, and 2012

short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.
Concentrations of credit risk. As of December 31, 2014, the Company's primary concentration of credit risks are the risks of collecting accounts receivable – trade and the risk of counterparties' failure to perform under derivative obligations. See Note L for information regarding the Company's major customers.
The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note E for additional information regarding the Company's derivative activities and information regarding derivative net assets and liabilities by counterparty.
NOTE E.     Derivative Financial Instruments
The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness.

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December 31, 2014, 2013, and 2012

Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and actual index prices at which the oil is sold.
The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of December 31, 2014 and the weighted average oil prices for those contracts:
 
 
2015
 
2016
Swap contracts:
 
 
 
Volume (Bbls)
82,000

 
—

Price per Bbl
$
71.18

 
$
—

Collar contracts with short puts:
 
 
 
Volume (Bbls) (a)(b)
13,767

 
73,000

Price per Bbl:
 
 
 
Ceiling
$
101.36

 
$
96.46

Floor
$
86.82

 
$
85.47

Short put
$
75.73

 
$
74.35

Rollfactor swap contracts:
 
 
 
Volume (Bbl)
36,575

 
—

NYMEX roll price (c)
$
0.06

 
$
—

____________________
(a)
Counterparties have the option to extend for an additional year 5,000 Bbls per day of 2015 collar contracts with short puts with a ceiling price of $100.08 per Bbl, a floor price of $90.00 per Bbl and a short put price of $80.00 per Bbl. The option to extend is exercisable on December 31, 2015. These contracts give the counterparties the option to extend the contracts under the same terms for an additional year if the option to extend is exercised by the counterparties on December 31, 2015.
(b) During the period from January 1, 2015 through February 13, 2015, the Company converted (i) 3,000 Bbls per day of 2015 collar contracts with short puts into new 2015 collar contract with short puts with a ceiling price of $78.33 per Bbl, a floor price of $66.50 per Bbl and a short put price of $40.00 per Bbl and (ii) 55,000 Bbls per day of 2016 collar contracts with short puts into new 2016 collar contracts with short puts with a ceiling price of $77.41 per Bbl, a floor price of $66.58 per Bbl and a short put price of $41.55 per Bbl.
(c)
Represents swaps that fix the difference between (i) each day's price per Bbl of 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.
NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities' NGL component product posted prices. The Company uses derivative contracts to manage the NGL component product price volatility.
The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of December 31, 2014 and the weighted average NGL prices for those contracts:
 
2015
 
2016
 
Swap contracts:
 
 
 
 
Volume (Bbl) (a)
—

 
4,000

 
Average price per Bbl:
$
—

 
$
12.29

 
____________________
(a)
Represent derivative contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

During the period from January 1, 2015 through February 13, 2015, the Company entered into (i) 5,000 Bbls per day of swap contracts for ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices for February through December 2015 with a fixed price of $7.83 per Bbl, (ii) 500 Bbls per day of swap contracts for ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices for March through December 2015 with a fixed price of $7.56 per Bbl, (iii) 8,500 Bbls per day of swap contracts for propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices for February through December 2015 with a fixed price of $21.48 per Bbl and (iv) 2,000 Bbls per day of swap contracts for propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices for 2016 with a fixed price of $21.63 per Bbl.
Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("HH") gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual index prices at which the gas is sold.
The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of December 31, 2014 and the weighted average gas prices for those contracts:
 
 
2015
 
2016
 
2017
Swap contracts:
 
 
 
 
 
Volume (MMBtu)
20,000

 
70,000

 
—

Price per MMBtu
$
4.31

 
$
4.06

 
$
—

Collar contracts with short puts:
 
 
 
 
 
Volume (MMBtu)
285,000

 
20,000

 
—

Price per MMBtu:
 
 
 
 
 
Ceiling
$
5.07

 
$
5.36

 
$
—

Floor
$
4.00

 
$
4.00

 
$
—

Short put
$
3.00

 
$
3.00

 
$
—

Basis swap contracts:
 
 
 
 
 
Gulf Coast basis swap contracts (a)
20,000

 
—

 
—

Price differential ($/MMBtu)
$
—

 
$
—

 
$
—

Mid-Continent index swap volume (a)
95,000

 
15,000

 
30,000

Price differential ($/MMBtu)
$
(0.24
)
 
$
(0.32
)
 
$
(0.34
)
Permian Basin index swap volume (a)
10,000

 
—

 
—

Price differential ($/MMBtu)
$
(0.13
)
 
$
—

 
$
—

____________________
(a)
Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast, Mid-Continent and Permian Basin gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts.
Marketing and basis differential derivatives activities. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of December 31, 2014, the Company had oil index swap contracts totaling 10,000 Bbls per day for 2015 with a price differential of $2.99 per Bbl between Cushing WTI and Louisiana Light Sweet.
Interest rate derivative activities. During the second quarter of 2014, the Company terminated its interest rate derivative contracts for cash proceeds of $14 million. Prior to termination, the Company received a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month London Interbank Offered Rate ("LIBOR") plus an average rate of 1.11 percent on a notional amount of $400 million.
As of December 31, 2014, the Company was a party to (i) interest rate derivative contracts that expire on June 30, 2015 for a notional amount of $200 million and (ii) interest rate derivative contracts that expire on September 15, 2015 for a notional amount of $100 million. The Company will pay an average fixed rate of 2.43 percent and 2.46 percent, respectively, in exchange for receiving the 10-year Treasury rate as of the expiration date.
During the period from January 1, 2015 through February 13, 2015, the Company entered into additional interest rate derivative contracts that expire on September 15, 2015 for a notional amount of $50 million. The Company will pay an average fixed rate of 2.20 percent in exchange for receiving the 10-year Treasury rate as of the expiration date.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of December 31, 2014 and December 31, 2013 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.
The aggregate fair value of the Company's derivative instruments reported in the consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following:
 
Fair Value of Derivative Instruments as of December 31, 2014
Type
 
Consolidated Balance Sheet
Location
 
Fair
Value
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Fair Value Presented in the Consolidated Balance Sheet
 
 
 
 
(in millions)
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Asset Derivatives:
 
 
 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
579

 
$
(1
)
 
$
578

Commodity price derivatives
 
Derivatives - noncurrent
 
$
182

 
$
(1
)
 
181

 
 
 
 
 
 
 
 
$
759

Liability Derivatives:
 
 
 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
1

 
$
(1
)
 
$
—

Interest rate derivatives
 
Derivatives - current
 
3

 
$
—

 
3

Commodity price derivatives
 
Derivatives - noncurrent
 
$
3

 
$
(1
)
 
2

 
 
 
 
 
 
 
 
$
5


Fair Value of Derivative Instruments as of December 31, 2013
Type
 
Consolidated Balance Sheet
Location
 
Fair
Value
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Fair Value Presented in the Consolidated Balance Sheet
 
 
 
 
(in millions)
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Asset Derivatives:
 
 
 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
73

 
$
(7
)
 
$
66

Interest rate derivatives
 
Derivatives - current
 
$
10

 
$
—

 
10

Commodity price derivatives
 
Derivatives - noncurrent
 
$
95

 
$
(4
)
 
91

Interest rate derivatives
 
Derivatives - noncurrent
 
$
15

 
$
(15
)
 
—

 
 
 
 
 
 
 
 
$
167

Liability Derivatives:
 
 
 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
19

 
$
(7
)
 
$
12

Commodity price derivatives
 
Derivatives - noncurrent
 
$
4

 
$
(4
)
 
—

Interest rate derivatives
 
Derivatives - noncurrent
 
$
25

 
$
(15
)
 
10

 
 
 
 
 
 
 
 
$
22



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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

The following table details the location of gains and losses reclassified from AOCI-Hedging into earnings on the Company's discontinued cash flow hedging contracts in the accompanying consolidated statements of operations:
Derivatives in Cash Flow Hedging Relationships
 
Location of Gain/(Loss)
Reclassified from AOCI
into Earnings
 
Amount of Gain/(Loss) Reclassified
from AOCI into Earnings
Year Ended December 31,
2014
 
2013
 
2012
 
 
 
 
(in millions)
Commodity price derivatives
 
Oil and gas revenue
 
$
—

 
$
—

 
$
(3
)
Interest rate derivatives
 
Interest expense
 
—

 
—

 
(2
)
Total
 
 
 
$
—

 
$
—

 
$
(5
)
 
The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations:

Derivatives Not Designated as Hedging Instruments
 
Location of Gain/(Loss)
Recognized in Earnings on Derivatives
 
Amount of Gain/(Loss) Recognized in
Earnings on Derivatives
Year Ended December 31,
2014
 
2013
 
2012
 
 
 
 
(in millions)
Commodity price derivatives
 
Derivative gains, net
 
$
697

 
$
(6
)
 
$
353

Interest rate derivatives
 
Derivative gains, net
 
15

 
10

 
(23
)
Total
 
 
 
$
712

 
$
4

 
$
330

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures.
The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2014:
 
 
Net Assets
 
(in millions)
JP Morgan Chase
$
130

J. Aron & Company
120

Merrill Lynch
101

Citibank, N.A.
98

Morgan Stanley
69

BMO Financial Group
47

Barclays Capital
45

Wells Fargo Bank, N.A.
44

Societe Generale
39

Macquarie Bank
19

Credit Suisse
18

Toronto Dominion
12

Den Norske Bank
11

Royal Bank of Canada
1

Total
$
754


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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

NOTE F.    Exploratory Well Costs
The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.
The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Beginning capitalized exploratory well costs
$
159

 
$
213

 
$
108

Additions to exploratory well costs pending the determination of proved reserves
1,860

 
1,220

 
926

Reclassification due to determination of proved reserves
(1,628
)
 
(1,045
)
 
(790
)
Disposition of assets sold
(47
)
 
(93
)
 
—

Impairment of properties
(13
)
 
(87
)
 
—

Exploratory well costs charged to exploration and abandonment expense (a)
(26
)
 
(49
)
 
(31
)
Ending capitalized exploratory well costs (b)
$
305

 
$
159

 
$
213

 _______________
(a)
Includes exploration and abandonment expense of $43 million and $22 million in 2013 and 2012, respectively, that is included in discontinued operations for each respective period in the accompanying consolidated statements of operations.
(b)
The December 31, 2013 balance includes $60 million of capitalized exploratory well costs classified as held for sale in the accompanying consolidated balance sheet as of December 31, 2013.
The following table provides an aging, as of December 31, 2014, 2013 and 2012 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:
 
 
As of December 31,
 
2014
 
2013
 
2012
 
(in millions, except well counts)
Capitalized exploratory well costs that have been suspended:
 
 
 
 
 
One year or less
$
305

 
$
116

 
$
191

More than one year
—

 
43

 
22

 
$
305

 
$
159

 
$
213

Number of projects with exploratory well costs that have been suspended for a period greater than one year
—

 
1

 
1

The $43 million and $22 million of suspended well costs that were suspended for a period greater than one year at December 31, 2013 and December 31, 2012, respectively, related to Pioneer Alaska, which was sold in April 2014. See Note C for additional information on the sale of Pioneer Alaska.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

NOTE G.    Long-term Debt and Interest Expense
Long-term debt, including the effects of issuance discounts and net deferred fair value hedge losses, consisted of the following components at December 31, 2014 and 2013:
 
 
December 31,
 
2014
 
2013
 
(in millions)
Outstanding debt principal balances:
 
5.875% senior notes due 2016
$
455

 
$
455

6.65% senior notes due 2017
485

 
485

6.875 % senior notes due 2018
450

 
450

7.500 % senior notes due 2020
450

 
450

3.95% senior notes due 2022
600

 
600

7.20% senior notes due 2028
250

 
250

 
2,690

 
2,690

Issuance discounts
(24
)
 
(36
)
Net deferred fair value hedge losses
(1
)
 
(1
)
Total long-term debt
$
2,665

 
$
2,653

Credit facility. The Company maintains a revolving credit agreement (the "Credit Facility") with a syndicate of financial institutions with aggregate loan commitments of $1.5 billion that expire in December 2017. As of December 31, 2014, the Company had no outstanding borrowings under the Credit Facility.
Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin, which is currently 0.5 percent based on the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin"), which is currently 1.50 percent and is also determined by the Company's debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.25 percent). Borrowings under the Credit Facility are general unsecured obligations.
The Credit Facility requires the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments, not to exceed .60 to 1.0. As of December 31, 2014, the Company was in compliance with all of its debt covenants.
Senior notes. The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes is payable semiannually.
Convertible senior notes. As of December 31, 2012, the Company had $480 million of Convertible Senior Notes outstanding. During December 2012 and March 2013, the Company's stock price met the price threshold that caused the Convertible Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued. On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six months ended June 30, 2013, holders of $479 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479 million of cash

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

and issued to the tendering holders 4.4 million shares of the Company's common stock in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $1 million in principal and interest to redeem all Convertible Senior Notes that remained outstanding.
For the years ended December 31, 2013 and 2012, the Company recorded $9.4 million and $33.5 million, respectively, of interest expense relating to the Convertible Senior Notes, which had an effective interest rate of 6.75 percent.
Principal maturities. Principal maturities of long-term debt at December 31, 2014, are as follows (in millions):
 
2015
$
—

2016
$
455

2017
$
485

2018
$
450

2019
$
—

Thereafter
$
1,300

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Cash payments for interest
$
193

 
$
183

 
$
168

Amortization of issuance discounts
12

 
12

 
28

Amortization of net deferred hedge losses (a)
—

 
—

 
2

Amortization of capitalized loan fees
5

 
5

 
6

Net changes in accruals
(22
)
 
(6
)
 
11

Interest incurred
188

 
194

 
215

Less capitalized interest
(4
)
 
(10
)
 
(11
)
Total interest expense
$
184

 
$
184

 
$
204

_______________
(a)
Includes interest rate derivative hedges of $2 million for the period ended December 31, 2012 that were reclassified from AOCI - Hedging into earnings upon expiration (see Note E).
NOTE H.     Incentive Plans
Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Company's board of directors (the "Board") approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company will provide a matching contribution of 100 percent of the officer's and key employee's contribution limited to the first ten percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company's matching contributions were $3 million, $3 million and $2 million for the years ended December 31, 2014, 2013 and 2012, respectively.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

401(k) plan. The Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company) 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount up to 80 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's base compensation (the "Matching Contribution"). Each participant's account is credited with the participant's contributions, Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four-year period that begins with the participant's date of hire. During the years ended December 31, 2014, 2013 and 2012, the Company recognized compensation expense of $33 million, $30 million and $25 million, respectively, as a result of Matching Contributions.
Stock-based compensation costs. In accordance with GAAP, the Company records stock-based compensation expense ratably over the vesting periods of the Company's stock-based compensation awards using the awards' fair value. The Company maintains three plans providing for stock-based compensation, the Pioneer Long-Term Incentive Plan ("LTIP"), the Pioneer 2008 PSE Employee Long-Term Incentive Plan ("PSE LTIP") and the Company's Employee Stock Purchase Plan ("ESPP").
Pioneer Long-Term Incentive Plan. The LTIP provides for the granting of various forms of awards, including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers and employees of the Company. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market. The following table shows the number of shares available for issuance pursuant to awards under the Company's LTIP at December 31, 2014:
 
Approved and authorized awards
9,100,000

Awards issued after May 3, 2006
(6,738,082
)
Awards available for future grant
2,361,918

Pioneer 2008 PSE Employee Long-Term Incentive Plan. The PSE LTIP was adopted by Pioneer Southwest in May 2008. The plan, along with all of Pioneer Southwest's obligations under outstanding awards, was assumed by the Company in connection with the Company's acquisition of all outstanding common units of Pioneer Southwest not owned by the Company in December 2013, at which time the plan's name was changed. The only outstanding awards under the PSE LTIP at the time of the acquisition were phantom units of Pioneer Southwest, all of which were converted into restricted stock units of the Company, and no awards have been granted under the PSE LTIP since the Company's assumption of the plan. The PSE LTIP provides for the granting of various forms of awards, including stock options, stock appreciation rights, performance units, restricted stock and other stock-based awards to directors, officers and employees of the Company. The shares to be delivered under the PSE LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market. The following table shows the number of Pioneer common shares available for issuance pursuant to awards under the PSE LTIP at December 31, 2014:
 
Approved and authorized awards
678,034

Awards issued under the PSE LTIP
(23,192
)
Awards available for future grant
654,842



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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

Employee Stock Purchase Plan. The Company has an ESPP that allows eligible employees to annually purchase the Company's common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay (subject to certain ESPP limits) during the eight-month offering period (January 1 to August 31). Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's common stock on either the first day or the last day of each offering period, whichever closing sales price is lower. The following table shows the number of shares available for issuance under the ESPP at December 31, 2014:
 
Approved and authorized shares
1,250,000

Shares issued
(774,638
)
Shares available for future issuance
475,362

The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award and the associated income tax benefit for the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Restricted stock-Equity Awards
$
65

 
$
57

 
$
50

Restricted stock-Liability Awards
28

 
40

 
23

Stock options (a)
2

 
3

 
4

Performance unit awards
13

 
9

 
6

ESPP
2

 
2

 
2

Other
—

 
1

 
1

Total
$
110

 
$
112

 
$
86

Income tax benefit
$
33

 
$
36

 
$
28

 _____________________
(a)
Cash proceeds received from stock option exercises during 2014, 2013 and 2012 amounted to $6 million, $5 million and $3 million, respectively.
As of December 31, 2014, there was $122 million of unrecognized stock-based compensation expense related to unvested share-based compensation plans, including $25 million attributable to Liability Awards. The stock-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.
Restricted stock awards. During 2014, the Company awarded 546,710 restricted shares or units of the Company's common stock as compensation to directors, officers and employees of the Company (including 140,093 shares or units representing Liability Awards). The Company's issued shares, as reflected in the consolidated balance sheet as of December 31, 2014, do not include 170,210 of issued, but unvested shares awarded under stock-based compensation plans that have voting rights.
The following table reflects the restricted stock award activity for the year ended December 31, 2014:
 
 
Equity Awards
 
Liability Awards
 
Number of
Shares
 
Weighted
Average Grant-
Date Fair
Value
 
Number of Shares
Outstanding at beginning of year
1,371,207

 
$
117.09

 
422,382

Shares granted
406,617

 
$
184.39

 
140,093

Shares forfeited
(79,777
)
 
$
134.25

 
(33,052
)
Shares vested
(464,508
)
 
$
108.79

 
(201,336
)
Outstanding at end of year
1,233,539

 
$
140.57

 
328,087


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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

The weighted average grant-date fair value of restricted stock equity awards awarded during 2014, 2013 and 2012 was $184.39, $134.17 and $113.09, respectively. The fair value of shares for which restrictions lapsed during 2014, 2013 and 2012 was $88 million, $69 million and $137 million, respectively, based on the market price on the vesting date.
As of December 31, 2014 and 2013, accounts payable – due to affiliates in the accompanying consolidated balance sheets includes $23 million and $33 million of liabilities attributable to the Liability Awards, representing the earned portion of the fair value of the outstanding awards as of that date. The fair value of Liability Awards for which restrictions lapsed during 2014, 2013 and 2012 was $38 million, $26 million and $14 million respectively, based on the market price on the vesting date.
Stock option awards. Certain employees may be granted options to purchase shares of the Company's common stock with an exercise price equal to the fair market value of Pioneer common stock on the date of grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Option awards have a ten-year contract life. The expected life of an option is estimated based on historical and expected exercise behavior. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical volatility. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a seven-year average dividend yield.
The Company did not grant any stock options during the years ended December 31, 2014 and 2013. The Company used the following weighted-average assumptions to estimate the fair value of stock options granted during the year ended December 31, 2012:
 
 
2012
Expected option life - years
7.0

Volatility
49.4
%
Risk-free interest rate
1.5
%
Dividend yield
0.4
%
 
A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2014 is presented below:
 
 
Number
of Shares
 
Weighted
Average
Exercise Price
 
Weighted
Average
Remaining
Contractual
Life
 
Aggregate
Intrinsic Value
 
 
 
 
 
(in years)
 
(in millions)
Outstanding at beginning of year
289,927

 
$
74.90

 
 
 
 
Options exercised
(90,869
)
 
$
69.19

 
 
 
 
Outstanding at end of year
199,058

 
$
77.51

 
5.96
 
$
14

Exercisable at end of year
106,278

 
$
45.86

 
4.92
 
$
11

The weighted average grant-date fair value of options awarded during 2012 was $56.29 using the Black-Scholes option-pricing model. The intrinsic value of options exercised during 2014, 2013 and 2012 was $12 million, $21 million and $17 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

Performance unit awards. During 2014, 2013 and 2012, the Company awarded performance units to certain of the Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company's total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34-month service period. The grant-date fair values per unit of the 2014, 2013 and 2012 performance unit awards were $232.20, $189.23 and $172.57, respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as stock-based compensation expense ratably over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2014, 2013 and 2012:
 
 
2014
 
2013
 
2012
Risk-free interest rate
0.62%
 
0.40%
 
0.40%
Range of volatilities
29.0
%
-
41.5%
 
30.4
%
-
42.9%
 
33.6
%
-
49.0%
The following table summarizes the performance unit activity for the year ended December 31, 2014:
 
 
Number of
Units (a)
 
Weighted  Average
Grant-Date
Fair Value
Beginning performance unit awards
134,476

 
$
183.66

Units granted
67,182

 
$
232.20

Units forfeited
(1,153
)
 
$
189.23

Units vested (b)
(45,772
)
 
$
172.87

Ending performance unit awards
154,733

 
$
207.88

 _____________________
(a)
These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date.
(b)
On December 31, 2014, the service period lapsed on 44,949 of these performance unit awards, which does not include 823 retirement deferred shares scheduled for release on December 31, 2015. The lapsed units earned two shares for each vested award representing 89,898 aggregate shares of common stock issued on January 2, 2015.
 The fair value of shares for which restrictions lapsed during 2014, 2013 and 2012 was $13 million, $19 million and $19 million, respectively, based on the market price on the vesting date.

101
PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011

NOTE I.    Asset Retirement Obligations
The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Beginning asset retirement obligations
$
194

 
$
198

 
$
137

Obligations assumed in acquisitions
6

 
—

 
10

New wells placed on production
5

 
6

 
10

Changes in estimates (a)
7

 
8

 
52

Disposition of wells
(14
)
 
(16
)
 
(2
)
Obligations settled
(21
)
 
(15
)
 
(18
)
Accretion of discount on continuing operations
12

 
12

 
8

Accretion of discount on discontinued operations
—

 
1

 
1

Ending asset retirement obligations
$
189

 
$
194

 
$
198

 _____________________
(a)
The changes in the 2014, 2013 and 2012 estimates are primarily due to increases in abandonment cost estimates based on recent actual costs incurred to abandon wells and declines in the credit-adjusted risk-free discount rates used to value the Company's asset retirement obligations. The increases in the 2014 and 2012 estimates were further impacted by declines in oil, NGL and gas prices used to calculate proved reserves, which had the effect of shortening the economic life of certain wells and increasing the present value of future retirement obligations. The increases in 2013 estimates were partially offset by higher commodity prices, which had the effect of lengthening the economic life of certain wells and decreasing the present value of future retirement obligations.
As of December 31, 2014 and 2013, the current portions of the Company's asset retirement obligations were $28 million and $19 million, respectively. 
NOTE J. Commitments and Contingencies
Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $41 million.
Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.
Legal actions. The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. These retention and indemnification arrangements were undertaken by the Company with respect to some or all of such pre-closing matters in connection with the sale of its Argentine assets in 2006, the sale of its Canadian assets in 2007, the sale of Pioneer Tunisia in February 2011, the sale of Pioneer South Africa in August 2012, and the sale of Pioneer Alaska and the Company's Hugoton and Barnett Shale assets in 2014, as well as in connection with sales of joint interests. The Company does not believe that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

Drilling commitments. The Company periodically enters into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company also enters into agreements to secure drilling rig services, which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments in the periods in which the well is drilled or rig services are performed. Future minimum drilling commitments at December 31, 2014 are as follows (in millions):
2015
$
303

2016
$
197

2017
$
113

2018
$
32

2019
$
2

Thereafter
$
—

Lease agreements. The Company leases equipment and office facilities under operating leases. Rent expense for the years ended December 31, 2014, 2013 and 2012 was $66 million, $58 million and $48 million, respectively. These payments include $9 million, $10 million and $8 million associated with discontinued operations for the years ended December 31, 2014, 2013 and 2012, respectively, which are included in earnings from discontinued operations, net of tax, in the accompanying consolidated statements of operations. Future minimum lease commitments under noncancelable operating leases at December 31, 2014 are as follows (in millions):
 
2015
$
30

2016
$
22

2017
$
20

2018
$
19

2019
$
19

Thereafter
$
27

Firm purchase, gathering, processing, transportation and fractionation commitments. The Company from time to time enters into, and as of December 31, 2014 is a party to, take-or-pay agreements, which include contractual commitments to purchase sand and water to accommodate the Company's drilling operations and contractual commitments with midstream service companies and pipeline carriers for future gathering, processing, transportation and fractionation. These commitments are normal and customary for the Company's business activities. Future minimum purchase, gathering, processing, transportation and fractionation commitments at December 31, 2014 are as follows (in millions):
 
2015
$
455

2016
$
486

2017
$
364

2018
$
332

2019
$
325

Thereafter
$
1,011

Certain future minimum gathering, processing, transportation and fractionation fees are based upon rates and tariffs subject to change over the lives of the commitments. The above commitments include demand fees associated with volume delivery commitments, principally comprised of approximately 50,000 Bbls per day through August 2017 related to the Company's Permian Basin operations. If the Company does not expect to be able to fulfill its short-term and long-term delivery obligations from projected production of available reserves, the Company expects to purchase third party volumes to satisfy its commitment if it is economical to do so; otherwise, it will pay demand fees for commitment shortfalls.
NOTE K.     Related Party Transactions
Transactions with affiliated partnerships. Prior to December 2014, the Company, through a wholly-owned subsidiary, served as operator of properties in which it and its affiliated partnerships had an interest. The Company received lease operating and supervision charges in accordance with standard industry operating agreements related to the operation of the properties in

103
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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

which it and its affiliated partnerships had an interest and other fees related to the administration of the affiliated partnerships. For the years ended December 31, 2014, 2013 and 2012, the Company received $3 million, $3 million and $2 million, respectively, associated with these fees.
In December 2014, the Company acquired the remaining limited partner interests in the affiliated partnerships and caused the partnerships to be merged with and into the Company. Prior to the acquisition, the Company proportionately consolidated the affiliated partnerships.
 Transactions with EFS Midstream. The Company, through a wholly-owned subsidiary, owns a noncontrolling interest in its unconsolidated affiliate, EFS Midstream. During the years ended December 31, 2014 and 2013, the Company received $50 million and $25 million, respectively, in distributions from EFS Midstream.
The Company also (i) provides certain services as the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) is the operator of Eagle Ford Shale properties for which EFS Midstream provides certain services under a Hydrocarbon Gathering and Handling Agreement (the "HGH Agreement").
Master Services Agreement. The terms of the Master Services Agreement provide that the Company will perform certain manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to expenses incurred by employees whose time is substantially dedicated to EFS Midstream's business. During 2014, 2013 and 2012, the Company received $3 million, $3 million and $2 million of fixed payments and $18 million, $16 million and $12 million of variable payments, respectively, from EFS Midstream. During 2013, the Company purchased other plant and equipment from EFS Midstream totaling $3 million.
Hydrocarbon Gathering and Handling Agreement. Under the terms of the HGH Agreement, EFS Midstream is obligated to construct certain equipment and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale properties operated by the Company. The HGH Agreement also obligates the Company and its Eagle Ford Shale working interest partners to use the EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with the terms of the HGH Agreement, the Company paid EFS Midstream $103 million, $81 million and $59 million of gathering and treating fees during 2014, 2013 and 2012, respectively. Such amounts were expensed as oil and gas production costs in the accompanying consolidated statements of operations.
NOTE L.     Major Customers
The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts.
The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas revenues, including the revenues from discontinued operations, in at least one of the three years ended December 31, 2014:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
Plains Marketing LP
24
%
 
26
%
 
25
%
Occidental Energy Marketing Inc.
13
%
 
12
%
 
13
%
Enterprise Products Partners L.P.
11
%
 
12
%
 
14
%
Valero Marketing and Supply Company
10
%
 
5
%
 
—
%
The loss of any of these significant purchasers could have a material adverse effect on the ability of the Company to sell its oil and gas production.

104
Table of Contents
PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

NOTE M.    Interest and Other Income    
The following table provides the components of the Company's interest and other income during the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Equity interest in income of EFS Midstream
$
13

 
$
7

 
$
2

Other income
9

 
9

 
6

Deferred compensation plan income
3

 
6

 
2

Interest income
—

 
—

 
1

Loss from vertical integration services (a)
(16
)
 
(5
)
 
(12
)
Total interest and other income
$
9

 
$
17

 
$
(1
)
 ______________________
(a)
Loss from vertical integration services represents net margins, after intercompany gains or losses are eliminated, associated with (i) sales of proppant to third-party customers and providing fracture stimulation and well services to working interest owners in Company-operated properties and (ii) extended idle time activities. For the three years ended December 31, 2014, 2013 and 2012, these net margins include $374 million, $285 million and $248 million of gross vertical integration revenues, respectively and $390 million, $290 million and $260 million of total vertical integration costs and expenses, respectively.
NOTE N.    Other Expense
The following table provides the components of the Company's other expense during the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Transportation commitment charge (a)
$
46

 
$
39

 
$
39

Other
19

 
16

 
20

Terminated drilling rig contract charges (b)
9

 
1

 
16

Impairment of inventory and other property and equipment (c)
8

 
62

 
6

Above market and idle drilling and well services equipment charges (d)
7

 
10

 
33

Contingency and environmental accrual adjustments
—

 
9

 
—

Total other expense
$
89

 
$
137

 
$
114

 ____________________
(a)
Primarily represents firm transportation payments on excess pipeline capacity commitments.
(b)
Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.
(c)
Primarily represents charges of $8 million and $36 million to reduce excess materials and supplies inventories to their market values for the years ended December 31, 2014 and 2013, respectively, and a charge of $25 million for the year ended December 31, 2013 to reduce the carrying value of Sendero to its estimated fair value. See Notes C and D for additional information on the fair value of Sendero and material and supplies inventory, respectively.
(d)
Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that were above market rates and idle drilling rig and fracture stimulation fleet fees, neither of which were chargeable to joint operations.
NOTE O.    Income Taxes
The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject

105
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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

to examination by United States federal, state, local and foreign taxing authorities. The Company made current and estimated tax payments of $22 million, $12 million and $32 million (net of tax refunds) during 2014, 2013 and 2012, respectively. These payments and net refunds include tax payments related to Pioneer South Africa's operations of $10 million during 2012.
The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and assesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the United States, state, local and foreign tax jurisdictions will be utilized prior to their expiration.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. During 2014, the Company recognized a $21 million tax benefit resulting from the resolution of the tax uncertainty related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 acquisition of Premier Silica.  There are no unrecognized tax benefits as of December 31, 2014.
With respect to income taxes, the Company's policy is to account for interest charges as interest expense and any penalties as other expense in the consolidated statements of operations. The Company files income tax returns in the United States federal jurisdiction, and various state and foreign jurisdictions. As of December 31, 2014, there are no proposed adjustments or uncertain positions in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position. The Company's earliest open years in its key jurisdictions are as follows:
 
United States
2013
Various U.S. states
2009
South Africa
2009
The Company's income tax (provision) benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Income tax (provision) benefit from continuing operations
$
(556
)
 
$
213

 
$
(288
)
Income tax (provision) benefit from discontinued operations
$
60

 
$
249

 
$
181

Changes in stockholders' equity:
 
 
 
 
 
Net deferred hedge (loss) gain
$
—

 
$
—

 
$
(2
)
Excess tax benefit related to stock-based compensation
$
19

 
$
18

 
$
58

Tax benefit attributable to conversion of 2.875% senior convertible notes
$
—

 
$
38

 
$
—

Tax benefit attributable to 2013 merger with Pioneer Southwest
$
—

 
$
200

 
$
—

Tax attributable to 2008 Pioneer Southwest initial public offering
$
—

 
$
—

 
$
(49
)

106
Table of Contents
PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

The Company's income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Current:
 
 
 
 
 
U.S. federal
$
(3
)
 
$
(11
)
 
$
(5
)
U.S. state
(1
)
 
—

 
1

 
(4
)
 
(11
)
 
(4
)
Deferred:
 
 
 
 
 
U.S. federal
(537
)
 
208

 
(270
)
U.S. state
(15
)
 
16

 
(14
)
 
(552
)
 
224

 
(284
)
Income tax (provision) benefit from continuing operations
$
(556
)
 
$
213

 
$
(288
)
 Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income (loss) from continuing operations are as follows for the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions, except percentages)
Income (loss) from continuing operations before income taxes
$
1,597

 
$
(574
)
 
$
832

Less: Net income attributable to noncontrolling interests
—

 
(39
)
 
(51
)
Income (loss) from continuing operations attributable to common stockholders before income taxes
1,597

 
(613
)
 
781

Federal statutory income tax rate
35
%
 
35
%
 
35
%
(Provision) benefit for federal income taxes at the statutory rate
(559
)
 
215

 
(273
)
State income tax (provision) benefit (net of federal tax)
(10
)
 
10

 
(8
)
Premier Silica benefit
21

 
—

 
—

Other
(8
)
 
(12
)
 
(7
)
Income tax (provision) benefit from continuing operations
$
(556
)
 
$
213

 
$
(288
)
Effective income tax rate, excluding income attributable to the noncontrolling interest
35
%
 
35
%
 
37
%

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Table of Contents
PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2014 and 2013:
 
 
December 31,
 
2014
 
2013
 
(in millions)
Deferred tax assets:
 
Net operating loss carryforward (a)
$
330

 
$
329

Asset retirement obligations
68

 
74

Incentive plans
71

 
68

Other
74

 
74

Total deferred tax assets
543

 
545

Deferred tax liabilities:
 
 
 
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes
(1,881
)
 
(1,570
)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes
(251
)
 
(255
)
Net deferred hedge gains
(280
)
 
(109
)
Other
(95
)
 
(103
)
Total deferred tax liabilities
(2,507
)
 
(2,037
)
Net deferred tax liability
$
(1,964
)
 
$
(1,492
)
Reflected in accompanying consolidated balance sheets as:
 
 
 
Current deferred income tax liability
$
(161
)
 
$
(19
)
Noncurrent deferred income tax liability
(1,803
)
 
(1,473
)
Total
$
(1,964
)
 
$
(1,492
)
____________________
(a)
Net operating loss carryforwards as of December 31, 2014 consist of $927 million of U.S. federal NOLs which expire primarily in 2032 and $120 million of Colorado NOLs which expire between 2027 and 2033.
NOTE P.    Net Income Per Share Attributable To Common Stockholders
In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income (loss) per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. 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 net loss per share and conversion into common stock is assumed not to occur. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented.
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 diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding.

108
Table of Contents
PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2014, 2013, and 2012

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Net income (loss) from continuing operations attributable to common stockholders
$
1,041

 
$
(400
)
 
$
493

Participating basic earnings (a)
(10
)
 
—

 
(2
)
Basic and diluted net income (loss) from continuing operations attributable to common stockholders
1,031

 
(400
)
 
491

Basic and diluted net loss from discontinued operations attributable to common stockholders
(111
)
 
(438
)
 
(301
)
Basic and diluted net income (loss) attributable to common stockholders
$
920

 
$
(838
)
 
$
190

 ______________________
(a)
Unvested restricted stock awards and Pioneer Southwest phantom unit awards (prior to the December 2013 Pioneer Southwest merger) represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average common shares outstanding for the years ended December 31, 2014, 2013 and 2012:
 
 
Year Ended December 31,
 
2014
 
2013 (a)
 
2012
 
(in millions)
Weighted average common shares outstanding:
 
 
 
 
 
Basic
144

 
136

 
123

Convertible Senior Notes dilution (b)
—

 
—

 
3

Diluted
144

 
136

 
126

______________________
(a)
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 to the loss recorded for the period: (i) 135,190 outstanding options to purchase the Company's common stock, (ii) 200,360 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.
(b)
Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if the Convertible Senior Notes had qualified for and been converted during the year ended December 31, 2012.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012


Oil & Gas Exploration and Production Activities
The Company has only one reportable operating segment, which is oil and gas exploration and production in the United States. See the Company's accompanying statements of operations for information about results of operations for oil and gas producing activities.
Capitalized Costs 
 
December 31,
 
2014
 
2013 (a)
 
(in millions)
Oil and gas properties:
 
 
 
Proved
$
15,662

 
$
14,292

Unproved
159

 
123

Capitalized costs for oil and gas properties
15,821

 
14,415

Less accumulated depletion, depreciation and amortization
(5,431
)
 
(5,294
)
Net capitalized costs for oil and gas properties
$
10,390

 
$
9,121

_______________
(a)
Includes $885 million of proved property and $391 million of accumulated depletion, depreciation and amortization related to Pioneer Alaska and the Barnett Shale field, which were classified as assets held for sale at December 31, 2013.
Costs Incurred for Oil and Gas Producing Activities (a)
 
 
Year Ended December 31,
 
 
2014
 
2013
 
2012
 
(in millions)
Property acquisition costs:
 
 
 
 
 
 
Proved
 
$
19

 
$
13

 
$
17

Unproved
 
85

 
63

 
141

Exploration costs
 
1,943

 
1,291

 
967

Development costs
 
1,535

 
1,481

 
1,881

Total costs incurred
 
$
3,582

 
$
2,848

 
$
3,006

_______________
(a)
The costs incurred for oil and gas producing activities includes the following amounts of asset retirement obligations:
 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Exploration costs
$
3

 
$
3

 
$
2

Development costs
4

 
10

 
57

Total
$
7

 
$
13

 
$
59

Reserve Quantity Information
The estimates of the Company's proved reserves as of December 31, 2014, 2013 and 2012 were based on evaluations prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major properties and prepared by the Company's engineers with respect to all other properties. Proved reserves were estimated in accordance with guidelines established by the United States Securities and Exchange Commission (the "SEC") and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012


Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes available in the future.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012


The following table provides a rollforward of total proved reserves for the years ended December 31, 2014, 2013 and 2012. Oil and NGL volumes are expressed in thousands of Bbls ("MBbls"), gas volumes are expressed in millions of cubic feet ("MMcf") and total volumes are expressed in thousands of barrels of oil equivalent ("MBOE").
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Gas
(MMcf) (a)
 
Total
(MBOE)
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Gas
(MMcf) (a)
 
Total
(MBOE)
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Gas
(MMcf) (a)
 
Total
(MBOE)
Balance, January 1
342,105

 
185,422

 
1,906,341

 
845,250

 
486,838

 
232,576

 
2,197,480

 
1,085,661

 
430,005

 
211,035

 
2,531,038

 
1,062,881

Production (b)
(32,718
)
 
(15,761
)
 
(154,424
)
 
(74,217
)
 
(27,455
)
 
(12,999
)
 
(157,690
)
 
(66,736
)
 
(22,990
)
 
(10,913
)
 
(161,197
)
 
(60,769
)
Revisions of previous estimates
(46,354
)
 
(20,125
)
 
(2,574
)
 
(66,907
)
 
(184,359
)
 
(64,986
)
 
(304,531
)
 
(300,101
)
 
(11,158
)
 
(17,417
)
 
(485,216
)
 
(109,444
)
Extensions and discoveries
114,864

 
55,987

 
275,825

 
216,822

 
78,922

 
38,639

 
205,899

 
151,878

 
78,375

 
48,422

 
320,243

 
180,170

Sales of minerals-in-place
(26,952
)
 
(36,926
)
 
(359,548
)
 
(123,803
)
 
(11,937
)
 
(7,931
)
 
(35,326
)
 
(25,756
)
 
(275
)
 
(588
)
 
(16,845
)
 
(3,671
)
Purchases of minerals-in-place
1,139

 
647

 
3,252

 
2,328

 
96

 
123

 
509

 
304

 
5,383

 
2,037

 
9,457

 
8,996

Improved recovery
—

 
—

 
—

 
—

 
—

 
—

 
—

 
—

 
7,498

 
—

 
—

 
7,498

Balance, December 31 (c)
352,084

 
169,244

 
1,668,872

 
799,473

 
342,105

 
185,422

 
1,906,341

 
845,250

 
486,838

 
232,576

 
2,197,480

 
1,085,661

 ______________________
(a)
The proved gas reserves as of December 31, 2014, 2013 and 2012 include 191,932 MMcf, 240,093 MMcf and 280,344 MMcf, respectively, of gas that the Company expected to be produced and utilized as field fuel. Field fuel is gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.
(b)
Production for 2014, 2013 and 2012 includes 16,738 MMcf, 18,813 MMcf and 18,930 MMcf of field fuel, respectively. Also, for 2014, 2013 and 2012, production includes 4,911 MBOE, 7,170 MBOE and 7,715 MBOE of production associated with discontinued operations. See Note C for additional information regarding the Company's discontinued operations.
(c)
As of December 31, 2013 and 2012, the portions of the Company's proved reserves attributable to discontinued operations in the Hugoton field, the Barnett Shale field and Alaska were 99,795 MBOE and 154,594 MBOE, respectively. Upon completion of the Pioneer Southwest merger in 2013, the Company had no proved reserves associated with any subsidiary in which there is a noncontrolling interest. Proved reserves attributable to noncontrolling interests in Pioneer Southwest were approximately two percent as of December 31, 2012.
    

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012


Revisions of previous estimates. At December 31, 2014, revisions of previous estimates are comprised of 79 MMBOE of negative revisions due to removing vertical proved undeveloped locations in the Spraberry/Wolfcamp play, replacing previously recorded undeveloped horizontal locations with new locations based on new well performance data, updated well performance profiles and updated cost estimates, partially offset by 12 MMBOE of positive price revisions. During 2014, the Company continued to shift its drilling activity in the Spraberry/Wolfcamp play in the Midland Basin of West Texas from vertical drilling to horizontal drilling. The Company believes that replacing vertical drilling with horizontal drilling will enhance ultimate resource recoveries and improve rates of return per dollar invested. As a result, Pioneer no longer expects to drill any vertical proved undeveloped locations. Consequently, the Company's proved undeveloped reserves were reduced by 39 MMBOE associated with vertical drilling locations in the Spraberry/Wolfcamp area. Based on the limited horizontal drilling conducted to date in six Wolfcamp and Spraberry shale intervals across Pioneer's acreage position in the Spraberry/Wolfcamp field, sufficient production and well control data is not yet available to support the replacement of the vertical proved undeveloped reserves removed in 2014 and 2013 with horizontal proved undeveloped reserve additions. During 2014, the Company also removed 14 MMBOE of proved undeveloped reserves associated with horizontal locations in the Spraberry/Wolfcamp area that are no longer expected to be drilled within five years as a result of optimizing the Company's horizontal drilling program in other areas of the field. Negative well performance revisions of 19 MMBOE were comprised of a combination of negative revisions associated with horizontal and vertical downspacing performance and normal production decline changes. Cost inflation resulted in negative revisions of 6 MMBOE due to the assumed economic limit of producing and planned wells being shortened. The December 31, 2014 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines was $94.98 per barrel of oil and $4.35 per Mcf of gas, compared to $96.82 per barrel of oil and $3.67 per Mcf of gas at December 31, 2013.
At December 31, 2013, revisions of previous estimates are comprised of 319 MMBOE of proved undeveloped reserves that were no longer expected to be drilled and 11 MMBOE of negative revisions attributable to updated performance profiles and cost estimates, partially offset by 30 MMBOE of positive price revisions. As noted above, the Company began shifting its drilling activity in the Spraberry/Wolfcamp play in the Midland Basin of West Texas from vertical drilling to horizontal drilling during 2013 based on the Company's belief that replacing vertical drilling with horizontal drilling would enhance ultimate resource recoveries and improve rates of return per dollar invested. As a result, Pioneer no longer expected to drill a significant number of its previously recorded vertical proved undeveloped locations. Consequently, proved undeveloped reserves associated with vertical drilling locations in the Spraberry/Wolfcamp area were reduced by 231 MMBOE during 2013. Pioneer also removed an additional 88 MMBOE of proved undeveloped reserves that were primarily attributable to the announced divestitures of Pioneer's Alaska and Barnett Shale Combo assets (45 MMBOE) and previously recorded gas wells that were no longer expected to be drilled due to the reallocation of drilling capital to higher-rate-of-return oil wells. The December 31, 2013 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines was $96.82 per barrel of oil and $3.67 per Mcf of gas, compared to $94.84 per barrel of oil and $2.76 per Mcf of gas at December 31, 2012.
At December 31, 2012, revisions of previous estimates are comprised of 82 MMBOE of negative price revisions and 27 MMBOE of negative revisions due to updated performance profiles and cost estimates. The December 31, 2012 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines was $94.84 per barrel of oil and $2.76 per Mcf of gas, compared to $96.13 per barrel of oil and $4.12 per Mcf of gas at December 31, 2011.
Extensions and discoveries. Extensions and discoveries at December 31, 2014, 2013 and 2012 are primarily comprised of discoveries and extensions in the Spraberry, Wolfcamp, Strawn and Atoka horizons in the Spraberry/Wolfcamp area and discoveries in the Eagle Ford Shale.
Sales of minerals-in-place. Sales of minerals-in-place in 2014, 2013 and 2012 are primarily related to the divestments of the Hugoton field, the Barnett Shale field and Pioneer Alaska in 2014, the divestment of 40 percent of the Company's interest in 207,000 net acres in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas in 2013, and the divestment of Pioneer South Africa in 2012. See Note C for additional information regarding the Company's divestitures and discontinued operations.
Purchases of minerals-in-place. Purchases of minerals-in-place during all years are primarily attributable to acquisitions in the Company's Spraberry/Wolfcamp area.
Improved recovery. Additions from improved recovery during 2012 related to recognizing secondary recovery reserves attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012


The following table provides the Company's proved developed and proved undeveloped reserves for the years ended December 31, 2014, 2013 and 2012.
    
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Gas
(MMcf)
 
Total
(MBOE)
Proved Developed Reserves:
 
 
 
 
 
 
 
December 31, 2012
230,700

 
134,637

 
1,605,209

 
632,872

December 31, 2013
256,638

 
148,161

 
1,703,667

 
688,743

December 31, 2014
267,193

 
130,206

 
1,486,289

 
645,113

 
 
 
 
 
 
 
 
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Gas
(MMcf)
 
Total
(MBOE)
Proved Undeveloped Reserves:
 
 
 
 
 
 
 
December 31, 2012
256,138

 
97,939

 
592,271

 
452,789

December 31, 2013
85,467

 
37,261

 
202,674

 
156,507

December 31, 2014
84,891

 
39,038

 
182,583

 
154,360

The following table summarizes the Company's proved undeveloped reserves activity during the year ended December 31, 2014 (in MBOE).  
        
Beginning proved undeveloped reserves
156,507

Revisions of previous estimates
(59,329
)
Extensions and discoveries
90,865

Sales of minerals-in-place
(6,535
)
Transfers to proved developed
(27,148
)
Ending proved undeveloped reserves
154,360

As of December 31, 2014, the Company had 394 proved undeveloped well locations as compared to 783 and 3,810 at December 31, 2013 and 2012, respectively. The Company has no proved undeveloped well locations that are scheduled to be drilled more than five years from their original date of booking.
The changes in proved undeveloped reserves during 2014 are comprised of the following items:
Revisions of previous estimates. Revisions of previous estimates are comprised of 59 MMBOE of negative revisions due to removing vertical proved undeveloped locations in the Spraberry/Wolfcamp play, replacing previously recorded undeveloped horizontal locations with new locations based on new well performance data, updated well performance profiles and updated cost estimates. As described in revisions of previous estimates of total proved reserves, the Company shifted its drilling activity in the Spraberry/Wolfcamp play in the Midland Basin of West Texas during 2014 and 2013 from vertical drilling to horizontal drilling, resulting in the 2014 removal of 39 MMBOE associated with proved undeveloped vertical locations. During 2014, the Company also removed 14 MMBOE of proved undeveloped reserves associated with horizontal locations in the Spraberry/Wolfcamp area that are no longer expected to be drilled within five years as a result of optimizing the Company's horizontal drilling program in other areas of the field.
Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions and discoveries in the Spraberry, Wolfcamp, Strawn and Atoka horizons in the Spraberry/Wolfcamp area and discoveries in the Eagle Ford Shale.
Sales of minerals-in-place. Sales of minerals-in-place are primarily related to the divestments of the Hugoton field, the Barnett Shale field and Pioneer Alaska.
Transfers to proved developed. Transfers to proved developed reserves represents those undeveloped proved reserves that moved to proved developed as a result of development drilling during 2014. During 2014, the Company incurred $1.5 billion of development costs and developed 17 percent of its proved undeveloped reserves.
The Company uses both public and proprietary geologic data to establish continuity of the formation and its producing properties. This included seismic data and interpretations (2-D, 3-D and micro seismic); open hole log information (both vertical

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012


and horizontally collected) and petrophysical analysis of the log data; mud logs; gas sample analysis; drill cutting samples; measurements of total organic content; thermal maturity; sidewall cores and data measured from the Company's internal core analysis facility. After the geologic area was shown to be continuous, statistical analysis of existing producing wells was conducted to generate areas of reasonable certainty at distances from established production. As a result of this analysis, proved undeveloped reserves for drilling locations within these areas of reasonable certainty were recorded during 2014.
While the Company expects, based on Management's Price Outlooks, that future operating cash flows will provide adequate funding for future development of its proved undeveloped reserves over the next five years, it may also use any combination of internally-generated cash flows, cash and cash equivalents on hand, availability under its credit facility, proceeds from the sale of joint interests and nonstrategic assets or external financing sources to fund these and other capital expenditures, including exploratory drilling and acquisitions. The following table represents the estimated timing and cash flows of developing the Company's proved undeveloped reserves as of December 31, 2014 (dollars in millions):
 
Year Ended December 31, (a)
Estimated
Future
Production
(MBOE)
 
Future Cash
Inflows
 
Future
Production
Costs
 
Future
Development
Costs
 
Future Net
Cash Flows
2015
6,236

 
$
412

 
$
51

 
$
677

 
$
(316
)
2016
13,139

 
788

 
106

 
687

 
(5
)
2017
14,282

 
848

 
117

 
432

 
299

2018
13,608

 
846

 
115

 
459

 
272

2019
12,731

 
798

 
110

 
219

 
469

Thereafter (b)
94,364

 
5,477

 
1,362

 
24

 
4,091

 
154,360

 
$
9,169

 
$
1,861

 
$
2,498

 
$
4,810

______________________ 
(a)
Production and cash flows represent the drilling results from the respective year plus the incremental effects of proved undeveloped drilling.
(b)
The $24 million of future development costs includes (i) $4 million of completion costs forecasted in 2020 and (ii) $20 million of net abandonment costs in future years.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012



Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed by applying commodity prices used in determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end estimated costs) to be incurred in developing and producing the proved reserves, discounted using a rate of ten percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future cash flow estimates do not include the effects of the Company's commodity derivative contracts.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.
The following tables provide the standardized measure of discounted future cash flows as of December 31, 2014, 2013 and 2012, as well as a rollforward in total for each respective year:
 
 
December 31,
 
2014
 
2013
 
2012
 
(in millions)
Oil and gas producing activities:
 
 
 
 
 
Future cash inflows
$
42,061

 
$
43,542

 
$
56,693

Future production costs
(18,228
)
 
(20,044
)
 
(23,977
)
Future development costs (a)
(4,285
)
 
(4,102
)
 
(9,804
)
Future income tax expense
(4,874
)
 
(4,955
)
 
(6,600
)
 
14,674

 
14,441

 
16,312

10% annual discount factor
(6,889
)
 
(7,140
)
 
(9,959
)
Standardized measure of discounted future cash flows (b)
$
7,785

 
$
7,301

 
$
6,353

 __________________
(a)
Includes $626 million, $815 million and $840 million of undiscounted future asset retirement expenditures estimated as of December 31, 2014, 2013 and 2012, respectively, using current estimates of future abandonment costs. See Note I for additional information regarding the Company's discounted asset retirement obligations.
(b)
Includes $283 million attributable to a 48 percent noncontrolling interest in Pioneer Southwest for 2012.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012



Changes in Standardized Measure of Discounted Future Net Cash Flows 
 
Year Ended December 31,
 
2014
 
2013
 
2012
 
(in millions)
Oil and gas sales, net of production costs
$
(2,813
)
 
$
(2,500
)
 
$
(2,038
)
Revisions of previous estimates:
 
 
 
 
 
Net changes in prices and production costs
(1,570
)
 
(1,772
)
 
(3,070
)
Changes in future development costs
115

 
1,340

 
(1,649
)
Revisions in quantities
(581
)
 
(2,675
)
 
(1,127
)
Accretion of discount
1,326

 
832

 
1,109

Changes in production rates, timing and other (a)
608

 
2,454

 
743

Extensions, discoveries and improved recovery
4,086

 
2,248

 
1,731

Development costs incurred during the period
403

 
1,255

 
1,400

Sales of minerals-in-place
(1,123
)
 
(338
)
 
(38
)
Purchases of minerals-in-place
34

 
4

 
172

Change in present value of future net revenues
485

 
848

 
(2,767
)
Net change in present value of future income taxes
(1
)
 
100

 
1,307

 
484

 
948

 
(1,460
)
Balance, beginning of year
7,301

 
6,353

 
7,813

Balance, end of year
$
7,785

 
$
7,301

 
$
6,353

__________________
(a)
The Company's changes in Standardized Measure attributable to production rates, timing and other primarily represent changes in the Company's estimates of when proved reserve quantities will be realized. During the twelve months ended December 31, 2013, the Company's undiscounted future net cash flows from proved reserves declined; however, the timing of the recovery of the future net cash flows accelerated, partially due to the removal of lower-return-on-investment vertical well locations, resulting in an increase in Standardized Measure.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2014, 2013 and 2012


Selected Quarterly Financial Results
The following table provides selected quarterly financial results for the years ended December 31, 2014 and 2013, with adjustments to conform to the annual results:
 
 
Quarter
 
 
First
 
Second
 
Third
 
Fourth
 
 
(in millions, except per share data)
Year Ended December 31, 2014:
 
 
 
 
 
 
 
 
Oil and gas revenues:
 
 
 
 
 
 
 
 
As reported
 
$
910

 
$
959

 
$
967

 
$
804

Adjustment for discontinued operations
 
(20
)
 
(21
)
 
—

 
—

As Adjusted
 
$
890

 
$
938

 
$
967

 
$
804

Total revenues and other income: (a)
 
 
 
 
 
 
 
 
As reported
 
$
963

 
$
953

 
$
1,513

 
$
1,666

Adjustment for discontinued operations
 
(19
)
 
(21
)
 
—

 
—

As Adjusted
 
$
944

 
$
932

 
$
1,513

 
$
1,666

Total costs and expenses:
 
 
 
 
 
 
 
 
As reported
 
$
761

 
$
861

 
$
866

 
$
1,000

Adjustment for discontinued operations
 
(13
)
 
(16
)
 
—

 
—

As Adjusted
 
$
748

 
$
845

 
$
866

 
1,000

Net income
 
$
123

 
$
1

 
$
374

 
$
431

Net income attributable to common stockholders
 
$
123

 
$
1

 
$
374

 
$
431

Net income attributable to common stockholders per share:
 
 
 
 
 
 
 
 
Basic
 
$
0.85

 
$
0.01

 
$
2.58

 
$
2.92

Diluted
 
$
0.85

 
$
0.01

 
$
2.58

 
$
2.91

Year Ended December 31, 2013:
 
 
 
 
 
 
 
 
Oil and gas revenues:
 
 
 
 
 
 
 
 
As reported
 
$
729

 
$
781

 
$
836

 
$
810

Adjustment for discontinued operations
 
(16
)
 
(18
)
 
(16
)
 
(18
)
As Adjusted
 
$
713

 
$
763

 
$
820

 
$
792

Total revenues and other income: (a)
 
 
 
 
 
 
 
 
As reported
 
$
767

 
$
1,159

 
$
823

 
$
971

Adjustment for discontinued operations
 
(16
)
 
(18
)
 
(16
)
 
(18
)
As Adjusted
 
$
751

 
$
1,141

 
$
807

 
$
953

Total costs and expenses: (b)
 
 
 
 
 
 
 
 
As reported
 
$
624

 
$
636

 
$
694

 
$
2,328

Adjustment for discontinued operations
 
(14
)
 
(13
)
 
(14
)
 
(13
)
As Adjusted
 
$
610

 
$
623

 
$
680

 
$
2,315

Net income (loss)
 
$
109

 
$
351

 
$
98

 
$
(1,358
)
Net income (loss) attributable to common stockholders
 
$
101

 
$
337

 
$
91

 
$
(1,367
)
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
)
 _____________________
(a)
The Company's total revenues and other income include net derivative losses of $104 million and $218 million during the first and second quarters of 2014, respectively, and net derivative gains of $341 million and $693 million during the third and fourth quarters of 2014, respectively. During 2013, the Company's total revenues and other income include net derivative gains of $144 million and $4 million during the second and fourth quarters, respectively, and net derivative losses of $42 million and $102 million during the first and third quarters, respectively.
(b)
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 $49 million to impair the carrying value of excess materials inventory and other property and equipment held for sale.

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ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A.
CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 ("the Exchange Act"), the effectiveness of the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the Company's disclosure controls and procedures were effective, as of the end of the period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Company's management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Changes in internal control over financial reporting. There have been no changes in the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2014 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process designed by or under the supervision of the Company's principal executive officer and principal financial officer and effected by the Board, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.
The Company's management, with the participation of its principal executive officer and principal financial officer assessed the effectiveness, as of December 31, 2014, of the Company's internal control over financial reporting based on the criteria for effective internal control over financial reporting established in "Internal Control — Integrated Framework (2013)," issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting at a reasonable assurance level as of December 31, 2014, based on those criteria.
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2014. The report, which expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2014, is included in this Item under the heading "Report of Independent Registered Public Accounting Firm."

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REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The Board of Directors and Stockholders of
Pioneer Natural Resources Company
We have audited Pioneer Natural Resources Company's (the "Company") internal control over financial reporting as of December 31, 2014, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Pioneer Natural Resources Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Pioneer Natural Resources Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2014, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Natural Resources Company as of December 31, 2014 and 2013 and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period ended December 31, 2014, and our report dated February 19, 2015 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Dallas, Texas
February 19, 2015


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ITEM 9B.
OTHER INFORMATION
None.
PART III

ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2015 and is incorporated herein by reference.
 
ITEM 11.
EXECUTIVE COMPENSATION
The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2015 and is incorporated herein by reference.
 
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance under Equity Compensation Plans
The following table summarizes information about the Company's equity compensation plans as of December 31, 2014:
 
 
Number of securities 
to be issued upon exercise of
outstanding options,
warrants and rights (a)
 
Weighted-average
exercise price of
outstanding
options, warrants
and rights
 
Number of securities remaining
available for future issuance under equity compensation
plans (excluding securities reflected in first column)
Equity compensation plans approved by security holders:
 
 
 
 
 
Pioneer Natural Resources Company:
 
 
 
 
 
2006 Long-Term Incentive Plan (b)(c)
106,278

 
$
45.86

 
2,361,918

Employee Stock Purchase Plan (d)
—

 
—

 
475,362

Equity compensation plans not approved by security holders (e)
—

 
—

 
654,842

Total:
106,278

 
$
45.86

 
3,492,122

 _______________________
(a)
There are no outstanding warrants or equity rights awarded under the Company's equity compensation plans. The securities listed do not include restricted stock awarded under the Company's previous Long-Term Incentive Plan and the Company's 2006 Long-Term Incentive Plan.
(b)
In May 2006, the stockholders of the Company approved the 2006 Long-Term Incentive Plan, which provided for the issuance of up to 9.1 million awards, as was supplementally approved by the stockholders of the Company during May 2009. Awards under the 2006 Long-Term Incentive Plan can be in the form of stock options, stock appreciation rights, performance units, restricted stock and restricted stock units. No additional awards may be made under the prior Long-Term Incentive Plan.
(c)
The number of securities remaining for future issuance has been reduced by the maximum number of shares that could be issued pursuant to outstanding grants of performance units at December 31, 2014.
(d)
The number of remaining securities available for future issuance under the Company's Employee Stock Purchase Plan is based on the original authorized issuance of 750,000 shares plus an additional 500,000 shares supplementally approved less 774,638 cumulative shares issued through December 31, 2014.
(e)
These represent awards available for issuance under the Pioneer Southwest 2008 Long-Term Incentive Plan, which was assumed by the Company as part of the Pioneer Southwest merger.
See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of each of the Company's equity compensation plans.

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The remaining information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2015 and is incorporated herein by reference.
ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2015 and is incorporated herein by reference. 
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2015 and is incorporated herein by reference.
PART IV
 
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
Listing of Financial Statements
Financial Statements
The following consolidated financial statements of the Company are included in "Item 8. Financial Statements and Supplementary Data":
•
Report of Independent Registered Pubic Accounting Firm
•
Consolidated Balance Sheets as of December 31, 2014 and 2013
•
Consolidated Statements of Operations for the Years Ended December 31, 2014, 2013 and 2012
•
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2014, 2013 and 2012
•
Consolidated Statements of Equity for the Years Ended December 31, 2014, 2013 and 2012
•
Consolidated Statements of Cash Flows for the Years Ended December 31, 2014, 2013 and 2012
•
Notes to Consolidated Financial Statements
•
Unaudited Supplementary Information

(b)
Exhibits
The exhibits to this Report that are required to be filed pursuant to Item 15(b) are listed below and in the "Exhibit Index" attached hereto.
 
(c)
Financial Statement Schedules
No financial statement schedules are required to be filed as part of this Report or they are inapplicable.

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Exhibits 
Exhibit
Number
 
Description
2.1
—  
Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 12, 2013).
2.2
—  
Amendment No. 1, entered into as of October 25, 2013, to the Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 31, 2013).

3.1
—  
Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 26, 1997, Registration No. 333-26951).
3.2
—  
Certificate of Amendment of the Amended and Restated Certificate of Incorporation, effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
3.3
—  
Third Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
4.1
—  
Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4, dated June 26, 1997, Registration No. 333-26951).
4.2
—  
Indenture dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.3
—  
First Supplemental Indenture dated as of January 13, 1998, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).

4.4
—  
Second Supplemental Indenture dated as of April 11, 2000, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-13245).

4.5
—  
Third Supplemental Indenture dated as of April 30, 2002, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-13245).

4.6
—  
Fourth Supplemental Indenture dated as of July 15, 2004, among the Company and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.7
—  
Fifth Supplemental Indenture dated as of July 15, 2004, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).

4.8
—  
Sixth Supplemental Indenture, dated as of May 1, 2006, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York Trust Company, N.A., as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 4, 2006).

4.9
—  
Seventh Supplemental Indenture, dated as of March 12, 2007, among the Company, Pioneer Natural Resources USA, Inc., The Bank of New York Trust Company, N.A, as original trustee under the indenture, and Wells Fargo Bank, National Association, as series trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 12, 2007).

4.10
—  
Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).
4.11
—
First Supplemental Indenture dated January 22, 2008 by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).


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4.12
—  
Second Supplemental Indenture dated November 13, 2009 by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 13, 2009).

4.13
—  
Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.14
—  
First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
10.1
—  
Second Amended and Restated 5-Year Revolving Credit Agreement dated as of March 31, 2011, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on April 5, 2011).
10.2
—  
First Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement dated as of December 20, 2012, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 20, 2012).
10.3 H
—  
The Company's Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35087, filed with the SEC on September 8, 1997).
10.4 H
—  
First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.5 H
—  
Amendment No. 2 to the Company's Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.6 H
—  
Amendment No. 3 to the Company's Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.7 H
—  
Amendment No. 4 to the Company's Long-Term Incentive Plan, effective as of November 20, 2003 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.8 H
—  
Amendment No. 5 to the Company's Long-Term Incentive Plan, effective as of May 12, 2004 (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.9 H
—  
Amendment No. 6 to the Company's Long-Term Incentive Plan, effective as of December 17, 2004 (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.10 H
—  
Amendment No. 7 to the Company's Long-Term Incentive Plan, effective November 20, 2008 (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.11 H
—  
Form of Omnibus Nonstatutory Stock Option Agreement for Option Award Participants with respect to grants under the Company's Long-Term Incentive Plan (Group 1) (incorporated by reference to Exhibit 10.20 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.12 H
—  
Pioneer Natural Resources Company 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006).
10.13 H
—  
First Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective November 20, 2008 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.14 H
—  
Second Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective May 28, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 28, 2009).
10.15 H
—  
Third Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.16 H
—  
Fourth Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).

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10.17 H
—  
Fifth Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective August 20, 2012 (incorporated by reference to Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, File No. 1-13245).

10.18 H (a)
—  
Form of Restricted Stock Unit Award Agreement for Non-Employee Directors to be used in connection with initial equity awards under the Company's 2006 Long-Term Incentive Plan.
10.19 H
—  
Form of Restricted Stock Unit Award Agreement for Non-Employee Directors to be used in connection with annual equity awards under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 1-13245).

10.20 H
—  
Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long-Term Incentive Plan. (incorporated by reference to Exhibit 10.64 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.21 H
—  
Form of Restricted Stock Award Agreement between the Company and Timothy L. Dove, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.22 H
—  
Form of Nonstatutory Stock Option Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.23 H
—  
Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.24 H
—  
Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.25 H
—  
Form of Restricted Stock Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.26 H 
—  
Form of Restricted Stock Unit Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).

10.27 H
—  
Pioneer Natural Resources Company Employee Stock Purchase Plan, as amended and restated, effective September 1, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-13245).
10.28 H
—  
First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan, effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
10.29 H
—  
The Company's Executive Deferred Compensation Plan, Amended and Restated, effective as of August 1, 2002 (incorporated by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.30 H
—  
Amendment No. 1 to the Company's Executive Deferred Compensation Plan, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-13245).
10.31 H
—  
Amended and Restated Executive Deferred Compensation Plan, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).

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10.32 H
—  
Amendment No. 1 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245).
10.33 H
—  
Amendment No. 2 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011 (incorporated by reference to Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.34 H
—  
Amendment No. 3 to the Company's Amended and Restated Executive Deferred Compensation Plan, executed August 19, 2013 and effective January 1, 2009 (incorporated by reference to Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.35 H
—  
Amendment No. 4 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2014 (incorporated by reference to Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.36 H
—  
Pioneer USA 401(k) and Matching Plan, Amended and Restated, effective as of January 1, 2013 (incorporated by reference to Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.37 H (a)
—  
First Amendment to Pioneer USA 401(k) and Matching Plan dated February 27, 2014.
10.38 H     (a)
—  
Second Amendment to Pioneer USA 401(k) and Matching Plan dated November 10, 2014.
10.39 H
—  
Indemnification Agreement, dated February 21, 2013, between the Company and Thomas D. Arthur, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 26, 2013).

10.40 H
—
Indemnification Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 8, 2013).
10.41 H
—
Indemnification Agreement, dated March 4, 2013, between the Company and J.D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014).
10.42 H
—  
Indemnification Agreement, dated effective July 23, 2013, between the Company and Stacy P. Methvin, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 29, 2013).
10.43 H
—  
Indemnification Agreement, dated March 13, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
10.44 H
—  
Indemnification Agreement, dated July 7, 2014, between the Company and Phillip A. Gobe, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 10, 2014).
10.45 H
—  
Severance Agreement dated August 16, 2005, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Severance Agreement (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13245).
10.46 H
—  
Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.47 H
—
Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.48 H
—  
Severance Agreement, dated effective August 10, 2005, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Severance Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).

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10.49 H
—  
Amendment to Severance Agreement, dated December 8, 2008, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Amendment to Severance Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.50 H
—  
Severance Agreement, dated effective January 14, 2010, between the Company and J. D. Hall (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.51 H     
—  
Severance Agreement, dated effective January 1, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-13245).
10.52 H
—  
Change in Control Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 1-13245).
10.53 H
—  
Change in Control Agreement, dated March 4, 2013, between the Company and J. D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.54 H
—  
Change in Control Agreement, dated March 13, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-13245).
10.55 H
—  
Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (now known as the Pioneer 2008 PSE Employee Long Term Incentive Plan) (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 17, 2013).
10.56 H
—
First Amendment to Pioneer 2008 PSE Employee Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 17, 2013).
10.57 H
—  
Form of Phantom Unit Award Agreement between the General Partner of Pioneer Southwest Energy Partners L.P. and Scott D. Sheffield, with respect to awards of phantom units made under the Pioneer 2008 PSE Employee Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the General Partner and each of its other recipients of phantom unit awards and identifying the material differences between those agreements and the filed Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.1 to Pioneer Southwest Energy Partners L.P.'s Current Report on Form 8-K, File No. 001-34032, filed with the SEC on March 9, 2010).
12.1  (a)
—  
Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.
21.1  (a)
—  
Subsidiaries of the registrant.
23.1  (a)
—  
Consent of Ernst & Young LLP.
23.2  (a)
—  
Consent of Netherland, Sewell & Associates, Inc.
23.3  (a)
—  
Consent of Ryder Scott Company, L.P.
31.1  (a)
—  
Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2  (a)
—  
Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1  (b)
—  
Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2  (b)
—  
Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
95.1 (a)
—  
Mine Safety Disclosure pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
99.1  (a)
—  
Report of Netherland, Sewell & Associates, Inc.
101. INS  (a)
—  
XBRL Instance Document.
101. SCH  (a)
—  
XBRL Taxonomy Extension Schema.
101. CAL  (a)
—  
XBRL Taxonomy Extension Calculation Linkbase Document.
101. DEF  (a)
—  
XBRL Taxonomy Extension Definition Linkbase Document.
101. LAB  (a)
—  
XBRL Taxonomy Extension Label Linkbase Document.
101. PRE  (a)
—  
XBRL Taxonomy Extension Presentation Linkbase Document.

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 __________________________
(a)
Filed herewith.
(b)
Furnished herewith.
H
Executive Compensation Plan or Arrangement.


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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
 
 
PIONEER NATURAL RESOURCES COMPANY
Date:
February 19, 2015
 
 
 
 
 
 
 
 
 
 
By:
 
/s/ Scott D. Sheffield
 
 
 
 
Scott D. Sheffield,
Chairman of the Board and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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Signature
  
Title
 
Date
 
 
 
/s/ Scott D. Sheffield
  
Chairman of the Board and Chief Executive Officer
(principal executive officer)
 
February 19, 2015
Scott D. Sheffield
 
 
 
 
 
 
/s/ Timothy L. Dove
 
President, Chief Operating Officer and Director
 
February 19, 2015
Timothy L. Dove
 
 
 
 
 
 
 
 
/s/ Richard P. Dealy
  
Executive Vice President and Chief Financial Officer
(principal financial officer)
 
February 19, 2015
Richard P. Dealy
 
 
 
 
 
 
/s/ Margaret M. Montemayor
  
Vice President and Chief Accounting Officer
(principal accounting officer)
 
February 19, 2015
Margaret M. Montemayor
 
 
 
 
 
 
/s/ Edison C. Buchanan
  
Director
 
February 19, 2015
Edison C. Buchanan
 
 
 
 
 
 
/s/ Andrew F. Cates
  
Director
 
February 19, 2015
Andrew F. Cates
 
 
 
 
 
 
/s/ Phillip A. Gobe
  
Director
 
February 19, 2015
Phillip A. Gobe
 
 
 
 
 
 
/s/ Larry R. Grillot
 
Director
 
February 19, 2015
Larry R. Grillot
 
 
 
 
 
 
 
 
/s/ Stacy P. Methvin
 
Director
 
February 19, 2015
Stacy P. Methvin
 
 
 
 
 
 
 
 
/s/ Royce W. Mitchell
 
Director
 
February 19, 2015
Royce W. Mitchell
 
 
 
 
 
 
 
 
/s/ Charles E. Ramsey, Jr.
  
Director
 
February 19, 2015
Charles E. Ramsey, Jr.
 
 
 
 
 
 
/s/ Frank A. Risch
  
Director
 
February 19, 2015
Frank A. Risch
 
 
 
 
 
 
/s/ J. Kenneth Thompson
  
Director
 
February 19, 2015
J. Kenneth Thompson
 
 
 
 
 
 
/s/ Jim A. Watson
  
Director
 
February 19, 2015
Jim A. Watson
 
 
 
 
 
 
 
 
/s/ Phoebe A. Wood
 
Director
 
February 19, 2015
Phoebe A. Wood
 
 
 

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Exhibit Index
Exhibit
Number
 
Description
2.1
—  
Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 12, 2013).
2.2
—  
Amendment No. 1, entered into as of October 25, 2013, to the Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer Natural Resources USA, Inc., PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 31, 2013).

3.1
—  
Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 26, 1997, Registration No. 333-26951).
3.2
—  
Certificate of Amendment of the Amended and Restated Certificate of Incorporation, effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
3.3
—  
Third Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
4.1
—  
Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4, dated June 26, 1997, Registration No. 333-26951).
4.2
—  
Indenture dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.3
—  
First Supplemental Indenture dated as of January 13, 1998, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).

4.4
—  
Second Supplemental Indenture dated as of April 11, 2000, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-13245).

4.5
—  
Third Supplemental Indenture dated as of April 30, 2002, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-13245).

4.6
—  
Fourth Supplemental Indenture dated as of July 15, 2004, among the Company and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.7
—  
Fifth Supplemental Indenture dated as of July 15, 2004, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).

4.8
—  
Sixth Supplemental Indenture, dated as of May 1, 2006, among the Company, Pioneer Natural Resources USA, Inc. and The Bank of New York Trust Company, N.A., as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 4, 2006).

4.9
—  
Seventh Supplemental Indenture, dated as of March 12, 2007, among the Company, Pioneer Natural Resources USA, Inc., The Bank of New York Trust Company, N.A, as original trustee under the indenture, and Wells Fargo Bank, National Association, as series trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 12, 2007).

4.10
—  
Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).
4.11
—
First Supplemental Indenture dated January 22, 2008 by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).


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4.12
—  
Second Supplemental Indenture dated November 9, 2009 by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 13, 2009).

4.13
—  
Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.14
—  
First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer Natural Resources USA, Inc. and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
10.1
—  
Second Amended and Restated 5-Year Revolving Credit Agreement dated as of March 31, 2011, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on April 5, 2011).
10.2
—  
First Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement dated as of December 20, 2012, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 20, 2012).
10.3 H
—  
The Company's Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35087, filed with the SEC on September 8, 1997).
10.4 H
—  
First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.5 H
—  
Amendment No. 2 to the Company's Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.6 H
—  
Amendment No. 3 to the Company's Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.7 H
—  
Amendment No. 4 to the Company's Long-Term Incentive Plan, effective as of November 20, 2003 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.8 H
—  
Amendment No. 5 to the Company's Long-Term Incentive Plan, effective as of May 12, 2004 (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.9 H
—  
Amendment No. 6 to the Company's Long-Term Incentive Plan, effective as of December 17, 2004 (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.10 H
—  
Amendment No. 7 to the Company's Long-Term Incentive Plan, effective November 20, 2008 (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.11 H
—  
Form of Omnibus Nonstatutory Stock Option Agreement for Option Award Participants with respect to grants under the Company's Long-Term Incentive Plan (Group 1) (incorporated by reference to Exhibit 10.20 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.12 H
—  
Pioneer Natural Resources Company 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006).
10.13 H
—  
First Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective November 20, 2008 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.14 H
—  
Second Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective May 28, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 28, 2009).
10.15 H
—  
Third Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.16 H
—  
Fourth Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).

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10.17 H
—  
Fifth Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective August 20, 2012 (incorporated by reference to Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, File No. 1-13245).

10.18 H (a)
—  
Form of Restricted Stock Unit Award Agreement for Non-Employee Directors to be used in connection with initial equity awards under the Company's 2006 Long-Term Incentive Plan.
10.19 H
—  
Form of Restricted Stock Unit Award Agreement for Non-Employee Directors to be used in connection with annual equity awards under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 1-13245).

10.20 H
—  
Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to awards made under the Company's 2006 Long-Term Incentive Plan. (incorporated by reference to Exhibit 10.64 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.21 H
—  
Form of Restricted Stock Award Agreement between the Company and Timothy L. Dove, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.22 H
—  
Form of Nonstatutory Stock Option Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.23 H
—  
Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.24 H
—  
Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.25 H
—  
Form of Restricted Stock Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.26 H 
—  
Form of Restricted Stock Unit Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).

10.27 H
—  
Pioneer Natural Resources Company Employee Stock Purchase Plan, as amended and restated, effective September 1, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-13245).
10.28 H
—  
First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan, effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
10.29 H
—  
The Company's Executive Deferred Compensation Plan, Amended and Restated, effective as of August 1, 2002 (incorporated by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.30 H
—  
Amendment No. 1 to the Company's Executive Deferred Compensation Plan, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-13245).
10.31 H
—  
Amended and Restated Executive Deferred Compensation Plan, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).

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10.32 H
—  
Amendment No. 1 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245).
10.33 H
—  
Amendment No. 2 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011 (incorporated by reference to Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.34 H
—  
Amendment No. 3 to the Company's Amended and Restated Executive Deferred Compensation Plan, executed August 19, 2013 and effective January 1, 2009 (incorporated by reference to Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.35 H
—  
Amendment No. 4 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2014 (incorporated by reference to Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.36 H
—  
Pioneer USA 401(k) and Matching Plan, Amended and Restated, effective as of January 1, 2013 (incorporated by reference to Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.37 H (a)
—  
First Amendment to Pioneer USA 401(k) and Matching Plan dated February 27, 2014.
10.38 H     (a)
—  
Second Amendment to Pioneer USA 401(k) and Matching Plan dated November 10, 2014.
10.39 H
—  
Indemnification Agreement, dated February 21, 2013, between the Company and Thomas D. Arthur, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 26, 2013).

10.40 H
—
Indemnification Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 8, 2013).
10.41 H
—
Indemnification Agreement, dated March 4, 2013, between the Company and J.D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014).
10.42 H
—  
Indemnification Agreement, dated effective July 23, 2013, between the Company and Stacy P. Methvin, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 29, 2013).
10.43 H
—  
Indemnification Agreement, dated March 13, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
10.44 H
—  
Indemnification Agreement, dated July 7, 2014, between the Company and Phillip A. Gobe, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 10, 2014).
10.45 H
—  
Severance Agreement dated August 16, 2005, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Severance Agreement (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13245).
10.46 H
—  
Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.47 H
—
Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.48 H
—  
Severance Agreement, dated effective August 10, 2005, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Severance Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).

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10.49 H
—  
Amendment to Severance Agreement, dated December 8, 2008, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Amendment to Severance Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.50 H
—  
Severance Agreement, dated effective January 14, 2010, between the Company and J. D. Hall (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.51 H
—  
Severance Agreement, dated effective January 1, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-13245).
10.52 H
—  
Change in Control Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 1-13245).
10.53 H
—  
Change in Control Agreement, dated March 4, 2013, between the Company and J. D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.54 H
—  
Change in Control Agreement, dated March 13, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-13245).
10.55 H
—  
Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (now known as the Pioneer 2008 PSE Employee Long Term Incentive Plan) (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 17, 2013).
10.56 H
—
First Amendment to Pioneer 2008 PSE Employee Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 17, 2013).
10.57 H
—  
Form of Phantom Unit Award Agreement between the General Partner of Pioneer Southwest Energy Partners L.P. and Scott D. Sheffield, with respect to awards of phantom units made under the Pioneer 2008 PSE Employee Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the General Partner and each of its other recipients of phantom unit awards and identifying the material differences between those agreements and the filed Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.1 to Pioneer Southwest Energy Partners L.P.'s Current Report on Form 8-K, File No. 001-34032, filed with the SEC on March 9, 2010).
12.1  (a)
—  
Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.
21.1  (a)
—  
Subsidiaries of the registrant.
23.1  (a)
—  
Consent of Ernst & Young LLP.
23.2  (a)
—  
Consent of Netherland, Sewell & Associates, Inc.
23.3  (a)
—  
Consent of Ryder Scott Company, L.P.
31.1  (a)
—  
Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2  (a)
—  
Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1  (b)
—  
Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2  (b)
—  
Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
95.1 (a)
—  
Mine Safety Disclosure pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
99.1  (a)
—  
Report of Netherland, Sewell & Associates, Inc.
101.INS (a)
—  
XBRL Instance Document.
101. SCH (a)
—  
XBRL Taxonomy Extension Schema.
101. CAL  (a)
—  
XBRL Taxonomy Extension Calculation Linkbase Document.
101. DEF  (a)
—  
XBRL Taxonomy Extension Definition Linkbase Document.
101. LAB  (a)
—  
XBRL Taxonomy Extension Label Linkbase Document.
101. PRE (a)
—  
XBRL Taxonomy Extension Presentation Linkbase Document.

135
Table of Contents

 _____________________________
(a)
Filed herewith.
(b)
Furnished herewith.
H
Executive Compensation Plan or Arrangement.


136