Edgar Filing: PIONEER NATURAL RESOURCES CO

Document

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, 2017



¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File Number: 1-13245

Pioneer Natural Resources Company

(Exact name of registrant as specified in its charter)



Delaware		75-2702753
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

5205 N. O'Connor Blvd., Suite 200, Irving, Texas		75039
(Address of principal executive offices)		(Zip Code)

Registrant's telephone number, including area code: (972) 444-9001

Securities registered pursuant to Section 12(b) of the Act:



Title of each class		Name of each exchange on which registered
Common Stock, par value $.01		New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ý No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No ý

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ý No ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.



Large accelerated filer	ý	Accelerated filer	o

Non-accelerated filer	o (Do not check if a smaller reporting company)	Smaller reporting company	o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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	$	26,939,176,465

Number of shares of Common Stock outstanding as of February 14, 2018	170,300,825

DOCUMENTS INCORPORATED BY REFERENCE:


(1)	Portions of the Definitive Proxy Statement for the Company's Annual Meeting of Shareholders to be held during May 2018 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	7
	Marketing of Production	9
	Competition, Markets and Regulations	9
Item 1A.	Risk Factors	15
Item 1B.	Unresolved Staff Comments	32
Item 2.	Properties	32
	Reserve Estimation Procedures and Audits	32
	Proved Reserves	35
	Description of Properties	36
	Selected Oil and Gas Information	38
Item 3.	Legal Proceedings	44
Item 4.	Mine Safety Disclosures	44
	Executive Officers of the Registrant	45
PART II
Item 5.	Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	48
	Purchases of Equity Securities by the Issuer and Affiliated Purchasers	48
Item 6.	Selected Financial Data	49
Item 7.	Management's Discussion and Analysis of Financial Condition and Results of Operations	50
	Financial and Operating Performance	50
	First Quarter 2018 Outlook	50
	2018 Capital Budget	51
	Acquisitions	51
	Divestitures	51
	Results of Operations	52
	Capital Commitments, Capital Resources and Liquidity	57
	Critical Accounting Estimates	60
	New Accounting Pronouncements	63
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	64
	Quantitative Disclosures	64
	Qualitative Disclosures	67
Item 8.	Financial Statements and Supplementary Data	69
	Index to Consolidated Financial Statements	69
	Report of Independent Registered Public Accounting Firm	70
	Consolidated Financial Statements	71
	Notes to Consolidated Financial Statements	77
	Unaudited Supplementary Information	107
Item 9.	Changes in and Disagreements With Accountants on Accounting and Financial Disclosure	116
Item 9A.	Controls and Procedures	116
	Management's Report on Internal Control Over Financial Reporting	116
	Report of Independent Registered Public Accounting Firm	117
Item 9B.	Other Information	118

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PART III
Item 10.	Directors, Executive Officers and Corporate Governance	118
Item 11.	Executive Compensation	118
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	118
	Securities Authorized for Issuance Under Equity Compensation Plans	118
Item 13.	Certain Relationships and Related Transactions, and Director Independence	119
Item 14.	Principal Accounting Fees and Services	119
PART IV
Item 15.	Exhibits, Financial Statement Schedules	119
Item 16.	10-K Summary	126
Signatures		126

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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.


•	"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.


•	"GHG" means green house gases.


•	"HH" means Henry Hub, a distribution hub on the natural gas pipeline in Louisiana that serves as the delivery location for futures contracts on the NYMEX.


•	"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.


•	"LLS" means Louisiana light sweet oil, a light, sweet blend of oil produced from the Gulf of Mexico.


•	"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.


•	"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.

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(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.

(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.


•	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

Pioneer is a large independent oil and gas exploration and production company that explores for, develops and produces oil, NGLs and gas within the United States. The Company is a Delaware corporation, and its common stock has been listed and traded on the NYSE under the ticker symbol "PXD" since its formation in 1997.

The Company's principal executive office is located at 5205 N. O'Connor Blvd., Suite 200, Irving, Texas 75039. The Company also maintains an office in Midland, Texas and field offices in its areas of operation.

At December 31, 2017, Pioneer had 3,836 employees, 1,423 of whom were employed in field and plant operations and 1,010 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 be America's leading independent energy company, focused on value, safety, the environment, technology and our greatest asset, our people. The Company's long-term growth strategy is centered around the following strategic objectives:


•	maintaining a strong balance sheet to ensure financial flexibility;


•	delivering economic production and reserve growth;


•	enhancing drilling, completion and production activities by utilizing the Company's scale and technology advancements to reduce costs and improve efficiency;


•	developing and training employees and contractors to perform their jobs in a safe manner; and


•	stewarding the environment through industry leading sustainable development efforts.

The Company's long-term strategy is 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 over 75 percent of the Company's total proved oil and gas reserves as of December 31, 2017.

In February 2018, the Company announced plans to divest its oil and gas production activities and development and exploration opportunities in the following areas:


•	the Eagle Ford Shale gas and liquids 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;


•	the Edwards gas field located in South Texas; and


•	the Sinor Nest Wilcox oil field located in South Texas.

No assurance can be given that the sales will be completed in accordance with the Company's plans or on terms and at prices acceptable to the Company.

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PIONEER NATURAL RESOURCES COMPANY

Business Activities

Pioneer's purpose is to competitively and profitably explore for, develop and produce oil and gas reserves. In so doing, the Company sells homogeneous 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. The Company's portfolio of resources and opportunities are primarily located in the Spraberry/Wolfcamp oil field, and provide long-lived, dependable production and lower-risk exploration and development opportunities.

Petroleum industry. The petroleum industry has been operating in a lower oil price environment since late 2014, when North American oil prices began declining due to a worldwide oversupply of oil. During the fourth quarter of 2016, the Organization of Petroleum Exporting Countries ("OPEC") members and some nonmembers, led by Russia, pledged to reduce their oil output by roughly 1.8 million barrels a day from October 2016 levels in an effort to draw down a global oversupply and to rebalance supply and demand. The agreement became effective in January 2017 and was originally set to expire in March 2018. During November 2017, OPEC members and some nonmembers agreed to lengthen the output reductions through December 2018. These output reductions represented an unprecedented level of cooperation among oil-producing countries and, coupled with healthy oil demand, resulted in an increase in oil prices during 2017. In 2018, the worldwide demand for oil is expected to increase further as economic growth around the world is forecasted to be stronger than the last several years. This demand increase is expected to be met by higher supplies of oil from U.S. shale production growth and further oil inventory drawdowns. The Company expects ongoing oil price volatility as compliance with the output reduction agreement, changes in oil inventories and actual demand growth is reported.

The growth of unconventional shale drilling in the United States has substantially increased the supply of gas and NGLs, resulting in a significant decline in related prices as the supply of these products has grown. While the industry has invested in initiatives designed to increase takeaway capacity, such as the construction of liquefied natural gas ("LNG") and NGL export facilities, the supply of these products has exceeded the overall United States and international demand for these commodities. NGL products and gas supplies are expected to increase during 2018, which is expected to cause prices to decline slightly or remain flat during 2018.

Significant factors that are likely to affect 2018 commodity prices include: the effect of new policies enacted by the President of the United States and his administration; fiscal challenges facing the United States federal government; enacted changes to the tax laws in the United States; expected economic growth throughout the world; political and economic developments in North Africa and the Middle East; forecasted increased demand from Asian and European markets; the extent to which members of OPEC and other oil exporting nations adhere to and agree to extend the agreed oil production cuts, which expire in December 2018; 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 incremental LNG export capacity additions and the pace that gas storage is refilled during the year given that gas storage levels are anticipated to be at normal levels 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. The Company has entered into commodity derivative contracts for a large portion of its forecasted production for 2018 and, to a lesser extent, its forecasted 2019 production; however, commodity prices are volatile and if commodity prices decline, the Company could realize lower prices for unprotected volumes and could see 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 will be negatively impacted by a reduction in commodity prices. 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, 2017, and subsequent changes to these positions.

Liquidity. In spite of the lower commodity price environment, the Company has maintained a strong liquidity position. The Company's primary needs for cash are for capital expenditures, acquisitions of oil and gas properties, vertical integration assets and facilities, payments of contractual obligations, including debt maturities, dividends, share repurchases and working capital obligations. Principal sources of liquidity include cash and cash equivalents, net cash provided by operating activities, short-term and long-term investments, 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 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 (i) by using cash on hand, (ii) through sales of short-term and long-term investments, (iii) with borrowings under the Company's credit facility, (iv) through issuances of debt or equity securities or (v) through other sources, such as sales of nonstrategic 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 controllable

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costs associated with production activities. For the year ended December 31, 2017, the Company's production of 99 MMBOE, excluding field fuel usage, represented a 16 percent increase compared to production during 2016. Production, price and cost information with respect to the Company's properties for 2017, 2016 and 2015 is set forth in "Item 2. Properties — Selected Oil and Gas Information — Production, price and cost data."

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. 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, negotiations of letters of intent or negotiations of definitive agreements. The success of any acquisition is uncertain and depends on a number of factors, some of which are outside the Company's control. See "Item 1A. Risk Factors — The Company may be unable to make attractive acquisitions and any acquisition it completes is subject to substantial risks that could materially and adversely affect its business."

During 2017, 2016 and 2015, the Company spent $136 million, $446 million and $36 million, respectively, primarily to purchase undeveloped acreage for future exploitation and exploration activities in the Spraberry/Wolfcamp field of the Permian Basin.

2016 Permian Basin acquisition. The Company's 2016 acquisition activities included the August 2016 acquisition of 28,000 net acres in the Permian Basin, with net production of approximately 1,400 BOEPD, from an unaffiliated third party for $428 million, including normal closing adjustments. The fair value of the assets acquired included $347 million of unproved property, $79 million of proved property and $5 million of other property and equipment. The fair value of the asset retirement obligations and other liabilities assumed were $2 million and $1 million, respectively.

Exploratory activities. The Company has devoted significant efforts and resources to hiring and developing a highly skilled geoscience, engineering and land 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."

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, 2017, the Company drilled 181 gross (130 net) development wells, with 100 percent of the wells being successfully completed as productive wells, at a total drilling cost (net to the Company's interest) of $2.0 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, 2017 include proved undeveloped reserves and proved developed non-producing reserves of 45 MMBbls of oil, 22 MMBbls of NGLs and 291 Bcf of gas. 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.

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 470,000 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, Pioneer Sands LLC, the Company's wholly-owned sand mining subsidiary, is supplying high-quality brown sand for proppant, which is being used by the Company to fracture stimulate horizontal wells in the Spraberry and Wolfcamp Shale intervals.

The Company is also constructing a field-wide water distribution system to reduce the cost of water for drilling and completion activities and to secure adequate supplies of water to support the Company's long-term growth plan for the Spraberry/Wolfcamp field. During 2017, the Company expanded its mainline system, subsystems and frac ponds to efficiently deliver water to Pioneer's drilling locations. The Company is purchasing up to 120 thousand barrels per day of effluent water from the City of Odessa and has signed an agreement with the City of Midland to upgrade the city's wastewater treatment plant in return for a dedicated long-term supply of water from the plant. Once the upgrade to the wastewater treatment plant is complete, the Company expects to receive approximately two billion barrels of low-cost, non-potable water over a 28-year contract period (up to 240 thousand barrels per day) to support its completion operations.

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Asset divestitures. 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, create organizational and operational efficiencies and further the Company's objective of maintaining a strong balance sheet to ensure financial flexibility. In February 2018, the Company announced its intention to divest its properties in South Texas, Raton and the West Panhandle field and focus its efforts and capital resources to its Permian Basin assets. No assurance can be given that the sales will be completed in accordance with the Company's plans or on terms and at prices acceptable to the Company.

Permian Basin. In April 2017, the Company completed the sale of approximately 20,500 acres in the Martin County region of the Permian Basin, with net production of approximately 1,500 BOEPD, to an unaffiliated third party for cash proceeds of $264 million. The sale resulted in a gain of $194 million. In conjunction with the divestiture, the Company reduced the carrying value of goodwill by $2 million, reflecting the portion of the Company's goodwill related to the assets sold.

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 $501 million was received in July 2016. The Company recorded a net gain on the disposition of $777 million in September 2015.

The Company will continue to review its acreage in the Permian Basin and negotiate with other operators in the area to sell or trade nonstrategic properties to achieve operating 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 and impairments. 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 risks associated with planned 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.

Seasonal nature of business. Generally, but not always, the demand for gas decreases during the summer months and increases during the winter months. Seasonal anomalies such as mild winters or hot summers may impact general seasonal changes in demand.

Significant purchasers. During 2017, the Company's significant purchasers of oil, NGLs and gas were Occidental Energy Marketing Inc. (24 percent), Sunoco Logistics Partners L.P. (14 percent) and Plains Marketing LP (10 percent). 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 the Company's ability to sell its oil, NGL and gas production. See "Item 1A. Risk Factors - The Company may not be able to obtain access on commercially reasonable terms or otherwise to pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities to market its oil, NGL and gas production; the Company relies on a limited number of purchasers for a majority of its products" and Note L of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information about infrastructure capacity risks and the Company's significant customers.

Derivative risk management activities. The Company primarily utilizes commodity swap contracts, collar contracts and collar contracts with short puts that are intended 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 intended to reduce the effect of interest rate volatility on the Company's indebtedness and marketing derivatives to mitigate price risk associated with buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. The Company accounts for its derivative contracts using the mark-to-market ("MTM") method of accounting. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" for a description of the Company's derivative risk management activities, "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information about the impact of commodity derivative activities on oil, NGL and gas revenues and net derivative gains and losses during 2017, 2016 and 2015, as well as the Company's open commodity derivative positions at December 31, 2017, and subsequent changes to those positions.

Competition, Markets and Regulations

Competition. The oil and gas industry is highly competitive in the exploration for and acquisition of reserves, the acquisition of oil and gas leases and the hiring and retention of staff necessary for the identification, evaluation and acquisition and development of such properties. The Company's competitors include a large number of companies, including major integrated oil and gas companies, other independent oil and gas companies, and individuals engaged in the exploration for and development of oil and gas properties. Some of the Company's competitors are substantially larger and have financial and other resources greater than those of the Company; as such, the Company may be at a competitive disadvantage in the identification, acquisition and development of properties that complement the Company's operations.

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. 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.

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 many requirements, including 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

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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 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"), the U.S. Occupational Safety and Health Administration (the "OSHA") 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 may result in the assessment of sanctions, including administrative, civil and criminal penalties, imposition of investigatory remedial or corrective action of obligations, the occurrence of delays or restrictions in permitting or the performance of projects and the issuance of orders enjoining the Company from conducting certain operations in a particular area. While the Company's environmental compliance costs have historically not had a material adverse effect on its results of operations, there can be no assurance that such costs will not be material in the future, or that new or more stringently applied laws and regulations will not materially increase the cost of doing business.

The following is a summary of the more significant environmental and worker health and safety laws, as amended from time to time, to which the Company's business operations are or may be subject and with which compliance or the failure to maintain compliance may have a material adverse effect on the Company's capital expenditures, results of operations or financial position.

Hazardous wastes and substances. 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. The Company generates some amounts of ordinary industrial wastes that may be regulated as RCRA hazardous wastes. RCRA currently excludes drilling fluids, produced waters and certain other wastes associated with the exploration, development and production of oil or gas from the definition of hazardous waste. These wastes are instead regulated under RCRA's less stringent non-hazardous waste provisions. There have been efforts from time to time to remove this exclusion, which removal could have a material adverse effect on the Company's results of operations and financial position, and it is possible that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous waste in the future. For example, in response to a lawsuit filed by several non-governmental environmental groups against the EPA for the agency's failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into a settlement agreement that was finalized in a consent decree issued by the U.S. District Court for the District of Columbia in December 2016, whereby the EPA is required to propose no later than March 15, 2019, a rulemaking for the revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, the decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021.

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. 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 generates materials in the course of its operations that may be regulated as CERCLA hazardous substances.

See "Item 1A. Risk Factors - The nature of the Company's assets and production operations may impact the environment or cause environmental contamination, which could result in material liabilities to the Company" for further discussion on environmental contamination issues.

Water use, surface discharges and discharges into belowground formations. 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

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discharge of pollutants, including spills and leaks of oil and hazardous substances, into waters of the United States and state waters. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon spill, rupture or leak. Additionally, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of stormwater runoff from certain types of facilities. The CWA also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by an appropriately issued permit. 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.

The federal Oil Pollution Act ("OPA") sets minimum standards for prevention, containment and cleanup of oil spills into waters of the United States. Under OPA, responsible parties, including owners and operators of onshore facilities, such as exploration and production 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 amends the CWA and thus noncompliance with OPA could result in civil and criminal penalties under the CWA.

In June 2015, the EPA and the U.S. Army Corps of Engineers (the "Corps") published a final rule attempting to clarify the federal jurisdictional reach over waters of the United States, but legal challenges to this rule followed and the rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 pending resolution of the court challenges. In January 2017, the U.S. Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Additionally, following the issuance of a presidential executive order to review the rule, the EPA and the Corps proposed a rulemaking in June 2017 to repeal the June 2015 rule. The EPA and the Corps also announced their intent to issue a new rule defining the CWA's jurisdiction. On November 22, 2017, the EPA and the Corps published a proposed rule specifying that the contested June 2015 rule would not take effect until two years after the rule proposed on November 22, 2017 is finalized and published in the federal register. As a result, future implementation of the June 2015 rule is uncertain at this time. To the extent this rule or a revised rule expands the scope of the CWA's jurisdiction, the Company could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas in connection with any expansion activities.

The Company may dispose of produced water from oil and gas activities in underground wells, which are designed and permitted to place the water into non-productive geologic formations that are isolated from fresh water sources. The Underground Injection Control ("UIC") program established under the federal Safe Drinking Water Act ("SDWA") requires issuance of permits from the EPA or an analogous state agency for the construction and operation of disposal wells. Additionally, the UIC program establishes minimum standards for disposal well operations and restricts the types and quantities of fluids that may be disposed. Because some states have become concerned that the disposal of produced water into below ground formations could contribute to seismicity, they have adopted or are considering adopting additional regulations governing such disposal. Should future onerous regulations or bans relating to underground wells be placed in effect in areas where the Company has significant operations, there could be an adverse impact on the Company's ability to operate. See "Item 1A. Risk Factors - Pioneer's operations are substantially dependent on the availability of water and its ability to dispose of produced water gathered from drilling and production activities and restrictions on the Company's ability to obtain water or dispose of produced water may have a materially adverse effect on its financial condition, results of operations and cash flows" for further discussion on seismicity issues.

Hydraulic fracturing. Hydraulic fracturing is an important and common practice to stimulate production of oil and gas from dense subsurface rock formations. The process involves the injection of water, sand and additives under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate oil and gas production. The Company routinely conducts hydraulic fracturing in its drilling and completion programs. The process is typically regulated by state oil and gas commissions, but, in recent years, several federal, state and local agencies have asserted regulatory authority over certain aspects of the process. Additionally, from time to time, the U.S. Congress has considered legislation that would provide for federal regulation of hydraulic fracturing and disclosure of chemicals used in the fracturing process but, to date, no such federal legislation has been adopted. The Company participates in FracFocus, a national publicly accessible internet-based registry managed by the Ground Water Protection Council and the Interstate Oil and Gas Compact Commission. FracFocus provides the public access to Company-reported information on the additives it uses in the hydraulic fracturing process on wells the Company operates. In the event federal, state or local restrictions are adopted in areas where the Company is currently conducting operations, 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.

See "Item 1A. Risk Factors - 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 materially and adversely affect the Company's production" for further discussion on hydraulic fracturing issues.

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Air emissions. The federal 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 could require a facility to obtain pre-approval for construction or modification projects expected to produce air emissions or result in the increase of existing air emissions. Additionally, these legal requirements could impose stringent air permit conditions or utilize specific emission control technologies to limit emissions of certain air pollutants. 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. See "Item 1A. Risk Factors - The Company's operations are subject to stringent environmental and oil and gas-related laws and regulations that could cause it to suspend or curtail its operations or expose it to material costs and liabilities" for further discussion on air emission issues.

Climate change. Climate change continues to attract considerable public, political and scientific attention. As a result, numerous proposals have been made, and are likely to continue to be made, at the international, national, regional and state levels of government to monitor and limit emissions of greenhouse gases ("GHGs"). These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. The adoption and implementation of any international, federal or state 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. See "Item 1A. Risk Factors - 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, and the potential physical effects of climate change could disrupt the Company's production and cause it to incur significant costs in preparing for or responding to those effects" for further discussion on climate change issues.

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. See "Item 1A. Risk Factors - Laws and regulations pertaining to threatened and endangered species could delay or restrict the Company's operations and cause it to incur substantial costs" for further discussion on endangered species issues.

Activities on federal lands. Oil and gas exploration, development and production activities on federal lands are subject to the National Environmental Policy Act ("NEPA"). NEPA requires federal agencies, including the federal Bureau of Land Management (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 some of the Company's 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 the federal Occupational Safety and Health Act and comparable state statutes. These laws and the related regulations issued by OSHA strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that the Company organize or disclose information about hazardous materials used or produced in the Company's operations.

Additionally, the Company's sand mining operations are subject to mining safety regulation. The U.S. Mining Safety and Health Administration ("MSHA") is the primary regulatory organization that regulates quarries, surface mines, underground mines and the industrial mineral processing facilities associated with and located at quarries and mines. 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.

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OSHA promulgated new rules in March 2016 for workplace exposure to respirable silica for several other industries. Respirable silica is a known health hazard for workers exposed over long periods. The MSHA has been considering the adoption of similar rules. If any new rule issued by MSHA lowers the workplace exposure limit significantly, the Company could incur significant capital and operating expenditures for equipment to reduce this exposure.

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 that are 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 the 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 production rates. 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 that the Company can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, NGLs 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 limit the amounts of oil and gas that may be produced from the Company's wells, negatively affect the economics of production from these wells or limit the number of locations the Company can drill.

Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of gas. Federal and state regulations govern the price and terms for access to gas pipeline transportation. Intrastate gas pipeline transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies. The interstate transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission ("FERC"). FERC endeavors to make gas transportation more accessible to gas buyers and sellers on an open-access and non-discriminatory basis.

Pursuant to the Energy Policy Act of 2005 ("EPAct 2005") it is unlawful for any entity, such as the Company, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of gas or transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The EPAct 2005 also gives FERC authority to impose civil penalties of up to $1 million per day for each violation of the Natural Gas Act ("NGA"), the Natural Gas Policy Act of 1978 and related regulations.

Under FERC Order 704, which regulates annual gas transaction reporting requirements, 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 by May 1 of the year following the calendar year when such sales and purchases occurred. Form No. 552 contains aggregate volumes of wholesale gas purchased or sold in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices. 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.

Intrastate gas pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate gas pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate gas pipeline rates, vary from state

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to state. Additional proposals and proceedings that might affect the gas industry are considered from time to time by the U.S. Congress, FERC, state legislatures, 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 believes that the regulation of intrastate gas pipeline transportation rates will not affect its operations in any way that is materially different from the effects on its similarly situated competitors.

Natural gas processing. The Company's gas processing operations are generally not subject to FERC or state regulation with respect to rates or terms and conditions of service. There can be no assurance that the Company's processing operations will continue to be unregulated in the future. However, although the processing facilities may not be directly regulated, 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 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 the 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. 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. Intrastate liquids pipeline transportation rates, terms and conditions are subject to regulation by numerous federal, state and local authorities and, in a number of instances, the ability to transport and sell such products on interstate pipelines is dependent on pipelines that are also subject to FERC jurisdiction under the Interstate Commerce Act (the "ICA"). The Company does not believe these regulations affect it any differently than other producers.

The ICA requires that pipelines maintain a tariff on file with the 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 the FERC.

Rates of interstate liquids pipelines are currently regulated by the FERC, primarily through an annual indexing methodology, under which pipelines increase or decrease their rates in accordance with an index adjustment specified by the FERC. For the five-year period beginning in July 2016, the FERC established an annual index adjustment equal to the change in the producer price index for finished goods plus 1.23 percent. This adjustment is subject to review every five years. Under the 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.

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 million per violation per day, subject to annual inflation adjustment. The Commodity Futures Trading Commission (the "CFTC") has also issued anti-manipulation rules that subject violators to a civil penalty of up to the greater of $1 million per violation, subject to annual inflation adjustment, or triple the monetary gain to the person for each violation. See "Items 1A. Risk Factors - The Company's transportation of gas, sales and purchases of oil, NGLs, gas or other energy commodities, and any derivative activities related to such energy commodities, expose the Company to potential regulatory risks."

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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 or impair the Company's ability to implement business plans or complete development activities as scheduled. In that case, the market price of the Company's common stock could decline.

The prices of oil, NGLs and gas are highly volatile and have declined significantly in recent years. A sustained decline in these commodity prices could materially and 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;


•	the price and quantity of foreign imports of 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;


•	volatility and trading patterns in the commodity-futures markets;


•	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, NGL and LNG imports to and exports from the U.S.;


•	technological advances affecting energy consumption and energy supply;


•	domestic and foreign governmental regulations, including environmental regulations, and taxation;


•	the effect of energy conservation efforts;


•	shareholder activism or activities by non-governmental organizations to restrict the exploration, development and production of oil and gas so as to minimize emissions of carbon dioxide and methane GHGs;


•	the proximity, capacity, cost and availability of pipelines and other transportation facilities; and


•	the price, availability and acceptance 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, 2017, oil prices fluctuated from a high of $110.53 per Bbl in 2013 to a low of $26.21 per Bbl in 2016 while gas prices fluctuated from a high of $6.15 per Mcf in 2014 to a low of $1.64 per Mcf in 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.

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Significant or extended price declines could also materially and adversely affect the amount of oil, NGLs and gas that the Company can produce economically, which may result in the Company having to make significant downward adjustments to its estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require the Company to reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively affect the Company's ability to replace its production and its future rate of growth.

The Company'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 production through 2018, the volumes of protected production for 2019 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's production volumes forecasted for 2019 and beyond may not be protected by derivative arrangements. In addition, the Company's derivatives arrangements may not achieve their intended strategic purposes.

Finally, the Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act"), enacted in July 2010, established federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that participate in that market. Regulation by the CFTC and banking regulators may materially and adversely affect the cost and availability of derivatives, including by causing the Company's contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities.

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 and could increase the likelihood that the Company's derivative arrangements may not achieve their intended strategic purposes.

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;


•	construction delays;


•	fracture stimulation accidents or failures;


•	adverse weather conditions;


•	restricted access to land for drilling or laying pipelines;

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•	title defects;


•	lack of available gathering, transportation, processing, fractionation, storage, refining or export facilities;


•	lack of available capacity on interconnecting transmission 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 2018.

Future price declines could result in a reduction in the carrying value of the Company's proved oil and gas properties, which could materially and adversely affect the Company's results of operations.

Significant or extended price declines could result in the Company having to make downward adjustments to the carrying value of its proved oil and gas properties. The Company performs assessments of its 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. 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 2017 the Company recognized an impairment charge of $285 million attributable to its Raton field in southeast Colorado, and in 2016 the Company recognized an impairment charge of $32 million attributable to its 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. 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 to determine recoverability of its cost and could be required to recognize noncash charges in the earnings of future periods.

At December 31, 2017, the Company carried unproved oil and gas property costs of $558 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 the 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, 2017, the Company had a carrying value for goodwill of $270 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 materially and adversely affect its business.

Acquisitions of producing oil and gas properties have from time to time contributed to the Company's growth. 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:

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•	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.

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 pre-closing matters, such as matters of litigation, environmental contingencies, royalty obligations and income taxes. 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 NGL and gas leaks, oil and produced water spills, pipeline and vessel ruptures, encountering naturally occurring radioactive materials ("NORM"), and unauthorized discharges of toxic chemicals, gases, brine, well stimulation and completion fluids or other pollutants onto the surface or into the 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;


•	surface access restrictions;


•	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 increases internally-provided fracture stimulation, water distribution, water disposal and other services. Any of these risks could result in substantial

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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, 2017, the Company owned interests in 10 gas processing plants and four treating facilities. The Company is the operator of one of the gas processing plants and all four of the treating facilities. Nine of the gas processing plants are operated by third parties and one of the treating facilities is 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.

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.

Drilling in emerging areas is more uncertain than drilling in areas that are more developed and have a longer history of established drilling operations. 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 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, 2017 include proved undeveloped reserves and proved developed non-producing reserves of 45 MMBbls of oil, 22 MMBbls of NGLs and 291 Bcf of gas. The Company's ability to drill and develop these locations depends on a number of factors, including the availability and cost 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. Well results vary by formation and geographic area, and the Company's drilling activities are generally focused on remaining locations that are believed to offer the highest return. Changes in the laws or regulations on which the Company relies in planning and executing its drilling programs could materially and 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 materially and 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

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expectations, which could have a material adverse effect on the Company's proved reserves, financial condition and results of operations.

A portion of the Company's total estimated proved reserves at December 31, 2017 were undeveloped, and those proved reserves may not ultimately be developed.

At December 31, 2017, approximately eight 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.

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 and other financial and operating results. These forecasts are based on a number of estimates and assumptions, including that none of the risks associated with the Company's oil and gas operations summarized in this "Item 1A. Risk Factors" occur. Production forecasts, specifically, are based on assumptions such as:


•	expectations of production from existing wells and future drilling activity;


•	the absence of facility or equipment malfunctions;


•	the absence of adverse weather effects;


•	expectations of commodity prices, which could experience significant volatility;


•	expected well costs; and


•	the assumed effects of regulation by governmental agencies, which could make certain drilling activities or production uneconomical.

Should any of these assumptions prove inaccurate, or should the Company's development plans change, actual production could be materially and adversely affected.

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, gathering systems and other transportation, processing, fractionation, refining and export 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, gathering systems and other transportation, processing, fractionation, refining and export 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, fractionation, refining or export facilities to the Company, especially in areas of planned expansion where such facilities do not currently exist.

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For example, following Hurricane Harvey in 2017 and Hurricanes Gustav and Ike in 2008, certain Permian Basin gas processors were forced to shut down their plants due to the inability of certain Texas Gulf Coast NGL fractionators to operate. 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 limitations in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, transportation, storage, processing, fractionation, refining or export facilities, or lack of capacity at 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 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 a FERC-related 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 the Permian Basin of West Texas, an area 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; such concentration also makes the Company vulnerable to risks associated with operating in a limited geographic area.

The Company's producing properties are geographically concentrated in the Permian Basin of West Texas. At December 31, 2017, 77 percent of the Company's total estimated proved reserves were attributable to properties located in this area. In addition, the Company's operations and drilling activity are concentrated in this area where industry activity is high. As a result, demand for personnel, equipment, power, services and resources has increased, as well as the costs for these items. Any delay or inability to secure the personnel, equipment, power, services and resources could result in oil, NGL 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 results of operations, cash flow and profitability.

As a result of this concentration, the Company may be disproportionately exposed to the impact of delays or interruptions of operations or production in this area caused by external factors such as governmental regulation, state politics, market limitations, water or sand shortages or extreme weather related conditions.

Pioneer's operations are substantially dependent upon the availability of water and its ability to dispose of produced water gathered from drilling and production activities. Restrictions on the Company's ability to obtain water or dispose of produced water may have a material adverse effect on its financial condition, results of operations and cash flows.

Water is an essential component of both the drilling and hydraulic fracturing processes. Limitations or restrictions on the Company's ability to secure sufficient amounts of water (including limitations resulting from natural causes such as drought), could materially and adversely impact its operations. Severe drought conditions can result in local water districts taking steps to restrict the use of water in their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. If the Company is unable to obtain water to use in its operations from local sources, it may need to be obtained from new sources and transported to drilling sites, resulting in increased costs, which could have a material adverse effect on its financial condition, results of operations and cash flows.

In addition, the Company must dispose of the fluids produced from oil and gas production operations, including produced water, which it does directly or through the use of third party vendors. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern arises from recent seismic events near underground disposal wells that are used for the disposal by injection of produced water resulting from oil and gas activities. In March 2016, the United States Geological Survey identified Texas and Colorado as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells to assess any relationship between seismicity and the use of such wells. For example, in Texas, the Texas Railroad Commission adopted new rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.

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States may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events. Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by the Company or by commercial disposal well vendors whom the Company may use from time to time to dispose of produced water. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and gas activities utilizing injection wells for produced water disposal. Any one or more of these developments may result in the Company or its vendors having to limit disposal well volumes, disposal rates and pressures or locations, or require the Company or its vendors to shut down or curtail the injection into disposal wells, which events could have a material adverse effect on the Company's business, financial condition and results of operations.

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 production and ad valorem taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to cost reductions for 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 materially and adversely affect the Company's results of operations.

Absent an expansion of U.S. refining and export 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 export capacity expansions, 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 stringent environmental and oil and gas-related laws and regulations that could cause it to suspend or curtail its operations or expose it to material costs and liabilities.

The Company's operations are subject to stringent federal, state and local laws and regulations governing, among other things, the drilling of wells, developing rates of production, the size and shape of drilling and spacing units or proration units, the transportation and sale of oil, NGLs and gas, and the discharging of materials into the environment and environmental protection. In connection with its operations, the Company must obtain and maintain numerous environmental and oil and gas-related permits, approvals, and certificates from various federal, state and local governmental authorities, and may incur substantial costs in doing so. The need to obtain permits has the potential to delay the development of oil and gas projects. Over the next several years, the Company may be charged royalties on gas emissions or required to incur certain capital expenditures for air pollution control equipment or other air emissions-related issues. For example, in October 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality Standard ("NAAQS") for ground-level ozone from 75 parts per billion to 70 parts per billion under standards to provide protection of public health and welfare. In November 2017, the EPA published a final rule that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either "attainment/unclassifiable" or "unclassifiable" but has not yet issued non-attainment designations for the remaining areas of the U.S. not addressed under the November 2017 final rule. Reclassification of areas or imposition of more stringent standards may make it more difficult to construct new or modify air pollution control systems to reduce or eliminate sources of air pollution in newly designated non-attainment areas. Moreover, states are expected to implement regulations implementing the NAAQS rule that may be more stringent than the federal standards. In another example, in June 2016, the EPA published a final rule updating federal permitting regulations for stationary sources in the oil and gas industry by defining and clarifying the meaning of the term "adjacent" for determining when separate surface sites and the equipment at those sites will be aggregated for permitting purposes. Future compliance with these legal requirements or with any new or amended 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

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expenses by, for example, requiring installation of new emission controls on some of the Company's equipment, any one or more of which developments could have a material adverse effect on the Company's business, financial condition and results of operations.

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 materially and adversely affect the Company's future operations and financial condition. Noncompliance with these laws and regulations may subject the Company to sanctions, including administrative, civil or criminal penalties, remedial cleanups or corrective actions, delays in permitting or performance of projects, natural resource damages and 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.

The nature of the Company's assets and production operations may impact the environment or cause environmental contamination, which could result in material liabilities to the Company.

The Company's assets and production operations may give rise to significant environmental costs and liabilities as a result of the Company's 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, treatment, storage, transport and disposal of wastes, hazardous substances and petroleum hydrocarbons and is subject to environmental hazards, such as oil and produced water spills, NGL and gas leaks, pipeline and vessel ruptures and unauthorized discharges of such wastes, substances and hydrocarbons, that could expose the Company to substantial liability due to pollution and other environmental damage. The Company currently owns, leases or operates, and in the past has owned, leased or operated, 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, or on or under other locations, including off-site locations, where such substances have been taken for treatment or disposal. These wastes, substances and hydrocarbons may also be released during future operations. In addition, some of the Company's properties have been operated by predecessors or previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under the Company's control. Joint and several strict liabilities may be incurred in connection with such releases of petroleum hydrocarbons, hazardous substances 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, hazardous substances 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. Such properties and the substances disposed or released on or under them may be subject to CERCLA, RCRA and analogous state laws, which could require the Company to remove previously disposed substances, wastes and petroleum hydrocarbons, remediate contaminated property or perform remedial plugging or pit closure operations to prevent future contamination, the costs of which could have a material adverse effect on the Company's business, financial condition and results of operations.

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.

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 and the potential physical effects of climate change could disrupt the Company's production and cause the Company to incur significant costs in preparing for or responding to those effects.

Climate change continues to attract considerable public, political and scientific attention. As a result, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. The EPA has, however, 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 in air quality by GHG emissions from large stationary sources that are already potential sources of significant 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. Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and gas

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operations. In June 2016, the EPA published a final rule establishing New Source Performance Standards, known as Subpart OOOOa, that require certain new, modified or reconstructed facilities in the oil and gas sector to reduce certain methane gas and volatile organic compound emissions. These Subpart OOOOa standards expand previously issued New Source Performance Standards, published by the EPA in 2012 and known as Subpart OOOO, by using certain equipment-specific emissions control practices. However, in June 2017, the EPA published a proposed rule to stay certain portions of these Subpart OOOOa standards for two years and revisit the entirety of the 2016 standard, but has not yet published a final rule. As a result, future implementation of the 2016 standards is uncertain at this time. Furthermore, with respect to a final rule published by the BLM in November 2016 and imposing requirements to reduce methane emissions from venting, flaring and leaking on public lands, the BLM has since published a proposed rulemaking in October 2017 that would temporarily suspend certain requirements contained in the November 2016 final rule until January 17, 2019, but the October 2017 rulemaking has not yet been finalized.

At the state level, some states are considering and other states, including Colorado, where the Company conducts operations, have issued requirements for the performance of leak detection programs that identify and repair methane leaks at certain oil and gas sources. State rules may be more stringent than federal rules. Compliance with the EPA's June 2016, the BLM's November 2016 rule or with any future federal or state methane regulations could, among other things, require installation of new emission controls on some of the Company's equipment and significantly increase the Company's capital expenditures and operating costs.

Internationally, in December 2015, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France that prepared an agreement requiring member countries to review and "represent a progression" in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This "Paris agreement" was signed by the United States in April 2016 and entered into force in November 2016. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges to voluntarily limit or reduce future emissions. In August 2017, the U.S. State Department officially informed the United Nations of the United States' intention to withdraw from the Paris agreement. The Paris agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States' adherence to the exit process and/or the terms on which the United States may re-enter the Paris agreement or a separately negotiated agreement are unclear at this time.

The adoption and implementation of any federal or state legislation or regulations or international agreements 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, any of which could have a material adverse effect on the Company's business, financial condition and results of operations. Moreover, such new legislation or regulatory programs as well as conservation plans and efforts undertaken in response to climate change could also materially and adversely affect demand for the oil, NGLs and gas the Company produces and lower the value of its reserves. Depending on the severity of any such limitations, the effect on the value of the Company's reserves could be material. In addition, recent non-governmental activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

Finally, it should be noted that 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, floods, droughts and other extreme climatic events. If any such effects were to occur, they could have a material adverse effect on the Company's exploration and production operations.

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 materially 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 conducts hydraulic fracturing 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 in recent years, several federal agencies have conducted investigations or asserted regulatory authority over certain aspects of the process. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that "water cycle" activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Additionally, the EPA has asserted regulatory authority pursuant to the SDWA's UIC program over hydraulic fracturing activities involving the use of diesel and issued guidance covering such activities. Moreover, in June 2016, the EPA published an effluent water final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly-owned wastewater treatment plants, and in 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

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in March 2015 that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands. However, with respect to this BLM rule, a Wyoming federal judge struck down this rule in June 2016, finding that the BLM lacked congressional authority to promulgate the rule, the BLM appealed the decision in July 2017, the appellate court issued a ruling in September 2017 to vacate the Wyoming trial court decision and dismiss the lawsuit challenging the 2015 rule in response to the BLM's issuance of a proposed rulemaking to rescind the 2015 rule and, on December 29, 2017, the BLM published a final rule rescinding the March 2017 rule.

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 additives used in the hydraulic-fracturing process. In addition, certain states in which the Company operates, including Texas and Colorado, have adopted, and other states are considering adopting, regulations that could impose new or more stringent permitting, disclosure, disposal and well-construction requirements on hydraulic-fracturing operations. States could elect to prohibit high volume hydraulic fracturing altogether, following the lead of New York. Also, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic fracturing in particular although in May 2015 in response to one city in Texas voting to ban hydraulic fracturing within city limits the Texas Legislature adopted Texas House Bill 40, which provides that the regulation of oil and gas operations in Texas is under the exclusive jurisdiction of the state and preempted local regulation of those operations. Despite Texas House Bill 40, municipalities and political subdivisions in Texas continue to have the right to enact "commercially reasonable" regulations for surface activities. In the event federal, state or local restrictions pertaining to hydraulic fracturing are adopted in areas where the Company is currently conducting operations, 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 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.

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 U.S. Fish and Wildlife Service (the "FWS") may designate critical habitat and suitable habitat areas that it believes are necessary for survival of threatened or endangered species. Any designation by the FWS of a critical or suitable habitat 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 petroleum hydrocarbons, wastes, hazardous substances or other regulated materials, and, in some cases, may seek criminal penalties. Moreover, as a result of one or more settlements entered into by the FWS, the agency is required to make determinations on the potential listing of numerous species as endangered or threatened under the ESA. 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 a material adverse effect on the Company's ability to develop and produce reserves.

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. In addition, from time to time, the Company enters into arrangements and transactions that can give rise to material off-balance sheet obligations, including firm purchase, transportation and fractionation commitments, gathering, processing and transportation commitments on uncertain volumes of future throughput, operating lease agreements and drilling commitments. The Company's financial commitments could have important consequences to its business including, but not limited to, the following:


•	the incurrence of charges associated with unused commitments if future events do not meet the Company's expectations at the time such commitments are entered into;


•	increasing its vulnerability to adverse economic and industry conditions;


•	limiting its flexibility to plan for, or react to, changes in its business and industry;


•	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.

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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, 2017 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 materially and 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.

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 transportation of gas, sales and purchases of oil, NGLs, gas or other energy commodities, and any derivative activities related to such energy commodities, expose the Company to potential regulatory risks.

The 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 transportation of gas in interstate commerce, physical sales and purchases 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 development costs, operating costs, severance, ad valorem and excise taxes, 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.

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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;


•	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 materially and adversely 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. The Company relies extensively on information technology systems, including Internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting its business. The Company's technologies systems and networks, and those of its business associates may become the target of cybersecurity attacks, including without limitation malicious software, attempts to gain unauthorized access to data and systems, and other electronic security breaches that could lead to disruptions in critical systems and materially and adversely affect the Company in a variety of ways, including the following:


•	unauthorized access to and release of seismic data, reserves information, strategic information or other sensitive or proprietary information, which could have a material adverse effect on the Company's ability to compete for oil and gas resources;


•	data corruption or operational disruption of production infrastructure, which could result in loss of production or accidental discharge;


•	unauthorized access to and release of personal identifying information of royalty owners, employees and vendors, which could expose the Company to allegations that it did not sufficiently protect that information;


•	a cybersecurity attack on a vendor or service provider, which could result in supply chain disruptions and could delay or halt operations; and


•	a cybersecurity attack on third-party gathering, transportation, processing, fractionation, refining or export facilities, which could delay or prevent the Company from transporting and marketing its production, resulting in a loss of revenues.

These events could damage the Company's reputation and lead to financial losses from remedial actions, loss of business or potential liability. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

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As cyber threats continue to evolve, the Company may be required to expend significant additional resources to continue to modify or enhance its protective measures or to investigate and remediate any information security vulnerabilities.

A failure by purchasers of the Company's production to satisfy their obligations to the Company could require the Company to recognize a 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 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 2016, the economies in the United States and certain countries in Europe and Asia have continued to stabilize with resulting improvements in industrial demand and consumer confidence. However, other economies, such as those of certain South American nations, continue to face economic struggles or slowing economic growth. If these conditions worsen, combined with a decline in economic growth in other parts of the world, there could be a significant adverse effect on global financial markets and commodity prices. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. 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.

The Company's use of seismic data is subject to interpretation and may not accurately identify the presence of oil and gas, which could materially and adversely affect the results of its drilling operations.

Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, the Company's drilling activities may not be successful or economic. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and the Company could incur losses as a result of such expenditures.

The enactment of derivatives legislation could have a material 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 Act enacted in July 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 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.

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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 materially and 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 materially and 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.

The future of the SEC and CFTC's rulemaking remains uncertain. Regulatory agendas that were released in late 2017 indicated that the SEC and CFTC plan to pursue fewer rulemaking items than in prior years. For example, the CFTC announced its intent to take action on an agency-wide internal review focused on simplifying and modernizing CFTC rules, regulations and practices and focus on streamlining the implementation of existing regulations and practices. Although the SEC and the CFTC's agendas are less expansive than they have been in the past, wholesale deregulation of the markets will not necessarily be the outcome. For example, the CFTC plans to take a new look at passing rules on position limits for certain futures contracts, and the SEC intends to re-propose rules for "plain vanilla" exchange-traded funds and add amendments to the Volcker Rule.

Moreover, regulation by the CFTC and banking regulators of the over-the-counter derivatives market and market participants could cause the Company's contract counterparties, which are generally financial institutions and other market participants, to curtail or cease their derivatives activities, which could materially and adversely affect the cost and availability of derivatives to the Company.

Provisions of the Company's charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for the Company's common stock.

Provisions in the Company's certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which the Company is not the surviving company and may otherwise prevent or slow changes in the Company's board of directors and management. In addition, because the Company is incorporated in Delaware, it is governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for the Company's common stock.

The Company's sand mining operations are subject to operating risks that are often beyond the Company's control, and such risks may not be covered by insurance.

Ownership of industrial sand mining operations is subject to risks, many of which are beyond the Company's control. These risks include:


•	unusual or unexpected geological formations or pressures;


•	cave-ins, pit wall failures or rock falls;


•	unanticipated ground, grade or water conditions;


•	inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;


•	environmental hazards, such as unauthorized spills, releases and discharges of wastes, vessel ruptures and emission of unpermitted levels of pollutants;


•	changes in laws and regulations;


•	inability to acquire or maintain necessary permits or mining or water rights;


•	restrictions on blasting operations;

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•	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, wastes, hazardous substances and other regulated 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 wastes, hazardous substances and other regulated 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 re-interpretation by more stringent and comprehensive legal requirements. While the Company's environmental compliance costs with existing laws and regulations have not historically had a material adverse effect on its results of operations, there can be no assurance that such costs will not be material in the future. Moreover, such future compliance with existing, new or amended 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 materially and 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

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•	requirements to perform site investigatory, remedial or other corrective actions.

In addition to environmental regulation, the Company's sand mining operations are subject to laws and regulations relating to worker health and safety, including such matters as human exposure to crystalline silica dust. Several federal and state regulatory authorities, including the MSHA, 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, mining and other permits and 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, recently adopted OSHA silica regulations and increased scrutiny by federal, state and local regulatory authorities.

Pioneer Sands LLC ("Pioneer Sands"), the Company's wholly-owned sand mining subsidiary, 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 Pioneer Sands or its commercial customers alleging damages caused by silica exposure. As of December 31, 2017, Pioneer Sands was the subject of silica exposure claims from 19 plaintiffs. Almost all of the claims pending against Pioneer Sands arise out of the alleged use of Pioneer Sands' sand products in foundries or as an abrasive blast media and have been filed in the states of Texas, Mississippi and Alabama, although some cases have been brought in other jurisdictions over the years.

It is possible that Pioneer Sands 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 its 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, 2017, 2016 and 2015 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 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.

Corporate Reserves is responsible for the management of the oil and gas proved reserve estimation processes in each of the Company's Permian Basin, South Texas, Raton and West Panhandle asset areas. Corporate Reserves is 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 oversight of the reservoir engineers by the Director of Corporate Reserves 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 Financial Officer and other executive officers. The reserve estimates are prepared by reservoir engineers before being submitted to the Director and Vice President of 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

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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 through internal Pioneer programs. Additionally, Corporate Reserves has prepared and maintains written policies and guidelines for its staff to reference on reserve estimation and preparation to promote consistency in the preparation of the Company's reserve estimates and compliance with the SEC reserve estimation and reporting rules.

Proved reserves audits. The proved reserve audits performed by NSAI for the years ended December 31, 2017, 2016 and 2015, in the aggregate, represented 77 percent, 77 percent and 82 percent of the Company's year-end 2017, 2016 and 2015 proved reserves, respectively; and 91 percent, 93 percent and 97 percent of the Company's year-end 2017, 2016 and 2015 associated pre-tax present value of proved reserves discounted at ten percent, respectively.

NSAI follows the general principles set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information" promulgated by the Society of Petroleum Engineers (the "SPE"). A reserve audit as defined by the SPE is not the same as a financial audit. The SPE's definition of a reserve audit includes the following concepts:


•	A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as to whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with the 2007 SPE publication entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information."

•

The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable.

•

The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare their own estimates of reserve information for the audited properties.

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

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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 who 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 40 years of experience as a petroleum engineer, with 33 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 39 years of practical experience in petroleum engineering, including over 36 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.

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.

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Proved Reserves

As of December 31, 2017, 2016 and 2015, 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, 2017, 2016 and 2015:



	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, 2017:
Developed	442,364	189,434	1,629,451	903,373	92	%
Undeveloped	40,525	21,063	122,429	81,993	8	%
Total proved reserves	482,889	210,497	1,751,880	985,366	100	%

December 31, 2016:
Developed	343,515	126,928	1,215,861	673,085	93	%
Undeveloped	34,681	10,013	48,868	52,840	7	%
Total proved reserves	378,196	136,941	1,264,729	725,925	100	%

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	%

_____________________


(a)	Total proved gas reserves contain 171,623 MMcf, 137,853 MMcf and 144,955 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, 2017, 2016 and 2015, respectively.

The Company's Standardized Measure of total proved reserves as of December 31, 2017 was $8.2 billion, including $7.7 billion and $443 million related to proved developed and proved undeveloped reserves, respectively. The Standardized Measure of total proved reserves as of December 31, 2017 includes the reduction of the federal corporate income tax rate to 21 percent associated with the enactment of the Tax Cut and Jobs Act. The Company's Standardized Measure of total proved reserves as of December 31, 2016 was $4.2 billion, including $4.0 billion and $178 million related to proved developed and proved undeveloped reserves, 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.

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 2017:



	Development Drilling
	Beginning Wells In Progress	Wells Spud	Successful Wells	Ending Wells In Progress
Permian Basin	8	22	16	14
South Texas—Eagle Ford Shale	4	1	5	—
South Texas—Other	—	5	5	—
Total	12	28	26	14



	Exploration/Extension Drilling
	Beginning Wells In Progress	Wells Spud	Successful Wells	Unsuccessful Wells	Ending Wells In Progress
Permian Basin	119	214	207	1	125
South Texas—Eagle Ford Shale	14	10	15	1	8
West Panhandle	—	3	—	—	3
Total	133	227	222	2	136

The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during 2017:



	Oil (Bbls)	NGLs (Bbls)	Gas (Mcf) (a)	Total (BOE)
Permian Basin	147,641	44,099	194,904	224,224
South Texas—Eagle Ford Shale	7,754	7,141	44,039	22,235
Raton Basin	—	—	88,497	14,750
West Panhandle	1,669	3,490	7,484	6,407
South Texas—Other	1,502	277	17,531	4,700
Other	5	1	52	14
Total	158,571	55,008	352,507	272,330

_____________________


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

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The following table summarizes the Company's costs incurred by asset area during 2017:



	Property Acquisition Costs				Exploration Costs		Development Costs		Asset Retirement Obligations
	Proved		Unproved		Exploration Costs		Development Costs		Asset Retirement Obligations			Total
	(in millions)
Permian Basin	$	8	$	128	$	1,950	$	579	$	(17	)	$	2,648
South Texas—Eagle Ford Shale	—		—		74		37		(4		)	107
Raton Basin	—		—		1		6		5			12
West Panhandle	—		—		2		10		(4		)	8
South Texas—Other	—		—		—		15		3			18
Other	—		—		4		—		—			4
Total	$	8	$	128	$	2,031	$	647	$	(17	)	$	2,797

Permian Basin. In November 2016, the U.S. Geological Survey ("USGS") announced, based on its estimates, that the Wolfcamp shale in the Permian Basin is the largest continuous oil field in the United States. Pioneer is the largest acreage holder in the Spraberry/Wolfcamp field, with approximately 750,000 gross acres (660,000 net acres). Pioneer's interests in the northern portion of the play comprise approximately 550,000 gross acres and its interests in the southern portion of the play, where the Company has a joint venture with Sinochem, comprise approximately 200,000 gross acres. The oil produced from the Spraberry/Wolfcamp field 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 seven formations, the upper and lower Spraberry, the Jo Mill, the Dean, the Wolfcamp, the Strawn and the Atoka, at depths ranging from 7,500 feet to 14,000 feet. The Company believes that it has significant resource potential within its Spraberry and Wolfcamp formation acreage, based on its extensive geologic data covering the Spraberry and Wolfcamp A, B, C and D intervals and its drilling results to date.

During 2017, the Company successfully completed 183 horizontal wells in the northern portion of the play and 40 horizontal wells in the southern portion of the play. In the northern portion of the play, approximately 50 percent of the horizontal wells placed on production were Wolfcamp B interval wells, approximately 35 percent were Wolfcamp A interval wells and approximately 15 percent were Lower Spraberry Shale interval wells. The majority of the wells placed on production in the southern portion of the play were Wolfcamp B interval wells. In addition, during 2017, the Company completed acreage trades that allow the Company to drill wells with longer laterals, improving the expected returns of the wells. The Company estimates that the acreage trades completed in 2017 added approximately 7.2 million lateral feet to the Company's drilling inventory.

The Company plans to operate 20 rigs in the Spraberry/Wolfcamp field in 2018, with 16 rigs operating in the northern portion of the play and four rigs operating in the southern portion of the play. During 2018, the Company expects to place on production between 250 and 275 horizontal wells (200 to 225 horizontal wells in the northern portion of the play and approximately 50 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 the remaining 15 percent will be a combination of wells in the Spraberry Shale intervals (Jo Mill, Lower Spraberry and Middle Spraberry) and a limited appraisal program for the Clearfork and Wolfcamp D intervals. The Company's 2018 appraisal program includes appraising: (i) its first Clearfork horizontal well (located in Midland County), (ii) seven wells in the Jo Mill and Middle Spraberry intervals in conjunction with nine Lower Spraberry Shale wells to determine an optimal development strategy for the Spraberry formation (these appraisals will test different spacing, staggering, sequencing, and completion design) and (iii) three Wolfcamp D interval wells.

The Company expects to spend $2.6 billion in the Spraberry/Wolfcamp field during 2018, including $2.0 billion of horizontal drilling and completion capital, $300 million for tank battery and disposal facilities, $170 million for gas processing facilities and $110 million for land, science and other costs.

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/Wolfcamp field. The majority of 2018 drilling activities will be supported by seven of the Company's eight pressure pumping fleets. 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. The 2018 capital budget includes $78 million for upgrades and maintenance to the Company's pressure pumping and well service equipment.

The Company's sand mine in Brady, Texas, which is strategically located within close proximity (approximately190 miles) of the Spraberry/Wolfcamp field, provides a secure sand source for the Company's horizontal drilling program. In addition, Pioneer has signed a contract for its initial offtake of sand sourced in West Texas where significant new sand supplies are expected to be

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available in 2018. The Company is evaluating additional contracts for lower cost sand sourced in West Texas. As a result of the expected supply growth of West Texas sand, the planned expansion of the Company’s sand mine at Brady, Texas has been deferred.

In addition to the efficiencies from the Company's integrated services, the Company has been and continues to pursue initiatives to improve drilling and completion efficiencies and reduce costs. The Company's long-term growth plan continues to focus on optimizing the development of the field and addressing the future requirements for water sourcing and disposal, field infrastructure, gas processing, pipeline takeaway capacity for its products, oilfield services, tubulars, electricity, buildings and roads.

The Company is constructing a field-wide water distribution system to reduce the cost of water for drilling and completion activities and to secure adequate supplies of non-potable water to support the Company's long-term growth plan for the Spraberry/Wolfcamp field. Over the past few years, the Company has expanded its mainline system, subsystems and frac ponds to efficiently deliver water to many of Pioneer's drilling locations. The Company is purchasing approximately 120 thousand barrels per day of effluent water from the City of Odessa and has signed an agreement with the City of Midland to upgrade the City's wastewater treatment plant in return for a dedicated long-term supply of water from the plant. Once the Midland plant upgrade is complete, the Company expects to receive approximately two billion barrels of low-cost, non-potable water over a 28-year contract period (up to 240 thousand barrels per day) to support its completion operations. During 2018, the Company expects to spend approximately $135 million to begin the Midland plant upgrade construction and build additional subsystems, frac ponds and produced water reuse facilities.

South Texas Eagle Ford Shale. During 2017, the Company operated two rigs in the Eagle Ford Shale area and drilled 11 new Eagle Ford Shale wells. The objective of this drilling program was to test longer laterals with wider spacing and higher intensity completions in the new wells. The Company's 2017 completions included 25 wells in South Texas, comprising 11 new Eagle Ford Shale wells and nine wells that were drilled but not completed in 2016, as well as five oil wells in the Wilcox formation that were drilled and placed on production during 2017.

See Note Q of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's plan to sell its South Texas assets.

Raton Basin. The Raton Basin properties are located in the southeast portion of Colorado. The Company owns approximately 180,000 gross acres (165,000 net acres) in the center of the Raton Basin and produces coal bed methane gas from the coal seams in the Vermejo and Raton formations from approximately 2,200 wells.

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 approximately 240,000 gross and net acres covering approximately 375 square miles.

See Note D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the impairment charges recorded during 2017, 2016 and 2015 to reduce the carrying value of the Company's properties in the Raton, West Panhandle, South Texas - Eagle Ford Shale and South Texas - Other fields.

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, 2017, 2016 and 2015. 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. A decline in oil and gas prices or poor drilling results 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.

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The following tables set forth production, price and cost data with respect to the Company's properties for 2017, 2016 and 2015. These amounts represent the Company's historical results of 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, 2017
	Spraberry/ Wolfcamp Field			Eagle Ford Shale Field			Raton Field		Total Company Fields
Production information:
Annual sales volumes:
Oil (MBbls)	53,889			2,830			—		57,878
NGLs (MBbls)	16,096			2,607			—		20,078
Gas (MMcf)	71,140			16,074			32,302		128,665
Total (MBOE)	81,842			8,116			5,384		99,401
Average daily sales volumes:
Oil (Bbls)	147,641			7,754			—		158,571
NGLs (Bbls)	44,099			7,141			—		55,008
Gas (Mcf)	194,904			44,039			88,497		352,507
Total (BOE)	224,224			22,235			14,750		272,330
Average prices:
Oil (per Bbl)	$	48.32		$	47.78		$	—	$	48.24
NGL (per Bbl)	$	18.69		$	19.39		$	—	$	19.31
Gas (per Mcf)	$	2.45		$	3.06		$	2.74	$	2.63
Revenue (per BOE)	$	37.62		$	28.95		$	16.47	$	35.39
Average costs (per BOE):
Production costs:
Lease operating	$	4.36		$	4.56		$	5.92	$	4.58
Third-party transportation charges	0.19			6.26			2.21		0.85
Net natural gas plant/gathering	(0.63		)	(0.03		)	2.03		(0.28		)
Workover	0.87			0.56			0.47		0.80
Total	$	4.79		$	11.35		$	10.63	$	5.95
Production and ad valorem taxes:
Ad valorem	$	0.58		$	0.41		$	0.54	$	0.57
Production	1.81			0.72			0.15		1.59
Total	$	2.39		$	1.13		$	0.69	$	2.16
Depletion expense	$	15.34		$	8.79		$	2.44	$	13.61

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PRODUCTION, PRICE AND COST DATA - (continued)



	Year Ended December 31, 2016
	Spraberry/ Wolfcamp Field			Eagle Ford Shale Field			Raton Field		Total Company Fields
Production information:
Annual sales volumes:
Oil (MBbls)	43,049			4,418			—		48,926
NGLs (MBbls)	10,886			3,755			—		15,922
Gas (MMcf)	51,528			26,133			35,368		124,428
Total (MBOE)	62,523			12,528			5,895		85,586
Average daily sales volumes:
Oil (Bbls)	117,619			12,070			—		133,677
NGLs (Bbls)	29,743			10,260			—		43,504
Gas (Mcf)	140,788			71,402			96,634		339,966
Total (BOE)	170,827			34,231			16,106		233,842
Average prices:
Oil (per Bbl)	$	40.30		$	35.60		$	—	$	39.65
NGL (per Bbl)	$	13.48		$	12.86		$	—	$	13.49
Gas (per Mcf)	$	2.11		$	2.36		$	1.87	$	2.11
Revenue (per BOE)	$	31.84		$	21.32		$	11.25	$	28.25
Average costs (per BOE):
Production costs:
Lease operating	$	5.35		$	2.87		$	5.07	$	5.02
Third-party transportation charges	0.20			6.81			2.93		1.41
Net natural gas plant/gathering	(0.43		)	(0.04		)	1.96		0.01
Workover	0.35			0.40			0.32		0.35
Total	$	5.47		$	10.04		$	10.28	$	6.79
Production and ad valorem taxes:
Ad valorem	$	0.50		$	0.31		$	0.07	$	0.46
Production	1.44			0.36			0.01		1.14
Total	$	1.94		$	0.67		$	0.08	$	1.60
Depletion expense	$	19.62		$	12.61		$	5.42	$	16.77

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PRODUCTION, PRICE AND COST DATA - (continued)



	Year Ended December 31, 2015
	Spraberry/ Wolfcamp 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	$	9.08		$	3.21	$	6.04		$	7.24
Third-party transportation charges	0.26			4.90		3.12			1.60
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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PIONEER NATURAL RESOURCES COMPANY

Productive wells. Productive wells consist of producing wells and wells capable of production, including shut-in wells and gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. One or more completions in the same well bore are counted as one well. Any well in which one of the multiple completions is an oil completion is classified as an oil well.

The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of December 31, 2017:

PRODUCTIVE WELLS



Gross Productive Wells			Net Productive Wells
Oil	Gas	Total	Oil	Gas	Total
6,905	3,679	10,584	6,146	3,150	9,296

Leasehold acreage. The following table sets forth information about the Company's developed, undeveloped and royalty leasehold acreage as of December 31, 2017:

LEASEHOLD ACREAGE

Developed Acreage

Undeveloped Acreage

Royalty Acreage

Gross Acres

Net Acres

Gross Acres

Net Acres

1,315,707

1,132,711

111,627

104,894

241,133

The following table sets forth the expiration dates of the leases on the Company's gross and net undeveloped acres as of December 31, 2017:



	Acres Expiring (a)
	Gross	Net
2018	87,718	84,683
2019	8,031	6,630
2020	1,950	1,320
2021	1,487	1,072
2022	—	—
Thereafter	12,441	11,189
Total	111,627	104,894

_____________________


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

Of the 91,313 net acres expiring in 2018 and 2019, 60,485 net acres (66 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 two 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 2017, 2016 and 2015 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,
	2017		2016		2015		2017		2016		2015
Productive wells:
Development	26		39		116		20		32		78
Exploratory	222		215		218		198		194		151
Dry holes:
Development	—		—		—		—		—		—
Exploratory	2		—		2		1		—		1
Total	250		254		336		219		226		230
Success ratio (a)	99	%	100	%	99	%	99	%	100	%	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, 2017:



	Gross Wells	Net Wells
Development	14	12
Exploratory	136	123
Total	150	135



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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EXECUTIVE OFFICERS OF THE REGISTRANT

The following table sets forth certain information as of the date of this Report regarding the Company's executive officers. All of the Company's executive officers serve at the discretion of the Company's board of directors. There are no family relationships among any of the Company's directors or executive officers.



Name	Position	Age
Timothy L. Dove	President and Chief Executive Officer	61
Mark S. Berg	Executive Vice President, Corporate/Vertically Integrated Operations	59
Chris J. Cheatwood	Executive Vice President and Chief Technology Officer	57
Richard P. Dealy	Executive Vice President and Chief Financial Officer	51
J.D. Hall	Executive Vice President, Permian Operations	52
Kenneth H. Sheffield, Jr.	Executive Vice President, Operations/Engineering/Facilities	57
William F. Hannes	Senior Vice President, Special Projects	58
Frank E. Hopkins	Senior Vice President, Investor Relations	69
Mark H. Kleinman	Senior Vice President and General Counsel	56
Teresa A. Fairbrook	Vice President and Chief Human Resources Officer	44
Margaret M. Montemayor	Vice President and Chief Accounting Officer	40
Stephanie D. Stewart	Vice President and Chief Information Officer	49

Timothy L. Dove

Mr. Dove has served as the Company's President and Chief Executive Officer since January 1, 2017. He held the positions for the Company of President and Chief Operating Officer from December 2004 to January 2017, Executive Vice President and Chief Financial Officer from February 2000 to November 2004 and Executive Vice President - Business Development from August 1997 to January 2000. Mr. Dove also served as President and Chief Operating Officer of the general partner of Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest") from June 2007 through the Company's acquisition of Pioneer Southwest in December 2013. Mr. Dove joined Parker & Parsley in 1994 as a Vice President and was promoted to Senior Vice President - Business Development in October 1996, in which position he served until the Company's formation in August 1997. Before joining Parker & Parsley, Mr. Dove was employed with Diamond Shamrock Corp and its successor, Maxus Energy Corp., in various capacities in international exploration and production, marketing, refining, and planning and development. Mr. Dove earned a Bachelor of Science degree in Mechanical Engineering from Massachusetts Institute of Technology and received his Master of Business Administration from the University of Chicago.

Mark S. Berg

Mr. Berg was elected the Company's Executive Vice President and General Counsel in April 2005, serving in those capacities until January 2014, at which time he assumed broader executive responsibilities, most recently being elected to serve as Executive Vice President, Corporate/Vertically Integrated Operations in May 2017. Mr. Berg had previously served as Executive Vice President, Corporate/Operations since August 2015 and Executive Vice President and General Counsel of the general partner of Pioneer Southwest from June 2007 through the Company's acquisition of Pioneer Southwest in December 2013. Prior to joining the Company, Mr. Berg served as Executive Vice President, General Counsel and Secretary of American General Corporation, a Fortune 200 diversified financial services company, from 1997 through 2002. Subsequent to the sale of American General to American International Group, Inc., Mr. Berg joined Hanover Compressor Company as Senior Vice President, General Counsel and Secretary. He served in that capacity from May 2002 through April 2004. Mr. Berg began his career in 1983 with the Houston-based law firm of Vinson & Elkins L.L.P. He was a partner with the firm from 1990 through 1997. Mr. Berg graduated Magna Cum Laude and Phi Beta Kappa with a Bachelor of Arts degree from Tulane University in 1980. He earned his Juris Doctorate with honors from the University of Texas School of Law in 1983.

Chris J. Cheatwood

Mr. Cheatwood was elected the Company's Executive Vice President and Chief Technology Officer in May 2017. Mr. Cheatwood had previously served the Company as Executive Vice President, Business Development and Geoscience since November 2011, Executive Vice President, Business Development and Technology from February 2010 until November 2011, Executive Vice President, Geoscience from November 2007 until February 2010, Executive Vice President - Worldwide Exploration from January 2002 until November 2007, Senior Vice President - Worldwide Exploration from December 2000 to January 2002 and Vice President - Domestic Exploration from July 1998 to December 2000. Mr. Cheatwood also served as an Executive Vice President of the general partner of Pioneer Southwest from June 2007 through the Company's acquisition of Pioneer Southwest

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in December 2013. Before joining the Company, Mr. Cheatwood spent ten years with Exxon Corporation. Mr. Cheatwood is a graduate of the University of Oklahoma with a Bachelor of Science degree in Geology and earned his Master of Science degree in Geology from the University of Tulsa.

Richard P. Dealy

Mr. Dealy was elected the Company's Executive Vice President and Chief Financial Officer in November 2004. Mr. Dealy held positions for the Company as Vice President and Chief Accounting Officer from February 1998 to November 2004 and Vice President and Controller from August 1997 to January 1998. Mr. Dealy also served as Executive Vice President, Chief Financial Officer, Treasurer and Director of the general partner of Pioneer Southwest from June 2007 through the Company's acquisition of Pioneer Southwest in December 2013. Mr. Dealy joined Parker & Parsley in July 1992 and was promoted to Vice President and Controller in 1996, in which position he served until August 1997. He is a Certified Public Accountant, and before joining Parker & Parsley, he was employed by KPMG LLP. Mr. Dealy graduated with honors from Eastern New Mexico University with a Bachelor of Business Administration degree in Accounting and Finance and is a Certified Public Accountant.

J. D. Hall

Mr. Hall was elected Executive Vice President, Permian Operations, in August 2015. Mr. Hall had previously held positions for the Company as Executive Vice President, Southern Wolfcamp Operations from August 2014 to August 2015, Senior Vice President, South Texas Operations from June 2013 to August 2014, Vice President, South Texas Operations from February 2013 to June 2013, Vice President, South Texas Asset Team from September 2012 to February 2013 and Vice President, Eagle Ford Asset Team from January 2010 to September 2012. Prior to his positions in South Texas, he was the Operations Manager in Alaska from January 2005 to January 2010. He previously held several other positions with the Company, including managing offshore, onshore and international projects. He began his career with a predecessor company, MESA, Inc. ("MESA"), in 1989. He has a Bachelor of Science degree in Mechanical Engineering from Texas Tech University and is a Registered Professional Engineer in Texas.

Kenneth H. Sheffield, Jr.

Mr. Sheffield was elected as Executive Vice President, Operations/Engineering/Facilities in May 2017. Mr. Sheffield has previously served the Company in a number of executive positions, including Executive Vice President, STAT (the Company's South Texas Asset Team), WAT (the Company's Western Asset Team) and Corporate Engineering from August 2015 to May 2017, Executive Vice President, South Texas Operations from August 2014 to August 2015, Senior Vice President, Operations and Engineering from June 2013 to August 2014, Vice President, Corporate Engineering from November 2011 to June 2013 and President of the Company's Alaska subsidiary from September 2002 to November 2011. Mr. Sheffield joined MESA in June 1982 and held a number of supervisory and technical positions with MESA in the areas of drilling, production, reservoir engineering and acquisitions until being promoted to Vice President Acquisitions & Development in 1996. He is a graduate of Texas A&M University with a Bachelor of Science degree in Petroleum Engineering.

William F. Hannes

Mr. Hannes was elected the Company's Senior Vice President, Special Projects in January 2017. Mr. Hannes had previously served the Company as Senior Vice President, Special Management Committee Advisor since August 2014, Executive Vice President, Southern Wolfcamp Operations from February 2013 until August 2014, Executive Vice President, South Texas Operations from February 2010 until February 2013, Executive Vice President, Business Development from December 2007 until February 2010, Executive Vice President, Worldwide Business Development from November 2005 until December 2007 and Vice President, Engineering and Development from September 2003 until November 2005. Mr. Hannes joined Parker & Parsley in July 1997 as Director of Business Development, and continued to serve the Company in this capacity after the Company's formation in August 1997 until he was promoted to Vice President - Engineering and Development in June 2001, which position he held until November 2005. Prior to joining Parker & Parsley, Mr. Hannes held engineering positions with Mobil Corporation and Superior Oil Company. Mr. Hannes earned his Bachelor of Science degree in Petroleum Engineering from Texas A&M University.

Frank E. Hopkins

Mr. Hopkins was elected the Company's Senior Vice President, Investor Relations in August 2011. Mr. Hopkins had previously held the position of Vice President, Investor Relations since joining the Company in February 2005. Before joining the Company, Mr. Hopkins was with Exxon Mobil Corporation where he served as General Manager, Strategic Planning for the Global Services Company, and as Deputy Manager, Investor Relations. He also served in various capacities with Mobil Corporation, including Manager, Investor Relations and Assistant Controller. Mr. Hopkins earned his Bachelor of Science degree in Business

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Administration from Penn State University and also participated in the executive education program at the Kellogg School of Management of Northwestern University.

Mark H. Kleinman

Mr. Kleinman was elected Senior Vice President and General Counsel in January 2014. He also held the positions of Corporate Secretary from June 2005 through August 2015, Vice President from May 2006 until January 2014 and Chief Compliance Officer from June 2005 until May 2013. Mr. Kleinman also served as Vice President and Secretary of the general partner of Pioneer Southwest from June 2007 until April 2008 and as its Vice President and Chief Compliance Officer from April 2008 through the Company's acquisition of Pioneer Southwest in December 2013. Mr. Kleinman earned a Bachelor of Arts degree in Government from the University of Texas and graduated, with honors, from the University of Texas School of Law.

Teresa A. Fairbrook

Ms. Fairbrook was elected the Company's Vice President and Chief Human Resources Officer in March 2016, prior to which she had served as Vice President, Human Resources since February 2013. She joined the Company in 1999, serving in a number of positions in the Human Resources Department. Prior to joining the Company, Ms. Fairbrook was in human resources at Dal-Tile Corporation in Dallas, Texas, where she held a variety of roles in employee relations, recruiting and benefits. Ms. Fairbrook received a Bachelor of Business Administration degree from St. Mary's University in San Antonio, Texas, with an emphasis in Human Resource Management, and is a Certified Compensation Professional.

Margaret M. Montemayor

Ms. Montemayor was elected the Company's Vice President and Chief Accounting Officer in March 2014. Ms. Montemayor had previously served the Company as Vice President and Corporate Controller since January 2014, Corporate Controller from April 2012 to December 2013 and Director of Technical Accounting and Financial Reporting from June 2010 to March 2012. Prior to joining the Company, Ms. Montemayor served as Manager at PricewaterhouseCoopers LLP since June 2006. Ms. Montemayor graduated from St. Mary's University in San Antonio, Texas with a Bachelor of Business Administration degree in Accounting and a Master of Business Administration and is a Certified Public Accountant.

Stephanie D. Stewart

Ms. Stewart joined the Company in June 2014 as Vice President and Chief Information Officer. Before joining the Company, she served as Vice President of E&P Data and Analytics at Devon Energy at the end of her 12-year tenure there. Prior to Devon, she worked in information technology at Williams Energy and BP Amoco. Ms. Stewart earned a Bachelor of Business Administration degree from the University of Oklahoma and her Executive MBA in Energy from the University of Oklahoma's Price College of Business.

Officers are generally elected by the Company's board of directors at its meeting on the day of each annual election of directors, with each such officer serving until a successor has been elected and qualified.

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PIONEER NATURAL RESOURCES COMPANY

PART II



ITEM 5.	MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

The Company's common stock is listed and traded on the NYSE under the symbol "PXD." The Company's board of directors (the "Board") declared dividends to the holders of the Company's common stock of $0.04 per share during each of the first and third quarters of the years ended December 31, 2017 and 2016. 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. In February 2018, the Board (i) declared a cash dividend of $0.16 per share on Pioneer’s outstanding common stock, payable April 12, 2018 to stockholders of record at the close of business on March 29, 2018 and (ii) approved a common stock repurchase program to offset the impact of dilution associated with annual employee stock awards. The stock repurchase program allows for up to $100 million of common stock to be repurchased during 2018.

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, 2017 and 2016:



	High		Low		Dividends Declared Per Share
Year ended December 31, 2017
Fourth quarter	$	174.59	$	140.31	$	—
Third quarter	$	166.29	$	125.46	$	0.04
Second quarter	$	192.93	$	153.42	$	—
First quarter	$	199.83	$	168.13	$	0.04
Year ended December 31, 2016
Fourth quarter	$	195.00	$	166.50	$	—
Third quarter	$	190.94	$	147.21	$	0.04
Second quarter	$	171.88	$	136.97	$	—
First quarter	$	145.87	$	103.50	$	0.04

On February 14, 2018, the last reported sales price of the Company's common stock, as reported in the NYSE composite transactions, was $179.50 per share.

As of February 14, 2018, the Company's common stock was held by 10,633 holders of record.

Purchases of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes the Company's purchases of its common stock during the three months ended December 31, 2017.



Period	Total Number of Shares Purchased (a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs	Approximate Dollar Amount of Shares that May Yet Be Purchased under Plans or Programs
October 2017	—	$	—	—	—
November 2017	—	$	—	—	—
December 2017	174	$	156.58	—	—
Total	174	$	156.58	—	$	—

_____________________


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

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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, 2017 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,
	2017		2016			2015			2014			2013
	(in millions, except per share data)
Statements of Operations Data:
Oil and gas revenues	$	3,518	$	2,418		$	2,178		$	3,599		$	3,088
Total revenues and other income (a)	$	5,455	$	3,382		$	4,561		$	4,954		$	3,658
Total costs and expenses (a)(b)	$	5,146	$	4,341		$	4,982		$	3,357		$	4,232
Income (loss) from continuing operations	$	833	$	(556	)	$	(266	)	$	1,041		$	(361	)
Loss from discontinued operations, net of tax (c)	$	—	$	—		$	(7	)	$	(111	)	$	(438	)
Net income (loss) attributable to common stockholders	$	833	$	(556	)	$	(273	)	$	930		$	(838	)
Income (loss) from continuing operations attributable to common stockholders per share:
Basic	$	4.86	$	(3.34	)	$	(1.79	)	$	7.17		$	(2.94	)
Diluted	$	4.85	$	(3.34	)	$	(1.79	)	$	7.15		$	(2.94	)
Net income (loss) attributable to common stockholders per share:
Basic	$	4.86	$	(3.34	)	$	(1.83