Edgar Filing: PIONEER NATURAL RESOURCES CO

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



¨	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.

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TABLE OF CONTENTS



		Page
Definitions of Certain Terms and Conventions Used Herein		4
Cautionary Statement Concerning Forward-Looking Statements		5
PART I
Item 1.	Business	6
	General	6
	Available Information	6
	Mission and Strategies	6
	Business Activities	6
	Marketing of Production	9
	Competition, Markets and Regulations	10
Item 1A.	Risk Factors	17
Item 1B.	Unresolved Staff Comments	33
Item 2.	Properties	33
	Reserve Estimation Procedures and Audits	33
	Proved Reserves	35
	Description of Properties	36
	Selected Oil and Gas Information	39
Item 3.	Legal Proceedings	44
Item 4.	Mine Safety Disclosures	44
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	45
	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	45
Item 6.	Selected Financial Data	46
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	47
	Financial and Operating Performance	47
	Significant Events	47
	First Quarter 2016 Outlook	48
	2016 Capital Budget	49
	Acquisitions	50
	Divestitures and Discontinued Operations	50
	Results of Operations	50
	Capital Commitments, Capital Resources and Liquidity	56
	Critical Accounting Estimates	60
	New Accounting Pronouncements	61
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	62
	Quantitative Disclosures	62
	Qualitative Disclosures	65
Item 8.	Financial Statements and Supplementary Data	66
	Index to Consolidated Financial Statements	66
	Report of Independent Registered Public Accounting Firm	67
	Consolidated Financial Statements	68
	Notes to Consolidated Financial Statements	74
	Unaudited Supplementary Information	106
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	115
Item 9A.	Controls and Procedures	115
	Management's Report on Internal Control Over Financial Reporting	115
	Report of Independent Registered Public Accounting Firm	116
Item 9B.	Other Information	117

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PART III
Item 10.	Directors, Executive Officers and Corporate Governance	117
Item 11.	Executive Compensation	117
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	117
	Securities Authorized for Issuance Under Equity Compensation Plans	117
Item 13.	Certain Relationships and Related Transactions, and Director Independence	118
Item 14.	Principal Accounting Fees and Services	118
PART IV
Item 15.	Exhibits, Financial Statement Schedules	118
Signatures		125
Exhibit Index		127

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Definitions of Certain Terms and Conventions Used Herein

Within this Report, the following terms and conventions have specific meanings:


•	"Bbl" means a standard barrel containing 42 United States gallons.


•	"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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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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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 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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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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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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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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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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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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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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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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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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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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•	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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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.

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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

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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.

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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.

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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		Exploration Costs		Development Costs		Asset Retirement Obligations		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

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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

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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.

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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.

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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.

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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

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PRODUCTION, PRICE AND COST DATA - (continued)



	Year Ended December 31, 2013
	Included in Continuing Operations										Included in Discontinued Operations
	Spraberry Field			Eagle Ford Shale Field		Raton Field		Total Company Fields			United States		Total
Production information:
Annual sales volumes:
Oil (MBbls)	19,176			5,014		—		25,377			2,078		27,455
NGLs (MBbls)	5,410			3,804		—		10,917			2,082		12,999
Gas (MMcf)	24,679			29,367		49,126		120,816			18,062		138,878
Total (MBOE)	28,699			13,712		8,188		56,431			7,170		63,601
Average daily sales volumes:
Oil (Bbls)	52,537			13,737		—		69,527			5,693		75,220
NGLs (Bbls)	14,822			10,421		—		29,910			5,705		35,615
Gas (Mcf)	67,614			80,458		134,591		331,003			49,484		380,487
Total (BOE)	78,627			37,568		22,432		154,604			19,645		174,249
Average prices:
Oil (per Bbl)	$	93.30		$	91.74	$	—	$	92.62		$	98.81	$	93.09
NGL (per Bbl)	$	30.34		$	26.72	$	—	$	29.99		$	28.76	$	29.79
Gas (per Mcf)	$	3.23		$	3.63	$	3.27	$	3.39		$	3.53	$	3.41
Revenue (per BOE)	$	70.84		$	48.73	$	19.61	$	54.71		$	45.88	$	53.71
Average costs (per BOE):
Production costs:
Lease operating	$	11.38		$	3.23	$	6.25	$	8.19		$	11.64	$	8.58
Third-party transportation charges	0.24			3.86		3.02		1.59			1.43		1.57
Net natural gas plant/gathering	(1.11		)	0.01		1.90		(0.16		)	1.45		0.02
Workover	1.45			0.20		—		0.80			1.76		0.91
Total	$	11.96		$	7.30	$	11.17	$	10.42		$	16.28	$	11.08
Production and ad valorem taxes:
Ad valorem	$	1.70		$	0.65	$	0.42	$	1.15		$	2.01	$	1.25
Production	3.45			1.31		0.35		2.25			0.67		2.07
Total	$	5.15		$	1.96	$	0.77	$	3.40		$	2.68	$	3.32
Depletion expense	$	18.47		$	8.80	$	18.97	$	15.05		$	16.47	$	15.20

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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.

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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.

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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.

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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		$	5,072		$	3,658		$	3,021		$	2,402
Total costs and expenses (a)(b)	$	5,246		$	3,475		$	4,232		$	2,189		$	1,847
Income (loss) from continuing operations	$	(266	)	$	1,041		$	(361	)	$	544		$	380
Income (loss) from discontinued operations, net of tax (c)	$	(7	)	$	(111	)	$	(438	)	$	(301	)	$	501
Net income (loss) attributable to common stockholders	$	(273	)	$	930		$	(838	)	$	192		$	834
Income (loss) from continuing operations attributable to common stockholders per share:
Basic	$	(1.79	)	$	7.17		$	(2.94	)	$	3.99		$	2.80
Diluted	$	(1.79	)	$	7.15		$	(2.94	)	$	3.88		$	2.74
Net income (loss) attributable to common stockholders per share:
Basic	$	(1.83	)	$	6.40		$	(6.16	)	$	1.54		$	7.01
Diluted	$	(1.83	)	$	6.38		$	(6.16	)	$	1.50		$	6.88
Dividends declared per share	$	0.08		$	0.08		$	0.08		$	0.08		$	0.08
Balance Sheet Data (as of December 31):
Total assets	$	15,154		$	14,909		$	12,272		$	13,041		$	11,422
Long-term obligations	$	5,317		$	4,901		$	4,426		$	6,225		$	4,760
Total equity	$	8,375		$	8,589		$	6,615		$	5,867		$	5,651

______________________

(a)

The Company recognized revenues from the sale of purchased oil and gas of $964 million, $726 million and $334 million for the years ended December 31, 2015, 2014 and 2013, respectively. The Company also recognized expenses related to purchased oil and gas of $1.0 billion, $703 million and $336 million for the years ended December 31, 2015, 2014 and 2013, respectively. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's revenues and expenses from these transactions.

(b)

During 2015, 2013 and 2011, the Company recognized impairment charges of $1.1 billion related to oil and gas properties in the West Panhandle, South Texas - Other and South Texas - Eagle Ford Shale fields, $1.5 billion related to dry gas properties in the Raton field and $354 million related to its Edwards and Austin Chalk net assets in South Texas, respectively. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's impairment charges.

(c)

The Company recognized impairment charges of (i) $305 million attributable to its Hugoton assets, its Barnett Shale assets and Pioneer Alaska in 2014, (ii) $729 million attributable to its Barnett Shale assets and Pioneer Alaska in 2013 and (iii) $533 million attributable to its Barnett Shale assets in 2012. During 2011, the Company recognized a gain of $645 million on the sale of its assets in Tunisia. The results of these operations are classified as discontinued operations in accordance with GAAP. See Notes C and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's discontinued operations and related impairment charges.

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ITEM 7.	MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Financial and Operating Performance

Pioneer's financial and operating performance for 2015 included the following highlights:

•

Net loss attributable to common stockholders was $273 million ($1.83 per diluted share) for the year ended December 31, 2015, as compared to net income attributable to common stockholders of $930 million ($6.38 per diluted share) in 2014. The $1.2 billion decrease in earnings attributable to common stockholders is primarily comprised of a $1.3 billion decrease in income from continuing operations, partially offset by a $104 million decrease in loss from discontinued operations, net of tax.

The primary components of the decrease in earnings from continuing operations include:


•	a $1.4 billion decrease in oil and gas revenues as a result of a 46 percent decrease in average commodity prices per BOE, partially offset by a 12 percent increase in sales volumes;

•

a $1.1 billion increase in impairment charges related to impairments recorded in 2015 to reduce the carrying value of the Company's South Texas - Eagle Ford Shale, West Panhandle and South Texas - Other fields based on reductions in management's long-term commodity price outlook (see Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and "Results of Operations" below);


•	a $338 million increase in DD&A expense, primarily attributable to the 12 percent increase in sales volumes and reductions in proved reserves as a result of the decline in commodity prices, partially offset by the aforementioned impairments of proved properties during 2015, which reduced the carrying value of the Company's oil and gas properties;


•	a $209 million increase in other expense, primarily related to idle drilling rig charges, inventory valuation allowances, other property and equipment impairments, restructuring charges associated with the closing of the Company's Denver, Colorado office, losses on vertical integration services and increases in transportation commitment charges; and


•	a $62 million decrease in net margins associated with purchases and sales of oil and gas used to fulfill transportation commitments; partially offset by


•	a $773 million increase in net gains on disposition of assets, principally related to the sale of EFS Midstream in July 2015;


•	a $711 million increase in the Company's income tax benefit as a result of the decrease in income from continuing operations before income taxes;


•	a $167 million increase in net derivative gains, primarily as a result of declines in commodity prices and changes in the Company's portfolio of derivatives; and


•	a $51 million decrease in total oil and gas production costs and production and ad valorem taxes, primarily due to the Company's cost saving initiatives and the decline in commodity prices.

The decline in the loss from discontinued operations, net of tax, during 2015 reflects the Company no longer recognizing results of operations associated with its Hugoton assets, its Barnett Shale assets and Pioneer Alaska that were sold during 2014.


•	Daily sales volumes from continuing operations increased on a BOE basis by 12 percent to 204,050 BOEPD during 2015, as compared to 182,237 BOEPD during 2014, primarily due to the success of the Company's Spraberry/Wolfcamp horizontal drilling program;


•	Average oil, NGL and gas prices from continuing operations decreased during 2015 to $43.55 per Bbl, $13.31 per Bbl and $2.40 per Mcf, respectively, as compared to respective average prices of $85.29 per Bbl, $27.06 per Bbl and $4.10 per Mcf during 2014;


•	Net cash provided by operating activities decreased by 47 percent to $1.2 billion for 2015, as compared to $2.4 billion during 2014, primarily due to the decrease in oil, NGL and gas prices, partially offset by an increase in net cash flows from derivative settlements and an increase in oil and gas sales volumes; and


•	As of December 31, 2015, the Company's net debt to book capitalization increased to 21 percent, as compared to 16 percent as of December 31, 2014, primarily due to the net loss recognized for the year.

Significant Events

Oil Exports. In December 2015, the United States Congress and President Obama adopted legislation to lift the ban on oil exports. Pioneer expects to have the ability to physically export oil by the middle of 2016. The Company has been actively working

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with its midstream partners to secure export facilities along the U.S. Gulf Coast, which will improve the Company's oil marketing flexibility going forward. Europe, Asia and Latin America are potential markets for U.S. oil as countries from these areas could realize economic and security advantages by diversifying their sources of supply.

Issuance of common stock. In early 2016, the Company issued 13.8 million shares of its common stock and received cash proceeds of $1.6 billion, net of associated underwriting and offering expenses.

Commodity prices. North American and worldwide oil, NGL and gas prices remain under pressure given the current oversupply of such commodities. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and the OPEC oil production increases as part of an effort to retain market share combined with only modest demand growth in the United States and decreasing demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil and NGL storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begin to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has caused the market to anticipate increased supplies of oil from Iran in early 2016, further weakening the outlook for oil prices. The declining demand for drilling rigs, fracture-stimulation services and oilfield supplies during 2015 has led to a reduction in these costs. However, despite these significant cost savings, the Company experienced a significant deterioration in its operating margins during the year, which have further deteriorated in 2016. The duration and magnitude of the commodity price declines and the timing and amount of cost reductions cannot be accurately predicted. However, the Company does expect adverse charges associated with the decline in commodity prices, including (i) stacked rig charges, (ii) charges associated with excess firm gathering and transportation commitments and (iii) increased depletion, depreciation and amortization expense due to continued declines in commodity prices which are expected to lead to reduction in proved reserves as a result of shortening the economic productive lives of the Company's producing wells, partially offset by reserve additions as a results of successful drilling.

Low price environment initiatives. Based on the Company's outlook for continuing weak oil prices, the Company is reducing its Company-wide horizontal drilling activity from 24 rigs at year-end 2015 to 12 rigs by the middle of 2016. This includes reducing (i) the Eagle Ford Shale rig count from six rigs at December 31, 2015 to zero rigs during the first quarter of 2016, (ii) the rig count in the southern Wolfcamp area from four rigs at December 31, 2015 to zero rigs by the middle of 2016 and (iii) the rig count in the northern Spraberry/Wolfcamp area from 14 rigs at December 31, 2015 to 12 rigs during the first quarter of 2016. With the planned reduction in activity, the Company's capital expenditures budget for 2016 is expected to be $2.0 billion, including $1.85 billion for drilling and completions (includes tank batteries, salt water disposal facilities and gas processing facilities) and $150 million for vertical integration, systems upgrades and field facilities.

As a result of the reduction in drilling activities, the Company expects that its stacked drilling rig charges and charges associated with excess firm gathering and transportation commitments will increase until commodity prices improve, allowing the Company to increase its drilling activities or the contractual obligations expire. Further, an extended commodity price decline could adversely affect the amount of oil, NGLs and gas that the Company can economically produce, which could result in the Company having to make further downward adjustments to its estimated proved reserves. Reductions in estimated proved reserves could increase the amount of depletion, depreciation and amortization expense the Company recognizes as a result of shortening the economic productive lives of the Company's producing wells. It is also possible that 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 performs 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.

In conjunction with decision to no longer run any drilling rigs in the Eagle Ford Shale until commodity prices improve, the Company is also relocating its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. The Company expects to relocate the majority of its pressure pumping employees from South Texas to Midland, Texas. This initiative is expected to be substantially completed by the end of the second quarter of 2016. The Company estimates that it will incur $10 million to $20 million of restructuring costs in connection with this plan, primarily made up of employee relocation and severance payments and other related costs.

First Quarter 2016 Outlook

Based on current estimates, the Company expects the following operating and financial results from continuing operations for the quarter ending March 31, 2016:

Production is forecasted to average 211,000 to 216,000 BOEPD.

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Production costs (including production and ad valorem taxes and transportation costs) are expected to average $10.50 to $12.50 per BOE, based on current NYMEX strip commodity prices. DD&A expense is expected to average $18.50 to $20.50 per BOE.

Total exploration and abandonment expense is expected to be $20 million to $30 million. General and administrative expense is expected to be $78 million to $83 million. Interest expense is expected to be $58 million to $63 million, and other expense is expected to be $70 million to $80 million. Other expense includes $20 million to $25 million of expected charges for each of the following: (i) stacked drilling rig charges, (ii) charges associated with excess firm gathering and transportation commitments and (iii) estimated losses (principally noncash) associated with the portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 million.

The Company also expects to incur restructuring charges of $10 million to $20 million associated with relocating its two pressure pumping fleets from the Eagle Ford Shale to the Spraberry/Wolfcamp. The restructuring charges include relocation and severance payments and other related costs.

The Company's effective income tax rate is expected to range from 35 percent to 40 percent, assuming current capital spending plans and no significant derivative MTM changes in the Company's derivative position. Cash income taxes are expected to be $1 million to $5 million and are primarily attributable to state taxes.

2016 Capital Budget

Pioneer's capital program for 2016 totals $2.0 billion, consisting of $1.85 billion for drilling and completions related activities, and $150 million for water infrastructure, vertical integration, systems upgrades and field facilities. The 2016 budget excludes acquisitions, asset retirement obligations, capitalized interest, and geological and geophysical general and administrative expense.

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The 2016 drilling capital of $1.85 billion continues to be focused on oil- and liquids-rich drilling, with substantially all of the capital allocated to horizontal drilling activities in the Spraberry/Wolfcamp field. The following is the forecasted spending by asset area:


•	Spraberry/Wolfcamp field - $1.77 billion, including (i) $1.485 billion of horizontal drilling capital, (ii) $170 million for infrastructure (tank batteries and salt water disposal wells), (iii) $45 million for gas processing facilities and (iv) $70 million of land-related and other expenditures;


•	Eagle Ford Shale - $60 million; and


•	Other assets - $20 million.

The 2016 capital budget is expected to be funded from a combination of operating cash flow, cash and cash equivalents on hand, the receipt of the remaining approximately $500 million of proceeds from the EFS Midstream divestiture, proceeds from the issuance of common stock in early 2016, and, if necessary, borrowings under the Company's credit facility.

Acquisitions

During 2015, 2014 and 2013, the Company spent $36 million, $104 million and $76 million, respectively, to acquire primarily undeveloped acreage for future exploitation and exploration activities. The 2015, 2014 and 2013 acquisitions primarily increased the Company's acreage positions in the West Texas Spraberry field. During 2014, the Company acquired the remaining limited partner interests in five affiliated partnerships for $54 million and caused the partnerships to be merged with and into a wholly-owned subsidiary of the Company. During 2013, the Company completed the acquisition of all of the outstanding common units of Pioneer Southwest not already owned by the Company in exchange for 0.2325 of a share of common stock of the Company per Pioneer Southwest common unit. In total, the Company issued an aggregate of 3.96 million shares of its common stock to Pioneer Southwest unitholders. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's acquisitions.

Divestitures and Discontinued Operations

EFS Midstream. 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.

Hugoton, Barnett Shale and Alaska. 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 the capital stock in 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.

Sendero. In March 2014, the Company completed the sale of its majority interest in 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 to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for total consideration of $1.8 billion. In May 2013, the Company completed the sale for net cash proceeds of $624 million, resulting in a gain of $181 million. Sinochem 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.

See Notes C and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's divestitures and discontinued operations.

Results of Operations

Oil and gas revenues. Oil and gas revenues from continuing operations totaled $2.2 billion, $3.6 billion and $3.1 billion during 2015, 2014 and 2013, respectively.

The decrease in 2015 oil and gas revenues relative to 2014 is primarily due to declines of 49 percent, 51 percent and 41 percent in oil, NGL and gas prices, respectively, partially offset by 21 percent and six percent increases in oil and gas sales volumes, respectively.

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The increase in 2014 oil and gas revenues relative to 2013 is reflective of 25 percent, 29 percent and three percent increases in oil, NGL, and gas sales volumes, respectively, and a 21 percent increase in gas prices. Partially offsetting the effects of these increases were declines of eight percent and 10 percent in oil and NGL prices, respectively.

The following table provides average daily sales volumes from continuing operations for 2015, 2014 and 2013:



	Year Ended December 31,
	2015	2014	2013
Oil (Bbls)	105,347	87,034	69,527
NGLs (Bbls)	38,592	38,646	29,910
Gas (Mcf)	360,662	339,341	331,003
Total (BOE)	204,050	182,237	154,604

Average daily sales volumes from continuing operations in 2015 and 2014 increased by 12 percent and 18 percent, respectively, as compared to the average daily sales volumes in the respective prior years, principally due to the Company's successful Spraberry/Wolfcamp horizontal drilling program.

Production for the year ended December 31, 2015 reflects lower NGL production volumes of approximately 5,300 barrels per day due to voluntary reductions in recoveries of ethane since it had a higher value if sold as part of the gas stream.

The following table provides average daily sales volumes from discontinued operations during 2014 and 2013:



	Year Ended December 31,
	2014	2013
Oil (Bbls)	2,605	5,693
NGL (Bbls)	4,535	5,705
Gas (Mcf)	37,881	49,484
Total (BOE)	13,453	19,645

The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities. The following table provides the Company's average prices from continuing operations for 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
Oil (per Bbl)	$	43.55	$	85.29	$	92.62
NGL (per Bbl)	$	13.31	$	27.06	$	29.99
Gas (per Mcf)	$	2.40	$	4.10	$	3.39
Total (per BOE)	$	29.25	$	54.11	$	54.71

Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company's areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. The net effect of third party purchases and sales of oil and gas for the year ended December 31, 2015 was a loss of $39 million, as compared to earnings of $23 million and a loss of $2 million for the years ended December 31, 2014 and 2013, respectively. Firm transportation payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for further information on unused transportation commitment charges.

Interest and other income. The Company's interest and other income from continuing operations was $22 million during 2015, as compared to $26 million and $23 million during 2014 and 2013, respectively. The $4 million decrease during 2015, as compared to 2014, is primarily attributable to an $8 million decrease in equity in earnings of EFS Midstream, partially offset by a $3 million increase in interest income. The $3 million increase during 2014, as compared to 2013, was primarily attributable to a $6 million increase in equity in earnings of EFS Midstream, partially offset by a $3 million decrease in deferred compensation

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plan income. See Note M of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's interest and other income.

Derivative gains, net. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts 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. During the years ended December 31, 2015, 2014 and 2013, the Company recorded $879 million, $712 million and $4 million of net derivative gains, respectively, on commodity price and interest rate derivatives, of which $876 million, $103 million and $168 million represented net cash receipts, respectively.

The following table details the net cash receipts (payments) on the Company's commodity derivatives and the relative price impact (per Bbl or Mcf) for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015					2014							2013
	Net cash receipts		Price impact			Net cash receipts			Price impact				Net cash receipts		Price impact
	(in millions)					(in millions)							(in millions)
Oil derivative receipts	$	744	$	19.36	per Bbl	$	104		$	3.34		per Bbl	$	12	$	0.46	per Bbl
NGL derivative receipts	18		$	0.79	per Bbl	8			$	0.56		per Bbl	1		$	0.11	per Bbl
Gas derivative receipts (payments)	114		$	0.87	per Mcf	(27		)	$	(0.22	)	per Mcf	155		$	1.28	per Mcf
Total net commodity derivative receipts	$	876				$	85						$	168

The Company's open derivative contracts are subject to continuing market risk. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's derivative contracts.

Gain on disposition of assets, net. The Company recorded net gains on the disposition of assets of $782 million, $9 million and $209 million during 2015, 2014 and 2013, respectively.

During 2015, the Company's gains on disposition of assets are primarily due to the gain of $777 million recognized on the sale of EFS Midstream. During 2013, the Company's gains on disposition of assets included a $181 million gain on the sale of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas to Sinochem and a gain of $22 million on the sale of the Company's interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations.

Oil and gas production costs. The Company's oil and gas production costs from continuing operations totaled $717 million, $693 million and $588 million during 2015, 2014 and 2013, respectively. In general, lease operating expenses and workover expenses represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/gathering charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from gathering and processing of third party gas in Company-owned facilities.

Total oil and gas production costs per BOE for the year ended December 31, 2015 decreased 8 percent as compared to 2014. The decrease in lease operating expenses per BOE is primarily due to a greater proportion of the Company's production coming from horizontal wells in the Spraberry/Wolfcamp area, which have lower per BOE lease operating costs, cost reduction initiatives and lower electricity and fuel costs, which are impacted by lower commodity prices. The increase in third-party transportation charges reflects the impact of the Company's sale of its interest in EFS Midstream in July 2015 whereby the Company is no longer able to reduce its transportation costs by its proportionate share of the cash flow generated by EFS Midstream. The increase in net natural gas plant charges per BOE during 2015, as compared to 2014, is primarily reflective of reduced earnings on third-party volumes that are processed in Company-owned facilities due to lower NGL and gas prices. During 2014, total production costs per BOE did not substantially change as compared to 2013.

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The following table provides the components of the Company's total production costs per BOE for 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014			2013
Lease operating expenses	$	6.97	$	8.27		$	8.19
Third-party transportation charges	1.87		1.68			1.59
Net natural gas plant/gathering charges	0.16		(0.20		)	(0.16		)
Workover costs	0.62		0.65			0.80
Total production costs	$	9.62	$	10.40		$	10.42

Production and ad valorem taxes. The Company recorded production and ad valorem taxes from continuing operations of $145 million during 2015, as compared to $220 million and $192 million for 2014 and 2013, respectively. In general, production taxes and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices.

The following table provides the Company's production and ad valorem taxes per BOE from continuing operations for 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
Production taxes	$	1.19	$	2.18	$	2.25
Ad valorem taxes	0.76		1.13		1.15
Total ad valorem and production taxes	$	1.95	$	3.31	$	3.40

Depletion, depreciation and amortization expense. The Company's total DD&A expense from continuing operations was $1.4 billion ($18.59 per BOE), $1.0 billion ($15.75 per BOE), and $889 million ($15.75 per BOE) for 2015, 2014 and 2013, respectively. Depletion expense on oil and gas properties, the largest component of DD&A expense, was $18.01, $15.19 and $15.05 per BOE during 2015, 2014 and 2013, respectively.

During 2015, the 19 percent increase in per BOE depletion expense, as compared to 2014, is primarily due to (i) declines in commodity prices during the fourth quarter of 2014 and further price declines in 2015, which led to reductions in proved reserves as a result of shortening the economic productive lives of the Company's producing wells and, to a lesser extent, (ii) a decline in proved undeveloped reserves during the fourth quarter of 2014 to remove 39 MMBOE of proved undeveloped vertical well locations that were no longer expected to be drilled as a result of the Company shifting its planned capital expenditures to higher-rate-of-return horizontal drilling.

During 2014, the one percent increase in per BOE depletion expense, as compared to that of 2013 was primarily due to (i) a decline in proved undeveloped reserves during the fourth quarter of each of 2014 and 2013 (39 MMBOE and 231 MMBOE, respectively) to remove undeveloped vertical well locations that were no longer expected to be drilled as a result of the Company shifting its planned capital expenditures to higher-rate-of-return horizontal drilling, offset by (ii) the impairment of proved properties in the Raton field during the fourth quarter of 2013, which reduced the Raton field's carrying value by $1.5 billion.

Impairment of oil and gas properties and other long-lived assets. The Company recorded impairment expense in continuing operations to reduce the carrying values of oil and gas properties by $1.1 billion and $1.5 billion during the years ended December 31, 2015 and 2013. For the year ended December 31, 2014, the Company did not have any impairment expense in continuing operations.

The Company performs assessments of its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying values of those assets may not be recoverable. In order to perform these assessments, management uses various observable and unobservable inputs, including management's outlooks for (i) proved reserves and risk-adjusted probable and possible reserves, (ii) commodity prices, (iii) production costs, (iv) capital expenditures and (v) production.

Management's long-term commodity price outlooks are developed based on third-party longer-term commodity futures price outlooks as of a measurement date ("Management's Price Outlooks"). During the years ended December 31, 2015 and 2014, Management's Price Outlook for oil declined by 23 percent and 15 percent, respectively, and Management's Price Outlook for gas declined by 20 percent and six percent, respectively. The trend of Management's Price Outlooks by year is as follows:

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	December 31, 2015	December 31, 2014	December 31, 2013
Management's oil outlook (Bbl)	$52.82	$68.64	$80.40
Management's gas outlook (MMBtu)	$3.34	$4.16	$4.43

As a result of the Company’s impairment assessments, including reductions in Management's Price Outlooks, the Company recognized pretax, noncash impairment charges to reduce the carrying values of (i) the Eagle Ford Shale field, the West Panhandle field and the South Texas - Other field during the year ended December 31, 2015 and (ii) the Raton field during the year ended December 31, 2013 to their estimated fair values.

In addition to those properties impaired during 2015, the Company assessed each of its other proved oil and gas property areas for possible impairment (including areas impaired in periods prior to the fourth quarter of 2015) by estimating the undiscounted future net cash flows attributable to each of those proved oil and gas property areas based on Management's Price Outlook as of December 31, 2015. As a result of those assessments, the Company concluded that, as of December 31, 2015, the carrying amounts of these proved oil and gas property areas were expected to be recovered.

Although the Company's estimates of undiscounted future net cash flows attributable to its Permian Basin and West Panhandle oil and gas properties indicated on December 31, 2015 that its carrying amounts were expected to be recovered, the Company's impairment assessments indicated that each of these assets are at risk for impairment if estimates of future cash flows decline. For example, the Company estimates that the carrying values of its Permian Basin and West Panhandle assets may become partially impaired if the average oil price in Management's Price Outlook of $52.82 per Bbl as of December 31, 2015 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 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 Management's Price Outlook 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.

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

See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's impairment assessments.

Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expense and leasehold abandonments and other exploration expense from continuing operations for 2015, 2014 and 2013 (in millions):



	Year Ended December 31,
	2015		2014		2013
Geological and geophysical	$	71	$	86	$	76
Exploratory dry holes	17		27		6
Leasehold abandonments and other	11		64		15
	$	99	$	177	$	97

During 2015, the Company's exploration and abandonment expense was primarily attributable to $71 million of geological and geophysical costs, of which $60 million was geological and geophysical administrative costs; $17 million of dry hole provisions, primarily associated with the Company's unproved acreage position in southeast Colorado; and $11 million of leasehold abandonment expense, which includes $7 million associated with the Company's unproved acreage position in southeast Colorado. During 2015, the Company completed and evaluated 220 exploration/extension wells, 218 of which were successfully completed as discoveries.

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During 2014, the Company's exploration and abandonment expense was primarily attributable to $86 million of geological and geophysical costs, of which $59 million was geological and geophysical administrative costs; $27 million of dry hole provisions, primarily associated with the Company's unproved acreage position in southeast Colorado; and $64 million of leasehold abandonment expense, which includes $50 million associated with the Company's unproved acreage position in southeast Colorado. During 2014, the Company completed and evaluated 335 exploration/extension wells, 330 of which were successfully completed as discoveries.

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

General and administrative expense. General and administrative expense from continuing operations totaled $327 million ($4.39 per BOE), $333 million ($5.01 per BOE) and $296 million ($5.24 per BOE) during 2015, 2014 and 2013, respectively. The increase in general and administrative expense during 2014, as compared to 2013, was primarily due to increases of $7 million and $5 million in contract labor and information technology, respectively, related to process improvement initiatives, and a $5 million increase in employee benefit costs.

Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations from continuing operations was $12 million during each of the years ended December 31, 2015, 2014 and 2013, respectively. See Note I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's asset retirement obligations.

Interest expense. Interest expense was $187 million, $184 million and $184 million during 2015, 2014 and 2013, respectively. The weighted average interest rate on the Company's indebtedness for the year ended December 31, 2015 was 6.6 percent, as compared to 6.4 percent and 6.5 percent for the years ended December 31, 2014 and 2013, respectively.

See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's long-term debt and interest expense.

Other expenses. Other expenses from continuing operations were $315 million during 2015, as compared to $106 million during 2014 and $143 million during 2013. The $209 million increase in other expense during 2015, as compared to 2014, is primarily associated with (i) an $85 million increase in idle drilling and well service equipment charges, (ii) a $63 million increase in inventory valuation allowances, principally related to excess vertical pipe inventory, (iii) restructuring charges of $23 million (see further information below), (iv) an $18 million increase in the net loss attributable to Company-provided fracture stimulation and related service operations provided to third-party working interest owners, (v) a $15 million increase in other property and equipment impairments and (vi) a $7 million increase in transportation commitment charges.

In May 2015, the Company announced plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pumping services operations. The restructuring plan is substantially complete as of December 31, 2015. In connection therewith, during the year ended December 31, 2015, the Company recognized $23 million of restructuring charges in other expense in the accompanying consolidated statements of operations, which includes approximately $17 million in employee severance costs and $6 million in office lease-related costs.

The $37 million decrease in other expense during 2014, as compared to 2013, was primarily associated with (i) a $28 million decrease in inventory valuation allowances, (ii) a $25 million decrease in other property impairments, which in 2013 was associated with the planned sale of the Company's majority interest in Sendero and (iii) a $9 million decrease in contingency and environmental accrual adjustments, partially offset by (iv) an $11 million increase in the net loss attributable to Company-provided fracture stimulation and related service operations provided to third-party working interest owners, (v) an $8 million increase in terminated drilling rig contract charges and (vi) a $7 million increase in firm transportation payments on excess pipeline capacity commitments.

See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's other expenses.

Income tax benefit (provision). The Company recognized an income tax benefit attributable to earnings from continuing operations of $155 million during 2015, as compared to an income tax provision of $556 million during 2014 and an income tax benefit of $213 million during 2013. The Company's effective tax rates on earnings from continuing operations, excluding income from noncontrolling interest, for 2015, 2014 and 2013 were 37 percent, 35 percent and 35 percent, respectively, as compared to the combined United States federal and state statutory rates of approximately 36 percent.

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See "Critical Accounting Estimates" below and Note O of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's income tax rates and tax attributes.

Loss from discontinued operations, net of tax. The Company recognized losses from discontinued operations, net of tax, of $7 million, $111 million and $438 million in 2015, 2014 and 2013, respectively. Loss from discontinued operations, net of tax, includes the results of operations of the following divestitures prior to their sale:


•	The Hugoton assets, which were placed into assets held for sale and discontinued operations in July 2014 and sold in September 2014;


•	The Barnett Shale assets, which were placed into assets held for sale and discontinued operations in December 2013 and sold in September 2014; and


•	Pioneer Alaska, which was placed into assets held for sale and discontinued operations in December 2013 and sold in April 2014.

The decrease in the loss from discontinued operations, net of tax, in 2015, as compared to 2014, is due to completing the above noted sales of the Hugoton assets, the Barnett Shale assets and Pioneer Alaska in 2014. The decrease in the loss recognized from discontinued operations, net of tax, in 2014, as compared to 2013, is primarily due to the reduction in impairment charges (net of the related tax benefits) associated with these assets in 2014. The Company recognized impairment charges of (i) $305 million attributable to its Hugoton assets, its Barnett Shale assets and Pioneer Alaska in 2014 and (ii) $729 million attributable to its Barnett Shale assets and Pioneer Alaska in 2013.

See Note C and Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's discontinued operations and related impairment charges.

Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interests was nominal in 2015 and 2014, as compared to $39 million for 2013. In 2013, the Company's net income attributable to noncontrolling interest was primarily associated with the net income of Pioneer Southwest. The decrease in net income attributable to noncontrolling interest in 2015 and 2014, as compared to 2013, is due to the Company's acquisition of all outstanding common units of Pioneer Southwest not owned by the Company in December 2013.

See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding Pioneer Southwest and the Company's noncontrolling interest in consolidated subsidiaries' net income.

Capital Commitments, Capital Resources and Liquidity

Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas properties and related vertical integration assets and facilities, payments of contractual obligations, including debt maturities, dividends and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, cash and cash equivalents on hand, proceeds from divestitures or external financing sources as discussed in "Capital resources" below. During 2016, the Company expects that it will be able to fund its needs for cash (excluding acquisitions, if any) with a combination of internally generated cash flows, cash and cash equivalents on hand, the receipt of the remaining approximately $500 million of proceeds from the EFS Midstream divestiture, proceeds from the issuance of common stock in early 2016 and, if necessary, availability under the Company's credit facility or proceeds from divestitures of nonstrategic assets. Although the Company expects that these sources of funding will be adequate to fund capital expenditures, dividend payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

During 2016, the Company plans to continue to focus its capital spending primarily on liquids-rich drilling activities in the Spraberry/Wolfcamp area. The Company's 2016 capital budget totals $2.0 billion (excluding acquisitions, asset retirement obligations, capitalized interest, geological and geophysical administrative costs), consisting of $1.85 billion for drilling operations and $150 million for vertical integration, buildings and other plant and equipment additions. Based on the Company's current Management Price Outlooks, Pioneer expects its net cash flows from operating activities, cash and cash equivalents on hand, the receipt of the remaining approximately $500 million of proceeds from the EFS Midstream divestiture, proceeds from the issuance of common stock in early 2016 and, if necessary, availability under the Company's credit facility or proceeds from divestitures of nonstrategic assets to be sufficient to fund its planned capital expenditures and contractual obligations, including debt maturities.

Investing activities. Net cash used in investing activities during 2015 was $1.8 billion, as compared to net cash used in investing activities of $2.7 billion and $2.1 billion during 2014 and 2013, respectively. The decrease in net cash flow used in

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investing activities during 2015, as compared to 2014, is primarily due to (i) a $1.1 billion decrease in additions to oil and gas properties, (ii) a $50 million decrease in additions to other assets and other property and equipment, partially offset by (iii) a $324 million decrease in proceeds from the disposition of assets. Proceeds from the disposition of assets during 2015 includes $530 million associated with the sale of EFS Midstream, while the proceeds in 2014 include $834 million associated with the divestitures of the Hugoton assets, the Barnett Shale assets, Pioneer Alaska, Sendero and the proved and unproved properties in Gaines and Dawson counties in the Spraberry field. In addition to the aforementioned proceeds from the disposition of assets, the Company's investing activities during the year ended December 31, 2015 were primarily funded by net cash provided by operating activities and cash on hand.

The increase in net cash flow used in investing activities during 2014, as compared to 2013, was primarily due to (i) a $604 million increase in additions to oil and gas properties, (ii) a $96 million increase in additions to other assets and other property and equipment and (iii) a $25 million decrease in distributions from EFS Midstream recognized as investing activities, partially offset by (iv) a $166 million increase in proceeds from the disposition of assets. Proceeds from the disposition of assets during 2014 includes $834 million associated with the divestitures of the Hugoton assets, the Barnett Shale assets, Pioneer Alaska, Sendero and the proved and unproved properties in Gaines and Dawson counties in the Spraberry field, while the proceeds in 2013 include $662 million associated with the sale to Sinochem of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas and the sale of the Company's interest in unproved oil and gas properties adjacent to the West Panhandle field operations. See "Results of Operations" above and Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding asset divestitures.

Dividends/distributions. During each of the years ended December 31, 2015, 2014 and 2013, the Board declared semiannual dividends of $0.04 per common share. Associated therewith, the Company paid $12 million, $12 million and $11 million, respectively, of aggregate dividends. Future dividends are at the discretion of the Board, and, if declared, the Board may change the dividend amount based on the Company's liquidity and capital resources at that time.

During January, April, July and October of 2013, the board of directors of the general partner of Pioneer Southwest declared quarterly distributions aggregating annually to $2.08 per limited partner unit. Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $35 million during the year ended December 31, 2013.

Off-balance sheet arrangements. From time-to-time, the Company enters into off-balance sheet arrangements and transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2015, the material off-balance sheet arrangements and transactions that the Company had entered included (i) operating lease agreements, (ii) drilling commitments, (iii) firm purchase, transportation and fractionation commitments, (iv) open purchase commitments and (v) contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that are sensitive to future changes in commodity prices or interest rates, gathering, processing (primarily treating and fractionation) and transportation commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company's liquidity or availability of or requirements for capital resources. See "Contractual obligations" below and Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information regarding the Company's off-balance sheet arrangements.

Contractual obligations. The Company's contractual obligations include long-term debt, operating leases, drilling commitments (primarily related to commitments to pay day rates for contracted drilling rigs), capital funding obligations, derivative obligations, firm transportation and fractionation commitments, minimum annual gathering, processing and transportation commitments and other liabilities (including postretirement benefit obligations). Other joint owners in the properties operated by the Company will incur portions of the costs represented by these commitments.

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The following table summarizes by period the payments due by the Company for contractual obligations estimated as of December 31, 2015:



	Payments Due by Year
	2016		2017 and 2018		2019 and 2020		Thereafter
	(in millions)
Long-term debt (a)	$	455	$	935	$	450	$	1,850
Operating leases (b)	24		44		38		15
Drilling commitments (c)	179		174		10		—
Derivative obligations (d)	—		1		—		—
Purchase commitments (e)	107		2		—		—
Other liabilities (f)	56		78		74		180
Firm purchase, gathering, processing, transportation and fractionation commitments (g)	451		955		932		1,145
	$	1,272	$	2,189	$	1,504	$	3,190

_____________________


(a)	See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for information regarding estimated future interest payment obligations under long-term debt obligations. The amounts included in the table above represent principal maturities only.


(b)	See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about the Company's operating leases.


(c)	Drilling commitments represent future minimum expenditure commitments for drilling rig services and well commitments under contracts to which the Company was a party on December 31, 2015. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's drilling commitments.

(d)

Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity derivatives that were valued as of December 31, 2015. The ultimate settlement amounts of the Company's derivative obligations are unknown because they are subject to continuing market risk. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's derivative obligations.


(e)	Open purchase commitments primarily represent expenditure commitments for inventory, materials and other property and equipment ordered, but not received, as of December 31, 2015.

(f)

The Company's other liabilities represent current and noncurrent other liabilities that are comprised of postretirement benefit obligations, litigation and environmental contingencies, asset retirement obligations and other obligations for which neither the ultimate settlement amounts nor their timings can be precisely determined in advance. See Notes H, I and J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's postretirement benefit obligations, asset retirement obligations and litigation and environmental contingencies, respectively.

(g)

Firm purchase, gathering, processing, transportation and fractionation commitments represent take-or-pay agreements, which include (i) contractual commitments to purchase sand and water for use in the Company's drilling operations and (ii) estimated fees on production throughput commitments and demand fees associated with volume delivery commitments. The Company does not expect to be able to fulfill all of its short-term and long-term delivery obligations from projected production of available reserves; consequently, the Company plans to purchase third party volumes to satisfy its commitments if it is economic to do so; otherwise, it will pay demand fees for any commitment shortfalls. See "Item 2. Properties" and Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's firm purchase, gathering, processing, transportation and fractionation commitments.

Capital resources. The Company's primary capital resources are cash and cash equivalents, net cash provided by operating activities, proceeds from divestitures and proceeds from financing activities (principally borrowings under the Company's credit facility or issuances of debt or equity securities). If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, and/or fund a portion of its capital expenditures using availability under the Company's credit facility, issue debt or equity securities or obtain capital from other sources, such as through sales of nonstrategic assets.

Operating activities. Net cash provided by operating activities for the years ended December 31, 2015, 2014 and 2013 was $1.2 billion, $2.4 billion and $2.1 billion, respectively. The decrease in net cash flow provided by operating activities in 2015, as

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compared to 2014, was primarily due to declines in average oil, NGL and gas prices, partially offset by an increase in net cash receipts from derivative settlements and an increase in oil and gas sales volumes. The increase in net cash flows provided by operating activities in 2014, as compared to 2013, was primarily due to increases in oil and gas sales, partially offset by decreases in net cash receipts from derivative settlements.

Asset divestitures. In July 2015, the Company completed the sale of its 50.1 percent 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.

During 2014, the Company's major asset sales included the sale of (i) the Company's Hugoton assets for cash proceeds of $328 million, (ii) the Company's Barnett Shale assets for cash proceeds of $150 million, (iii) Pioneer Alaska for cash proceeds of $267 million, (iv) Sendero for cash proceeds of $31 million (Sendero had $14 million of cash on hand at the time of the sale) and (v) proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million.

In January 2013, the Company signed an agreement with Sinochem to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for consideration of $1.8 billion. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $624 million, resulting in a gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem 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. During 2013, the Company also completed a sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38 million, which resulted in a gain of $22 million.

See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information regarding the Company's divestitures.

Financing activities. Net cash provided by financing activities during 2015 was $958 million, as compared to net cash provided by financing activities during 2014 and 2013 of $965 million and $158 million, respectively. The following provides a description of the Company's significant financing activities during 2015, 2014 and 2013:


•	During December 2015, the Company issued $500 million of 3.45% Senior Notes due 2021 and $500 million of 4.45% Senior Notes due 2026 and received combined proceeds, net of $9 million of offering discounts and costs, of $991 million;


•	During August 2015, the Company amended its credit facility with a syndicate of financial institutions to extend its maturity to August 2020, while maintaining aggregate loan commitments of $1.5 billion;


•	During November 2014, the Company completed the sale of 5.75 million shares of its common stock at a per-share price, after underwriter and offering expenses, of $170.50, resulting in $980 million of net cash proceeds;

•

During December 2012 and March 2013, the Company's stock price met the price threshold that caused the Convertible Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued. On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six months ended June 30, 2013, holders of $479 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $1 million in principal and interest to redeem all Convertible Senior Notes that remained outstanding;


•	During February 2013, the Company completed the sale of 10.35 million shares of its common stock at a per-share price, after underwriting and offering expenses, of $123.76, resulting in $1.3 billion of net cash proceeds; and


•	During 2013, the Company made $1.1 billion of net payments on long-term debt and $47 million of dividend payments and distributions to noncontrolling interests.

Subsequent to December 31, 2015, the Company issued 13.8 million shares of its common stock at a per share price, after underwriting and offering expenses, of $115.78, resulting in $1.6 billion of net cash proceeds.

See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the significant debt financing activities.

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As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt, convertible securities, preferred stock or common stock. The Company cannot predict the timing or ultimate outcome of any such actions as they are subject to market conditions, among other factors. The Company may also issue securities in exchange for oil and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and preferences as determined by the Board.

Liquidity. The Company's principal sources of short-term liquidity are cash and cash equivalents and unused borrowing capacity under the Company's credit facility. As of December 31, 2015, the Company had no outstanding borrowings under the credit facility, leaving $1.5 billion of unused borrowing capacity. The Company was in compliance with all of its debt covenants. The Company's credit facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments, not to exceed .60 to 1.0, which is above the Company's December 31, 2015 ratio of .26 to 1.0. The Company also had cash on hand of $1.4 billion as of December 31, 2015. If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under the Company's credit facility, issuances of debt or equity securities or other sources, such as sales of nonstrategic assets. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable terms or at all. Although the Company expects that the combination of internal operating cash flows, cash and cash equivalents on hand, the receipt of the remaining approximately $500 million of proceeds from the EFS Midstream divestiture, proceeds from the issuance of common stock in early 2016 and, if necessary, available capacity under the Company's credit facility will be adequate to fund 2016 capital expenditures and dividend payments and provide adequate liquidity to fund other needs, including debt maturities, no assurances can be given that such funding sources will be adequate to meet the Company's future needs.

Debt ratings. The Company is rated as investment grade by three credit rating agencies. The Company receives debt credit ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the rating agencies considers many factors in determining the Company's ratings, including: (i) production growth opportunities, (ii) liquidity, (iii) debt levels, (iv) asset composition and (v) proved reserve mix. A reduction in the Company's debt ratings could increase the interest rates that the Company incurs on credit facility borrowings and could negatively affect the Company's ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing.

Book capitalization and current ratio. The Company's net book capitalization at December 31, 2015 was $10.6 billion, consisting of $1.4 billion of cash and cash equivalents, debt of $3.7 billion and equity of $8.4 billion. The Company's net debt to book capitalization increased to 21 percent at December 31, 2015 from 16 percent at December 31, 2014, primarily due to the net loss recognized for the year principally as a result of (i) a 46 percent reduction in the average commodity prices per BOE received during 2015, as compared to 2014, and (ii) impairment charges to reduce the carrying value of oil and gas properties of $1.1 billion. The Company's ratio of current assets to current liabilities increased to 2.19 to 1.00 at December 31, 2015, as compared to 1.66 to 1.00 at December 31, 2014, primarily due to the $498 million note receivable associated with the sale of EFS Midstream and increases in cash on hand, partially offset by the increase to the current portion of long-term debt.

Critical Accounting Estimates

The Company prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a comprehensive discussion of the Company's significant accounting policies. GAAP represents a comprehensive set of accounting and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain circumstances, choices between acceptable GAAP alternatives. The following is a discussion of the Company's most critical accounting estimates, judgments and uncertainties that are inherent in the Company's application of GAAP.

Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to restore the land at the end of oil and gas production operations. The Company's removal and restoration obligations are primarily associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, credit-adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a corresponding adjustment is generally made to the oil and gas property balance. See Notes B and I of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's asset retirement obligations.

Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for oil and gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net assets and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing activities than under the full cost method, particularly during periods of active exploration. The critical difference between the successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur; whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of successful wells and charged against the earnings of future periods as a component of depletion expense. During 2015, 2014 and 2013, the Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of $99 million, $177 million and $97 million, respectively. During 2015, 2014 and 2013, the Company recognized exploration, abandonment, geological and geophysical expense from discontinued operations of nil, $4 million and $54 million, respectively, under the successful efforts method.

Proved reserve estimates. Estimates of the Company's proved reserves included in this Report are prepared in accordance with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:


•	the quality and quantity of available data;


•	the interpretation of that data;


•	the accuracy of various mandated economic assumptions; and


•	the judgment of the persons preparing the estimate.

The Company's proved reserve information included in this Report as of December 31, 2015, 2014 and 2013 was prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major properties. Estimates prepared by third parties may be higher or lower than those included herein.

Because these estimates depend on many assumptions, all of which may substantially differ from future actual results, proved reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate of proved reserves.

It should not be assumed that the Standardized Measure included in this Report as of December 31, 2015 is the current market value of the Company's estimated proved reserves. In accordance with SEC requirements, the Company based the 2015 Standardized Measure on a twelve month average of commodity prices on the first day of the month and prevailing costs on the date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the estimate. See "Item 1A. Risk Factors," "Item 2. Properties" and Supplementary Information included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding estimates of proved reserves.

The Company's estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline, the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline in proved reserve estimates may impact the outcome of the Company's assessment of its proved properties and goodwill for impairment.

Impairment of proved oil and gas properties. The Company reviews its proved properties to be held and used whenever management determines that events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future recoverable proved and risk-adjusted probable and possible reserves, Management's Price Outlooks, production and capital costs expected to be incurred to recover the reserves, discount rates commensurate with the nature of the properties and net cash flows that may be generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved properties is calculated. See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's impairment assessments.

Impairment of unproved oil and gas properties. At December 31, 2015, the Company carried unproved property costs of $169 million. Management assesses unproved oil and gas properties for impairment on a project-by-project basis. Management's impairment assessments include evaluating the results of exploration activities, Management's Price Outlooks and planned future sales or expiration of all or a portion of such projects.

Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final determination of the commercial potential of the discovery. The ultimate disposition of these well costs is dependent on the results of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or development of these fields, the costs of these wells will be charged to exploration and abandonment expense.

The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following the completion of drilling unless both of the following conditions are met:


(i)	The well has found a sufficient quantity of reserves to justify its completion as a producing well; and


(ii)	The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves to sanction the project or is noncommercial and is impaired. See Note F of Notes to Consolidated Financial Statements included

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in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's suspended exploratory well costs.

Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that its deferred tax assets, if any, will be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and reassesses the likelihood that the Company's net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration. There can be no assurance that facts and circumstances will not materially change and require the Company to establish deferred tax asset valuation allowances in certain jurisdictions in a future period.

Goodwill impairment. The Company reviews its goodwill for impairment at least annually. During the third quarter of 2015, the Company performed a quantitative assessment of goodwill and determined that there was no impairment. During the fourth quarter of 2015 and the third and fourth quarters of 2014, the Company performed qualitative assessments of goodwill to assess whether it was more likely than not that the fair value of the Company's reporting unit was less than its carrying amount as a basis for determining whether it was necessary to perform the two-step goodwill impairment test. The Company determined that it was more likely than not that the Company's goodwill was not impaired. There is considerable judgment involved in estimating fair values, particularly in determining the valuation methodologies to utilize, the estimation of proved reserves as described above and the weighting of different valuation methodologies applied. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding goodwill and assessments of goodwill for impairment.

Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations, developing information relating to the extent and nature of site contamination and improvements in technology. A liability is recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's commitments and contingencies.

Valuation of stock-based compensation. The Company calculates the fair value of stock-based compensation using various valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the closing stock price on the day prior to the date of grant for the fair value of restricted stock awards, (iii) the closing stock price on the balance sheet date for restricted stock awards that are expected to be settled wholly or partially in cash on their vesting date and (iv) the Monte Carlo simulation method for the fair value of performance unit awards. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the Company's stock-based compensation.

Valuation of other assets and liabilities at fair value. The Company periodically measures and records certain assets and liabilities at fair value. The assets and liabilities that the Company periodically measures and records at fair value include trading securities, commodity derivative contracts and interest rate contracts. The Company also measures and discloses certain financial assets and liabilities at fair value, such as long-term debt. The valuation methods used by the Company to measure the fair values of these assets and liabilities require considerable management judgment and estimates to derive the inputs necessary to determine fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding the methods used by management to estimate the fair values of these assets and liabilities.

New Accounting Pronouncements

The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data."

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ITEM 7A.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The following quantitative and qualitative information is provided about financial instruments to which the Company was a party as of December 31, 2015, and from which the Company may incur future gains or losses from changes in commodity prices or interest rates.

The fair values of the Company's long-term debt and derivative contracts are determined based on observable inputs and utilizing the Company's valuation models and applications. As of December 31, 2015, the Company was a party to commodity swap contracts and commodity collar contracts with short put options. See Notes D and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's fair value measurements and derivative contracts. The following table reconciles the changes that occurred in the fair values of the Company's open derivative contracts during 2015:



	Derivative Contract Net Assets (Liabilities)
	Commodities			Interest Rate			Total
	(in millions)
Fair value of contracts outstanding as of December 31, 2014	$	757		$	(3	)	$	754
Changes in contract fair values	873			6			879
Contract maturities	(867		)	—			(867		)
Contract terminations	(6		)	(3		)	(9		)
Fair value of contracts outstanding as of December 31, 2015	$	757		$	—		$	757

Quantitative Disclosures

Interest rate sensitivity. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" and Capital Commitments, Capital Resources and Liquidity included in "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for information regarding the Company's outstanding debt and debt transactions.

The following table provides information about financial instruments to which the Company was a party as of December 31, 2015 and that are sensitive to changes in interest rates. The table presents debt maturities by expected maturity dates, the weighted average interest rates expected to be paid on the debt given current contractual terms and market conditions, and the aggregate estimated fair value of the Company's outstanding debt. For fixed rate debt, the weighted average interest rates represent the contractual fixed rates that the Company was obligated to periodically pay on the debt as of December 31, 2015. Although the Company had no outstanding variable rate debt as of December 31, 2015, the average variable contractual rates for its credit facility (that matures in August 2020) projected forward proportionate to the forward yield curve for LIBOR on February 12, 2016 is presented in the table below.

INTEREST RATE SENSITIVITY

DEBT OBLIGATIONS AS OF DECEMBER 31, 2015



	Year Ending December 31,																				Liability Fair Value at December 31,
	2016			2017			2018			2019			2020			Thereafter			Total		2015
Total Debt:	(dollars in millions)
Fixed rate principal maturities (a)	$	455		$	485		$	450		$	—		$	450		$	1,850		$	3,690	$	3,668
Weighted average fixed interest rate	5.53		%	5.35		%	5.11		%	5.00		%	4.42		%	5.28		%
Weighted average variable interest rate	2.19		%	2.37		%	2.66		%	2.98		%	3.27		%

_______________________


(a)	Represents maturities of principal amounts excluding debt issuance costs, debt issuance discounts and net deferred fair value hedge losses.

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Interest rate swaps. During the period from January 1, 2016 through February 16, 2016, the Company entered into interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 through December 2027 in exchange for paying a fixed interest rate of 1.98 percent on a notional amount of $200 million on December 15, 2017.

Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil, NGL and gas derivative financial instruments that were sensitive to changes in oil, NGL and gas prices as of December 31, 2015. Although mitigated by the Company's derivative activities, declines in oil, NGL and gas prices would reduce the Company's revenues.

The Company manages commodity price risk with derivative contracts, such as swap contracts, collar contracts and collar contracts with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum ("floor" or "long put") and maximum ("ceiling") prices on a notional amount of sales volumes, thereby allowing some price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other collar contracts by virtue of the short put option price, below which the Company's realized price will exceed the variable market prices by the long put-to-short put price differential.

See Notes B, D and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of the accounting procedures followed by the Company relative to its derivative financial instruments and for specific information regarding the terms of the Company's derivative financial instruments that are sensitive to changes in oil, NGL or gas prices.

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DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2015



	2016
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			Year Ending December 31, 2017			Asset (Liability) Fair Value at December 31, 2015 (a)
																(in millions)
Oil Derivatives:
Average daily notional Bbl volumes:
Swap contracts (b)	35,000			35,000			—			—			—			$	129
Weighted average fixed price per Bbl	$	59.88		$	59.88		$	—		$	—		$	—
Collar contracts with short puts (b)	63,000			68,000			112,000			112,000			34,000			$	552
Weighted average ceiling price per Bbl	$	73.29		$	72.43		$	75.94		$	75.94		$	70.42
Weighted average floor price per Bbl	$	63.04		$	62.08		$	65.41		$	65.41		$	57.65
Weighted average short put price per Bbl	$	43.17		$	42.94		$	47.03		$	47.03		$	47.65
Average forward NYMEX oil prices (c)	$	29.44		$	33.67		$	36.98		$	38.92		$	42.15
NGL Derivatives:
Average daily notional Bbl volumes:
Propane swap contracts (d)	7,500			7,500			7,500			7,500			—			$	14
Weighted average fixed price per BBL	$	21.57		$	21.57		$	21.57		$	21.57		$	—
Average forward propane prices (c)	$	15.44		$	15.70		$	16.36		$	17.22		$	—
Gas Derivatives:
Average daily notional MMBtu volumes:
Swap contracts	70,000			70,000			70,000			70,000			—			$	40
Weighted average fixed price per MMBtu	$	4.06		$	4.06		$	4.06		$	4.06		$	—
Collar contracts with short puts	180,000			180,000			180,000			180,000			—			$	24
Weighted average ceiling price per MMBtu	$	4.01		$	4.01		$	4.01		$	4.01		$	—
Weighted average floor price per MMBtu	$	3.24		$	3.24		$	3.24		$	3.24		$	—
Weighted average short put price per MMBtu	$	2.78		$	2.78		$	2.78		$	2.78		$	—
Average forward NYMEX gas prices (c)	$	1.97		$	2.10		$	2.26		$	2.44		$	—
Basis swap contracts (e)																$	(2	)
Gulf Coast index swap contracts	10,000			10,000			10,000			10,000			—
Weighted average fixed price per MMBtu	$	—		$	—		$	—		$	—		$	—
Average forward basis differential prices (f)	$	(0.05	)	$	(0.05	)	$	—		$	(0.06	)
Mid-Continent index swap contracts	15,000			15,000			15,000			15,000			45,000
Weighted average fixed price per MMBtu	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	(0.32	)
Average forward basis differential prices (f)	$	(0.27	)	$	(0.33	)	$	(0.24	)	$	(0.14	)	$	(0.22	)
Permian Basin index swap contracts (g) (i)	6,813			—			—			—			—
Weighted average fixed price per MMBTU	$	0.26		$	—		$	—		$	—		$	—
Average forward basis differential prices (h)	$	0.09		$	—		$	—		$	—		$	—

_____________________

(a)

In accordance with Financial Accounting Standards Board Accounting Standards Codification ("ASC") 210-20 and ASC 815-10, the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net derivative assets or net derivative liabilities, as the case may be. The net asset and liability amounts shown above have been provided on a commodity contract-type basis, which may differ from their master netting arrangements classifications.


(b)	During the period from January 1, 2016 through February 16, 2016, the Company converted 25,000 Bbls per day of March through June 2016 collar contracts with short puts with a ceiling price of $71.02 per Bbl, a floor price of $60.00 per Bbl and a short put price of $48.00 per Bbl into new swap contracts covering the same period with a fixed price of $43.54 per Bbl.


(c)	The average forward NYMEX oil, propane and gas prices are based on February 12, 2016 market quotes.


(d)	Represent swaps that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and

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PIONEER NATURAL RESOURCES COMPANY

Conway, Kansas-posted prices.


(e)	Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the NYMEX Henry Hub ("HH") index price used in gas swap and collar contracts with short puts.


(f)	The average forward basis differential prices are based on February 12, 2016 market quotes for basis differentials between the relevant index prices and NYMEX-quoted forward prices.


(g)	Represent swaps that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California.


(h)	The average forward basis differential prices are based on February 12, 2016 market quotes for basis differentials between Permian Basin index prices and southern California index prices.


(i)	During the period from January 1, 2016 through February 16, 2016, the Company entered into (i) 40,000 MMBtu per day of additional basis swap contracts for November 2016 through March 2017 with a fixed price of $0.37 per MMBtu and (ii) 25,000 MMBtu per day of additional basis swap contracts for December 2016 with a fixed price of $0.53 per MMBtu.

Marketing and basis derivative activities. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of December 31, 2015, the Company does not have any marketing derivatives outstanding.

Qualitative Disclosures

The Company's primary market risk exposures are to changes in commodity prices and interest rates. These risks did not change materially from December 31, 2014 to December 31, 2015.

Non-derivative financial instruments. The Company is a borrower under fixed rate debt instruments and, from time to time, under a variable rate debt instrument that gives rise to interest rate risk. The Company's objective in borrowing under fixed or variable rate debt is to satisfy capital requirements while minimizing the Company's costs of capital. The Company also enters into oil and gas purchase and sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a discussion of the Company's debt instruments.

Derivative financial instruments. The Company, from time to time, utilizes commodity price and interest rate derivative contracts to mitigate commodity price and interest rate risks in accordance with policies and guidelines approved by the Board. In accordance with those policies and guidelines, the Company's executive management determines the appropriate timing and extent of derivative transactions.

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ITEM 8.	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

Index to Consolidated Financial Statements



	Page
Consolidated Financial Statements of Pioneer Natural Resources Company:

Report of Independent Registered Public Accounting Firm	67
Consolidated Balance Sheets as of December 31, 2015 and 2014	68
Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013	70
Consolidated Statements of Equity for the Years Ended December 31, 2015, 2014 and 2013	71
Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013	73
Notes to Consolidated Financial Statements	74
Unaudited Supplementary Information	106

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REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM

The Board of Directors and Stockholders of

Pioneer Natural Resources Company

We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company (the "Company") as of December 31, 2015 and 2014, and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Pioneer Natural Resources Company at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Pioneer Natural Resources Company's internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 19, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

February 19, 2016

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS

(in millions)



	December 31,
	2015			2014
ASSETS
Current assets:
Cash and cash equivalents	$	1,391		$	1,025
Accounts receivable:
Trade, net	384			436
Due from affiliates	1			4
Income taxes receivable	43			23
Inventories	155			241
Prepaid expenses	17			15
Notes receivable	498			—
Derivatives	694			578
Other	11			37
Total current assets	3,194			2,359
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties	16,631			15,662
Unproved properties	169			159
Accumulated depletion, depreciation and amortization	(6,778		)	(5,431		)
Total property, plant and equipment	10,022			10,390
Goodwill	272			272
Other property and equipment, net	1,523			1,391
Investment in unconsolidated affiliate	—			239
Derivatives	64			181
Other, net	79			77
	$	15,154		$	14,909

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED BALANCE SHEETS (continued)

(in millions, except share data)



	December 31,
	2015			2014
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable:
Trade	$	798		$	1,197
Due to affiliates	85			123
Interest payable	65			40
Income taxes payable	2			1
Current portion of long-term debt	448			—
Derivatives	—			3
Other	64			55
Total current liabilities	1,462			1,419
Long-term debt	3,207			2,648
Derivatives	1			2
Deferred income taxes	1,776			1,964
Other liabilities	333			287
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 152,775,920 and 152,158,428 shares issued as of December 31, 2015 and 2014, respectively	2			2
Additional paid-in capital	6,267			6,167
Treasury stock, at cost: 3,396,220 and 3,253,781 shares as of December 31, 2015 and 2014, respectively	(199		)	(171		)
Retained earnings	2,298			2,583
Total equity attributable to common stockholders	8,368			8,581
Noncontrolling interest in consolidated subsidiaries	7			8
Total equity	8,375			8,589
Commitments and contingencies
	$	15,154		$	14,909

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)



	Year Ended December 31,
	2015			2014			2013
Revenues and other income:
Oil and gas	$	2,178		$	3,599		$	3,088
Sales of purchased oil and gas	964			726			334
Interest and other	22			26			23
Derivative gains, net	879			712			4
Gain on disposition of assets, net	782			9			209
	4,825			5,072			3,658
Costs and expenses:
Oil and gas production	717			693			588
Production and ad valorem taxes	145			220			192
Depletion, depreciation and amortization	1,385			1,047			889
Purchased oil and gas	1,003			703			336
Impairment of oil and gas properties	1,056			—			1,495
Exploration and abandonments	99			177			97
General and administrative	327			333			296
Accretion of discount on asset retirement obligations	12			12			12
Interest	187			184			184
Other	315			106			143
	5,246			3,475			4,232
Income (loss) from continuing operations before income taxes	(421		)	1,597			(574		)
Income tax benefit (provision)	155			(556		)	213
Income (loss) from continuing operations	(266		)	1,041			(361		)
Loss from discontinued operations, net of tax	(7		)	(111		)	(438		)
Net income (loss)	(273		)	930			(799		)
Net income attributable to noncontrolling interests	—			—			(39		)
Net income (loss) attributable to common stockholders	$	(273	)	$	930		$	(838	)
Basic earnings per share attributable to common stockholders:
Income (loss) from continuing operations	$	(1.79	)	$	7.17		$	(2.94	)
Loss from discontinued operations	(0.04		)	(0.77		)	(3.22		)
Net income (loss)	$	(1.83	)	$	6.40		$	(6.16	)
Diluted earnings per share attributable to common stockholders:
Income (loss) from continuing operations	$	(1.79	)	$	7.15		$	(2.94	)
Loss from discontinued operations	(0.04		)	(0.77		)	(3.22		)
Net income (loss)	$	(1.83	)	$	6.38		$	(6.16	)
Weighted average shares outstanding:
Basic	149			144			136
Diluted	149			144			136

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF EQUITY

(in millions, except share data and dividends per share)



			Equity Attributable to Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital			Treasury Stock			Retained Earnings			Noncontrolling Interests			Total Equity
	(in thousands)
Balance as of December 31, 2012	123,356		$	1	$	3,684		$	(510	)	$	2,514		$	178		$	5,867
Issuance of common stock	10,350		—		1,281			—			—			—			1,281
Dividends declared ($0.08 per share)	—		—		—			—			(11		)	—			(11		)
Exercise of long-term incentive plan stock options and employee stock purchases	222		—		—			10			—			—			10
Purchase of treasury stock	(154	)	—		—			(20		)	—			—			(20		)
Conversion of 2.875% convertible senior notes	4,381		—		(197		)	197			—			—			—
Deferred tax benefit related to conversion of 2.875% senior convertible notes	—		—		38			—			—			—			38
Tax benefits related to stock-based compensation	—		—		18			—			—			—			18
Pioneer Southwest merger:
Issuance of treasury stock to acquire outstanding PSE units	3,956		—		(179		)	179			—			—			—
Pioneer Southwest merger transaction costs	—		—		(4		)	—			—			—			(4		)
Pioneer Southwest noncontrolling interest transferred to APIC	—		—		169			—			—			(169		)	—
Deferred tax benefit associated with Pioneer Southwest merger	—		—		200			—			—			—			200
Compensation costs:
Vested compensation awards, net	517		—		—			—			—			—			—
Compensation costs included in net loss	—		—		70			—			—			1			71
Distributions to noncontrolling interests	—		—		—			—			—			(36		)	(36		)
Net loss	—		—		—			—			(838		)	39			(799		)
Balance as of December 31, 2013	142,628		$	1	$	5,080		$	(144	)	$	1,665		$	13		$	6,615
Issuance of common stock	5,750		1		979			—			—			—			980
Dividends declared ($0.08 per share)	—		—		—			—			(12		)	—			(12		)
Exercise of long-term incentive plan stock options and employee stock purchases	130		—		6			7			—			—			13
Purchase of treasury stock	(178	)	—		—			(34		)	—			—			(34		)
Sendero divestiture	—		—		—			—			—			(4		)	(4		)
Tax benefits related to stock-based compensation	—		—		19			—			—			—			19
Pioneer Southwest merger transaction costs	—		—		(1		)	—			—			—			(1		)
Compensation costs:
Vested compensation awards, net	575		—		—			—			—			—			—
Compensation costs included in net income	—		—		84			—			—			—			84
Distributions to noncontrolling interests	—		—		—			—			—			(1		)	(1		)
Net income	—		—		—			—			930			—			930
Balance as of December 31, 2014	148,905		$	2	$	6,167		$	(171	)	$	2,583		$	8		$	8,589

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF EQUITY (continued)

(in millions, except share data and dividends per share)



			Equity Attributable to Common Stockholders
	Shares Outstanding		Common Stock		Additional Paid-in Capital		Treasury Stock			Retained Earnings			Noncontrolling Interests			Total Equity
	(in thousands)
Balance as of December 31, 2014	148,905		$	2	$	6,167	$	(171	)	$	2,583		$	8		$	8,589
Dividends declared ($0.08 per share)	—		—		—		—			(12		)	—			(12		)
Employee stock purchases	58		—		3		3			—			—			6
Purchases of treasury stock	(201	)	—		—		(31		)	—			—			(31		)
Tax benefits related to stock-based compensation	—		—		7		—			—			—			7
Compensation costs:
Vested compensation awards, net	618		—		—		—			—			—			—
Compensation costs included in net loss	—		—		90		—			—			—			90
Cash distributions to noncontrolling interests	—		—		—		—			—			(1		)	(1		)
Net loss	—		—		—		—			(273		)	—			(273		)
Balance as of December 31, 2015	149,380		$	2	$	6,267	$	(199	)	$	2,298		$	7		$	8,375

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

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PIONEER NATURAL RESOURCES COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)



	Year Ended December 31,
	2015			2014			2013
Cash flows from operating activities:
Net income (loss)	$	(273	)	$	930		$	(799	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depletion, depreciation and amortization	1,385			1,047			889
Impairment of oil and gas properties	1,056			—			1,495
Impairment of inventory and other property and equipment	86			8			62
Exploration expenses, including dry holes	28			90			21
Deferred income taxes	(178		)	552			(224		)
Gain on disposition of assets, net	(782		)	(9		)	(209		)
Accretion of discount on asset retirement obligations	12			12			12
Discontinued operations	(4		)	251			633
Interest expense	18			17			17
Derivative related activity	(3		)	(609		)	164
Amortization of stock-based compensation	90			84			71
Other	38			34			(6		)
Change in operating assets and liabilities
Accounts receivable, net	54			(29		)	(123		)
Income taxes receivable	(20		)	(18		)	3
Inventories	8			(37		)	(39		)
Prepaid expenses	(2		)	(3		)	(1		)
Other current assets	2			1			4
Accounts payable	(258		)	104			209
Interest payable	25			(22		)	(6		)
Income taxes payable	1			1			—
Other current liabilities	(35		)	(38		)	(27		)
Net cash provided by operating activities	1,248			2,366			2,146
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold	553			877			711
Distribution from unconsolidated subsidiary	—			—			25
Additions to oil and gas properties	(2,110		)	(3,243		)	(2,639		)
Additions to other assets and other property and equipment, net	(283		)	(333		)	(237		)
Net cash used in investing activities	(1,840		)	(2,699		)	(2,140		)
Cash flows from financing activities:
Borrowings under long-term debt	998			523			467
Principal payments on long-term debt	—			(523		)	(1,547		)
Proceeds from issuance of common stock, net of issuance costs	—			980			1,281
Distributions to noncontrolling interests	(1		)	(1		)	(36		)
Payments of other liabilities	—			—			(4		)
Exercise of long-term incentive plan stock options and employee stock purchases	6			13			10
Purchases of treasury stock	(31		)	(34		)	(20		)
Tax benefits related to stock-based compensation	7			19			18
Payments of financing fees	(9		)	—			—
Dividends paid	(12		)	(12		)	(11		)
Net cash provided by financing activities	958			965			158
Net increase in cash and cash equivalents	366			632			164
Cash and cash equivalents, beginning of period	1,025			393			229
Cash and cash equivalents, end of period	$	1,391		$	1,025		$	393

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014 and 2013

NOTE A. Organization and Nature of Operations

Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company operating in the United States, with operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeast Colorado and the West Panhandle field in the Texas Panhandle. The Company's objective is to maximize shareholder investment returns by maintaining financial flexibility, capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions.

NOTE B. Summary of Significant Accounting Policies

Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-owned and majority-owned subsidiaries since their acquisition or formation. All material intercompany balances and transactions have been eliminated.

Certain reclassifications have been made to the 2014 and 2013 financial statement and footnote amounts in order to conform them to the 2015 presentations.

Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial statements in conformity with generally accepted accounting principles in the United States ("GAAP") requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.

Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and marketable securities with original issuance maturities of 90 days or less.

Accounts receivable. As of December 31, 2015 and 2014, the Company had accounts receivable – trade, net of allowances for bad debts, of $384 million and $436 million, respectively. The Company's accounts receivable – trade are primarily comprised of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral security.

As of both December 31, 2015 and 2014, the Company's allowances for doubtful accounts totaled $1 million. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable. Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations in the accounting periods during which failure to collect an estimable portion is determined to be probable.

Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market, on a first-in, first-out cost basis. Valuation allowances for materials and supplies inventories are recorded as reductions to the carrying values of the materials and supplies inventories in the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations.

Commodity inventories are carried at the lower of cost or market, on a first-in, first-out basis. The Company's commodity inventories consist of oil, natural gas liquids ("NGLs") and gas volumes held in storage or as linefill in pipelines. Any valuation allowances of commodity inventories are recorded as reductions to the carrying values of the commodity inventories included in

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

the Company's accompanying consolidated balance sheets and as charges to other expense in the accompanying consolidated statements of operations.

The following table presents the Company's materials and supplies and commodity inventories as of December 31, 2015 and 2014:



	As of December 31,
	2015		2014
	(in millions)
Materials and supplies (a)	$	132	$	223
Commodities	23		18
	$	155	$	241

____________________


(a)	As of December 31, 2015 and 2014, the Company's materials and supplies inventories were net of valuation allowances of $78 million and $22 million, respectively. See Note D for additional information regarding inventory impairments.

Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties. Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are ready for their intended use.


(i)	The well has found a sufficient quantity of reserves to justify its completion as a producing well; and


(ii)	The Company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly. Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs.

The Company owns interests in 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. The Company's ownership interests in the gas processing plants and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity. All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities in continuing operations for the years ended December 31, 2015, 2014 and 2013 were $39 million, $56 million and $53 million, respectively. Third party expenses attributable to the processing plants and treating facilities in continuing operations for the same respective periods were $27 million, $24 million and $21 million. The capitalized costs of the plants and treating facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other capitalized costs of the field that they service.

The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However, gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially impact the depletion rate of the remaining properties in the amortization base.

The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows, including vertical integrated services that are used in the development of the assets, is less than the carrying amount of the assets, including the carrying value of vertical integrated services assets. In these circumstances, the Company recognizes an impairment loss for the amount by which the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding the Company's impairment of proved oil and gas properties.

Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time.

Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost of the acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired, it is reduced to the impaired value with a corresponding charge to earnings in the period in which it is determined to be impaired. During the third quarter of 2015, the Company performed a quantitative assessment of goodwill and determined that there was no impairment. The Company reevaluated this assessment during the fourth quarter of 2015 due to reductions in (i) management's longer-term commodity price outlooks ("Management's Price Outlooks") and (ii) the Company's common stock price. Based upon the results of this qualitative assessment, the Company determined that it was more likely than not that the Company's goodwill was not impaired.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2015 and 2014, respectively, the net carrying value of other property and equipment consisted of the following:



	As of December 31,
	2015 (a)		2014 (a)
	(in millions)
Proved and unproved sand properties (b)	$	473	$	469
Land and buildings	468		440
Equipment and rigs (c)	287		338
Water infrastructure (d)	180		10
Vehicles	21		35
Furniture and fixtures	67		70
Leasehold improvements	27		29
	$	1,523	$	1,391

____________________


(a)	At December 31, 2015 and 2014, other property and equipment was net of accumulated depreciation of $711 million and $563 million, respectively.


(b)	Includes sand mines, facilities and unproved leaseholds that primarily provide the Company with proppant for use in the fracture stimulation of oil and gas wells.

(c)

Includes well servicing equipment and rigs and fracture stimulation equipment that are owned by wholly-owned subsidiaries that provide pumping and well services on Company-operated properties. As of December 31, 2015, the Company owned eight fracture stimulation fleets and other oilfield services equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools.


(d)	Includes water supply wells and pipeline infrastructure costs.

The primary purposes of the Company's sand mines and pumping and well services operations are to accommodate the Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than being dependent on third-party availability, and to contain associated costs. All intercompany gains or losses of the Company's sand mines and pumping and well services operations are eliminated.

The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand reserves. Other property and equipment is depreciated over its estimated useful life on a straight-line basis. Buildings are generally depreciated over 20 to 39 years. Equipment and rigs, vehicles, and furniture and fixtures are generally depreciated over two to 15 years. Water infrastructure is generally depreciated over 10 to 50 years. Leasehold improvements are amortized over the lesser of their estimated useful lives or the underlying terms of the associated leases.

The Company reviews its long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such assets are considered to be impaired, the impairment to be recognized is measured by the amount by which the carrying amount of the asset exceeds its estimated fair value. The estimated fair value is determined using either a discounted future cash flow model or another appropriate fair value method.

Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas. During June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party. In July 2015, the Company sold its remaining 50.1 percent interest in EFS Midstream to an unaffiliated third party. See Note C for additional information regarding the Company's divestitures.

Prior to the sale, the Company did not have control of EFS Midstream. Consequently, the Company accounted for this investment under the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company's investment in unconsolidated affiliates is increased for investments made and the investor's share of the investee's net income, and decreased for distributions received, the carrying value of member interests sold and the investor's share of the investee's net losses.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The Company's equity interest in the net income or loss of EFS Midstream (prior to its sale) was recorded in interest and other income, net of eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS Midstream, in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the net income of EFS Midstream for the years ended December 31, 2015, 2014 and 2013.

Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the period in which it is incurred, if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition of liabilities and are recognized when incurred if their fair values can be reasonably estimated.

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets and expenditures are classified as cash used in operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the Company's asset retirement obligations.

Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced by the average purchase price per share of the aggregate treasury shares held.

Issuance of common stock. In November 2014 and February 2013, the Company issued 5.75 million shares and 10.35 million shares of its common stock, respectively, and realized cash proceeds of $980 million and $1.3 billion, respectively, net of associated underwriting and offering expenses.

Noncontrolling interest in consolidated subsidiaries. The Company owns the majority interests in certain subsidiaries with operations in the United States. Prior to December 17, 2013, the Company owned a 0.1 percent general partner interest and a 52.4 percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest") and consolidated the financial position, results of operations and cash flows of Pioneer Southwest with those of Pioneer. Pioneer Southwest owned proved and unproved oil and gas properties in the Spraberry field in the Permian Basin of West Texas. On December 17, 2013, the holders of a majority of the outstanding common units of Pioneer Southwest approved an amended agreement and plan of merger, pursuant to which (i) all of the then outstanding common units of Pioneer Southwest were canceled and converted into the right to receive 0.2325 of a share of common stock of the Company and (ii) Pioneer Southwest became a wholly-owned subsidiary of the Company. The changes in the Company's ownership of Pioneer Southwest were accounted for by eliminating the noncontrolling interest attributable to Pioneer Southwest. See Note C for additional information about Pioneer Southwest and the amended agreement and plan of merger.

Noncontrolling interests in the net assets of consolidated subsidiaries totaled $7 million and $8 million as of December 31, 2015 and 2014, respectively. For the years ended December 31, 2015 and December 31, 2014, the Company recorded nominal net losses attributable to the noncontrolling interests, as compared to $39 million of net income attributable to the noncontrolling interests for the years ended December 31, 2013. The decrease in income attributable to noncontrolling interests for the years ended December 31, 2015 and 2014, as compared 2013, is due to the Company's acquisition of all of the outstanding common units of Pioneer Southwest not owned by the Company in December 2013.

The Company records transfers of any gains or losses, net of taxes, from noncontrolling interests in consolidated subsidiaries to additional paid in capital in an amount proportionate to the ownership of those noncontrolling interests after giving effect to the purchase or sale of common units. There were no transfers of gains or losses, net of tax, from noncontrolling interest to additional paid in capital during 2015. The effect of transfers of gains or losses, net of tax, from noncontrolling interest to additional paid in capital was a decrease of $1 million in 2014 associated with Pioneer Southwest merger transaction costs and an increase of $365 million in 2013, comprised of (i) an increase of $169 million to record the acquisition of noncontrolling interest of Pioneer Southwest, (ii) an increase of $200 million to recognize deferred taxes associated with the Pioneer Southwest acquisition and (iii) a decrease of $4 million associated with Pioneer Southwest merger transaction costs.

Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.

The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets in the accompanying consolidated balance sheets. The Company had no material oil, NGL or gas entitlement assets or liabilities as of December 31, 2015 or 2014.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's West Texas Intermediate ("WTI") oil sales to a Gulf Coast market price and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming the responsibility to deliver the commodities sold. Firm transportation payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations. See Note N for further information on transportation commitment charges.

Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. The Company recognizes all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods in which they occur.

The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties' credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's credit-adjusted risk-free rate curve. The credit-adjusted risk-free rate curves for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the United States Treasury Bill yield curve as of the valuation date. See Note E for additional information about the Company's derivative instruments.

Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject to revision until settlement occurs.

Stock-based compensation. Stock-based compensation expense is being recognized on restricted stock, restricted stock units, performance units and stock option awards that are expected to be settled in the Company's common stock ("Equity Awards") in the Company's financial statements on a straight line basis over the awards' vesting periods based on their fair values on the dates of grant or modification, as applicable. Stock-based compensation awards generally vest over a period of three years. The amount of stock-based compensation expense recognized at any date is approximately equal to the ratable portion of the grant date value of the award that is vested at that date.

Stock-based compensation liability awards ("Liability Awards") are restricted stock awards that are expected to be settled in cash on their vesting dates, rather than in common stock. Liability Awards are recorded as accounts payable—affiliates based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases to stock-based compensation expense.

The Company utilizes (i) the Black-Scholes option pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant to measure the fair value of Equity Awards and Liability Awards, (iii) the closing stock price on the balance sheet date to measure the fair value of the vested portions of Liability Awards and (iv) the Monte Carlo simulation method to measure the fair value of performance unit awards.

Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated by the chief operating decision maker for the purpose of allocating resources and assessing performance.

Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which is oil and gas development, exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas development, exploration and producing activities and manages these services to support such activities. In addition, the Company has a single, company-wide management team that allocates capital resources to maximize profitability and measures financial performance as a single enterprise.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria, the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities are measured at the lower of their carrying amount or estimated fair value less cost to sell.

In addition, after determining that held for sale criteria has been met, the Company considers whether the assets held for sale meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued operations, the Company classifies the results of operations from the assets held for sale as income or loss from discontinued operations, net of tax in the accompanying consolidated statements of operations for the current period and all prior periods. See Note C for additional information about the Company's divestitures.

Restructuring. In May 2015, the Company announced plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pumping services operations. The restructuring plan was substantially complete as of December 31, 2015. In connection therewith, during the year ended December 31, 2015, the Company recognized $23 million of restructuring charges in other expense in the accompanying consolidated statements of operations. The restructuring costs included $17 million in employee severance costs and $6 million in office lease-related costs.

Employee severance costs. The $17 million of employee severance costs was based on the number of employees impacted by the restructuring, with $16 million related to cash severance payments and $1 million related to accelerated vesting of share-based grants, which were noncash charges.

Lease obligations and other. The $6 million of office lease-related costs relates to certain Denver office space that will no longer be used, of which $2 million represents the impairment of leasehold improvements and $4 million represents the Company's future obligations under the operating leases, net of anticipated sublease income.

As of December 31, 2015, the Company had $4 million of restructuring liabilities, primarily related to future lease obligations recorded in other current and noncurrent liabilities in the accompanying consolidated balance sheets.

New accounting pronouncements.

Recently Adopted Accounting Pronouncements

In November 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-17, "Balance Sheet Classification of Deferred Taxes." ASU 2015-17 requires that deferred tax assets and liabilities be classified as noncurrent in a classified statement of financial position. ASU 2015-17 is required to be adopted by all public companies for all annual and interim reporting periods beginning after December 15, 2016. Early adoption of this standard was permitted and the Company elected to adopt this standard, on a retrospective basis, during the fourth quarter of 2015. The adoption of ASU 2015-17 only affects the presentation of the Company's accompanying consolidated balance sheets and related financial statement disclosure in Note O. In conjunction with the adoption of ASU 2015-17, the December 31, 2014 consolidated balance sheet has been restated to reclassify $161 million of current deferred income tax liabilities to noncurrent deferred tax liabilities.

In April 2015, the FASB issued ASU 2015-03, "Simplifying the Presentation of Debt Issuance Costs." ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. Prior to ASU 2015-03, debt issuance costs were required to be recognized as deferred charges and recorded as assets. ASU 2015-03 is required to be adopted by all public companies for all annual and interim reporting periods beginning after December 15, 2015. Early adoption of this standard was permitted and the Company elected to adopt this standard, on a retrospective basis, during the fourth quarter of 2015. The adoption of ASU 2015-03 only affects the presentation of the Company's accompanying consolidated balance sheets and related financial statement disclosures in Note G. In conjunction with the adoption of ASU 2015-03, the December 31, 2014 consolidated balance sheet has been restated to reclassify $17 million of debt issuance costs previously presented as part of other assets to be included as part of long-term debt.

In April 2014, the FASB issued ASU 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." ASU 2014-08 restricts the presentation of discontinued operations to business circumstances when the disposal of business operations represents a strategic shift that has or will have a major effect on an entity's operating and financial results. The new guidance also expands the required disclosures for entities that have assets held for sale but do not meet the new definition of discontinued operations. The Company prospectively adopted this standard effective January 1, 2015. The adoption of this standard did not

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

have a material impact on the Company's accompanying consolidated balance sheets or related disclosures as there was not a change to the recognition of assets previously recorded to discontinued operations and the Company did not have any assets available for sale at the time of adoption.

New Accounting Pronouncements not adopted as of December 31, 2015

In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities." ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.

In July 2015, the FASB issued ASU 2015-11, "Simplifying the Measurement of Inventory." ASU 2015-11 requires an entity to measure inventory at the lower of cost or net realizable value rather than lower of cost or market as previously required by GAAP. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. This update should be applied prospectively with early application permitted. The Company is evaluating the new guidance and does not expect the standard to have a material impact on its consolidated financial statements.

In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to annual reports beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.

NOTE C. Acquisitions and Divestitures

Acquisitions

Affiliated Partnerships. In December 2014, the Company acquired the remaining limited partner interests in five affiliated partnerships for $54 million and caused the partnerships to be merged with and into a wholly-owned subsidiary of the Company.

Pioneer Southwest Merger Transaction. In December 2013, the Company completed the acquisition of all of the outstanding common units of Pioneer Southwest not already owned by the Company, through a merger of a wholly-owned subsidiary of the Company into Pioneer Southwest, the result of which was that Pioneer Southwest became a wholly-owned subsidiary of the Company. All of the common units outstanding as of the closing of the merger, except for the common units owned by the Company, were canceled and converted into the right to receive 0.2325 of a share of common stock of the Company per common unit. Consequently, in December 2013, the Company issued an aggregate of 3.96 million shares of its common stock to Pioneer Southwest unitholders.

The Company subsequently caused Pioneer Southwest, its general partner and all of Pioneer Southwest's subsidiaries to be merged with and into a wholly-owned subsidiary of the Company, the result of which was that all common units of Pioneer Southwest were canceled and the Company no longer holds any common units.

Divestitures Recorded in Continuing Operations

The Company recorded net gains on the disposition of assets in continuing operations of $782 million, $9 million and $209 million during the years ended December 31, 2015, 2014 and 2013, respectively. The following describes the significant divestitures included in continuing operations:

•

EFS Midstream. In November 2014, the Company announced that it was pursuing the divestment of its 50.1 percent equity interest in EFS Midstream, which was accounted for under the equity method of accounting for investments in unconsolidated affiliates. In July 2015, the Company completed the sale of its 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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

closing and the remaining approximately $500 million will be received in July 2016. The amount to be received in July 2016, less imputed interest, is included in notes receivable in the accompanying consolidated balance sheets and represents a noncash investing activity. Associated with the sale, the Company recorded a pretax gain of $777 million during 2015.

•

Vertical drilling rigs. During December 2013, the Company committed to a plan to sell the Company's majority interest in Sendero Drilling Company, LLC ("Sendero") to Sendero's minority interest owner. At December 31, 2013, the assets and liabilities of Sendero were classified as held for sale at their estimated fair value. In March 2014, the Company completed the sale of Sendero for cash proceeds of $31 million, which resulted in a gain of $1 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. During the years ended December 31, 2015 and 2014, the Company incurred $40 million and $7 million, respectively, of idle drilling rig fees related to the leased Sendero rigs. See Note D and Note N for additional information about the impairment charges and idle drilling rig fees, respectively, related to Sendero.


•	Permian Basin. During February 2014, the Company completed the sale of proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million, which resulted in a gain of $2 million.

•

Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem") to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas for total consideration of $1.8 billion. In May 2013, the Company completed the sale for cash proceeds of $624 million, which resulted in a gain of $181 million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the southern portion of the horizontal Wolfcamp Shale play. At December 31, 2015, the unused carry balance totaled $197 million.


•	West Panhandle. During the first quarter of 2013, the Company completed a sale of its interest in unproved oil and gas properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38 million, which resulted in a gain of $22 million.


•	Other. During 2015, 2014 and 2013, the Company sold other proved and unproved properties, inventory and other property and equipment and recorded net gains of $5 million, $6 million and $6 million, respectively.

Divestitures Recorded in Discontinued Operations

Hugoton. In September 2014, the Company completed the sale of its net assets in the Hugoton field in southwest Kansas for cash proceeds of $328 million, including normal closing adjustments.

Barnett Shale. In September 2014, the Company completed the sale of its Barnett Shale net assets for cash proceeds of $150 million, including normal closing adjustments. Also included in discontinued operations in 2013 is the sale of the Company's interest in certain proved and unproved oil and gas properties in the Barnett Shale field for net cash proceeds of $34 million, which resulted in a gain of $9 million on the unproved properties sold.

Alaska. In April 2014, the Company completed the sale of its 100 percent interest in the capital stock of Pioneer's Alaskan subsidiary ("Pioneer Alaska") for cash proceeds of $267 million, including normal closing and other adjustments.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The following table represents the components of the Company's discontinued operations for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(in millions)

Revenues and other income (a)	$	1		$	238		$	376
Costs and expenses (b)	10			409			1,063
Loss from discontinued operations before income taxes	(9		)	(171		)	(687		)
Current tax provision	(1		)	—			(6		)
Deferred tax benefit	3			60			255
Loss from discontinued operations, net of tax	$	(7	)	$	(111	)	$	(438	)

____________________


(a)	Revenues and other income for the years ended December 31, 2014 and 2013 were primarily comprised of oil and gas revenues of $198 million and $329 million, respectively.

(b)

Costs and expenses during 2015 were primarily related to an arbitration award associated with plugging and abandonment obligations for two Gulf of Mexico wells from which Pioneer withdrew in 2009. The Company incurred noncash impairment charges of $305 million and $729 million during the years ended December 31, 2014 and 2013, respectively, on the Company's net assets in the Hugoton field, Barnett Shale field and Pioneer Alaska. Costs and expenses in 2014 and 2013 also included oil and gas production costs of $60 million and $117 million, respectively. See Note D for additional information regarding the noncash impairment charges related to the Hugoton assets, the Barnett Shale assets and Pioneer Alaska.

NOTE D. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:


•	Level 1 – quoted prices for identical assets or liabilities in active markets.


•	Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or liabilities in markets that are not active; inputs other than quoted prices that are observable for the asset or liability (e.g. interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.


•	Level 3 – unobservable inputs for the asset or liability.

Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of December 31, 2015 and 2014 for each of the fair value hierarchy levels:



	Fair Value Measurements at December 31, 2015 Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value at December 31, 2015
	(in millions)
Assets:
Commodity derivatives	$	—	$	758	$	—	$	758
Deferred compensation plan assets	73		—		—		73
Total assets	73		758		—		831
Liabilities:
Commodity derivatives	—		1		—		1
Total liabilities	—		1		—		1
Total recurring fair value measurements	$	73	$	757	$	—	$	830



	Fair Value Measurements at December 31, 2014 Using
	Quoted Prices in Active Markets for Identical Assets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Fair Value at December 31, 2014
	(in millions)
Assets:
Commodity derivatives	$	—	$	759	$	—	$	759
Deferred compensation plan assets	70		—		—		70
Total assets	70		759		—		829
Liabilities:
Commodity derivatives	—		2		—		2
Interest rate derivatives	—		3		—		3
Total liabilities	—		5		—		5
Total recurring fair value measurements	$	70	$	754	$	—	$	824

Commodity derivatives. The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represented Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.

The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and collar contracts with short puts, which is based on active and independent market-quoted volatility factors.

Deferred compensation plan assets. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of December 31, 2015 and 2014, the significant inputs to these asset exchange values represented Level 1 independent active exchange market price inputs.

Interest rate derivatives. As of December 31, 2015 the Company had no interest rate derivative assets or liabilities. The Company's interest rate derivative liabilities as of December 31, 2014 represented Treasury rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

interest rate derivative contracts as of December 31, 2014 were based on (i) the contracted notional amounts, (ii) United States Treasury yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative liability measurements represented Level 2 inputs in the hierarchy priority.

Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale.

Inventories. During the years ended December 31, 2015 , 2014 and 2013 the Company recognized impairment charges of $71 million, $8 million and $23 million, respectively, primarily to reduce the carrying value of its excess well pipe inventory. The Company calculated the estimated fair value of the inventory using significant Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment charges are included in other expense in the Company's accompanying consolidated statements of operations.

Proved oil and gas properties. As a result of the Company’s proved property impairment assessments, the Company recognized pretax, noncash impairment charges to reduce the carrying values of (i) the Eagle Ford Shale field, the West Panhandle field and the South Texas - Other field during the year ended December 31, 2015 and (ii) the Raton field during the year ended December 31, 2013 to their estimated fair values.

The Company calculated the fair values of the Eagle Ford Shale field, the West Panhandle field, the South Texas - Other field and the Raton field proved properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of discounted future cash flows included Management's Price Outlooks and management's outlooks for (i) production costs, (ii) capital expenditures, (iii) production and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party longer-term commodity futures price outlooks as of each measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value.

The following table presents the fair value and fair value adjustments (in millions) for the Company's 2015 and 2013 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in the respective Management's Price Outlooks:



		Fair		Fair Value			Management's Price Outlooks
		Value		Adjustment			Oil		Gas
South Texas - Eagle Ford Shale	December 2015	$	483	$	(846	)	$	52.82	$	3.34
South Texas - Other	September 2015	$	88	$	(72	)	$	57.41	$	3.46
West Panhandle	March 2015	$	61	$	(138	)	$	65.02	$	3.83
Raton	December 2013	$	534	$	(1,495	)	$	80.40	$	4.43

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

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

Assets associated with divestitures. Long-lived assets that are classified as held for sale are recorded at the lower of the asset's net carrying amount or estimated fair value less costs to sell. At December 31, 2013, the Sendero assets, Pioneer Alaska and the Barnett Shale assets were classified as held for sale and carried as such until their divestitures in March 2014, April 2014 and September 2014, respectively. Beginning in the third quarter of 2014, the Hugoton assets were classified as held for sale until their divestiture in September 2014. At December 31, 2013, the fair value of the Barnett Shale assets was based upon a weighted average calculation that utilized management inputs for both an estimated sales price and a discounted cash flow model for the proved properties using Level 3 assumptions as discussed in the proved oil and gas properties section above, while Sendero and Pioneer Alaska fair values were each based solely on estimated sales prices, less costs to sell. During 2014, the fair value measurements of all assets classified as held for sale were based on their sales prices, less costs to sell. See Note C for additional information regarding the Company's divestitures.

The following table presents the fair value adjustments made by the Company during the years ended December 31, 2014 and 2013 related to assets associated with divestitures:



		Year Ended December 31, 2014					Year Ended December 31, 2013
	Classification	Estimated Fair Value Less Costs to Sell		Fair Value Adjustment			Estimated Fair Value Less Costs to Sell		Fair Value Adjustment
		(in millions)
Hugoton field	Discontinued operations	$	328	$	(34	)
Barnett Shale field	Discontinued operations	$	149	$	(174	)	$	180	$	(190	)
Pioneer Alaska	Discontinued operations	$	253	$	(97	)	$	351	$	(539	)
Sendero	Continuing operations						$	31	$	(25	)

Unproved oil and gas properties. During 2015 and 2014, the Company recorded impairment charges of $7 million and $50 million to reduce the carrying value of unproved properties in southeast Colorado (reported in exploration and abandonments in the accompanying consolidated statements of operations). During 2015, the Company impaired the remaining carrying value of its unproved properties in southeast Colorado as a result of the Company no longer planning to develop this acreage and the acreage's limited market value, if any, given the short time period until the leases expire. At December 31, 2014, the Company calculated the estimated fair values of the unproved acreage in southeast Colorado using significant Level 3 assumptions based on average lease bonuses per acre for its prospective acreage. No value was allocated to acreage that the Company did not plan to develop in southeast Colorado.

Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of December 31, 2015 and 2014 are as follows:



	December 31, 2015				December 31, 2014
	Carrying Value		Fair Value		Carrying Value		Fair Value
	(in millions)
Current portion of long-term debt	$	448	$	462	$	—	$	—
Long-term debt	$	3,207	$	3,206	$	2,648	$	2,938

Current and noncurrent long-term debt includes the Company's credit facility and the Company's senior notes. The fair value of the Company's debt obligations is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy.

Credit facility. The fair value of the Company's credit facility is calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rates and (iii) the applicable credit-adjustments.

Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The Company has other financial instruments consisting primarily of cash equivalents, accounts receivables, prepaid expenses, notes receivable, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.

Concentrations of credit risk. As of December 31, 2015, the Company's primary concentration of credit risks are the risks associated with collecting receivables (principally accounts receivables and notes receivables) and the risk of a counterparty's failure to perform under derivative contracts owed to the Company. See Note L for information regarding the Company's major customers.

With respect to accounts receivables and notes receivables, the Company uses credit and other financial criteria to evaluate the credit standing of the entity obligated to make the payment, and where appropriate, the Company obtains assurances of payment, such as a guarantee by the parent company of the entity or such other credit support as the Company believes is appropriate.

The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. See Note E for additional information regarding the Company's derivative activities and information regarding derivative net assets and liabilities by counterparty.

NOTE E. Derivative Financial Instruments

The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness.

Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") WTI oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and actual index prices at which the oil is sold.

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of December 31, 2015 and the weighted average oil prices for those contracts:



	2016								Year Ending December 31,
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter		2017
Swap contracts:
Volume (Bbl) (a)	35,000		35,000		—		—		—
Price per Bbl	$	59.88	$	59.88	$	—	$	—	$	—
Collar contracts with short puts:
Volume (Bbl) (a)	63,000		68,000		112,000		112,000		34,000
Price per Bbl:
Ceiling	$	73.29	$	72.43	$	75.94	$	75.94	$	70.42
Floor	$	63.04	$	62.08	$	65.41	$	65.41	$	57.65
Short put	$	43.17	$	42.94	$	47.03	$	47.03	$	47.65

_______________


(a)	During the period from January 1, 2016 through February 16, 2016, the Company converted 25,000 Bbls per day of March through June 2016 collar contracts with short puts with a ceiling price of $71.02 per Bbl, a floor price of $60.00 per Bbl and a short put price of $48.00 per Bbl into new swap contracts covering the same period with a fixed price of $43.54 per Bbl.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway NGL component product prices. The Company uses derivative contracts to manage the NGL component product price volatility.

The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of December 31, 2015 and the weighted average NGL prices for those contracts:



	2016
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
Propane swap contracts (a):
Volume (Bbl)	7,500		7,500		7,500		7,500
Price per Bbl	$	21.57	$	21.57	$	21.57	$	21.57

____________________


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

Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("HH") gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual index prices at which the gas is sold.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of December 31, 2015 and the weighted average gas prices for those contracts:



	2016												Year Ending December 31,
	First Quarter			Second Quarter			Third Quarter			Fourth Quarter			2017
Swap contracts:
Volume (MMBtu)	70,000			70,000			70,000			70,000			—
Price per MMBtu	$	4.06		$	4.06		$	4.06		$	4.06		$	—
Collar contracts with short puts:
Volume (MMBtu)	180,000			180,000			180,000			180,000			—
Price per MMBtu:
Ceiling	$	4.01		$	4.01		$	4.01		$	4.01		$	—
Floor	$	3.24		$	3.24		$	3.24		$	3.24		$	—
Short put	$	2.78		$	2.78		$	2.78		$	2.78		$	—
Basis swap contracts:
Gulf Coast basis swap contracts (a)	10,000			10,000			10,000			10,000			—
Price differential ($/MMBtu)	$	—		$	—		$	—		$	—		$	—
Mid-Continent index swap volume (a)	15,000			15,000			15,000			15,000			45,000
Price differential ($/MMBtu)	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	(0.32	)	$	(0.32	)
Permian Basin index swap volume (b) (c)	6,813			—			—			—			—
Price differential ($/MMBtu)	$	0.26		$	—		$	—		$	—		$	—

____________________


(a)	Represents swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts.


(b)	Represents swaps that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California.

(c)

During the period from January 1, 2016 through February 16, 2016, the Company entered into (i) an additional 40,000 MMBtu per day of basis swap contracts that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California for the November 2016 through March 2017 time period with a fixed price of $0.37 per MMBtu and (ii) an additional 25,000 MMBtu per day of basis swap contracts that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California for December 2016 with a fixed price of $0.53 per MMBtu.

Interest rate derivative activities. During 2015, the Company terminated its interest rate derivative contracts for cash proceeds of $3 million. As of December 31, 2015, the Company did not have any interest rate derivatives outstanding. During the period from January 1, 2016 through February 16, 2016, the Company entered into interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 through December 2027 in exchange for paying a fixed interest rate of 1.98 percent on a notional amount of $200 million on December 15, 2017.

Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives as of December 31, 2015 and December 31, 2014 and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following:



Fair Value of Derivative Instruments as of December 31, 2015
Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
		(in millions)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	695	$	(1	)	$	694
Commodity price derivatives	Derivatives - noncurrent	$	64	$	—		64
							$	758
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	1	$	(1	)	$	—
Commodity price derivatives	Derivatives - noncurrent	$	1	$	—		1
							$	1



Fair Value of Derivative Instruments as of December 31, 2014
Type	Consolidated Balance Sheet Location	Fair Value		Gross Amounts Offset in the Consolidated Balance Sheet			Net Fair Value Presented in the Consolidated Balance Sheet
		(in millions)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives	Derivatives - current	$	579	$	(1	)	$	578
Commodity price derivatives	Derivatives - noncurrent	$	182	$	(1	)	181
							$	759
Liability Derivatives:
Commodity price derivatives	Derivatives - current	$	1	$	(1	)	$	—
Interest rate derivatives	Derivatives - current	$	3	$	—		3
Commodity price derivatives	Derivatives - noncurrent	$	3	$	(1	)	2
							$	5

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



Derivatives Not Designated as Hedging Instruments	Location of Gain/(Loss) Recognized in Earnings on Derivatives	Amount of Gain/(Loss) Recognized in Earnings on Derivatives
		Year Ended December 31,
		2015		2014		2013
		(in millions)
Commodity price derivatives	Derivative gains, net	$	873	$	697	$	(6	)
Interest rate derivatives	Derivative gains, net	6		15		10
Total		$	879	$	712	$	4

Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The following table provides the Company's net derivative assets by counterparty as of December 31, 2015:



	Net Assets
	(in millions)
Merrill Lynch	$	138
Citibank, N.A.	109
BMO Financial Group	108
Societe Generale	105
J. Aron & Company	81
Morgan Stanley	53
Wells Fargo Bank, N.A.	51
JP Morgan Chase	49
Macquarie Bank	34
Den Norske Bank	16
Nextera Energy	9
Toronto Dominion	4
Total	$	757

NOTE F. Exploratory Well Costs

The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.

The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Beginning capitalized exploratory well costs	$	305		$	159		$	213
Additions to exploratory well costs pending the determination of proved reserves	1,178			1,860			1,220
Reclassification due to determination of proved reserves	(1,160		)	(1,628		)	(1,045		)
Divestitures	—			(47		)	(93		)
Impairment of properties	—			(13		)	(87		)
Exploratory well costs charged to exploration and abandonment expense (a)	(17		)	(26		)	(49		)
Ending capitalized exploratory well costs	$	306		$	305		$	159

_______________


(a)	Includes exploration and abandonment expense of $43 million in 2013 that is included in discontinued operations in the accompanying consolidated statements of operations.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The following table provides an aging, as of December 31, 2015, 2014 and 2013 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:



	As of December 31,
	2015		2014		2013
	(in millions, except well counts)
Capitalized exploratory well costs that have been suspended:
One year or less	$	303	$	305	$	116
More than one year	3		—		43
	$	306	$	305	$	159
Number of projects with exploratory well costs that have been suspended for a period greater than one year	1		—		1

The project with exploratory well costs that have been suspended for a period greater than one year at December 31, 2015 is scheduled to be completed during 2016. The $43 million of suspended well costs that were suspended for a period greater than one year at December 31, 2013 related to Pioneer Alaska, which was sold in April 2014. See Note C for additional information on the sale of Pioneer Alaska.

NOTE G. Long-term Debt and Interest Expense

Long-term debt, including the effects of issuance costs, issuance discounts and net deferred fair value hedge losses, consisted of the following components at December 31, 2015 and 2014:



	December 31,
	2015			2014
	(in millions)
Outstanding debt principal balances:
5.875% senior notes due 2016 (a)	$	455		$	455
6.65% senior notes due 2017	485			485
6.875% senior notes due 2018	450			450
7.500% senior notes due 2020	450			450
3.45% senior notes due 2021	500			—
3.95% senior notes due 2022	600			600
4.45% senior notes due 2026	500			—
7.20% senior notes due 2028	250			250
	3,690			2,690
Issuance costs and discounts	(35		)	(41		)
Net deferred fair value hedge losses	—			(1		)
Long-term debt	3,655			2,648
Less current portion of long-term debt (a)	448			—
Long-term debt	$	3,207		$	2,648

______________________________

(a) These notes, net of $7 million of unamortized issuance costs, issuance discounts and deferred fair value hedge losses, are classified as current in the accompanying consolidated balance sheets.

Credit facility. During August 2015, the Company entered into a Second Amendment to its Second Amended and Restated 5-year Revolving Credit Agreement ("Credit Facility") with a syndicate of financial institutions, primarily to extend the maturity of the credit facility from December 2017 to August 2020 while maintaining aggregate loan commitments of $1.5 billion. The Company accounted for the entry into the Credit Facility as a modification of the prior agreement and capitalized the debt issuance

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

costs along with those unamortized issuance costs that remained from the issuance of the prior agreement. As of December 31, 2015, the Company had no outstanding borrowings under the Credit Facility.

Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the Company, based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin, which is currently 0.5 percent based on the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the "Applicable Margin"), which is currently 1.50 percent and is also determined by the Company's debt rating. Swing line loans under the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under the Credit Facility that are determined by the Company's debt rating (currently 0.20 percent). Borrowings under the Credit Facility are general unsecured obligations.

The Credit Facility requires the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments, not to exceed .60 to 1.0. As of December 31, 2015, the Company was in compliance with all of its debt covenants.

Senior notes. During December 2015, the Company issued $500 million of 3.45% Senior Notes due 2021 and $500 million of 4.45% Senior Notes due 2026 and received combined proceeds, net of $9 million of offering costs and discounts, of $991 million. The Company's 5.875% senior notes (the "5.875% Senior Notes"), with an outstanding debt principal balance of $455 million, are due to mature in July 2016. The Company intends to fund the payments due at maturity of the 5.875% Senior Notes with cash on hand. As such, the 5.875% Senior Notes are classified as current in the accompanying consolidated balance sheets.

The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the senior notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes is payable semiannually.

Convertible senior notes. As of December 31, 2012, the Company had $480 million of Convertible Senior Notes outstanding. During December 2012 and March 2013, the Company's stock price met the price threshold that caused the Convertible Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible Senior Notes were issued. On April 15, 2013, the Company announced that it would exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six months ended June 30, 2013, holders of $479 million principal amount of the Convertible Senior Notes exercised their right to convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering holders $479 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company paid $1 million in principal and interest to redeem all Convertible Senior Notes that remained outstanding.

For the year ended December 31, 2013 the Company recorded $9 million of interest expense relating to the Convertible Senior Notes, which had an effective interest rate of 6.75 percent.

Principal maturities. Principal maturities of long-term debt at December 31, 2015, are as follows (in millions):



2016	$	455
2017	$	485
2018	$	450
2019	$	—
2020	$	450
Thereafter	$	1,850

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Cash payments for interest	$	148		$	193		$	183
Amortization of issuance discounts	13			12			12
Amortization of capitalized loan fees	5			5			5
Net changes in accruals	25			(22		)	(6		)
Interest incurred	191			188			194
Less capitalized interest	(4		)	(4		)	(10		)
Total interest expense	$	187		$	184		$	184

NOTE H. Incentive Plans

Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Company's board of directors (the "Board") approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The Company will provide a matching contribution of 100 percent of the officer's and key employee's contribution limited to the first ten percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement plan. The Company's matching contributions were $3 million, $3 million and $3 million for the years ended December 31, 2015, 2014 and 2013, respectively.

401(k) plan. The Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company) 401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the first day of the month following their date of hire. Participants may contribute an amount up to 80 percent of their annual salary into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's base compensation (the "Matching Contribution"). Each participant's account is credited with the participant's contributions, Matching Contributions and allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a four-year period that begins with the participant's date of hire. During the years ended December 31, 2015, 2014 and 2013, the Company recognized compensation expense of $31 million, $33 million and $30 million, respectively, as a result of Matching Contributions.

Stock-based compensation costs. In accordance with GAAP, the Company records stock-based compensation expense ratably over the vesting periods of the Company's stock-based compensation awards using the awards' fair value. The Company maintains two plans providing for stock-based compensation: the Long-Term Incentive Plan ("LTIP") and the Employee Stock Purchase Plan ("ESPP").

In December 2015, the Company terminated the Pioneer 2008 PSE Employee Long-Term Incentive Plan ("PSE LTIP"). The PSE LTIP was adopted by Pioneer Southwest in May 2008. The plan, along with all of Pioneer Southwest's obligations under outstanding awards, was assumed by the Company in connection with the Company's acquisition of all outstanding common units of Pioneer Southwest not owned by the Company in December 2013, at which time the plan's name was changed. The only outstanding awards under the PSE LTIP at the time of the acquisition were phantom units of Pioneer Southwest, all of which were converted into restricted stock units of the Company, and no awards have been granted under the PSE LTIP since the Company's assumption of the plan. The Company terminated the plan as there was no intent to issue additional awards under the plan. At the time of termination of the plan, there were 7,495 restricted units outstanding, all of which are scheduled to vest on February 20, 2016. These awards were originally granted on February 20, 2013.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

Long-Term Incentive Plan. The LTIP provides for the granting of various forms of awards, including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers and employees of the Company. The shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market. The following table shows the number of shares available for issuance pursuant to awards under the LTIP at December 31, 2015:



Approved and authorized awards	9,100,000
Awards issued after May 3, 2006	(7,017,999	)
Awards available for future grant	2,082,001

Employee Stock Purchase Plan. The ESPP allows eligible employees to annually purchase the Company's common stock at a discounted price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of an employee's pay (subject to certain ESPP limits) during the eight-month offering period (January 1 to August 31). Participants in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's common stock on either the first day or the last day of each offering period, whichever closing sales price is lower. The following table shows the number of shares available for issuance under the ESPP at December 31, 2015:



Approved and authorized shares	1,250,000
Shares issued	(833,078	)
Shares available for future issuance	416,922

The following table reflects stock-based compensation expense recorded for each type of stock-based compensation award and the associated income tax benefit for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
	(in millions)
Restricted stock-Equity Awards	$	70	$	65	$	57
Restricted stock-Liability Awards	22		28		40
Stock options (a)	—		2		3
Performance unit awards	18		13		9
ESPP	2		2		2
Other	—		—		1
Total	$	112	$	110	$	112
Income tax benefit	$	34	$	33	$	36

_____________________


(a)	Cash proceeds received from stock option exercises during 2014 and 2013 amounted to $6 million and $5 million, respectively. There were no stock option exercises during 2015.

As of December 31, 2015, there was $108 million of unrecognized stock-based compensation expense related to unvested share-based compensation plans, including $17 million attributable to Liability Awards. The stock-based compensation expense will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis.

Restricted stock awards. During 2015, the Company awarded 603,169 restricted shares or units of the Company's common stock as compensation to directors, officers and employees of the Company (including 161,692 shares or units representing Liability Awards). The Company's issued shares, as reflected in the accompanying consolidated balance sheet as of December 31, 2015, do not include 128,002 of issued, but unvested shares awarded under stock-based compensation plans that have voting rights.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The following table reflects the restricted stock award activity for the year ended December 31, 2015:



	Equity Awards				Liability Awards
	Number of Shares		Weighted Average Grant- Date Fair Value		Number of Shares
Outstanding at beginning of year	1,233,539		$	140.57	328,087
Shares granted	441,477		$	153.55	161,692
Shares forfeited	(46,429	)	$	155.52	(33,082	)
Shares vested	(546,937	)	$	138.76	(185,666	)
Outstanding at end of year	1,081,650		$	151.50	271,031

The weighted average grant-date fair value of restricted stock equity awards awarded during 2015, 2014 and 2013 was $153.55, $184.39 and $134.17, respectively. The fair value of shares for which restrictions lapsed during 2015, 2014 and 2013 was $66 million, $88 million and $69 million, respectively, based on the market price on the vesting date.

As of December 31, 2015 and 2014, accounts payable – due to affiliates in the accompanying consolidated balance sheets includes $16 million and $23 million of liabilities attributable to the Liability Awards, representing the fair value of the earned, but unvested, portion of the outstanding awards as of that date. The fair value of Liability Awards for which restrictions lapsed during 2015, 2014 and 2013 was $23 million, $38 million and $26 million respectively, based on the market price on the vesting date.

Stock option awards. Certain employees may be granted options to purchase shares of the Company's common stock with an exercise price equal to the fair market value of Pioneer common stock on the date of grant. The fair value of stock option awards is determined using the Black-Scholes option-pricing model. Option awards have a ten-year contract life. The expected life of an option is estimated based on historical and expected exercise behavior. The volatility assumption was estimated based upon expectations of volatility over the life of the option as measured by historical volatility. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon a seven-year average dividend yield.

A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2015 is presented below:



	Number of Shares	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life	Aggregate Intrinsic Value
				(in years)	(in millions)
Outstanding at beginning of year	199,058	$	77.51
Options exercised	—	$	—
Outstanding at end of year	199,058	$	77.51	4.96	$	10
Exercisable at end of year	199,058	$	77.51	4.96	$	10

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The Company has not granted stock options since February 2012. There were no options exercised during 2015. The intrinsic value of options exercised during 2014 and 2013 was $12 million and $21 million, respectively, based on the difference between the market price at the exercise date and the option exercise price.

Performance unit awards. During 2015, 2014 and 2013, the Company awarded performance units to certain of the Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company's total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period. The performance unit awards vest over a 34-month service period. The grant-date fair values per unit of the 2015, 2014 and 2013 performance unit awards were $222.33, $232.20 and $189.23, respectively, which amounts were determined using the Monte Carlo simulation method and are being recognized as stock-based compensation expense ratably over the performance period. The Monte Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a historical period consistent with the performance period of approximately three years. The risk-free interest rate was based on the United States Treasury rate for a term commensurate with the expected life of the grant. The Company used the following assumptions to estimate the fair value of performance unit awards granted during 2015, 2014 and 2013:



	2015				2014				2013
Risk-free interest rate	1.03%				0.62%				0.40%
Range of volatilities	26.1	%	-	41.3%	29.0	%	-	41.5%	30.4	%	-	42.9%

The following table summarizes the performance unit activity for the year ended December 31, 2015:



	Number of Units (a)		Weighted Average Grant-Date Fair Value
Beginning performance unit awards	154,733		$	207.88
Units granted	82,431		$	222.33
Units forfeited	—		$	—
Units vested (b)	(88,617	)	$	189.71
Ending performance unit awards	148,547		$	226.74

_____________________


(a)	These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company compared to peer companies at the vesting date.

(b)

Of the 88,617 units that vested during 2015, 87,551 units vested according to the scheduled timing of the associated award and 1,066 units, which were originally scheduled to vest in 2016 and 2017, vested upon retirement of the officer to whom the performance unit awards were granted. On December 31, 2015, the service period lapsed on 88,374 performance unit awards that earned 1.5 shares for each vested award, representing 132,566 aggregate shares of common stock issued on January 4, 2016. The vested performance units that earned 1.5 shares for each vested award included 87,551 units vested in the current year and 823 units that vested in 2014 upon the retirement of the officer to whom the performance unit awards were granted.

The fair value of shares for which restrictions lapsed during 2015, 2014 and 2013 was $17 million, $13 million and $19 million, respectively, based on the market price on the vesting date.

PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

NOTE I. Asset Retirement Obligations

The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table summarizes the Company's asset retirement obligation activity during the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Beginning asset retirement obligations	$	189		$	194		$	198
Obligations assumed in acquisitions	—			6			—
New wells placed on production	4			5			6
Changes in estimates (a)	103			7			8
Disposition of wells	—			(14		)	(16		)
Obligations settled	(23		)	(21		)	(15		)
Accretion of discount on continuing operations	12			12			12
Accretion of discount on discontinued operations	—			—			1
Ending asset retirement obligations	$	285		$	189		$	194

_____________________

(a)

Changes in estimates are determined based on several factors, including abandonment cost estimates based on recent actual costs incurred to abandon wells, credit-adjusted risk-free discount rates and well life estimates. The increase in 2015 is primarily due to the forecasted timing of abandoning the Company's oil and gas wells being accelerated as a result of lower commodity prices, which has the effect of shortening the economic lives of the Company's producing wells.

As of December 31, 2015 and 2014, the current portions of the Company's asset retirement obligations were $40 million and $28 million, respectively.

NOTE J. Commitments and Contingencies

Severance agreements. The Company has entered into severance and change in control agreements with its officers and certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $35 million.

Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.

Legal actions. The Company is party to various proceedings and claims incidental to its business. While many of these matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to these proceedings and claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.

Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. These retention and indemnification arrangements were undertaken by the Company with respect to some or all of such pre-closing matters in connection with the sale of its Argentine assets in 2006, the sale of its Canadian assets in 2007, the sale of Pioneer Tunisia in February 2011, the sale of Pioneer South Africa in August 2012, the sales of Pioneer Alaska and the Hugoton and Barnett Shale assets in 2014 and the sale of the Company's ownership interest in EFS Midstream in 2015, as well as in connection with sales of joint interests. The Company does not believe that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

Drilling commitments. The Company's principal drilling commitments are related to drilling rig contracts that require the Company to pay day rates for contracted drilling rigs over their contractual term. In addition, the Company periodically enters

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

into contractual arrangements under which the Company is committed to expend funds to drill wells in the future. The Company recognizes its drilling commitments in the periods in which the rig services are performed or the well is drilled. The Company's future minimum drilling commitments at December 31, 2015 include only drilling rig obligations that are expected to be paid as follows (in millions):



2016	$	179
2017	$	110
2018	$	64
2019	$	10
2020	$	—
Thereafter	$	—

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



2016	$	24
2017	$	23
2018	$	21
2019	$	21
2020	$	17
Thereafter	$	15

Future minimum lease commitments include $7 million for the Company's lease obligations related to the Denver, Colorado office, which was closed during 2015. The Company has recognized the remaining obligation, net of anticipated sublease income, of $3 million in restructuring expense for the year ended December 31, 2015. Since the Company is still responsible for the cash payment of the entire obligation before taking into account anticipated sublease income, the table above includes the gross amount of future lease payments associated with the Denver office. See Note B for further information on the Company's restructuring expense.

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



2016	$	451
2017	$	479
2018	$	476
2019	$	467
2020	$	465
Thereafter	$	1,145

Certain future minimum gathering, processing, transportation and fractionation fees are based upon rates and tariffs that are subject to change over the lives of the commitments. The above commitments include demand fees associated with volume delivery commitments. If the Company does not expect to be able to fulfill its short-term and long-term delivery obligations from projected production of available reserves, the Company expects to purchase third party volumes, where applicable, to satisfy its commitment assuming it is economic to do so; otherwise, it will pay the demand fees associated with any commitment shortfalls.

NOTE K. Related Party Transactions

Transactions with affiliated partnerships. Prior to December 2014, the Company, through a wholly-owned subsidiary, served as operator of properties in which it and its affiliated partnerships had an interest. The Company received lease operating and supervision charges in accordance with standard industry operating agreements related to the operation of the properties in which it and its affiliated partnerships had an interest and other fees related to the administration of the affiliated partnerships. For each of the years ended December 31, 2014 and 2013, the Company received $3 million associated with these fees.

In December 2014, the Company acquired the remaining limited partner interests in the affiliated partnerships and caused the partnerships to be merged with and into the Company. Prior to the acquisition, the Company proportionately consolidated the affiliated partnerships.

Transactions with EFS Midstream. Prior to July 2015, the Company, through a wholly-owned subsidiary, owned a noncontrolling interest in its unconsolidated affiliate, EFS Midstream. In July 2015, the Company completed the sale of its interest in EFS Midstream to an unaffiliated third party.

Prior to its sale in July 2015 and for the years ended December 31, 2014 and 2013, the Company received nil, $50 million and $25 million, respectively, in distributions from EFS Midstream.

Prior to July 2015, the Company also (i) provided certain services as the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) contracted for services from EFS Midstream under a Hydrocarbon Gathering and Handling Agreement (the "HGH Agreement").

Master Services Agreement. The terms of the Master Services Agreement provided that the Company would perform certain manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to expenses incurred by employees whose time was substantially dedicated to EFS Midstream's business. During 2015, 2014 and 2013, the Company received $2 million, $3 million and $3 million of fixed payments and $9 million, $18 million and $16 million

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

of variable payments, respectively, from EFS Midstream. During 2013, the Company purchased other plant and equipment assets from EFS Midstream for a total of $3 million.

Hydrocarbon Gathering and Handling Agreement. Under the terms of the HGH Agreement, EFS Midstream was obligated to construct certain equipment and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale properties operated by the Company. The HGH Agreement obligated the Company to use the EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with the terms of the HGH Agreement, the Company paid EFS Midstream $54 million (prior to its sale), $103 million and $81 million of gathering and treating fees during 2015, 2014 and 2013, respectively. Such amounts were expensed as oil and gas production costs in the accompanying consolidated statements of operations.

NOTE L. Major Customers

The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral or otherwise secure their accounts.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas production revenues, including the revenues from discontinued operations, in at least one of the three years ended December 31, 2015:



	Year Ended December 31,
	2015		2014		2013
Plains Marketing LP	22	%	29	%	28	%
Occidental Energy Marketing Inc.	18	%	16	%	13	%
Vitol, Inc.	18	%	9	%	5	%
Enterprise Products Partners L.P.	12	%	13	%	13	%

The loss of any of these significant purchasers could have a material adverse effect on the ability of the Company to sell its oil and gas production.

The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to a Gulf Coast market price and to satisfy unused pipeline capacity commitments. The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas revenues from sales of commodities purchased from third parties in at least one of the three years ended December 31, 2015:



	Year Ended December 31,
	2015		2014		2013
Valero Marketing and Supply Company	37	%	61	%	51	%
Occidental Energy Marketing Inc.	18	%	—	%	1	%
Plains Marketing LP	18	%	—	%	—	%
EDF Trading North America LLC	4	%	9	%	20	%

The Company believes that the loss of any of these purchasers would not have an adverse effect on the ability of the Company to sell commodities it purchases from third parties.

NOTE M. Interest and Other Income

The following table provides the components of the Company's interest and other income during the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
	(in millions)
Equity interest in income of EFS Midstream (a)	$	5	$	13	$	7
Deferred compensation plan income	4		3		6
Interest income	3		—		—
Other income	10		10		10
Total interest and other income	$	22	$	26	$	23

______________________


(a)	The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. See Note C for additional information on the Company's sale of EFS Midstream.

NOTE N. Other Expense

The following table provides the components of the Company's other expense during the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014		2013
	(in millions)
Idle drilling and well service equipment charges (a)	$	92	$	7	$	10
Impairment of inventory and other property and equipment (b)	86		8		62
Transportation commitment charges (c)	53		46		39
Loss from vertical integration services (d)	34		16		5
Restructuring charges (e)	23		—		—
Contingency and environmental accrual adjustments	—		—		9
Other	27		29		18
Total other expense	$	315	$	106	$	143

____________________


(a)	Primarily represents expenses attributable to idle drilling rig fees which are not chargeable to joint operations.

(b)

Primarily represents charges of $71 million, $8 million and $36 million to reduce excess materials and supplies inventories to their market values for the years ended December 31, 2015, 2014 and 2013, respectively, and a charge of $25 million for the year ended December 31, 2013 to reduce the carrying value of Sendero to its estimated fair value. See Notes C and D for additional information on the fair value of material and supplies inventory and Sendero, respectively.


(c)	Primarily represents firm transportation payments on excess pipeline capacity commitments.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

(d)

Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three years ended December 31, 2015, 2014 and 2013, these net losses include $298 million, $374 million and $285 million of gross vertical integration revenues, respectively, and $332 million, $390 million and $290 million of total vertical integration costs and expenses and elimination of revenues associated with intercompany transactions, respectively.


(e)	Represents restructuring costs associated with the Company's restructuring of its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pumping services operations. See Note B for additional information on the restructuring charges.

NOTE O. Income Taxes

The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject to examination by United States federal, state, local and foreign taxing authorities. The Company made current and estimated tax payments of $43 million, $22 million and $12 million (net of tax refunds) during 2015, 2014 and 2013, respectively.

The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide economic factors and assesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred tax attributes in the United States federal, state, local and foreign tax jurisdictions will be utilized prior to their expiration.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. During 2014, the Company recognized a $21 million tax benefit resulting from the resolution of a tax uncertainty related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 acquisition of Premier Silica. The Company does not have any unrecognized tax benefits as of December 31, 2015.

With respect to income taxes, the Company's policy is to account for interest charges as interest expense and any penalties as other expense in the accompanying consolidated statements of operations. The Company files income tax returns in the United States federal jurisdiction, and various state and foreign jurisdictions. As of December 31, 2015, there are no proposed adjustments or uncertain positions in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position. The Company's earliest open years in its key jurisdictions are as follows:



U.S. federal	2014
Various U.S. states	2010
South Africa	2010

The Company's income tax (provision) benefit and amounts separately allocated were attributable to the following items for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015		2014			2013
	(in millions)
Income tax (provision) benefit from continuing operations	$	155	$	(556	)	$	213
Income tax benefit from discontinued operations	$	2	$	60		$	249
Changes in equity:
Excess tax benefit related to stock-based compensation	$	7	$	19		$	18
Tax benefit attributable to conversion of 2.875% senior convertible notes	$	—	$	—		$	38
Tax benefit attributable to 2013 merger with Pioneer Southwest	$	—	$	—		$	200

The Company's income tax (provision) benefit attributable to income from continuing operations consisted of the following for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Current:
U.S. federal	$	(22	)	$	(3	)	$	(11	)
U.S. state	(1		)	(1		)	—
	(23		)	(4		)	(11		)
Deferred:
U.S. federal	165			(537		)	208
U.S. state	13			(15		)	16
	178			(552		)	224
Income tax (provision) benefit from continuing operations	$	155		$	(556	)	$	213

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income (loss) from continuing operations are as follows for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(in millions, except percentages)
Income (loss) from continuing operations before income taxes	$	(421	)	$	1,597		$	(574	)
Less: Net income attributable to noncontrolling interests	—			—			(39		)
Income (loss) from continuing operations attributable to common stockholders before income taxes	(421		)	1,597			(613		)
Federal statutory income tax rate	35		%	35		%	35		%
(Provision) benefit for federal income taxes at the statutory rate	147			(559		)	215
State income tax (provision) benefit (net of federal tax)	8			(10		)	10
Premier Silica benefit	—			21			—
Other	—			(8		)	(12		)
Income tax (provision) benefit from continuing operations	$	155		$	(556	)	$	213
Effective income tax rate, excluding net income attributable to the noncontrolling interests	37		%	35		%	35		%

The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax liabilities related to continuing operations are as follows as of December 31, 2015 and 2014:



	December 31,
	2015			2014
	(in millions)
Deferred tax assets:
Net operating loss carryforward (a)	$	441		$	330
Asset retirement obligations	102			68
Incentive plans	75			71
Other	102			74
Total deferred tax assets	720			543
Deferred tax liabilities:
Oil and gas properties, principally due to differences in basis, depletion and the deduction of intangible drilling costs for tax purposes	(1,997		)	(1,881		)
Other property and equipment, principally due to the deduction of bonus depreciation for tax purposes	(227		)	(251		)
Net deferred hedge gains	(272		)	(280		)
Other	—			(95		)
Total deferred tax liabilities	(2,496		)	(2,507		)
Net deferred tax liability	$	(1,776	)	$	(1,964	)

____________________


(a)	Net operating loss carryforwards as of December 31, 2015 consist of $1.2 billion of U.S. federal NOLs which expire primarily between 2032 and 2035 and $132 million of Colorado NOLs which expire between 2028 and 2034.

NOTE P. Net Income Per Share Attributable To Common Stockholders

In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable to common stockholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income (loss) per share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of common stock that would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to net loss per share and conversion into common stock is assumed not to occur. Diluted net income (loss) per share is calculated under both the two-class method and the treasury stock method and the more dilutive of the two calculations is presented.

The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss) attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as (i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings (iii) divided by weighted average diluted shares outstanding.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic and diluted net income (loss) attributable to common stockholders for the years ended December 31, 2015, 2014 and 2013:



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Income (loss) from continuing operations	$	(266	)	$	1,041		$	(400	)
Participating basic earnings (a)	—			(10		)	—
Basic and diluted net income (loss) from continuing operations	(266		)	1,031			(400		)
Basic and diluted net loss from discontinued operations	(7		)	(111		)	(438		)
Basic and diluted net income (loss) attributable to common stockholders	$	(273	)	$	920		$	(838	)

______________________

(a)

Unvested restricted stock awards and Pioneer Southwest phantom unit awards (prior to the December 2013 Pioneer Southwest merger) represent participating securities because they participate in nonforfeitable dividends or distributions with the common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- or unit-based earnings represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually obligated to do so.

Basic and diluted weighted average common shares outstanding were 149 million, 144 million and 136 million for the years ended December 31, 2015, 2014 and 2013, respectively.

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PIONEER NATURAL RESOURCES COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2015, 2014, and 2013

NOTE Q. Subsequent Events

Issuance of Common Stock. During the first quarter of 2016, the Company issued 13.8 million shares of its common stock and received cash proceeds of $1.6 billion, net of associated underwriting and offering expenses.

Pioneer Pumping Services. During February 2016, the Company announced that it is relocating its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. The Company expects to relocate the majority of its pressure pumping employees from South Texas to Midland, Texas. This initiative is expected to be substantially completed by the end of the second quarter of 2016. The Company estimates that it will incur $10 million to $20 million of restructuring costs in connection with this plan, primarily made up of employee relocation and severance payments and other related costs.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

Oil & Gas Exploration and Production Activities

The Company has only one reportable operating segment, which is oil and gas development, exploration and production in the United States. See the Company's accompanying consolidated statements of operations for information about results of operations for oil and gas producing activities.

Capitalized Costs



	December 31,
	2015			2014
	(in millions)
Oil and gas properties:
Proved	$	16,631		$	15,662
Unproved	169			159
Capitalized costs for oil and gas properties	16,800			15,821
Less accumulated depletion, depreciation and amortization	(6,778		)	(5,431		)
Net capitalized costs for oil and gas properties	$	10,022		$	10,390

Costs Incurred for Oil and Gas Producing Activities (a)



		Year Ended December 31,
		2015		2014		2013
	(in millions)
Property acquisition costs:
Proved		$	9	$	19	$	13
Unproved		27		85		63
Exploration costs		1,245		1,943		1,291
Development costs		894		1,535		1,481
Total costs incurred		$	2,175	$	3,582	$	2,848

_______________


(a)	The costs incurred for oil and gas producing activities includes the following amounts related to asset retirement obligations:



	Year Ended December 31,
	2015 (a)		2014		2013
	(in millions)
Exploration costs	$	2	$	3	$	3
Development costs	100		4		10
Total	$	102	$	7	$	13

_______________


(a)	The increase in 2015 is primarily due to the forecasted timing of abandoning the Company's oil and gas wells being accelerated as a result of lower commodity prices, which has the effect of shortening the economic lives of the Company's producing wells.

Reserve Quantity Information

The estimates of the Company's proved reserves as of December 31, 2015, 2014 and 2013 were based on evaluations prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major properties and prepared by the Company's engineers with respect to all other properties. Proved reserves were estimated in accordance with guidelines established by the United States Securities and Exchange Commission (the "SEC") and the FASB, which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price and cost escalations except by contractual arrangements.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

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

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

The following table provides a rollforward of total proved reserves for the years ended December 31, 2015, 2014 and 2013. Oil and NGL volumes are expressed in thousands of Bbls ("MBbls"), gas volumes are expressed in millions of cubic feet ("MMcf") and total volumes are expressed in thousands of barrels of oil equivalent ("MBOE").



	Year Ended December 31,
	2015								2014								2013
	Oil (MBbls)		NGLs (MBbls)		Gas (MMcf) (a)		Total (MBOE)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf) (a)		Total (MBOE)		Oil (MBbls)		NGLs (MBbls)		Gas (MMcf) (a)		Total (MBOE)
Balance, January 1	352,084		169,244		1,668,872		799,473		342,105		185,422		1,906,341		845,250		486,838		232,576		2,197,480		1,085,661
Production (b)	(38,452	)	(14,086	)	(147,173	)	(77,067	)	(32,718	)	(15,761	)	(154,424	)	(74,217	)	(27,455	)	(12,999	)	(157,690	)	(66,736	)
Revisions of previous estimates	(82,816	)	(54,439	)	(309,947	)	(188,913	)	(46,354	)	(20,125	)	(2,574	)	(66,907	)	(184,359	)	(64,986	)	(304,531	)	(300,101	)
Extensions and discoveries	80,726		25,496		143,991		130,221		114,864		55,987		275,825		216,822		78,922		38,639		205,899		151,878
Sales of minerals-in-place	(16	)	(3	)	(15	)	(21	)	(26,952	)	(36,926	)	(359,548	)	(123,803	)	(11,937	)	(7,931	)	(35,326	)	(25,756	)
Purchases of minerals-in-place	444		132		759		702		1,139		647		3,252		2,328		96		123		509		304
Balance, December 31 (c)	311,970		126,344		1,356,487		664,395		352,084		169,244		1,668,872		799,473		342,105		185,422		1,906,341		845,250

______________________


(a)	The proved gas reserves as of December 31, 2015, 2014 and 2013 include 144,955 MMcf, 191,932 MMcf and 240,093 MMcf, respectively, of gas that the Company expected to be produced and utilized as field fuel. Field fuel is gas consumed to operate field equipment (primarily compressors) rather than being delivered to a sales point.


(b)	Production for 2015, 2014 and 2013 includes 15,531 MMcf, 16,738 MMcf and 18,813 MMcf of field fuel, respectively. Also, for 2014 and 2013, production includes 4,911 MBOE and 7,170 MBOE of production associated with discontinued operations. See Note C for additional information regarding the Company's discontinued operations.


(c)	As of December 31, 2013, the portion of the Company's proved reserves attributable to discontinued operations in the Hugoton field, the Barnett Shale field and Alaska was 99,795 MBOE.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

Revisions of previous estimates. Revisions of previous estimates for 2015 were comprised of 269 MMBOE of negative price revisions due to 47 percent and 40 percent declines in the NYMEX oil and gas prices, respectively, that were used to determine proved oil and gas reserves for 2015, as compared to 2014, partially offset by 80 MMBOE of positive revisions that were primarily attributable to reductions in cost estimates (based on cost savings achieved during 2015) that had the effect of extending the economic lives of the Company's producing wells. The December 31, 2015 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines was $50.11 per barrel of oil and $2.59 per Mcf of gas, compared to $94.98 per barrel of oil and $4.35 per Mcf of gas at December 31, 2014.

Revisions of previous estimates for 2014 were comprised of 79 MMBOE of negative revisions due to removing vertical proved undeveloped locations in the Spraberry/Wolfcamp play, replacing previously recorded undeveloped horizontal locations with new locations based on new well performance data, updated well performance profiles and updated cost estimates, partially offset by 12 MMBOE of positive price revisions. During 2014, the Company continued to shift its drilling activity in the Spraberry/Wolfcamp play in the Midland Basin of West Texas from vertical drilling to horizontal drilling. The Company believes that replacing vertical drilling with horizontal drilling will enhance ultimate resource recoveries and improve rates of return per dollar invested. As a result, Pioneer no longer expects to drill any vertical proved undeveloped locations. Consequently, the Company's proved undeveloped reserves were reduced by 39 MMBOE associated with vertical drilling locations in the Spraberry/Wolfcamp area. Based on the limited horizontal drilling conducted to date in six Wolfcamp and Spraberry shale intervals across Pioneer's acreage position in the Spraberry/Wolfcamp field, sufficient production and well control data is not yet available to support the replacement of the vertical proved undeveloped reserves removed in 2014 and 2013 with horizontal proved undeveloped reserve additions. During 2014, the Company also removed 14 MMBOE of proved undeveloped reserves associated with horizontal locations in the Spraberry/Wolfcamp area that were no longer expected to be drilled within five years as a result of optimizing the Company's horizontal drilling program in other areas of the field. Negative well performance revisions of 19 MMBOE were comprised of a combination of negative revisions associated with horizontal and vertical downspacing performance and normal production decline changes. Cost inflation resulted in negative revisions of 6 MMBOE due to the assumed economic limit of producing and planned wells being shortened. The December 31, 2014 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines was $94.98 per barrel of oil and $4.35 per Mcf of gas, compared to $96.82 per barrel of oil and $3.67 per Mcf of gas at December 31, 2013.

Revisions of previous estimates for 2013 were comprised of 319 MMBOE of proved undeveloped reserves that were no longer expected to be drilled and 11 MMBOE of negative revisions attributable to updated performance profiles and cost estimates, partially offset by 30 MMBOE of positive price revisions. As noted above, the Company began shifting its drilling activity in the Spraberry/Wolfcamp play in the Midland Basin of West Texas from vertical drilling to horizontal drilling during 2013 based on the Company's belief that replacing vertical drilling with horizontal drilling would enhance ultimate resource recoveries and improve rates of return per dollar invested. As a result, Pioneer no longer expected to drill a significant number of its previously recorded vertical proved undeveloped locations. Consequently, proved undeveloped reserves associated with vertical drilling locations in the Spraberry/Wolfcamp area were reduced by 231 MMBOE during 2013. Pioneer also removed an additional 88 MMBOE of proved undeveloped reserves that were primarily attributable to the announced divestitures of Pioneer's Alaska and Barnett Shale assets (45 MMBOE) and previously recorded gas wells that were no longer expected to be drilled due to the reallocation of drilling capital to higher-rate-of-return oil wells. The December 31, 2013 NYMEX price used for oil and gas proved reserve preparation based upon SEC guidelines was $96.82 per barrel of oil and $3.67 per Mcf of gas, compared to $94.84 per barrel of oil and $2.76 per Mcf of gas at December 31, 2012.

Extensions and discoveries. Extensions and discoveries for 2015 were primarily comprised of proved reserve additions attributable to the Company's successful horizontal drilling program in the Spraberry/Wolfcamp intervals in West Texas. Extensions and discoveries for 2014 and 2013 were primarily comprised of proved reserve additions attributable to the Company's horizontal drilling program in the Spraberry/Wolfcamp area and its vertical drilling programs in the Strawn and Atoka horizons West Texas, combined with discoveries in the Eagle Ford Shale.

Sales of minerals-in-place. Sales of minerals-in-place in 2014 and 2013 were primarily related to (i) the sale of the Hugoton field, the Barnett Shale field and Pioneer Alaska in 2014, and (ii) the sale to Sinochem of 40 percent of the Company's interest in 207,000 net acres in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas in 2013. See Note C for additional information regarding the Company's divestitures and discontinued operations.

Purchases of minerals-in-place. Purchases of minerals-in-place during 2015, 2014 and 2013 were primarily attributable to acquisitions in the Company's Spraberry/Wolfcamp area.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

The following table provides the Company's proved developed and proved undeveloped reserves for the years ended December 31, 2015, 2014 and 2013.



	Oil (MBbls)	NGLs (MBbls)	Gas (MMcf)	Total (MBOE)
Proved Developed Reserves:
December 31, 2015	266,657	112,376	1,284,680	593,146
December 31, 2014	267,193	130,206	1,486,289	645,113
December 31, 2013	256,638	148,161	1,703,667	688,743

	Oil (MBbls)	NGLs (MBbls)	Gas (MMcf)	Total (MBOE)
Proved Undeveloped Reserves:
December 31, 2015	45,313	13,968	71,807	71,249
December 31, 2014	84,891	39,038	182,583	154,360
December 31, 2013	85,467	37,261	202,674	156,507

The following table summarizes the Company's proved undeveloped reserves activity during the year ended December 31, 2015 (in MBOE).



Beginning proved undeveloped reserves	154,360
Revisions of previous estimates	(77,178	)
Extensions and discoveries	30,609
Transfers to proved developed	(36,542	)
Ending proved undeveloped reserves	71,249

As of December 31, 2015, the Company had 138 proved undeveloped well locations as compared to 394 and 783 at December 31, 2014 and 2013, respectively. The Company has no proved undeveloped well locations that are scheduled to be drilled more than five years from their original date of booking.

The changes in proved undeveloped reserves during 2015 were comprised of the following items:

Revisions of previous estimates. Revisions of previous estimates were primarily comprised of 75 MMBOE of negative price revisions associated with proved undeveloped well locations that the Company no longer plans to drill as a result of the decline in commodity prices.

Transfers to proved developed. Transfers to proved developed reserves represented those undeveloped proved reserves that moved to proved developed as a result of development drilling during 2015. During 2015, the Company incurred $894 million of development costs and developed 24 percent of its proved undeveloped reserves.

The Company uses both public and proprietary geologic data to establish continuity of the formation and its producing properties. This included seismic data and interpretations (2-D, 3-D and micro seismic); open hole log information (both vertical and horizontally collected) and petrophysical analysis of the log data; mud logs; gas sample analysis; drill cutting samples; measurements of total organic content; thermal maturity; sidewall cores and data measured from the Company's internal core analysis facility. After the geologic area was shown to be continuous, statistical analysis of existing producing wells was conducted to generate areas of reasonable certainty at distances from established production. As a result of this analysis, proved undeveloped reserves for drilling locations within these areas of reasonable certainty were recorded during 2015.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

While the Company expects, based on Management's Price Outlooks, that future operating cash flows will provide adequate funding for future development of its proved undeveloped reserves over the next five years, it may also use any combination of internally-generated cash flows, cash and cash equivalents on hand, availability under its credit facility, proceeds from divestitures of nonstrategic assets or external financing sources to fund these and other capital expenditures, including exploratory drilling and acquisitions. The following table represents the estimated timing and cash flows of developing the Company's proved undeveloped reserves as of December 31, 2015 (dollars in millions):



Year Ended December 31, (a)	Estimated Future Production (MBOE)	Future Cash Inflows		Future Production Costs		Future Development Costs		Future Net Cash Flows
2016	4,511	$	165	$	29	$	316	$	(180	)
2017	7,077	256		47		275		(66		)
2018	7,020	250		51		126		73
2019	5,855	204		45		67		92
2020	4,601	155		37		3		115
Thereafter (b)	42,185	1,393		447		7		939
	71,249	$	2,423	$	656	$	794	$	973

______________________


(a)	Production and cash flows represent the drilling results from the respective year plus the incremental effects of proved undeveloped drilling.


(b)	The $7 million of future development costs represents net abandonment costs in years beyond the forecasted years.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

Standardized Measure of Discounted Future Net Cash Flows

The standardized measure of discounted future net cash flows is computed by applying commodity prices used in determining proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated future production of proved reserves less estimated future expenditures (based on year-end estimated costs) to be incurred in developing and producing the proved reserves, discounted using a rate of ten percent per year to reflect the estimated timing of the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future cash flow estimates do not include the effects of the Company's commodity derivative contracts.

Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of oil and gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity prices, interest rates, changes in development and production costs and risks associated with future production. Because of these and other considerations, any estimate of fair value is necessarily subjective and imprecise.

The following tables provide the standardized measure of discounted future cash flows as of December 31, 2015, 2014 and 2013, as well as a rollforward in total for each respective year:



	December 31,
	2015			2014			2013
	(in millions)
Oil and gas producing activities:
Future cash inflows	$	18,805		$	42,061		$	43,542
Future production costs	(11,475		)	(18,228		)	(20,044		)
Future development costs (a)	(1,622		)	(4,285		)	(4,102		)
Future income tax expense	—			(4,874		)	(4,955		)
	5,708			14,674			14,441
10% annual discount factor	(2,464		)	(6,889		)	(7,140		)
Standardized measure of discounted future cash flows	$	3,244		$	7,785		$	7,301

__________________


(a)	Includes $604 million, $626 million and $815 million of undiscounted future asset retirement expenditures estimated as of December 31, 2015, 2014 and 2013, respectively, using current estimates of future abandonment costs. See Note I for additional information regarding the Company's discounted asset retirement obligations.

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

Changes in Standardized Measure of Discounted Future Net Cash Flows



	Year Ended December 31,
	2015			2014			2013
	(in millions)
Oil and gas sales, net of production costs	$	(1,314	)	$	(2,813	)	$	(2,500	)
Revisions of previous estimates:
Net changes in prices and production costs	(7,960		)	(1,570		)	(1,772		)
Changes in future development costs	1,204			115			1,340
Revisions in quantities	(1,292		)	(581		)	(2,675		)
Accretion of discount	1,125			1,326			832
Changes in production rates, timing and other (a)	(93		)	608			2,454
Extensions, discoveries and improved recovery	1,597			4,086			2,248
Development costs incurred during the period	308			403			1,255
Sales of minerals-in-place	—			(1,123		)	(338		)
Purchases of minerals-in-place	13			34			4
Change in present value of future net revenues	(6,412		)	485			848
Net change in present value of future income taxes	1,871			(1		)	100
	(4,541		)	484			948
Balance, beginning of year	7,785			7,301			6,353
Balance, end of year	$	3,244		$	7,785		$	7,301

__________________

(a)

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

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PIONEER NATURAL RESOURCES COMPANY

UNAUDITED SUPPLEMENTARY INFORMATION

December 31, 2015, 2014 and 2013

Selected Quarterly Financial Results

The following table provides selected quarterly financial results for the years ended December 31, 2015 and 2014, with adjustments to conform to the annual results:



	Quarter
	First			Second			Third		Fourth
	(in millions, except per share data)
Year Ended December 31, 2015:
Oil and gas revenues	$	517		$	596		$	557	$	508
Total revenues and other income: (a)
As reported	$	868		$	648		$	2,218	$	1,074
Adjustment for vertical integration services (b)	1			(4		)	19		—
As adjusted	$	869		$	644		$	2,237	$	1,074
Total costs and expenses: (c)
As reported	$	979		$	988		$	1,215	$	2,047
Adjustment for vertical integration services (b)	1			(4		)	19		—
As adjusted	$	980		$	984		$	1,234	2,047
Net income (loss) attributable to common stockholders	$	(78	)	$	(218	)	$	646	$	(623	)
Net income (loss) attributable to common stockholders per share:
Basic	$	(0.52	)	$	(1.46	)	$	4.28	$	(4.17	)
Diluted	$	(0.52	)	$	(1.46	)	$	4.27	$	(4.17	)
Year Ended December 31, 2014:
Oil and gas revenues	$	890		$	938		$	967	$	804
Total revenues and other income: (a)
As reported	$	944		$	932		$	1,513	$	1,666
Adjustment for vertical integration services (b)	3			3			3		9
As adjusted	$	947		$	935		$	1,516	$	1,675
Total costs and expenses:	(19		)	(21		)	—
As reported	$	748		$	845		$	866	$	1,000
Adjustment for vertical integration services (b)	3			3			3		9
As adjusted	$	751		$	848		$	869	$	1,009
Net income (loss) attributable to common stockholders	$	123		$	1		$	374	$	431
Net income (loss) attributable to common stockholders per share:
Basic	$	0.85		$	0.01		$	2.58	$	2.92
Diluted	$	0.85		$	0.01		$	2.58	$	2.91

_____________________

(a)

During 2015, the Company's total revenues and other income included net derivative gains of $241 million, $573 million and $262 million during the first, third and fourth quarters, respectively, and net derivative losses of $197 million during the second quarter. The Company's total revenues and other income included net derivative losses of $104 million and $218 million during the first and second quarters of 2014, respectively, and net derivative gains of $341 million and $693 million during the third and fourth quarters of 2014, respectively.

(b)

Vertical integration services represent net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and well service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. These net margins have been reclassified from interest and other income to other expense on the accompanying statements of operations for all periods presented.

(c)

During the first, third and fourth quarters of 2015, the Company's total costs and expenses included charges of $138 million to impair the carrying value of proved properties in the West Panhandle field, $72 million to impair the carrying value of proved properties in the South Texas - Other field and $846 million to impair the carrying value of proved properties in the South Texas - Eagle Ford Shale field, respectively.

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ITEM 9.	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.



ITEM 9A.	CONTROLS AND PROCEDURES

Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act of 1934 ("the Exchange Act"), the effectiveness of the Company's disclosure controls and procedures (as defined in Exchange Act Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and principal financial officer concluded that the Company's disclosure controls and procedures were effective, as of the end of the period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's rules and forms, including that such information is accumulated and communicated to the Company's management, including the principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.

Changes in internal control over financial reporting. There have been no changes in the Company's internal control over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended December 31, 2015 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial reporting.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting is a process designed by or under the supervision of the Company's principal executive officer and principal financial officer and effected by the Board, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial statements for external purposes in accordance with generally accepted accounting principles.

The Company's management, with the participation of its principal executive officer and principal financial officer assessed the effectiveness, as of December 31, 2015, of the Company's internal control over financial reporting based on the criteria for effective internal control over financial reporting established in "Internal Control — Integrated Framework (2013)," issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that the Company maintained effective internal control over financial reporting at a reasonable assurance level as of December 31, 2015, based on those criteria.

Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company's internal control over financial reporting as of December 31, 2015. The report, which expresses an unqualified opinion on the effectiveness of the Company's internal control over financial reporting as of December 31, 2015, is included in this Item under the heading "Report of Independent Registered Public Accounting Firm."

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REPORT OF INDEPENDENT REGISTERED PUBLIC

ACCOUNTING FIRM

The Board of Directors and Stockholders of

Pioneer Natural Resources Company

We have audited Pioneer Natural Resources Company's (the "Company") internal control over financial reporting as of December 31, 2015, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). Pioneer Natural Resources Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Pioneer Natural Resources Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Pioneer Natural Resources Company as of December 31, 2015 and 2014 and the related consolidated statements of operations, equity and cash flows for each of the three years in the period ended December 31, 2015, and our report dated February 19, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Dallas, Texas

February 19, 2016

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ITEM 9B.	OTHER INFORMATION

None.

PART III



ITEM 10.	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE

The information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2016 and is incorporated herein by reference.



ITEM 11.	EXECUTIVE COMPENSATION



ITEM 12.	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS

Securities Authorized for Issuance under Equity Compensation Plans

The following table summarizes information about the Company's equity compensation plans as of December 31, 2015:



	Number of securities to be issued upon exercise of outstanding options, warrants and rights (a)	Weighted-average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in first column)
Equity compensation plans approved by security holders:
Pioneer Natural Resources Company:
2006 Long-Term Incentive Plan (b)(c)	199,058	$	77.51	2,082,001
Employee Stock Purchase Plan (d)	—	—		416,922
Total:	199,058	$	77.51	2,498,923

_______________________


(a)	There are no outstanding warrants or equity rights awarded under the Company's equity compensation plans. The securities listed do not include restricted stock awarded under the Company's previous Long-Term Incentive Plan and the Company's 2006 Long-Term Incentive Plan.

(b)

In May 2006, the stockholders of the Company approved the 2006 Long-Term Incentive Plan, which provided for the issuance of up to 9.1 million awards, as was supplementally approved by the stockholders of the Company during May 2009. Awards under the 2006 Long-Term Incentive Plan can be in the form of stock options, stock appreciation rights, performance units, restricted stock and restricted stock units. No additional awards may be made under the prior Long-Term Incentive Plan.


(c)	The number of securities remaining for future issuance has been reduced by the maximum number of shares that could be issued pursuant to outstanding grants of performance units at December 31, 2015.


(d)	The number of remaining securities available for future issuance under the Company's Employee Stock Purchase Plan is based on the original authorized issuance of 750,000 shares plus an additional 500,000 shares supplementally approved less 833,078 cumulative shares issued through December 31, 2015.

See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a description of each of the Company's equity compensation plans.

The remaining information required in response to this Item will be set forth in the Company's definitive proxy statement for the annual meeting of stockholders to be held during May 2016 and is incorporated herein by reference.

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ITEM 13.	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE



ITEM 14.	PRINCIPAL ACCOUNTING FEES AND SERVICES

PART IV



ITEM 15.	EXHIBITS, FINANCIAL STATEMENT SCHEDULES


(a)	Listing of Financial Statements

Financial Statements

The following consolidated financial statements of the Company are included in "Item 8. Financial Statements and Supplementary Data:"


•	Report of Independent Registered Pubic Accounting Firm


•	Consolidated Balance Sheets as of December 31, 2015 and 2014


•	Consolidated Statements of Operations for the Years Ended December 31, 2015, 2014 and 2013


•	Consolidated Statements of Equity for the Years Ended December 31, 2015, 2014 and 2013


•	Consolidated Statements of Cash Flows for the Years Ended December 31, 2015, 2014 and 2013


•	Notes to Consolidated Financial Statements


•	Unaudited Supplementary Information


(b)	Exhibits

The exhibits to this Report that are required to be filed pursuant to Item 15(b) are listed below and in the "Exhibit Index" attached hereto.


(c)	Financial Statement Schedules

No financial statement schedules are required to be filed as part of this Report or they are inapplicable.

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Exhibits



Exhibit Number		Description
2.1	—	Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer USA, PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 12, 2013).
2.2	—	Amendment No. 1, entered into as of October 25, 2013, to the Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer USA, PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 31, 2013).
3.1	—	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 26, 1997, Registration No. 333-26951).
3.2	—	Certificate of Amendment of the Amended and Restated Certificate of Incorporation, effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
3.3	—	Fourth Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 20, 2015).
4.1	—	Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4, dated June 26, 1997, Registration No. 333-26951).
4.2	—	Indenture dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.3	—	First Supplemental Indenture dated as of January 13, 1998, among the Company, Pioneer USA and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.4	—	Second Supplemental Indenture dated as of April 11, 2000, among the Company, Pioneer USA, and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-13245).
4.5	—	Third Supplemental Indenture dated as of April 30, 2002, among the Company, Pioneer USA and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-13245).
4.6	—	Fourth Supplemental Indenture dated as of July 15, 2004, among the Company and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.7	—	Fifth Supplemental Indenture dated as of July 15, 2004, among the Company, Pioneer USA and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.8	—	Sixth Supplemental Indenture, dated as of May 1, 2006, among the Company, Pioneer USA and The Bank of New York Trust Company, N.A., as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 4, 2006).
4.9	—	Seventh Supplemental Indenture, dated as of March 12, 2007, among the Company, Pioneer USA, The Bank of New York Trust Company, N.A, as original trustee under the indenture, and Wells Fargo Bank, National Association, as series trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 12, 2007).
4.10	—	Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).
4.11	—	First Supplemental Indenture dated January 22, 2008 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008.

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4.12	—	Second Supplemental Indenture dated November 13, 2009 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 13, 2009).
4.13	—	Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.14	—	First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.15	—	Second Supplemental Indenture, dated December 7, 2015, by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K File No. 1-13245, filed with the SEC on December 7, 2015).
4.16	—	Third Supplemental Indenture, dated December 7, 2015 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 7, 2015).
10.1	—	Second Amended and Restated 5-Year Revolving Credit Agreement dated as of March 31, 2011, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on April 5, 2011).
10.2	—	First Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement dated as of December 20, 2012, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 20, 2012).
10.3	—	Second Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement dated as of August 31, 2015, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on September 4, 2015).
10.4 H	—	The Company's Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35087, filed with the SEC on September 8, 1997).
10.5 H	—	First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.6 H	—	Amendment No. 2 to the Company's Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.7 H	—	Amendment No. 3 to the Company's Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.8 H	—	Amendment No. 4 to the Company's Long-Term Incentive Plan, effective as of November 20, 2003 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.9 H	—	Amendment No. 5 to the Company's Long-Term Incentive Plan, effective as of May 12, 2004 (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.10 H	—	Amendment No. 6 to the Company's Long-Term Incentive Plan, effective as of December 17, 2004 (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.11 H	—	Amendment No. 7 to the Company's Long-Term Incentive Plan, effective November 20, 2008 (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.12 H	—	Pioneer Natural Resources Company 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006).
10.13 H	—	First Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective November 20, 2008 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.14 H	—	Second Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective May 28, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 28, 2009).

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10.15 H	—	Third Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.16 H	—	Fourth Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.17 H	—	Fifth Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective August 20, 2012 (incorporated by reference to Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, File No. 1-13245).
10.18 H	—	Form of Restricted Stock Unit Award Agreement for Non-Employee Directors to be used in connection with initial equity awards under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, File No. 1-13245).
10.19 H	—	Form of Restricted Stock Unit Award Agreement for Non-Employee Directors to be used in connection with annual equity awards under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 1-13245).
10.20 H	—	Form of Restricted Stock Award Agreement between the Company and Timothy L. Dove, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.21 H	—	Form of Nonstatutory Stock Option Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.22 H	—	Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.23 H	—	Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.24 H	—	Form of Restricted Stock Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.25 H	—	Form of Restricted Stock Unit Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.26 H	—	Pioneer Natural Resources Company Employee Stock Purchase Plan, as amended and restated, effective September 1, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-13245).
10.27 H	—	First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan, effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
10.28 H	—	The Company's Executive Deferred Compensation Plan, Amended and Restated, effective as of August 1, 2002 (incorporated by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.29 H	—	Amendment No. 1 to the Company's Executive Deferred Compensation Plan, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-13245).

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10.30 H	—	Amended and Restated Executive Deferred Compensation Plan, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.31 H	—	Amendment No. 1 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245).
10.32 H	—	Amendment No. 2 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011 (incorporated by reference to Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.33 H	—	Amendment No. 3 to the Company's Amended and Restated Executive Deferred Compensation Plan, executed August 19, 2013 and effective January 1, 2009 (incorporated by reference to Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.34 H	—	Amendment No. 4 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2014 (incorporated by reference to Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.35 H	—	Pioneer USA 401(k) and Matching Plan, Amended and Restated, effective as of January 1, 2013 (incorporated by reference to Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.36 H	—	First Amendment to Pioneer USA 401(k) and Matching Plan dated February 27, 2014 (incorporated by reference to Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, File No. 1-13245).
10.37 H	—	Second Amendment to Pioneer USA 401(k) and Matching Plan dated November 10, 2014 (incorporated by reference to Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, File No. 1-13245).
10.38 H	—	Third Amendment to Pioneer USA 401(k) and Matching Plan dated May 13, 2015 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 1-13245).
10.39 H	—	Fourth Amendment to Pioneer USA 401(k) and Matching Plan dated July 7, 2015 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 1-13245).
10.40 H	—	Fifth Amendment to Pioneer USA 401(k) and Matching Plan dated October 29, 2015 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 1-13245).
10.41 H (a)	—	Sixth Amendment to Pioneer USA 401(k) and Matching Plan dated December 7, 2015.
10.42 H	—	Indemnification Agreement, dated February 21, 2013, between the Company and Thomas D. Arthur, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 26, 2013).
10.43 H	—	Indemnification Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 8, 2013).
10.44 H	—	Indemnification Agreement, dated March 4, 2013, between the Company and J.D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014).
10.45 H	—	Indemnification Agreement, dated effective July 23, 2013, between the Company and Stacy P. Methvin, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 29, 2013).
10.46 H	—	Indemnification Agreement, dated March 13, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
10.47 H	—	Indemnification Agreement, dated July 7, 2014, between the Company and Phillip A. Gobe, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 10, 2014).

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10.48 H	—	Indemnification Agreement, dated June 29, 2015, between the Company and Mona K. Sutphen, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 1-13245).
10.49 H	—	Severance Agreement dated August 16, 2005, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Severance Agreement (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13245).
10.50 H	—	Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.51 H	—	Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.52 H	—	Severance Agreement, dated effective August 10, 2005, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Severance Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.53 H	—	Amendment to Severance Agreement, dated December 8, 2008, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Amendment to Severance Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.54 H	—	Severance Agreement, dated effective January 14, 2010, between the Company and J. D. Hall (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.55 H	—	Severance Agreement, dated effective January 1, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-13245).
10.56 H (a)	—	Separation Agreement, dated effective January 4, 2016, between the Company and Danny Kellum.
10.57 H	—	Change in Control Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 1-13245).
10.58 H	—	Change in Control Agreement, dated March 4, 2013, between the Company and J. D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.59 H	—	Change in Control Agreement, dated March 13, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-13245).
10.60 H	—	Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (now known as the Pioneer 2008 PSE Employee Long Term Incentive Plan) (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 17, 2013).
10.61 H	—	First Amendment to Pioneer 2008 PSE Employee Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 17, 2013).
10.62 H	—	Form of Phantom Unit Award Agreement between the General Partner of Pioneer Southwest Energy Partners L.P. and Scott D. Sheffield, with respect to awards of phantom units made under the Pioneer 2008 PSE Employee Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the General Partner and each of its other recipients of phantom unit awards and identifying the material differences between those agreements and the filed Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.1 to Pioneer Southwest Energy Partners L.P.'s Current Report on Form 8-K, File No. 001-34032, filed with the SEC on March 9, 2010).
12.1 (a)	—	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.
21.1 (a)	—	Subsidiaries of the registrant.

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23.1 (a)	—	Consent of Ernst & Young LLP.
23.2 (a)	—	Consent of Netherland, Sewell & Associates, Inc.
31.1 (a)	—	Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	—	Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	—	Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	—	Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
95.1 (a)	—	Mine Safety Disclosure pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
99.1 (a)	—	Report of Netherland, Sewell & Associates, Inc.
101. INS (a)	—	XBRL Instance Document.
101. SCH (a)	—	XBRL Taxonomy Extension Schema.
101. CAL (a)	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101. DEF (a)	—	XBRL Taxonomy Extension Definition Linkbase Document.
101. LAB (a)	—	XBRL Taxonomy Extension Label Linkbase Document.
101. PRE (a)	—	XBRL Taxonomy Extension Presentation Linkbase Document.

__________________________



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

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



		PIONEER NATURAL RESOURCES COMPANY
Date:	February 19, 2016

		By:	/s/ Scott D. Sheffield
			Scott D. Sheffield, Chairman of the Board and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

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Signature	Title	Date

/s/ Scott D. Sheffield	Chairman of the Board and Chief Executive Officer (principal executive officer)	February 19, 2016
Scott D. Sheffield

/s/ Timothy L. Dove	President, Chief Operating Officer and Director	February 19, 2016
Timothy L. Dove	President, Chief Operating Officer and Director

/s/ Richard P. Dealy	Executive Vice President and Chief Financial Officer (principal financial officer)	February 19, 2016
Richard P. Dealy

/s/ Margaret M. Montemayor	Vice President and Chief Accounting Officer (principal accounting officer)	February 19, 2016
Margaret M. Montemayor

/s/ Edison C. Buchanan	Director	February 19, 2016
Edison C. Buchanan	Director

/s/ Andrew F. Cates	Director	February 19, 2016
Andrew F. Cates	Director

/s/ Phillip A. Gobe	Director	February 19, 2016
Phillip A. Gobe	Director

/s/ Larry R. Grillot	Director	February 19, 2016
Larry R. Grillot	Director

/s/ Stacy P. Methvin	Director	February 19, 2016
Stacy P. Methvin	Director

/s/ Royce W. Mitchell	Director	February 19, 2016
Royce W. Mitchell	Director

/s/ Frank A. Risch	Director	February 19, 2016
Frank A. Risch	Director

/s/ Mona K. Sutphen	Director	February 19, 2016
Mona K. Sutphen	Director

/s/ J. Kenneth Thompson	Director	February 19, 2016
J. Kenneth Thompson	Director

/s/ Phoebe A. Wood	Director	February 19, 2016
Phoebe A. Wood	Director

/s/ Michael D. Wortley	Director	February 19, 2016
Michael D. Wortley	Director

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Exhibit Index



Exhibit Number		Description
2.1	—	Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer USA, PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC (incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on August 12, 2013).
2.2	—	Amendment No. 1, entered into as of October 25, 2013, to the Agreement and Plan of Merger dated as of August 9, 2013, by and among the Company, Pioneer USA, PNR Acquisition Company, LLC, Pioneer Southwest Energy Partners L.P., and Pioneer Natural Resources GP LLC(incorporated by reference to Exhibit 2.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on October 31, 2013).
3.1	—	Amended and Restated Certificate of Incorporation of the Company (incorporated by reference to Exhibit 3.1 to the Company's Registration Statement on Form S-4, dated June 26, 1997, Registration No. 333-26951).
3.2	—	Certificate of Amendment of the Amended and Restated Certificate of Incorporation, effective May 18, 2012 (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
3.3	—	Fourth Amended and Restated Bylaws of the Company (incorporated by reference to Exhibit 3.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 20, 2015).
4.1	—	Form of Certificate of Common Stock, par value $.01 per share, of the Company (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-4, dated June 26, 1997, Registration No. 333-26951).
4.2	—	Indenture dated January 13, 1998, between the Company and The Bank of New York, as trustee (incorporated by reference to Exhibit 99.1 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.3	—	First Supplemental Indenture dated as of January 13, 1998, among the Company, Pioneer USA and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's and Pioneer USA's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 14, 1998).
4.4	—	Second Supplemental Indenture dated as of April 11, 2000, among the Company, Pioneer USA and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000, File No. 1-13245).
4.5	—	Third Supplemental Indenture dated as of April 30, 2002, among the Company, Pioneer USA and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2002, File No. 1-13245).
4.6	—	Fourth Supplemental Indenture dated as of July 15, 2004, among the Company and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.7	—	Fifth Supplemental Indenture dated as of July 15, 2004, among the Company, Pioneer USA and The Bank of New York, as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 99.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 19, 2004).
4.8	—	Sixth Supplemental Indenture, dated as of May 1, 2006, among the Company, Pioneer USA and The Bank of New York Trust Company, N.A., as trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 4, 2006).
4.9	—	Seventh Supplemental Indenture, dated as of March 12, 2007, among the Company, Pioneer USA, The Bank of New York Trust Company, N.A, as original trustee under the indenture, and Wells Fargo Bank, National Association, as series trustee, with respect to the indenture identified above as Exhibit 4.2 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 12, 2007).
4.10	—	Indenture dated January 22, 2008 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).
4.11	—	First Supplemental Indenture dated January 22, 2008 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on January 22, 2008).

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4.12	—	Second Supplemental Indenture dated November 13, 2009 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.10 (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 13, 2009).
4.13	—	Indenture dated June 26, 2012 between the Company and Wells Fargo Bank, National Association, as trustee (incorporated by reference to Exhibit 4.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.14	—	First Supplemental Indenture, dated June 26, 2012, by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 28, 2012).
4.15	—	Second Supplemental Indenture, dated December 7, 2015, by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.2 to the Company's Current Report on Form 8-K File No. 1-13245, filed with the SEC on December 7, 2015).
4.16	—	Third Supplemental Indenture, dated December 7, 2015 by and among the Company, Pioneer USA and Wells Fargo Bank, National Association, as trustee, with respect to the indenture identified above as Exhibit 4.13 (incorporated by reference to Exhibit 4.3 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 7, 2015).
10.1	—	Second Amended and Restated 5-Year Revolving Credit Agreement dated as of March 31, 2011, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on April 5, 2011).
10.2	—	First Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement dated as of December 20, 2012, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 20, 2012).
10.3	—	Second Amendment to Second Amended and Restated 5-Year Revolving Credit Agreement dated as of August 31, 2015, among the Company, as Borrower, Wells Fargo Bank, National Association, as Administrative Agent, and certain other lenders (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on September 4, 2015).
10.4 H	—	The Company's Long-Term Incentive Plan (incorporated by reference to Exhibit 4.1 to the Company's Registration Statement on Form S-8, Registration No. 333-35087, filed with the SEC on September 8, 1997).
10.5 H	—	First Amendment to the Company's Long-Term Incentive Plan, effective as of November 23, 1998 (incorporated by reference to Exhibit 10.72 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.6 H	—	Amendment No. 2 to the Company's Long-Term Incentive Plan, effective as of May 20, 1999 (incorporated by reference to Exhibit 10.73 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.7 H	—	Amendment No. 3 to the Company's Long-Term Incentive Plan, effective as of February 17, 2000 (incorporated by reference to Exhibit 10.76 to the Company's Annual Report on Form 10-K for the year ended December 31, 1999, File No. 1-13245).
10.8 H	—	Amendment No. 4 to the Company's Long-Term Incentive Plan, effective as of November 20, 2003 (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.9 H	—	Amendment No. 5 to the Company's Long-Term Incentive Plan, effective as of May 12, 2004 (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.10 H	—	Amendment No. 6 to the Company's Long-Term Incentive Plan, effective as of December 17, 2004 (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.11 H	—	Amendment No. 7 to the Company's Long-Term Incentive Plan, effective November 20, 2008 (incorporated by reference to Exhibit 10.8 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.12 H	—	Pioneer Natural Resources Company 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 9, 2006).
10.13 H	—	First Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective November 20, 2008 (incorporated by reference to Exhibit 10.7 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.14 H	—	Second Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective May 28, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 28, 2009).

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10.15 H	—	Third Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.16 H	—	Fourth Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on June 18, 2009).
10.17 H	—	Fifth Amendment to the Pioneer Natural Resources Company 2006 Long-Term Incentive Plan, effective August 20, 2012 (incorporated by reference to Exhibit 10.34 to the Company's Annual Report on Form 10-K for the year ended December 31, 2012, File No. 1-13245).
10.18 H	—	Form of Restricted Stock Unit Award Agreement for Non-Employee Directors to be used in connection with initial equity awards under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.18 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, File No. 1-13245).
10.19 H	—	Form of Restricted Stock Unit Award Agreement for Non-Employee Directors to be used in connection with annual equity awards under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, File No. 1-13245).
10.20 H	—	Form of Restricted Stock Award Agreement between the Company and Timothy L. Dove, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Award Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.21 H	—	Form of Nonstatutory Stock Option Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Nonstatutory Stock Option Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.22 H	—	Form of Performance Unit Award Agreement between the Company and each of Scott D. Sheffield and Timothy L. Dove, with respect to awards made under the Company's 2006 Long-Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers and identifying the material differences between each of those agreements and the filed Performance Unit Award Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.23 H	—	Form of Restricted Stock Unit Agreement between the Company and Scott D. Sheffield, with respect to annual awards made under the Company's 2006 Long-Term Incentive Plan together with a schedule identifying other substantially identical agreements between the Company and each of its other executive officers who received this award and identifying the material differences between each of those agreements and the filed Restricted Stock Unit Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.24 H	—	Form of Restricted Stock Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.6 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.25 H	—	Form of Restricted Stock Unit Award Agreement between the Company and executive officers of the Company with respect to retention awards made under the Company's 2006 Long-Term Incentive Plan (incorporated by reference to Exhibit 10.7 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2012, File No. 1-13245).
10.26 H	—	Pioneer Natural Resources Company Employee Stock Purchase Plan, as amended and restated, effective September 1, 2007 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2007, File No. 1-13245).
10.27 H	—	First Amendment to Amended and Restated Pioneer Natural Resources Company Employee Stock Purchase Plan, effective September 1, 2012 (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on May 18, 2012).
10.28 H	—	The Company's Executive Deferred Compensation Plan, Amended and Restated, effective as of August 1, 2002 (incorporated by reference to Exhibit 10.15 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2005, File No. 1-13245).
10.29 H	—	Amendment No. 1 to the Company's Executive Deferred Compensation Plan, effective as of January 1, 2007 (incorporated by reference to Exhibit 10.15 to the Company's Annual Report on Form 10-K for the year ended December 31, 2006, File No. 1-13245).

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10.30 H	—	Amended and Restated Executive Deferred Compensation Plan, effective as of January 1, 2009 (incorporated by reference to Exhibit 10.6 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.31 H	—	Amendment No. 1 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2009 (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2009, File No. 1-13245).
10.32 H	—	Amendment No. 2 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2011 (incorporated by reference to Exhibit 10.56 to the Company's Annual Report on Form 10-K for the year ended December 31, 2010, File No. 1-13245).
10.33 H	—	Amendment No. 3 to the Company's Amended and Restated Executive Deferred Compensation Plan, executed August 19, 2013 and effective January 1, 2009 (incorporated by reference to Exhibit 10.36 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.34 H	—	Amendment No. 4 to the Company's Amended and Restated Executive Deferred Compensation Plan, effective January 1, 2014 (incorporated by reference to Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.35 H	—	Pioneer USA 401(k) and Matching Plan, Amended and Restated, effective as of January 1, 2013 (incorporated by reference to Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2013, File No. 1-13245).
10.36 H	—	First Amendment to Pioneer USA 401(k) and Matching Plan dated February 27, 2014 (incorporated by reference to Exhibit 10.37 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, File No. 1-13245).
10.37 H	—	Second Amendment to Pioneer USA 401(k) and Matching Plan dated November 10, 2014 (incorporated by reference to Exhibit 10.38 to the Company's Annual Report on Form 10-K for the year ended December 31, 2014, File No. 1-13245).
10.38 H	—	Third Amendment to Pioneer USA 401(k) and Matching Plan dated May 13, 2015 (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 1-13245).
10.39 H	—	Fourth Amendment to Pioneer USA 401(k) and Matching Plan dated July 7, 2015 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 1-13245).
10.40 H	—	Fifth Amendment to Pioneer USA 401(k) and Matching Plan dated October 29, 2015 (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2015, File No. 1-13245).
10.41 H (a)	—	Sixth Amendment to Pioneer USA 401(k) and Matching Plan dated December 7, 2015.
10.42 H	—	Indemnification Agreement, dated February 21, 2013, between the Company and Thomas D. Arthur, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on February 26, 2013).
10.43 H	—	Indemnification Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on March 8, 2013).
10.44 H	—	Indemnification Agreement, dated March 4, 2013, between the Company and J.D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Indemnification Agreement (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014).
10.45 H	—	Indemnification Agreement, dated effective July 23, 2013, between the Company and Stacy P. Methvin, together with a schedule identifying other substantially identical agreements between the Company and each of the other non-employee directors identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 29, 2013).
10.46 H	—	Indemnification Agreement, dated March 13, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014).
10.47 H	—	Indemnification Agreement, dated July 7, 2014, between the Company and Phillip A. Gobe, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on July 10, 2014).

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10.48 H	—	Indemnification Agreement, dated June 29, 2015, between the Company and Mona K. Sutphen, together with a schedule identifying other substantially identical agreement between the Company and the other non-employee director identified on the schedule (incorporated by reference to Exhibit 10.3 to the Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2015, File No. 1-13245).
10.49 H	—	Severance Agreement dated August 16, 2005, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Severance Agreement (incorporated by reference to Exhibit 10.24 to the Company's Annual Report on Form 10-K for the year ended December 31, 2007, File No. 1-13245).
10.50 H	—	Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each of Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.51 H	—	Form of Amendment to Severance Agreement dated November 20, 2008, between the Company and each executive officer of the Company other than Scott D. Sheffield and Timothy L. Dove (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on November 25, 2008).
10.52 H	—	Severance Agreement, dated effective August 10, 2005, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Severance Agreement (incorporated by reference to Exhibit 10.4 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.53 H	—	Amendment to Severance Agreement, dated December 8, 2008, between the Company and Kenneth Sheffield, together with a schedule identifying the other substantially identical agreement between the Company and the executive officer identified on the schedule and identifying the material differences between that agreement and the filed Amendment to Severance Agreement (incorporated by reference to Exhibit 10.5 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.54 H	—	Severance Agreement, dated effective January 14, 2010, between the Company and J. D. Hall (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.55 H	—	Severance Agreement, dated effective January 1, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-13245).
10.56 H (a)	—	Separation Agreement, dated effective January 4, 2016, between the Company and Danny Kellum.
10.57 H	—	Change in Control Agreement, dated March 4, 2013, between the Company and Scott D. Sheffield, together with a schedule identifying other substantially identical agreements between the Company and each of its executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.1 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2013, File No. 1-13245).
10.58 H	—	Change in Control Agreement, dated March 4, 2013, between the Company and J. D. Hall, together with a schedule identifying other substantially identical agreements between the Company and the executive officers identified on the schedule and identifying the material differences between each of those agreements and the filed Change in Control Agreement (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2014, File No. 1-13245).
10.59 H	—	Change in Control Agreement, dated March 13, 2014, between the Company and Margaret M. Montemayor (incorporated by reference to Exhibit 10.2 to the Company's Quarterly Report on Form 10-Q for the quarter ended March 31, 2014, File No. 1-13245).
10.60 H	—	Pioneer Southwest Energy Partners L.P. 2008 Long Term Incentive Plan (now known as the Pioneer 2008 PSE Employee Long Term Incentive Plan) (incorporated by reference to Exhibit 10.1 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 17, 2013).
10.61 H	—	First Amendment to Pioneer 2008 PSE Employee Long Term Incentive Plan (incorporated by reference to Exhibit 10.2 to the Company's Current Report on Form 8-K, File No. 1-13245, filed with the SEC on December 17, 2013).
10.62 H	—	Form of Phantom Unit Award Agreement between the General Partner of Pioneer Southwest Energy Partners L.P. and Scott D. Sheffield, with respect to awards of phantom units made under the Pioneer 2008 PSE Employee Long Term Incentive Plan, together with a schedule identifying other substantially identical agreements between the General Partner and each of its other recipients of phantom unit awards and identifying the material differences between those agreements and the filed Phantom Unit Award Agreement (incorporated by reference to Exhibit 10.1 to Pioneer Southwest Energy Partners L.P.'s Current Report on Form 8-K, File No. 001-34032, filed with the SEC on March 9, 2010).
12.1 (a)	—	Computation of Ratios of Earnings to Fixed Charges and Earnings to Fixed Charges and Preferred Stock Dividends.
21.1 (a)	—	Subsidiaries of the registrant.

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Table of Contents



23.1 (a)	—	Consent of Ernst & Young LLP.
23.2 (a)	—	Consent of Netherland, Sewell & Associates, Inc.
31.1 (a)	—	Chief Executive Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
31.2 (a)	—	Chief Financial Officer certification under Section 302 of the Sarbanes-Oxley Act of 2002.
32.1 (b)	—	Chief Executive Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
32.2 (b)	—	Chief Financial Officer certification under Section 906 of the Sarbanes-Oxley Act of 2002.
95.1 (a)	—	Mine Safety Disclosure pursuant to Section 1503(a) of the Dodd-Frank Wall Street Reform and Consumer Protection Act.
99.1 (a)	—	Report of Netherland, Sewell & Associates, Inc.
101.INS (a)	—	XBRL Instance Document.
101. SCH (a)	—	XBRL Taxonomy Extension Schema.
101. CAL (a)	—	XBRL Taxonomy Extension Calculation Linkbase Document.
101. DEF (a)	—	XBRL Taxonomy Extension Definition Linkbase Document.
101. LAB (a)	—	XBRL Taxonomy Extension Label Linkbase Document.
101. PRE (a)	—	XBRL Taxonomy Extension Presentation Linkbase Document.

_____________________________



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

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