10-K 1 pxd-20151231x10k.htm 10-K 10-K
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, 2015
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.    ¨
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
$
20,541,004,904

 
 
Number of shares of Common Stock outstanding as of February 12, 2016
163,266,510

DOCUMENTS INCORPORATED BY REFERENCE:
(1)
Portions of the Definitive Proxy Statement for the Company's Annual Meeting of Shareholders to be held during May 2016 are incorporated into Part III of this report.


TABLE OF CONTENTS

 
 
Page
Item 1.
 
 
 
 
 
 
Item 1A.
Item 1B.
Item 2.
 
 
 
 
Item 3.
Item 4.
Item 5.
 
Item 6.
Item 7.
 
 
 
First Quarter 2016 Outlook
 
 
 
 
 
 
 
Item 7A.
 
 
Item 8.
 
 
 
 
 
Item 9.
Item 9A.
 
 
Item 9B.


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TABLE OF CONTENTS



3


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.
"Bcf" means one billion cubic feet.
"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.
"BOEPD" means BOE per day.
"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.
"CBM" means coal bed methane.
"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.
"DD&A" means depletion, depreciation and amortization.
"Field fuel" means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a sales point.
"GAAP" means accounting principles that are generally accepted in the United States of America.
"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.
"MBbl" means one thousand Bbls.
"MBOE" means one thousand BOEs.
"Mcf" means one thousand cubic feet and is a measure of gas volume.
"MMBbl" means one million Bbls.
"MMBOE" means one million BOEs.
"MMBtu" means one million Btus.
"MMcf" means one million cubic feet.
"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.
"NGL" means natural gas liquid.
"NYMEX" means the New York Mercantile Exchange.
"NYSE" means the New York Stock Exchange.
"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.
"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.
"U.S." means United States.
"WTI" means West Texas intermediate, a light, sweet blend of oil produced from fields in western Texas.
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 another office in Midland, Texas. At December 31, 2015, the Company had 3,732 employees, 1,533 of whom were employed in field and plant operations and 853 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 information from time to time in its press releases, investor presentations posted on its website and in publicly accessible conferences. Such information, including information posted on or connected to the Company's website, is not a part of, or incorporated by reference in, this Report or any other document the Company files with or furnishes to the SEC.
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 acquisition and divestiture activities. These strategies are primarily anchored by the Company's interests in the long-lived Spraberry/Wolfcamp oil field located in West Texas, which has an estimated remaining productive life in excess of 40 years. Underlying the Spraberry/Wolfcamp field is 70 percent of the Company's total proved oil and gas reserves as of December 31, 2015. Complementing this growth area, the Company has oil and gas production activities and development and exploration opportunities in the following areas:
the liquid-rich Eagle Ford Shale play located in South Texas;
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.
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. Until the middle of 2014, North American oil prices had been fairly stable 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 exports to

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PIONEER NATURAL RESOURCES COMPANY

the United States, 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 continued in 2015, resulting in further declines in oil prices, and the supply of oil in 2016 is expected to continue to outpace demand growth, with worldwide storage levels continuing to increase. With major world producers expecting to continue producing at current levels and the re-introduction of Iranian supplies previously subject to international sanctions, oil prices are expected to remain under pressure during 2016.
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. NGL product supplies are expected to remain at elevated levels during 2016, which is expected to keep NGL prices under pressure during 2016.
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 minimal economic demand growth in the United States. The increases in gas prices during the latter part of 2013 and the first nine months of 2014 were primarily related to reduced drilling activity in gas shale plays coupled with demand increases associated with colder winter weather, which resulted in reduced gas storage levels during 2014. Gas prices began decreasing in the fourth quarter of 2014 and continued to decline throughout 2015 and into 2016 as a result of supply increases and warmer than normal winter weather, which has resulted in gas storage levels being at historical highs. The current oversupply of gas is expected to continue during 2016.
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, higher storage levels and pipeline, gas plant and NGL fractionation infrastructure capacity limitations. These factors led to a reduction during 2015 in United States NYMEX oil, NGL and gas prices compared to international prices for similar commodities, including Brent oil prices, although United States and international prices have recently converged as a result of the lifting of the United States oil export ban in December 2015.
 Since 2010, the United States economy, along with the economies of a few other countries, has generally been stable, achieving modest 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. Consequently, the worldwide economy has remained sluggish despite multiple stimulus packages being enacted by various governments. The outlook for a worldwide economic recovery remains 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 2016.
Significant factors that will affect 2016 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 willing or able to manage oil supply through export quotas; 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 2016, the lower commodity price environment has resulted in lower realized prices for unprotected volumes and a reduction in the prices at which the Company is able to enter into derivative contracts on additional volumes in the future. As a result, the Company's internal cash flows have been negatively impacted by the reduction in commodity prices and are expected to continue to be impacted until commodity prices improve. If commodity prices remain at current levels or decline further, the Company could experience a shortfall in expected future 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, 2015, and subsequent changes to these positions.

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PIONEER NATURAL RESOURCES COMPANY

The Company. The Company's growth plan is primarily anchored by horizontal drilling in the Spraberry/Wolfcamp oil field located in West Texas. Complementing this growth area, the Company has oil and gas production activities and development and exploration opportunities in the liquid-rich Eagle Ford Shale field located in South Texas, 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, 2015, the Company's production from continuing operations of 74 MMBOE, excluding field fuel usage, represented a 12 percent increase over production from continuing operations during 2014. Production, price and cost information with respect to the Company's properties for 2015, 2014 and 2013 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, 2015, the Company drilled 870 gross (719 net) development wells, with over 99 percent of the wells being successfully completed as productive wells, at a total drilling cost (net to the Company's interest) of $3.9 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, 2015 include proved undeveloped reserves and proved developed reserves that are behind pipe of 47 MMBbls of oil, 15 MMBbls of NGLs and 157 Bcf of gas. The Company believes that its proved reserves provide a meaningful portfolio of development opportunities. The timing of the development of these proved 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 utilize its integrated services to control well costs and operating costs in addition to supporting the execution of its drilling and production activities. The Company owns fracture stimulation fleets totaling approximately 450,000 horsepower that support its drilling operations . The Company also owns other field service equipment that support its drilling and production operations, 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 high-quality and logistically advantaged brown sand for proppant, which is being used by the Company to fracture stimulate horizontal wells 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 2015, 2014 and 2013, the Company spent $36 million, $104 million and $76 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 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 —

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PIONEER NATURAL RESOURCES COMPANY

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.
EFS Midstream. In July 2015, the Company completed the sale of its 50.1 percent equity interest in EFS Midstream LLC ("EFS Midstream") to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion, of which $530 million was received at closing and the remaining approximately $500 million will be received in July 2016.
Sendero. In March 2014, the Company completed the sale of its majority interest in Sendero Drilling Company, LLC ("Sendero") to Sendero's minority interest owner 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 has been 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, 2015, the unused carry balance totaled $197 million.
Asset divestitures reflected as discontinued operations. During 2014, the Company completed the sale of (i) its net assets in the Hugoton field in southwest Kansas for cash proceeds of $328 million, (ii) its net assets in the Barnett Shale field in North Texas for cash proceeds of $150 million and (iii) 100 percent of its capital stock in Pioneer's Alaska subsidiary ("Pioneer Alaska") for cash proceeds of $267 million.
The Company has reflected the results of operations of its Hugoton assets, its Barnett Shale assets and Pioneer Alaska (prior to their sale) as discontinued operations in the accompanying consolidated statements of operations.
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 a 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 regarding price risk.
Significant purchasers. During 2015, the Company's significant purchasers of oil, NGLs and gas were Plains Marketing LP (22 percent), Occidental Energy Marketing Inc. (18 percent), Vitol, Inc. (18 percent) and Enterprise Product Partners L.P. (12 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 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

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PIONEER NATURAL RESOURCES COMPANY

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 2015, 2014 and 2013, as well as the Company's open commodity derivative positions at December 31, 2015, and subsequent changes to those 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 commodity prices or the degree to which commodity 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, which may cause the Company to incur significant capital expenditures or take costly actions to achieve and maintain compliance. Failure to comply with these laws and regulations or any underlying permits may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial or corrective action obligations; the occurrence of delays in the permitting, development or expansion of projects; and the issuance of injunctive relief limiting or prohibiting Company activities.
These laws and regulations may, among other things:
require the acquisition of various permits before drilling or other regulated activity commences;
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;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
impose specific criteria addressing worker protection;
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and
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

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activities that may adversely affect the environment. Any such changes that result in delays or restrictions in permitting, or more stringent and costly drilling, completion, construction or water management activities, or waste handling, disposal and cleanup requirements 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, which may be amended from time to time, to which the Company's business operations are or may be subject.
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 authority delegated by 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 excluded from regulation as hazardous wastes and instead are regulated under RCRA's non-hazardous waste provisions, it is possible that in the future such exclusion may be legally challenged or such excluded wastes classified as hazardous wastes. For example, in August 2015, several non-governmental organizations filed notice of intent to sue the EPA under RCRA for, among other things, the agency's alleged failure to reconsider whether such exclusion should continue to apply. Any removal of this exclusion could result in an increase in the Company's costs to manage and dispose of these wastes as hazardous 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.
Hazardous substance releases. 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 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

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leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for noncompliance with discharge permits or other requirements of the CWA and analogous state laws and regulations. In May 2015, the EPA issued a final rule that attempts to clarify the federal jurisdictional reach over waters of the United States but this rule has been stayed nationwide by the U.S. Sixth Circuit Court of Appeals as that appellate court and numerous district courts consider lawsuits opposing implementation of the rule.
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 held strictly liable for oil spill cleanup costs and natural resource damages as well as a variety of public and private damages that may result from oil spills. OPA also requires owners or operators of certain onshore facilities to prepare Facility Response Plans for responding to a worst-case discharge of oil into waters of the United States.
Fluids associated with oil and gas production from the Company's properties, consisting primarily of salt water, are generally 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 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 salt water and other fluids 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 and Colorado, where the Company operates. In Texas, the Texas Railroad Commission (the "TRC") published a final rule in 2014 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. In Colorado, the Colorado Oil and Gas Conservation Commission (the "COGCC") conducts, as part of the disposal well permit application review process, a review for seismicity that considers area-specific knowledge of earthquakes to assess seismic potential. If historical seismicity has been identified in the vicinity of a proposed disposal well permit application, the COGCC requires an operator to define the seismicity potential and the proximity to faults through geologic and geophysical data prior to any permit approval. With respect to existing disposal wells, in the event that seismic incidents occur in the vicinity of such wells, the COGCC may temporarily shut down such nearby wells and assess whether and to what extent activities at such wells may be linked to the seismic incidents, the results of which assessment could result in further well operating restrictions or even well abandonment, thereby delaying production by the Company.
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 the Colorado State Engineer, an agency separate from the COGCC 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 supplies for water rights owners with more senior rights. 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 CBM operations by the Company or other CBM producers.
Hydraulic fracturing. 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, in August 2015, the EPA issued a proposed rulemaking that would establish new requirements for emissions of methane from certain equipment and processes in the oil and gas source category, including first-time standards to address emissions of methane from hydraulically fractured oil and gas well completions; in April 2015, the EPA proposed guidelines that waste water from shale gas extraction operations must meet before discharging to a treatment plant; and in May 2014, the EPA issued a prepublication of its Advance Notice of Proposed Rulemaking

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regarding Toxic Substances Control Act reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, the federal Bureau of Land Management (the "BLM") published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands, but in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certain environmental groups.
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, following the lead of New York in 2015. Also, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective cities' limits in 2012-2013, but since that time, in response to lawsuits brought by an industry trade group, local district courts struck down the ordinances for certain of those Colorado cities in 2014, while a suit brought by the industry trade group against at least one other Colorado city remains pending. Two of the cities whose ordinances were struck down in 2014 were notified in September 2015 by the Colorado Supreme Court that the high court had agreed to hear their appeals. 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 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 the volume 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 conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater and, in June 2015, released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which report concluded, among other things, that hydraulic fracturing activities have not lead to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA's Science Advisory Board provided its comments on the draft study, indicating its concern that EPA's conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as other studies and initiatives or any future studies, depending on any meaningful results obtained or conclusions drawn, could spur efforts to further regulate hydraulic fracturing.
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 compliance 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 and 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 October 2015, the EPA issued a final rule under the CAA for the purpose of making more stringent the National Ambient Air Quality Standard ("NAAQS") for ground-level ozone (reducing the standard to 70 parts per billion) under both the primary and secondary standards intended to provide protection of public health and welfare. Compliance with this final rule could increase the Company's capital expenditures and operating expense by, for example, requiring installation of new emission controls on some of the Company's equipment or result in longer permitting timelines, which could adversely impact the Company's business, financial condition and results of operations.


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PIONEER NATURAL RESOURCES COMPANY

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 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 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, in April 2014, the FWS published a final rule listing 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. As a result of the 2014 listing of the lesser prairie chicken, the Company entered into a range-wide conservation planning agreement, pursuant to which 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. However, in September 2015, the U.S. District Court for the Western District of Texas vacated the FWS's rule listing the lesser prairie chicken in its entirety, concluding that the decision to list the species was arbitrary and capricious. Notwithstanding this court decision, the Company has continued its participation in the conservation planning agreement. In another example, the FWS is considering whether to list the Monarch butterfly, whose range includes Texas and Colorado, under the ESA; this listing status remains under review. Whether the lesser prairie chicken, the Monarch butterfly or other species will be listed in the future under the ESA is currently unknown, but any listing of a species under the ESA in areas where the Company performs activities 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. Moreover, depending on the mitigation strategies recommended in the Environmental Assessments, the Company could incur added costs, which could be substantial.
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.
Climate change. The EPA has made a determination 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

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Company's facilities. The Company is monitoring GHG emissions from its operations in accordance with these GHG emissions reporting rules.
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, in August 2015, the EPA announced proposed rules, expected to be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and gas source category, including production activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although it is not possible at this time to predict how new methane restrictions would impact the Company's business or how or when the United State might impose restrictions on GHGs as a result of the international agreement agreed to in Paris, any new legal requirements that impose more stringent requirements on the emission of GHGs from the Company's operations could result in increased compliance costs or additional operating restrictions, which could have an adverse effect on the Company's business, financial condition and results of operations. 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. 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;
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.

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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).
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.

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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 July 2011, 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.
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 sales 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.

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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:
domestic and worldwide supply of and demand for oil, NGLs and gas;
worldwide oil, NGL, and gas inventory levels , including at Cushing, Oklahoma, the benchmark location for WTI oil prices, and the U.S. Gulf Coast, where the majority of the U.S. refinery capacity exists;
the capacity of U.S. and international refiners to utilize U.S. supplies of oil and condensate;
weather conditions;
overall domestic and global political and economic conditions;
actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
the effect of oil and liquefied natural gas deliveries to and exports from the U.S.;
technological advances affecting energy consumption and energy supply;
domestic and foreign governmental regulations and taxation;
the effect of energy conservation efforts;
the proximity, capacity, cost and availability of pipelines and other transportation facilities; and
the price and availability of alternative fuels.
In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For the five years ended December 31, 2015, oil prices fluctuated from a high of $113.93 per Bbl in 2011 to a low of $34.73 per Bbl in 2015 while gas prices fluctuated from a high of $6.15 per Mcf in 2014 to a low of $1.76 per Mcf in 2015. During 2016, commodity prices have continued to be volatile, with oil prices reaching a low of $26.21 per Bbl on February 11, 2016 and gas prices reaching a low of $1.97 per MCF on February 12, 2016. 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. For example, the Company's proved reserves as of December 31, 2015 declined by 135,078 MBOEs as compared to proved reserves at December 31, 2014 as a result of the average oil and gas price used to calculate proved reserves for each respective period declining from $94.98 per BBL and $4.35 per MCF in 2014 to $50.11 per BBL and $2.59 per MCF in 2015. 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's derivative risk management activities could result in financial losses; the Company may not enter into derivative arrangements with respect to future volumes if prices are unattractive.
To mitigate the effect of commodity price volatility on the Company's net cash provided by operating activities and its net asset value, 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;
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. Although the Company has entered into commodity derivative contracts for a large portion of its forecasted

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production through 2016, the volumes of protected production for 2017 and future years is substantially less. 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 future volumes. This could make such transactions unattractive, and, as a result, some or all of the Company volumes of production forecasted for 2017 and beyond may not be protected by derivative arrangements.
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. The Company is unable to predict changes in a counterparty's creditworthiness or ability to perform. Even if the Company accurately predicts sudden changes, the Company's ability to negate the risk may be limited depending upon market conditions and the contractual terms of the transactions. During periods of declining commodity prices, the Company's derivative receivable positions generally increase, which increases the Company's counterparty credit exposure. If any of the Company's 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.
 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;
unexpected pressure or irregularities in formations;
equipment failures or accidents;
fracture stimulation accidents or failures;
adverse weather conditions;
restricted access to land for drilling or laying pipelines;
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; and
delays imposed by or resulting from compliance with environmental and other governmental or regulatory requirements.

The Company's future drilling activities may not be successful and, if unsuccessful, the Company's proved reserves and production would decline, which 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 2016.
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. From January 1, 2014 through February 12, 2016, oil prices have declined from a high of $107.26 per Bbl on June 20, 2014 to a low of $26.21 per Bbl on February 11, 2016, and gas prices have declined from a high of $6.15 per Mcf on February 19, 2014 to a low of $1.76 per Mcf on December 17, 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. For example, during 2015, the Company recognized aggregate impairment charges of $1.1 billion attributable to its Eagle Ford Shale assets, other South Texas assets and West Panhandle field assets in the panhandle region of Texas, primarily due to declines in commodity prices and downward adjustments to the economically recoverable reserves attributable to each asset. As another example, while the Company determined that the carrying value of its Permian Basin and West Panhandle oil and gas properties were not impaired as of December 31, 2015 based on the Company's longer-term commodity price outlook for oil of $52.82 per Bbl, the properties may become partially impaired if the average oil price in the Company's longer-term commodity

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price outlooks were to decline by approximately $5.00 to $10.00 per Bbl. The Company's Permian Basin and West Panhandle oil and gas properties are long-lived assets that had carrying values of $8.7 billion and $67 million, respectively, as of December 31, 2015. If the Company's Permian Basin and West Panhandle oil and gas properties were to become impaired in a future period, the Company could recognize noncash, pretax impairment charges in that period that could range from $5 billion to $7 billion for the Permian Basin properties and $40 million to $60 million for the West Panhandle properties. In addition, the Company could recognize noncash, pretax impairment charges that could range from $500 million to $700 million to reduce the carrying value of its vertical integration assets that provide services for the Permian Basin assets. The carrying values of those assets are included in "other property and equipment, net" in the accompanying consolidated balance sheets. Also, if the Company's longer-term commodity price outlooks were to decline further, it may constitute significant negative evidence as to whether it is more likely than not that all of the Company's deferred tax assets can be realized prior to their expirations. The Company may incur impairment charges in the future, which could materially affect the Company's results of operations in the period incurred. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations - Impairment of oil and gas properties and other long-lived assets" and Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for further information on the Company's impairment charges.
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, 2015, the Company carried unproved oil and gas property costs of $169 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, 2015, 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 (i) additional reserve adjustments both positive and negative, (ii) results of drilling activities, (iii) management's outlook for commodity prices and costs and expenses, (iv) changes in the Company's market capitalization, (v) changes in the Company's weighted average cost of capital and (vi) 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.
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;
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;
the validity of assumptions about costs, including synergies;
the effect on the Company's liquidity or financial leverage of using available cash or debt to finance acquisitions;
the diversion of management's attention from other business concerns; and
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.

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PIONEER NATURAL RESOURCES COMPANY

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 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, and water distribution and disposal activities, are subject to all the risks 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 chemicals, gases, brine, well stimulation and completion fluids or other pollutants into the surface and subsurface environment;
high costs, shortages or delivery delays of equipment, labor or other services or water and sand for hydraulic fracturing;
facility or equipment malfunctions, failures or accidents;
title problems;
pipe or cement failures or casing collapses;
uncontrollable flows of oil or gas well fluids;
compliance with environmental and other governmental requirements;
lost or damaged oilfield workover and service tools;
unusual or unexpected geological formations or pressure or irregularities in formations;
terrorism, vandalism and physical, electronic and cyber security breaches; 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.
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, 2015, the Company owned interests in seven 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. Six of the gas processing plants are operated by third parties and six of the treating facilities are not currently being used. 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.

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PIONEER NATURAL RESOURCES COMPANY

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:
landing the wellbore in the desired drilling zone;
staying in the desired drilling zone while drilling horizontally through the formation;
running casing the entire length of the wellbore; and
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:
the ability to fracture stimulate the planned number of stages;
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 in those areas.
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, 2015 include proved undeveloped reserves and proved developed reserves that are behind pipe of 47 MMBbls of oil, 15 MMBbls of NGLs and 157 Bcf of gas. The Company's ability to drill and develop these locations depends on a number of factors, including the availability of capital, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability of equipment, services, resources and personnel and drilling results. There can be no assurance that the Company will drill these locations or that the Company will be able to produce oil or gas reserves from these locations or any other potential drilling locations. 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.
A significant portion of the Company's total estimated proved reserves at December 31, 2015 were undeveloped, and those proved reserves may not ultimately be developed.

At December 31, 2015, approximately 11 percent of the Company's total estimated proved reserves were undeveloped. Recovery of undeveloped proved reserves requires significant capital expenditures and successful drilling. The Company's reserve data assumes that the Company can and will make these expenditures and conduct these operations successfully, which assumptions may not prove correct. If the Company chooses not to spend the capital to develop these proved undeveloped reserves, or if the Company is not otherwise able to successfully develop these proved undeveloped reserves, the Company will be required to write-off these proved reserves. In addition, under the SEC's rules, because proved undeveloped reserves may be booked only if they relate to wells planned to be drilled within five years of the date of booking, the Company may be required to write-off any proved undeveloped reserves that are not developed within this five-year timeframe. As with all oil and gas leases, the Company's leases require the Company to drill wells that are commercially productive and to maintain the production in paying quantities, and if the Company is unsuccessful in drilling such wells and maintaining such production, the Company could lose its rights under such leases. The Company's future production levels and, therefore, its future cash flow and income are highly dependent on successfully developing its proved undeveloped leasehold acreage.


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PIONEER NATURAL RESOURCES COMPANY

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 level and outcome of future drilling activity. Should these estimates prove inaccurate, or should the Company's development plans change, 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.
Because the Company's proved reserves and production decline continually over time, the Company will need to mitigate these declines through drilling and production enhancement initiatives and/or acquisitions.

Producing oil and gas reservoirs are characterized by declining production rates, which vary depending upon reservoir characteristics and other factors. Because the Company's proved reserves and production decline continually over time as those reserves are produced, the Company will need to mitigate these declines through drilling and production enhancement initiatives and/or acquisitions of additional recoverable reserves. There can be no assurance that the Company will be able to develop, exploit, find or acquire sufficient additional reserves to replace its current or future production.

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

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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 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. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in the Company's revenue if commodity prices rise, 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 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.
Absent an expansion of U.S. refining capacity, rising U.S. production of oil and condensates could result in a surplus of these products in the U.S., which would likely cause prices for these commodities to fall and markets to constrict. Although U.S. law was changed in 2015 to permit the export of oil, exports may not occur if demand is lacking in foreign markets or the price that can be obtained in foreign markets does not support associated transportation and other costs. 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.
The Company's operations are subject to federal, state and local laws and regulations, including those that govern the discharge of materials into the environment and environmental protection, that could cause it to suspend or curtail its operations or incur substantial costs.
The Company's operations are subject to stringent and complex federal, state and local laws and regulations governing, among other things, permits for the drilling of wells, production, the size and shape of drilling and spacing units or proration units, the transportation and sale of oil, gas and NGLs, worker health and safety, the discharge of materials into the environment and environmental protection. To operate in compliance with these laws and regulations, the Company must obtain and maintain numerous permits, approvals, and certificates from various federal, state and local governmental authorities, and may incur substantial costs in doing so. For example, owing to concerns that the injection of salt water and other fluids into underground disposal wells regulated under the UIC program triggers seismic activity in certain areas, including Texas, the TRC published a final rule in 2014 governing the permitting or re-permitting of such disposal wells that requires the submission of information on seismic events within a specified radius of the disposal well location in addition to other information intended to demonstrate that the injected fluids are confined to the disposal zone or otherwise not contributing to seismic activity. As another example, in October 2015 the EPA issued a final rule under the CAA for the purpose of making more stringent the NAAQS for ground-level ozone (reducing the standard to 70 parts per billion) under both the primary and secondary standards intended to provide protection of public health and welfare. Compliance with these legal requirements or with any future environmental laws or regulations could, among other things, delay, restrict or prohibit the issuance of necessary permits, increase the Company's capital expenditures and operating expenses by, for example, requiring installation of new emission controls on some of the Company's equipment, and limit or preclude the use of otherwise available water sources or disposal wells, any one or more of which developments could have a material adverse effect on the Company's business, financial condition and results of operations. As a third 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 in 2009 that water produced in connection with CBM operations should be subject to state water-use regulations, including regulations requiring the obtaining of 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 supplies for water rights owners with more senior rights.

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There can be no assurance that present or future 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. 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. Such laws and regulations may also affect the costs of acquisitions. In addition, these laws and regulations are subject to amendment or replacement by more stringent laws and regulations. See "Item 1. Business - Competition, Markets and Regulations - Environmental and occupational health and safety matters" above for additional discussion related to regulatory and environmental risks.

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.
There is inherent risk of incurring significant environmental costs and liabilities in the Company's operations as a result of its handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to its operations, and due to past industry operations and waste disposal practices. The Company's oil and gas business involves the generation, handling, transport and disposal of environmentally sensitive materials and wastes 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. 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 sources of contractual indemnity or insurance, as 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 deductibles associated with obtaining such insurance. See "Item 1. Business - Competition, Markets and Regulations - Environmental and occupational health and safety matters" above for additional discussion related to environmental and occupational health and safety risks.

The Company is a party to debt instruments, a credit facility and other financial commitments 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. The Company is also subject to various commitments for leases, drilling contracts, derivative contracts, firm transportation, processing and fractionation, and purchase obligations for services and products. The Company's financial commitments could have important consequences to its business including, but not limited to, the following:
increasing its vulnerability to adverse economic and industry conditions;
limiting its ability to fund future development activities or engage in future acquisitions; and
placing it at a competitive disadvantage compared to competitors that have less debt and/or fewer financial commitments.

See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Commitments, Capital Resources and Liquidity" and Notes G and J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's outstanding debt and other commitments as of December 31, 2015 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. A ratings downgrade could adversely impact the Company's ability to access debt markets, increase the borrowing cost under the Company's credit facility and the cost of future debt, and potentially require the Company to post letters of credit or other forms of collateral for certain obligations.

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PIONEER NATURAL RESOURCES COMPANY

 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. To a lesser extent, the Company also faces competition from companies that supply alternative sources of energy, such as wind or solar power. See "Item 1. Business - Competition, Markets and Regulations" for additional discussion regarding competition.

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. Failures 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:
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.
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;

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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 historical 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 future 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 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. Costs for insurance may also increase as a result of security threats, and some insurance coverage may become more difficult to obtain, if available at all. 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 and 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.
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 cash flows and profitability.
Changes to U.S. federal income tax legislation could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and development, or impose new or additional taxes or fees, and such changes could have an adverse effect on the Company's financial position, results of operations and cash flows.
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

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PIONEER NATURAL RESOURCES COMPANY

certain domestic production activities, (iv) an extension of the amortization period for certain geological and geophysical expenditures and (v) the imposition of new taxes or fees on oil or gas (such as the $10.25 fee per barrel on oil proposed in the President's Budget for Fiscal Year 2017). 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, or increase costs, and any such changes 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.
The EPA has made a determination 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. 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. In the absence of any federal climate legislation being adopted 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 emissions inventories or 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, in August 2015, the EPA announced proposed rules, expected to be finalized in 2016, that would establish new controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and gas source category, including production activities, as part of an overall effort to reduce methane emissions by up to 45 percent in 2025. On an international level, the United States is one of almost 200 nations that agreed in December 2015 to an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will use to achieve its GHG emissions targets. Although it is not possible at this time to predict how new methane restrictions would impact the Company's business or how or when the United State might impose restrictions on GHGs as a result of the international agreement agreed to in Paris, any new legal requirements that impose more stringent requirements on the emission of GHGs from the Company's operations could result in increased compliance costs or additional operating restrictions, which could have an adverse effect on the Company's business, financial condition and results of operations. Moreover, such new 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.
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 implementation. Although the CFTC has issued final regulations to implement significant aspects of the legislation, others remain to be finalized or implemented and it is not possible at this time to predict when this will be accomplished.
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 futures and options contracts and equivalent swaps 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

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PIONEER NATURAL RESOURCES COMPANY

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 swaps that the Company uses. If the Company's swaps do not qualify for the commercial end-user exception, or if the cost of entering into uncleared swaps becomes prohibitive, the Company may be required to clear such transactions. The ultimate effect of the proposed rules and any additional regulations on the Company's business is uncertain.
In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. Although the Company expects to qualify for the end-user exception from margin requirements for swaps entered into to manage its commercial risks, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that the Company uses. If any of the Company's swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce its liquidity and cash available for capital expenditures and could reduce its ability to manage commodity price volatility and the volatility in its cash flows.
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, in August 2015, the EPA issued a proposed rulemaking that would establish new requirements for emissions of methane from certain equipment and processes in the oil and gas source category, including first-time standards to address emissions of methane from hydraulically fractured oil and gas well completions; in April 2015, the EPA proposed guidelines that waste water from shale gas extraction operations must meet before discharging to a treatment plant; and in May 2014, the EPA issued 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, the BLM published a final rule in March 2015 that establishes new or more stringent standards for performing hydraulic fracturing on federal and Indian lands, but in September 2015, the U.S. District Court of Wyoming issued a preliminary injunction barring implementation of this rule, which order the BLM could appeal and is being separately appealed by certain environmental groups.
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, following the lead of New York in 2015. Also, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular. For example, several cities in Colorado passed temporary or permanent moratoria on hydraulic fracturing within their respective cities' limits in 2012-2013, but since that time, in response to lawsuits brought by an industry trade group, local district courts struck down the ordinances for certain of those Colorado cities in 2014, while a suit brought by the industry trade group against at least one other Colorado city remains pending. Two of the cities whose ordinances were struck down in 2014 were notified in September 2015 by the Colorado Supreme Court that the high court had agreed to hear their appeals. 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 be significant in nature, experience delays or curtailment in the

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PIONEER NATURAL RESOURCES COMPANY

pursuit of exploration, development or production activities, and perhaps be limited or precluded in the drilling of wells or in the volume 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 conducted a study of the potential environmental effects of hydraulic fracturing on drinking water and groundwater, and in June 2015, released its draft report on the potential impacts of hydraulic fracturing on drinking water resources, which report concluded, among other things, that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water sources in the United States, although there are above and below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water sources. However, in January 2016, the EPA's Science Advisory Board provided its comments on the draft study, indicating its concern that EPA's conclusion of no widespread, systemic impacts on drinking water sources arising from fracturing activities did not reflect the uncertainties and data limitations associated with such impacts, as described in the body of the draft report. The final version of this EPA report remains pending and is expected to be completed in 2016. Such EPA final report, when issued, as well as other studies and initiatives or any future studies, depending on any meaningful results obtained or conclusions drawn, could spur efforts to further regulate hydraulic fracturing.

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, in April 2014, the FWS listed the lesser prairie chicken as a threatened species under the ESA, and the FWS is considering whether to list the Monarch butterfly. The habitat of both species includes Texas and Colorado, where the Company conducts operations. While the FWS's rule listing the lesser prairie chicken has been vacated by a U.S. District Court, a critical habitat or suitable habitat designation with respect to a threatened or endangered species 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, 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;

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PIONEER NATURAL RESOURCES COMPANY

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;
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.

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PIONEER NATURAL RESOURCES COMPANY

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.
The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977 and amending legislation, which impose 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. This Act, as amended, is a strict liability statute and any failure by the Company to comply with such existing or any future standards, or any more stringent 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 governmental 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, renewals of permits or other approvals 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 or approvals 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. Moreover, issuance of any permits, permit renewals or other approvals by governmental agencies may be conditioned on new or modified requirements or procedures with respect to mining that may be costly or time-consuming to implement. 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 or other approvals 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, and may continue to be, 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, 2015, Premier Silica was the subject of silica exposure claims from approximately 420 plaintiffs. The great majority of these 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.

32

PIONEER NATURAL RESOURCES COMPANY

ITEM 1B.
UNRESOLVED STAFF COMMENTS
None. 

ITEM 2.
PROPERTIES
Reserve Estimation Procedures and Audits
The information included in this Report about the Company's proved reserves as of December 31, 2015, 2014 and 2013 is based on evaluations prepared by the Company's engineers and audited by Netherland, Sewell & Associates, Inc. ("NSAI"), with respect to the Company's major properties. 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, South Texas, Raton and West Panhandle 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) 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, 2015, 2014 and 2013, in the aggregate, represented 82 percent, 80 percent and 94 percent of the Company's year-end 2015, 2014 and 2013 proved reserves, respectively; and 97 percent, 91 percent and 92 percent of the Company's year-end 2015, 2014 and 2013 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

33

PIONEER NATURAL RESOURCES COMPANY

reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare their own estimates of reserve information for the audited properties.
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 38 years of experience as a petroleum engineer, with 31 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 37 years of practical experience in petroleum engineering, including over 35 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.
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 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.

34

PIONEER NATURAL RESOURCES COMPANY

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, 2015, 2014 and 2013, 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, 2015, 2014 and 2013:
 
 
Summary of Oil and Gas Proved Reserves as of Fiscal Year-End
Based on Average Fiscal-Year Prices
 
Proved Reserve Volumes
 
 
Oil
(MBbls)
 
NGLs
(MBbls)
 
Gas
(MMcf) (a)
 
Total (MBOE)
 
%
 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2015:
 
 
 
 
 
 
 
 
 
 
Developed
266,657

 
112,376

 
1,284,680

 
593,146

 
89
%
 
Undeveloped
45,313

 
13,968

 
71,807

 
71,249

 
11
%
 
Total proved reserves
311,970

 
126,344

 
1,356,487

 
664,395

 
100
%
 
 
 
 
 
 
 
 
 
 
 
 
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
%
 
 ______________________
(a)
Total proved gas reserves contain 144,955 MMcf, 191,932 MMcf and 240,093 MMcf of gas that the Company expected to be produced and used as field fuel (primarily for compressors), rather than being delivered to a sales point as of December 31, 2015, 2014 and 2013, respectively.
The Company's Standardized Measure of total proved reserves as of December 31, 2015 was $3.2 billion, including $3.0 billion and $245 million related to proved developed and proved undeveloped reserves, 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.
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.

35

PIONEER NATURAL RESOURCES COMPANY

Description of Properties
The following tables summarize the Company's development and exploration/extension drilling activities during 2015:
 
 
Development Drilling
 
Beginning
Wells In Progress
 
Wells
Spud
 
Successful
Wells
 
Ending
Wells In
Progress
Permian Basin
41

 
65

 
79

 
27

South Texas—Eagle Ford Shale
13

 
30

 
37

 
6

Total
54

 
95

 
116

 
33

 
 
Exploration/Extension Drilling
 
Beginning
Wells In Progress
 
Wells
Spud
 
Successful
Wells
 
Unsuccessful
Wells
 
Ending
Wells In
Progress
Permian Basin
75

 
138

 
136

 

 
77

South Texas—Eagle Ford Shale
30

 
76

 
82

 
1

 
23

Other
1

 

 

 
1

 

Total
106

 
214

 
218

 
2

 
100

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during 2015:
 
 
Oil (Bbls)
 
NGLs (Bbls)
 
Gas (Mcf) (a)
 
Total (BOE)
Permian Basin
83,046

 
23,306

 
113,909

 
125,336

South Texas—Eagle Ford Shale
17,670

 
11,590

 
96,492

 
45,343

Raton Basin

 

 
111,675

 
18,613

West Panhandle
2,921

 
3,524

 
14,252

 
8,820

South Texas—Other
1,709

 
171

 
24,245

 
5,921

Other
1

 
1

 
89

 
17

Total
105,347

 
38,592

 
360,662

 
204,050

 _____________________
(a)
Gas production excludes gas produced and used as field fuel.
The following table summarizes the Company's costs incurred by asset area during 2015:
 
 
Property
Acquisition Costs
 
Exploration Costs
 
Development Costs
 
Asset
Retirement Obligations
 
 
 
Proved
 
Unproved
 
 
 
 
Total
 
(in millions)
Permian Basin
$
9

 
$
27

 
$
994

 
$
587

 
$
67

 
$
1,684

South Texas—Eagle Ford Shale

 

 
233

 
182

 
21

 
436

Raton Basin

 

 
2

 
7

 
9

 
18

West Panhandle

 

 
1

 
12

 
2

 
15

South Texas—Other

 

 
1

 
6

 
3

 
10

Other

 

 
12

 

 

 
12

Total
$
9

 
$
27

 
$
1,243

 
$
794

 
$
102

 
$
2,175

 
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

36

PIONEER NATURAL RESOURCES COMPANY

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 2015, the Company drilled 215 wells in the Spraberry field and its total acreage position now approximates 800,000 gross acres (680,000 net acres). During 2015, the Company placed on production 111 horizontal wells in the northern portion of the play, 86 horizontal wells in the southern portion of the play, where the Company has its joint venture with Sinochem, and 43 vertical wells. Two-well and three-well pads were utilized to drill most of the horizontal wells in the 2015 program. In the northern portion of the play, approximately 70 percent of the horizontal wells placed on production were Wolfcamp B interval wells and the remaining 30 percent were split among Wolfcamp A and D interval and Lower Spraberry Shale wells. In the southern portion of the play, approximately 80 percent of the wells placed on production were Wolfcamp B interval wells, with the remainder being a mix of Wolfcamp A and D interval wells.
The Company plans to reduce its rig count in the Spraberry/Wolfcamp area during the first half of the year from 18 rigs at December 31, 2015 (14 rigs in the northern portion of the play and 4 rigs in the southern portion of the play) to 12 rigs (all in the northern portion of the play) in response to the lower commodity price environment. During 2016, the Company expects to complete approximately 230 horizontal wells (190 horizontal wells in the northern portion of the play and 40 horizontal wells in the southern portion of the play). Approximately 60 percent of the horizontal wells are planned to be drilled in the Wolfcamp B interval, 25 percent in the Wolfcamp A interval and 15 percent in the Lower Spraberry Shale interval. Pioneer does not expect to drill any additional vertical locations in the Spraberry field in 2016 and has extended leases with continuous drilling obligations to allow the Company to drill those locations in the future with higher returning horizontal wells. The Company expects to spend $1.77 billion of drilling and completion capital in the Spraberry field during 2016.
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 has been 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, 2015, the unused carry balance totaled $197 million.
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 utilize its integrated services to control well costs and operating costs in addition to supporting the execution of its drilling and production activities in the Spraberry field. The Company is currently utilizing eight Company-owned fracture stimulation fleets totaling approximately 450,000 horsepower to support its drilling operations in the Spraberry field. The Company also owns other field service equipment that supports its drilling and production operations, 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 high-quality and logistically advantaged brown sand for proppant, which is being used to fracture stimulate horizontal wells in the Spraberry and Wolfcamp Shale intervals.
The Company has been and continues to aggressively pursue initiatives to improve drilling and completion efficiencies and reduce costs. An approximate 30 percent reduction in drilling and completion costs in 2015 compared to 2014 has already been realized associated with these initiatives. The most significant drilling and completion cost reductions to date have been for materials for drilling and fracture stimulation, fuel charges, labor and transportation, rental equipment and well services, while efficiency gains include optimizing completions and expanding the use of a modified three-string casing design in the Spraberry and Wolfcamp Shale intervals. The Company expects further drilling and completion cost reductions and efficiency gains of five percent to ten percent in early 2016, with the key incremental cost reductions being attributable to casing, tubing and well stimulation costs.
The Company's long-term growth plan continues to be focused on optimizing the development of the field and addressing 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 spending plans, which are expected to provide significant future cost savings and support the Company's long-term growth plan in the Spraberry/Wolfcamp area, have been minimized given the significant decline in oil prices. The Company plans to continue to evaluate its infrastructure plans for

37

PIONEER NATURAL RESOURCES COMPANY

a field-wide water distribution network, additional gas processing facilities and expansion of Premier Silica's Brady sand mine based on the Company's outlook for commodity prices and/or incremental cost reductions.
South Texas Eagle Ford Shale
The Company's drilling activities in the South Texas area during 2015 continued to be primarily focused on development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2015 drilling program was focused on liquids-rich drilling in the lower and upper Eagle Ford intervals in Karnes and DeWitt counties, where the Company has drilled its most productive wells in the Eagle Ford Shale. No wells were drilled on dry gas acreage in 2015.
The Company completed 120 horizontal Eagle Ford Shale wells during 2015, 119 of which were successful, with average lateral lengths of 5,182 feet and, on average, 22-stage fracture stimulations. The Company placed 64 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.
Eagle Ford Shale production in 2015 was negatively impacted by well performance issues resulting from unsuccessful well completion design changes (primarily reduced fluid level concentrations) that were made in early 2015 to reduce costs. Recent completions have been using higher fluid level concentrations in an effort to return well performance back to historical levels. The Company has also been testing higher proppant concentrations, shorter stage lengths and tighter cluster spacing.
The Company's horizontal rig count in the Eagle Ford Shale is being reduced from six rigs in 2015 to zero rigs by the end of the first quarter of 2016 given current commodity prices that continue to adversely affect well returns. The Company plans to spend $60 million of capital in 2016 to complete 18 Eagle Ford Shale wells and add field compression to reduce wellhead pressures. No wells are scheduled to be drilled on dry gas acreage. Due to the forecasted reduction in drilling activity, the Company expects to incur additional expense associated with unused firm purchase, gathering, processing, transportation and fractionation commitments in 2016. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Capital Commitments, Capital Resources and Liquidity" and Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's commitments.
In July 2015, the Company completed the sale of its 50.1 percent equity interest in EFS Midstream to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion, of which $530 million was received at closing and the remaining approximately $500 million will be received in July 2016. Associated with the sale, the Company recorded a pretax gain of $777 million during 2015. As a result of the sale, the Company no longer receives its share of the cash flow generated by EFS Midstream, which had the effect of increasing the Company's third-party transportation component of oil and gas production costs by approximately $0.75 per BOE. In conjunction with this transaction, the Company also extended its downstream processing and transportation contracts to 20 years, with improved terms. 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 divestiture of EFS Midstream.
Raton Basin
The Raton Basin properties are located in the southeast portion of Colorado. The Company owns approximately 190,000 gross acres (172,000 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 2,200 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. As part of its cost reduction and efficiency improvement initiatives, the Company plans to connect its gathering system to a third-party system with excess gas processing capacity during 2016. Once the connection is operational, the Company plans to decommission its Fain gas processing plant. 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 2015 to reduce the carrying value of the Company's properties in the West Panhandle field.

38

PIONEER NATURAL RESOURCES COMPANY

Divestitures Recorded as Discontinued Operations
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 the results of operations of its Hugoton assets, its Barnett Shale assets and Pioneer Alaska (prior to their sale) 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 assets and Pioneer Alaska.
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, 2015, 2014 and 2013. 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 2015, 2014 and 2013. 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.
 

39

PIONEER NATURAL RESOURCES COMPANY


PRODUCTION, PRICE AND COST DATA
 
Year Ended December 31, 2015
 
Spraberry
Field
 
Eagle Ford Shale Field
 
Raton
Field
 
Total Company Fields
Production information:
 
 
 
 
 
 
 
Annual sales volumes:
 
 
 
 
 
 
 
Oil (MBbls)
30,312

 
6,450

 

 
38,452

NGLs (MBbls)
8,507

 
4,230

 

 
14,086

Gas (MMcf)
41,577

 
35,220

 
40,761

 
131,642

Total (MBOE)
45,748

 
16,550

 
6,794

 
74,478

Average daily sales volumes:
 
 
 
 
 
 
 
Oil (Bbls)
83,046

 
17,670

 

 
105,347

NGLs (Bbls)
23,306

 
11,590

 

 
38,592

Gas (Mcf)
113,909

 
96,492

 
111,675

 
360,662

Total (BOE)
125,336

 
45,343

 
18,613

 
204,050

Average prices:
 
 
 
 
 
 
 
Oil (per Bbl)
$
44.30

 
$
41.74

 
$

 
$
43.55

NGL (per Bbl)
$
12.95

 
$
13.90

 
$

 
$
13.31

Gas (per Mcf)
$
2.29

 
$
2.69

 
$
2.22

 
$
2.40

Revenue (per BOE)
$
33.84

 
$
25.55

 
$
13.30

 
$
29.25

Average costs (per BOE):
 
 
 
 
 
 
 
Production costs:
 
 
 
 
 
 
 
Lease operating
$
9.01

 
$
2.47

 
$
5.63

 
$
6.97

Third-party transportation charges
0.33

 
5.64

 
3.53

 
1.87

Net natural gas plant/gathering
(0.45
)
 
0.02

 
1.82

 
0.16

Workover
0.61

 
0.99

 

 
0.62

Total
$
9.50

 
$
9.12

 
$
10.98

 
$
9.62

Production and ad valorem taxes:
 
 
 
 
 
 
 
Ad valorem
$
0.92

 
$
0.50

 
$
0.27

 
$
0.76

Production (a)
1.62

 
0.65

 
(0.01
)
 
1.19

Total
$
2.54

 
$
1.15

 
$
0.26

 
$
1.95

Depletion expense
$
22.12

 
$
15.80

 
$
5.19

 
$
18.01

 ______________________
(a) The credit amount in production taxes per BOE for the Raton field is due to the receipt of a severance tax refund from the state of Colorado.


40

PIONEER NATURAL RESOURCES COMPANY


PRODUCTION, PRICE AND COST DATA - (continued)
 
 
Year Ended December 31, 2014
 
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)
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



41

PIONEER NATURAL RESOURCES COMPANY


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


 

42

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, 2015:
PRODUCTIVE WELLS
 
Gross Productive Wells
 
Net Productive Wells
Oil
 
Gas
 
Total
 
Oil
 
Gas
 
Total
7,414

 
3,670

 
11,084

 
6,546

 
3,248

 
9,794

Leasehold acreage. The following table sets forth information about the Company's developed, undeveloped and royalty leasehold acreage as of December 31, 2015:
LEASEHOLD ACREAGE
 
Developed Acreage
 
Undeveloped Acreage
 
Royalty Acreage
Gross Acres
 
Net Acres
 
Gross Acres
 
Net Acres
 
1,343,890

 
1,132,341

 
905,745

 
667,538

 
239,615

 
The following table sets forth the expiration dates of the leases on the Company's gross and net undeveloped acres as of December 31, 2015:
 
 
Acres Expiring (a)
 
Gross
 
Net
2016
721,284

 
512,836

2017
108,599

 
81,211

2018
64,794

 
63,919

2019
1,556

 
1,556

2020
321

 
321

Thereafter
9,191

 
7,695

Total
905,745

 
667,538

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

Of the 657,966 net acres expiring from 2016 through 2018, 613,109 net acres (93 percent) are concentrated in eastern Colorado. Over the past few years, the Company has conducted limited exploratory activities across this acreage. The Company's exploratory drilling activities have not resulted in discovering commercial quantities of hydrocarbons; therefore, no proved reserves have been attributed to any of this acreage. The remainder of the net undeveloped acres expiring over the next three year period is primarily concentrated in the Permian Basin in West Texas, where the Company has an active drilling program and ongoing efforts to extend leases that may not be drilled prior to expiration. The Company currently has no proved undeveloped reserve locations scheduled to be drilled after lease expiration.

43

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 2015, 2014 and 2013 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,
 
2015
 
2014
 
2013
 
2015
 
2014
 
2013
Productive wells:
 
 
 
 
 
 
 
 
 
 
 
Development
116

 
309

 
444

 
78

 
258

 
382

Exploratory
218

 
330

 
244

 
151

 
239

 
164

Dry holes:
 
 
 
 
 
 
 
 
 
 
 
Development

 

 
1

 

 

 
1

Exploratory
2

 
5

 
9

 
1

 
5

 
6

Total
336

 
644

 
698

 
230

 
502

 
553

Success ratio (a)
99
%
 
99
%
 
99
%
 
99
%
 
99
%
 
99
%
 ______________________
(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, 2015:
 
 
Gross Wells
 
Net Wells
Development
33

 
24

Exploratory
100

 
82

Total
133

 
106

 
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.  

 

44

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, 2015 and 2014. 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, 2015 and 2014:
 
 
High
 
Low
 
Dividends
Declared
Per Share
Year ended December 31, 2015
 
 
 
 
 
Fourth quarter
$
150.00

 
$
114.40

 
$

Third quarter
$
140.08

 
$
105.83

 
$
0.04

Second quarter
$
181.97

 
$
136.18

 
$

First quarter
$
167.30

 
$
133.95

 
$
0.04

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

On February 12, 2016, the last reported sales price of the Company's common stock, as reported in the NYSE composite transactions, was $115.36 per share.
As of February 12, 2016, the Company's common stock was held by 12,069 holders of record.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The Company did not purchase any of its common stock during the three months ended December 31, 2015.


45

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, 2015 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,
 
2015
 
2014
 
2013
 
2012
 
2011
 
(in millions, except per share data)
Statements of Operations Data:
 
 
 
 
 
 
 
 
 
Oil and gas revenues
$
2,178

 
$
3,599

 
$
3,088

 
$
2,512

 
$
1,985

Total revenues and other income (a)
$
4,825

 
$