10-Q
Table of Contents

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549 
______________________________
FORM 10-Q 
______________________________
ý
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2016
or 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from  ________ to ________                     
Commission File Number: 1-13245
______________________________ 
PIONEER NATURAL RESOURCES COMPANY
(Exact name of Registrant as specified in its charter)
______________________________
Delaware
 
75-2702753
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
5205 N. O'Connor Blvd., Suite 200, Irving, Texas
 
75039
(Address of principal executive offices)
 
(Zip Code)
(972) 444-9001
(Registrant's telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report) 
______________________________
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 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
 
¨
 
 
 
 
Non-accelerated filer
 
o (Do not check if a smaller reporting company)
  
Smaller reporting company
 
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes   ¨    No  ý
Number of shares of Common Stock outstanding as of April 26, 2016                               163,556,616


Table of Contents

PIONEER NATURAL RESOURCES COMPANY
TABLE OF CONTENTS 
 
 
Page
 
 
 
 
 
 
Item 1.
 
 
 
 
 
Consolidated Balance Sheets as of March 31, 2016 and December 31, 2015
 
 
 
 
Consolidated Statements of Operations for the three months ended March 31, 2016 and 2015
 
 
 
 
Consolidated Statement of Equity for the three months ended March 31, 2016
 
 
 
 
Consolidated Statements of Cash Flows for the three months ended March 31, 2016 and 2015
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 2.
 
 
 
Item 4.
 
 
 
Item 6.
 
 
 
 

2

Table of Contents

PIONEER NATURAL RESOURCES COMPANY
Cautionary Statement Concerning Forward-Looking Statements
The information in this Quarterly Report on Form 10-Q (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 Pioneer Natural Resources Company ("Pioneer" or 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.
These risks and uncertainties include, among other things, volatility of commodity prices, product supply and demand, competition, the ability to obtain environmental and other permits and the timing thereof, other government regulation or action, the ability to obtain approvals from third parties and negotiate agreements with third parties on mutually acceptable terms, litigation, the costs and results of drilling and operations, availability of equipment, services, resources and personnel required to perform the Company's drilling and operating activities, access to and availability of transportation, processing, fractionation and refining facilities, Pioneer's ability to replace reserves, implement its business plans or complete its development activities as scheduled, access to and cost of capital, the financial strength of counterparties to Pioneer's credit facility and derivative contracts and the purchasers of Pioneer's oil, NGL and gas production, uncertainties about estimates of reserves and the ability to add proved reserves in the future, the assumptions underlying production forecasts, quality of technical data, environmental and weather risks, including the possible impacts of climate change, the risks associated with the ownership and operation of the Company's industrial sand mining and oilfield services businesses, and acts of war or terrorism. These and other risks are described in the Company's Annual Report on Form 10-K, this Report and other filings with the United States Securities and Exchange Commission. 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 than the anticipated results described in the forward-looking statements. See "Part I, Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations," "Part 1, Item 3. Quantitative and Qualitative Disclosures About Market Risk" and "Part II, Item 1A. Risk Factors" in this Report and "Part I, Item 1. Business — Competition, Markets and Regulations," "Part I, Item 1A. Risk Factors," "Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and "Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk" in the Company's Annual Report on Form 10-K for the year ended December 31, 2015 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.

3

Table of Contents

PIONEER NATURAL RESOURCES COMPANY
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.
"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 Service ("OPIS") in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.
"DD&A" means depletion, depreciation and amortization.
"GAAP" means accounting principles that are generally accepted in the United States of America.
"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.
"Mcf" means one thousand cubic feet and is a measure of gas volume.
"MMBtu" means one million Btus.
"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.
"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.
"Proved reserves" mean the quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons ("LKH") as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.
(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.
"U.S." means United States.
With respect to information on the working interest in wells, drilling locations and acreage, "net" wells, drilling locations and acres are determined by multiplying "gross" wells, drilling locations and acres by the Company's working interest in such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted herein represent gross wells, drilling locations or acres.
Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.

4

Table of Contents

PART I. FINANCIAL INFORMATION
Item 1.    Financial Statements
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in millions)
 
 
 
March 31,
2016
 
December 31,
2015
 
 
(Unaudited)
 
 
ASSETS
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
1,612

 
$
1,391

Short-term investments
 
893

 

Accounts receivable:
 
 
 
 
Trade, net
 
351

 
384

Due from affiliates
 

 
1

Income taxes receivable
 
3

 
43

Inventories
 
153

 
155

Prepaid expenses
 
20

 
17

Notes receivable
 
500

 
498

Derivatives
 
540

 
694

Other
 
9

 
11

Total current assets
 
4,081

 
3,194

Property, plant and equipment, at cost:
 
 
 
 
Oil and gas properties, using the successful efforts method of accounting:
 
 
 
 
Proved properties
 
17,123

 
16,631

Unproved properties
 
133

 
169

Accumulated depletion, depreciation and amortization
 
(7,118
)
 
(6,778
)
Total property, plant and equipment
 
10,138

 
10,022

Long-term investments
 
21

 

Goodwill
 
272

 
272

Other property and equipment, net
 
1,527

 
1,523

Derivatives
 
50

 
64

Other, net
 
82

 
79

 
 
$
16,171

 
$
15,154








The financial information included as of March 31, 2016 has been prepared by management
without audit by independent registered public accountants.
The accompanying notes are an integral part of these consolidated financial statements.


5

Table of Contents


PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS (continued)
(in millions, except share data)
 
 
 
March 31,
2016
 
December 31,
2015
 
 
(Unaudited)
 
 
LIABILITIES AND EQUITY
Current liabilities:
 
 
 
 
Accounts payable:
 
 
 
 
Trade
 
$
700

 
$
798

Due to affiliates
 
28

 
85

Interest payable
 
49

 
65

Income taxes payable
 
2

 
2

Current portion of long-term debt
 
936

 
448

Derivatives
 
2

 

Other
 
66

 
64

Total current liabilities
 
1,783

 
1,462

Long-term debt
 
2,724

 
3,207

Derivatives
 
6

 
1

Deferred income taxes
 
1,635

 
1,776

Other liabilities
 
328

 
333

Equity:
 
 
 
 
Common stock, $.01 par value; 500,000,000 shares authorized; 167,142,101 and 152,775,920 shares issued as of March 31, 2016 and December 31, 2015, respectively
 
2

 
2

Additional paid-in capital
 
7,884

 
6,267

Treasury stock at cost: 3,585,485 and 3,396,200 shares as of March 31, 2016 and December 31, 2015, respectively
 
(222
)
 
(199
)
Retained earnings
 
2,024

 
2,298

Total equity attributable to common stockholders
 
9,688

 
8,368

Noncontrolling interests in consolidated subsidiaries
 
7

 
7

Total equity
 
9,695

 
8,375

Commitments and contingencies
 


 


 
 
$
16,171

 
$
15,154








The financial information included as of March 31, 2016 has been prepared by management
without audit by independent registered public accountants.
The accompanying notes are an integral part of these consolidated financial statements.

6

Table of Contents

PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
(Unaudited) 
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Revenues and other income:
 
 
 
 
Oil and gas
 
$
409

 
$
517

Sales of purchased oil and gas
 
223

 
103

Interest and other
 
8

 
7

Derivative gains, net
 
43

 
241

Gain on disposition of assets, net
 
2

 
1

 
 
685

 
869

Costs and expenses:
 
 
 
 
Oil and gas production
 
156

 
180

Production and ad valorem taxes
 
29

 
39

Depletion, depreciation and amortization
 
353

 
310

Purchased oil and gas
 
243

 
108

Impairment of oil and gas properties
 
32

 
138

Exploration and abandonments
 
59

 
25

General and administrative
 
74

 
82

Accretion of discount on asset retirement obligations
 
5

 
3

Interest
 
55

 
46

Other
 
87

 
49

 
 
1,093

 
980

Loss from continuing operations before income taxes
 
(408
)
 
(111
)
Income tax benefit
 
141

 
37

Loss from continuing operations
 
(267
)
 
(74
)
Loss from discontinued operations, net of tax
 

 
(4
)
Net loss attributable to common stockholders
 
$
(267
)
 
$
(78
)
 
 
 
 
 
Basic and diluted earnings per share attributable to common stockholders:
 
 
 
 
Loss from continuing operations
 
$
(1.65
)
 
$
(0.50
)
Loss from discontinued operations
 

 
(0.02
)
Net loss
 
$
(1.65
)
 
$
(0.52
)
Weighted average shares outstanding:
 
 
 
 
 
 
 
 
 
Basic
 
162

 
149

Diluted
 
162

 
149

 
 
 
 
 
Dividends declared per share
 
$
0.04

 
$
0.04

 
 
 
 
 


The financial information included herein has been prepared by management
without audit by independent registered public accountants.
The accompanying notes are an integral part of these consolidated financial statements.

7

Table of Contents

PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENT OF EQUITY
(in millions, except share data and dividends per share)
(Unaudited)
 
 
 
 
 
Equity Attributable To Common Stockholders
 
 
 
 
 
 
Shares
Outstanding
 
Common
Stock
 
Additional
Paid-in
Capital
 
Treasury
Stock
 
Retained
Earnings
 
Noncontrolling
Interests
 
Total Equity
 
 
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Balance as of December 31, 2015
 
149,380

 
$
2

 
$
6,267

 
$
(199
)
 
$
2,298

 
$
7

 
$
8,375

Issuance of common stock
 
13,800

 

 
1,597

 

 


 

 
1,597

Dividends declared ($0.04 per share)
 

 

 

 

 
(7
)
 

 
(7
)
Purchases of treasury stock
 
(189
)
 

 

 
(23
)
 

 

 
(23
)
Tax provision related to stock-based compensation
 

 

 
(1
)
 

 

 

 
(1
)
Compensation costs:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Vested compensation awards, net
 
566

 

 

 

 

 

 

Compensation costs included in net loss
 

 

 
21

 

 

 

 
21

Net loss
 

 

 

 

 
(267
)
 

 
(267
)
Balance as of March 31, 2016
 
163,557

 
$
2

 
$
7,884

 
$
(222
)
 
$
2,024

 
$
7

 
$
9,695








The financial information included herein has been prepared by management
without audit by independent registered public accountants.
The accompanying notes are an integral part of these consolidated financial statements.

8

Table of Contents

PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(Unaudited)
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Cash flows from operating activities:
 
 
 
 
Net loss
 
$
(267
)
 
$
(78
)
Adjustments to reconcile net loss to net cash provided by operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
353

 
310

Impairment of oil and gas properties
 
32

 
138

Impairment of inventory and other property and equipment
 
4

 
6

Exploration expenses, including dry holes
 
40

 
5

Deferred income taxes
 
(141
)
 
(37
)
Gain on disposition of assets, net
 
(2
)
 
(1
)
Accretion of discount on asset retirement obligations
 
5

 
3

Discontinued operations
 

 
(3
)
Interest expense
 
5

 
5

Derivative related activity
 
175

 
(35
)
Amortization of stock-based compensation
 
21

 
22

Other
 
18

 
(1
)
Change in operating assets and liabilities:
 
 
 
 
Accounts receivable, net
 
33

 
96

Income taxes receivable
 
40

 
1

Inventories
 

 
(34
)
Prepaid expenses
 
(3
)
 
(5
)
Other current assets
 

 
(7
)
Accounts payable
 
(169
)
 
(250
)
Interest payable
 
(16
)
 
(20
)
Other current liabilities
 
(17
)
 
(11
)
Net cash provided by operating activities
 
111

 
104

Cash flows from investing activities:
 
 
 
 
Proceeds from disposition of assets, net of cash sold
 
1

 
4

Purchase of investment securities
 
(914
)
 

Additions to oil and gas properties
 
(471
)
 
(658
)
Additions to other assets and other property and equipment, net
 
(79
)
 
(63
)
Net cash used in investing activities
 
(1,463
)
 
(717
)
Cash flows from financing activities:
 
 
 
 
Proceeds from issuance of common stock, net of issuance costs
 
1,597

 

Purchases of treasury stock
 
(23
)
 
(30
)
Tax (provision) benefits related to stock-based compensation
 
(1
)
 
1

Net cash provided by (used in) financing activities
 
1,573

 
(29
)
Net increase (decrease) in cash and cash equivalents
 
221

 
(642
)
Cash and cash equivalents, beginning of period
 
1,391

 
1,025

Cash and cash equivalents, end of period
 
$
1,612

 
$
383

  


The financial information included herein has been prepared by management
without audit by independent registered public accountants.
  
The accompanying notes are an integral part of these consolidated financial statements.

9

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)


NOTE A. Organization and Nature of Operations
Pioneer Natural Resources Company ("Pioneer" or the "Company") is a Delaware corporation whose common stock is listed and traded on the New York Stock Exchange. The Company is a large independent oil and gas exploration and production company operating in the United States, with operations primarily in the Permian Basin in West Texas, the Eagle Ford Shale play in South Texas, the Raton field in southeast Colorado and the West Panhandle field in the Texas Panhandle.
NOTE B. Basis of Presentation
Presentation. In the opinion of management, the consolidated financial statements of the Company as of March 31, 2016 and for the three months ended March 31, 2016 and 2015 include all adjustments and accruals, consisting only of normal, recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year.
Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles in the United States ("GAAP") have been condensed in or omitted from this report pursuant to the rules and regulations of the United States Securities and Exchange Commission (the "SEC"). These consolidated financial statements should be read together with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2015.
Certain reclassifications have been made to the 2015 financial statement and footnote amounts in order to conform to the 2016 presentation.
Restructuring. In February 2016, the Company announced plans to restructure its pressure pumping operations in South Texas, including relocating its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. In connection therewith, the Company offered severance to certain employees and relocated a number of other employees from its South Texas locations to its operations in the Permian Basin. This initiative is expected to be substantially complete by the end of the second quarter of 2016.
In connection therewith, during the three months ended March 31, 2016, the Company recognized $3 million of restructuring charges in other expense in the accompanying consolidated statements of operations. The Company estimates that it will incur an additional $2 million of restructuring charges related thereto during the remainder of 2016. The aggregate $5 million of estimated restructuring charges includes approximately $3 million in cash employee severance costs and $2 million in employee relocation and other costs.
In May 2015, the Company announced plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pressure pumping operations. The restructuring plan was substantially complete as of December 31, 2015.     
As of March 31, 2016, the Company had $5 million of restructuring liabilities recorded in other current and noncurrent liabilities in the accompanying consolidated balance sheet, primarily related to employee severance costs associated with the South Texas restructuring and future lease obligations associated with its Denver, Colorado office.
Issuance of common stock. In the first quarter of 2016, the Company issued 13.8 million shares of common stock and received cash proceeds of $1.6 billion, net of associated underwriting and offering expenses.
New accounting pronouncements. In March 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2016-09, "Improvements to Employee Share-Based Payment Accounting." ASU 2016-09 simplifies several aspects of the accounting for share-based payment transactions, including accounting for income taxes, forfeitures and statutory tax withholding requirements, as well as certain classification changes in the statement of cash flows. This update is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. Early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.
In February 2016, FASB issued ASU 2016-02, "Leases." ASU 2016-02 requires the recognition of lease assets and lease liabilities by lessees for those leases currently classified as operating leases and makes certain changes to the way lease expenses

10

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

are accounted for. This update is effective for fiscal years beginning after December 15, 2018 and for interim periods beginning the following year. This update should be applied using a modified retrospective approach, and early adoption is permitted. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.
In January 2016, the FASB issued ASU 2016-01, "Recognition and Measurement of Financial Assets and Financial Liabilities." ASU 2016-01 changes certain guidance related to the recognition, measurement, presentation and disclosure of financial instruments. This update is effective for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is not permitted for the majority of the update, but is permitted for two of its provisions. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements.
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. In August 2015, the FASB issued ASU 2015-14, which defers the effective date of ASU 2014-09 for one year to annual reports beginning after December 15, 2017. Early adoption is permitted for fiscal years beginning after December 15, 2016. Entities have the option of using either a full retrospective or modified approach to adopt the new standards. The Company is evaluating the new guidance and has not determined the impact this standard may have on its consolidated financial statements or decided upon its method of adoption.
NOTE C. Divestitures
EFS Midstream. In July 2015, the Company closed on the sale of its 50.1 percent equity interest in EFS Midstream LLC ("EFS Midstream") to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion, of which $530 million was received at closing and the remaining approximately $500 million will be received in July 2016. The amount to be received in July 2016, less imputed interest, is included in notes receivable in the accompanying consolidated balance sheets.
NOTE D. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:
Level 1 – quoted prices for identical assets or liabilities in active markets.
Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.
Level 3 – unobservable inputs for the asset or liability.

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PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in its entirety.
 
The following table presents the Company's assets and liabilities that are measured at fair value on a recurring basis as of March 31, 2016 for each of the fair value hierarchy levels: 
 
 
Fair Value Measurement at March 31, 2016 Using
 
 
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Fair Value at March 31, 2016
 
 
(in millions)
Assets:
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
590

 
$

 
$
590

Deferred compensation plan assets
 
75

 

 

 
75

Total assets
 
75

 
590

 

 
665

Liabilities:
 
 
 
 
 
 
 
 
Commodity derivatives
 

 
6

 

 
6

Interest rate derivatives
 

 
2

 

 
2

Total liabilities
 

 
8

 

 
8

Total recurring fair value measurements
 
$
75

 
$
582

 
$

 
$
657

Commodity derivatives. The Company's commodity derivatives represent oil, natural gas liquids ("NGL") and gas swap contracts and collar contracts with short puts. The asset and liability measurements for the Company's commodity derivative contracts represent Level 2 inputs in the hierarchy. The Company utilizes discounted cash flow and option-pricing models for valuing its commodity derivatives.
The asset and liability values attributable to the Company's commodity derivatives were determined based on inputs that include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar contracts with short puts, which is based on active and independent market-quoted volatility factors.
Deferred compensation plan assets. The Company's deferred compensation plan assets represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are measured based on observable prices on major exchanges. As of March 31, 2016, the significant inputs to these asset values represented Level 1 independent active exchange market price inputs.
Interest rate derivatives. The Company's interest rate derivative liabilities represent interest rate swap contracts. The Company utilizes discounted cash flow models for valuing its interest rate derivatives. The net derivative values attributable to the Company's interest rate derivative contracts are based on (i) the contracted notional amounts, (ii) forward active market-quoted London Interbank Offered Rate ("LIBOR") and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's interest rate derivative fair value measurements represent Level 2 inputs in the hierarchy.
Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets and liabilities are measured at fair value on a nonrecurring basis. These assets and liabilities are not measured at fair value on an ongoing basis, but are subject to fair value adjustments in certain circumstances. These assets and liabilities can include inventory, proved and unproved oil and gas properties and other long-lived assets that are written down to fair value when they are impaired or held for sale. During the three months ended March 31, 2016, the Company recorded charges in other expense in the Company's accompanying consolidated statements of operations of $4 million to reduce the carrying value of certain inventory and other property and equipment to fair value.

12

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

Proved oil and gas properties. As a result of the Company's proved property impairment assessments, the Company recognized pretax, noncash impairment charges to reduce the carrying values of (i) its West Panhandle field during the three months ended March 31, 2016 and (ii) the Eagle Ford Shale field, the West Panhandle field and South Texas - Other field during the year ended December 31, 2015 to their estimated fair values.
The Company calculated the fair values of the West Panhandle field, the Eagle Ford Shale field and South Texas - Other field using a discounted future cash flow model. Significant Level 3 assumptions associated with the calculations included management's longer-term commodity price outlooks ("Management's Price Outlooks") and management's outlooks for (i) production costs, (ii) capital expenditures, (iii) production and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party longer-term commodity futures price outlooks as of each measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.
The following table presents the fair value and fair value adjustments (in millions) for the Company's 2016 and 2015 proved property impairments, as well as the average oil price per barrel ("Bbl") and gas price per British thermal unit ("MMBtu") utilized in respective Management's Price Outlooks:
 
 
 
 
 
 
 
 
Management's Price Outlooks
 
 
Impairment Date
 
Fair Value
 
Fair Value Adjustment
 
Oil
 
Gas
West Panhandle
 
March 2016
 
$
33

 
$
(32
)
 
$
49.77

 
$
3.24

South Texas - Eagle Ford Shale
 
December 2015
 
$
483

 
$
(846
)
 
$
52.82

 
$
3.34

South Texas - Other
 
September 2015
 
$
88

 
$
(72
)
 
$
57.41

 
$
3.46

West Panhandle
 
March 2015
 
$
61

 
$
(138
)
 
$
65.02

 
$
3.83

It is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or other properties may change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future cash flows are (i) future adjustments, both positive and negative, to proved and risk-adjusted probable and possible oil and gas reserves, (ii) results of future drilling activities, (iii) Management's Price Outlooks and (iv) increases or decreases in production and capital costs associated with these fields.
Unproved oil and gas properties. During the three months ended March 31, 2016, the Company recorded an impairment charge of $32 million to write-off the carrying value of its unproved royalty acreage in Alaska (reported in exploration and abandonments in the accompanying consolidated statements of operations) as a result of the operator curtailing operations in the area and Management's Price Outlooks.
Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the accompanying consolidated balance sheets as of March 31, 2016 and December 31, 2015 are as follows: 

 
 
March 31, 2016
 
December 31, 2015
 
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
 
(in millions)
Commercial paper, corporate bonds and time deposits
 
$
1,369

 
$
1,369

 
$
275

 
$
275

Current portion of long-term debt
 
$
936

 
$
962

 
$
448

 
$
462

Long-term debt
 
$
2,724

 
$
2,877

 
$
3,207

 
$
3,206

Commercial paper, corporate bonds and time deposits. Periodically, the Company invests in commercial paper and corporate bonds with investment grade rated entities. The Company also periodically enters into time deposits with financial institutions. The investments are carried at amortized cost, which approximates fair value, and classified as held-to-maturity as the Company has the intent and ability to hold them until they mature. The net carrying value of held-to-maturity investments is adjusted for amortization of premiums and accretion of discounts to maturity over the life of the investments. Income related to these investments

13

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

is recorded in interest and other income in the Company's consolidated statement of operations. The investments represent Level 2 inputs in the hierarchy. Commercial paper, corporate bonds and time deposits are included in cash and cash equivalents, short-term investments or long-term investments in the accompanying consolidated balance sheets based on their maturity dates. The following table provides the components of the Company's cash and cash equivalents and investments as of March 31, 2016:
 
 
As of March 31, 2016
Consolidated Balance Sheet Location
 
Cash
 
Commercial Paper
 
Corporate Bonds
 
Time
Deposits
 
Total
 
 
(in millions)
Cash and cash equivalents
 
$
1,157

 
$
455

 
$

 
$

 
$
1,612

Short-term investments
 

 
645

 
58

 
190

 
893

Long-term investments
 

 

 
21

 

 
21

 
 
$
1,157

 
$
1,100

 
$
79

 
$
190

 
$
2,526

Debt obligations. Current and noncurrent long-term debt includes the Company's credit facility and the Company's senior notes. The fair value of the Company's debt obligations is determined utilizing inputs that are Level 2 measurements in the fair value hierarchy. The fair value of the Company's credit facility is calculated using a discounted cash flow model based on (i) forecasted contractual interest and fee payments, (ii) forward active market-quoted United States Treasury Bill rates and (iii) the applicable credit-adjustments. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.
The Company has other financial instruments consisting primarily of accounts receivables, prepaid expenses, notes receivable, payables and other current assets and liabilities that approximate fair value due to the nature of the instrument and their relatively short maturities. Non-financial assets and liabilities initially measured at fair value include assets acquired and liabilities assumed in a business combination, goodwill and asset retirement obligations.
NOTE E. Derivative Financial Instruments
The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness.
Oil production derivative activities. All material physical sales contracts governing the Company's oil production are tied directly to, or are highly correlated with, New York Mercantile Exchange ("NYMEX") West Texas Intermediate ("WTI") oil prices. The Company uses derivative contracts to manage oil price volatility and basis swap contracts to reduce basis risk between NYMEX prices and the actual index prices at which the oil is sold.

14

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of March 31, 2016 and the weighted average oil prices for those contracts: 
 
2016
 
 
Year Ending December 31,
 
Second Quarter
 
Third Quarter
 
Fourth Quarter
 
 
2017
Swap contracts:
 
 
 
 
 
 
 
 
Volume (Bbl)
60,000

 

 

 
 

Price per Bbl
$
53.08

 
$

 
$

 
 
$

Collar contracts with short puts:
 
 
 
 
 
 
 
 
Volume (Bbl) (a)
43,000

 
112,000

 
112,000

 
 
72,000

Price per Bbl:
 
 
 
 
 
 
 
 
Ceiling
$
73.26

 
$
75.94

 
$
75.94

 
 
$
61.16

Floor
$
63.29

 
$
65.41

 
$
65.41

 
 
$
50.97

Short put
$
40.00

 
$
47.03

 
$
47.03

 
 
$
42.07

____________________
(a)
Subsequent to March 31, 2016, the Company entered into additional oil collar contracts with short puts for 1,000 Bbls per day of 2017 production with a ceiling price of $57.50 per Bbl, a floor price of $47.50 per Bbl and a short put price of $40.00 per Bbl.
NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway NGL component product prices. The Company uses derivative contracts to manage the NGL component price volatility.
The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of March 31, 2016 and the weighted average NGL prices for those contracts: 
 
2016
 
 
Second Quarter
 
Third Quarter
 
Fourth Quarter
 
Propane swap contracts (a):
 
 
 
 
 
 
Volume (Bbl)
7,500

 
7,500

 
7,500

 
Price per Bbl
$
21.57

 
$
21.57

 
$
21.57

 
 ____________________
(a)
Represent derivative contracts that reduce the price volatility of propane forecasted for sale by the Company at Mont Belvieu, Texas and Conway, Kansas-posted prices.
Subsequent to March 31, 2016, the Company entered into (i) 3,000 Bbls per day of 2017 ethane collar contracts with a ceiling price of $11.83 per Bbl and a floor price of $8.68 per Bbl and (ii) a Mont Belvieu ethane basis swap that fixes the basis differential on a NYMEX Henry Hub ("HH") MMBtu equivalent basis. The Company will receive the HH price plus $0.91 per MMBtu on 2,768 MMBtu per day (equivalent to 1,000 Bbls per day of ethane) for May 2016 through December 2016.
Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to HH gas prices or regional index prices where the gas is sold. The Company uses derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and the actual index prices at which the gas is sold.

15

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of March 31, 2016 and the weighted average gas prices for those contracts: 
 
2016
 
 
Year Ending December 31,
 
Second Quarter
 
Third Quarter
 
Fourth Quarter
 
 
2017
Swap contracts:
 
 
 
 
 
 
 
 
Volume (MMBtu)
70,000

 
70,000

 
70,000

 
 

Price per MMBtu
$
4.06

 
$
4.06

 
$
4.06

 
 
$

Collar contracts with short puts:
 
 
 
 
 
 
 
 
Volume (MMBtu) (a)
180,000

 
180,000

 
180,000

 
 
80,000

Price per MMBtu:
 
 
 
 
 
 
 
 
Ceiling
$
4.01

 
$
4.01

 
$
4.01

 
 
$
3.15

Floor
$
3.24

 
$
3.24

 
$
3.24

 
 
$
2.75

Short put
$
2.78

 
$
2.78

 
$
2.78

 
 
$
2.35

Basis swap contracts:
 
 
 
 
 
 
 
 
Gulf Coast index swap volume (b)
10,000

 
10,000

 
10,000

 
 

Price differential ($/MMBtu)
$

 
$

 
$

 
 
$

Mid-Continent index swap volume (b)
15,000

 
15,000

 
15,000

 
 
45,000

Price differential ($/MMBtu)
$
(0.32
)
 
$
(0.32
)
 
$
(0.32
)
 
 
$
(0.32
)
Permian Basin index swap volume (c)

 

 
34,946

 
 
9,863

Price differential ($/MMBtu)
$

 
$

 
$
0.41

 
 
$
0.37

____________________
(a)
Subsequent to March 31, 2016, the Company entered into additional gas collar contracts with short puts for 50,000 MMBtu per day of 2018 production with a ceiling price of $3.40 per MMBtu, a floor price of $2.75 per MMBtu and a short put price of $2.25 per MMBtu.
(b)
Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast and Mid-Continent gas, respectively, and the HH index price used in gas swap and collar contracts with short puts.
(c)
Represent swaps that fix the basis differentials between Permian Basin index prices and southern California index prices for Permian Basin gas forecasted for sale in southern California.
Marketing and basis derivative activities. Periodically, the Company enters into buy and sell marketing arrangements to fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate price risk. As of March 31, 2016, the Company did not have any marketing derivatives outstanding.
Interest rate derivative activities. As of March 31, 2016, the Company was a party to interest rate derivative contracts whereby the Company will receive the three-month LIBOR rate for the 10-year period from December 2017 to December 2027 in exchange for paying a weighted average fixed interest rate of 1.98 percent on a notional amount of $200 million on December 15, 2017.
Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge derivatives and therefore all changes in the fair values of its derivative contracts are recognized as gains or losses in the earnings of the periods in which they occur. The Company classifies the fair value amounts of derivative assets and liabilities as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by commodity and counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.

16

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

The aggregate fair value of the Company's derivative instruments reported in the accompanying consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following:
 
Fair Value of Derivative Instruments as of March 31, 2016
Type
 
Consolidated Balance Sheet
Location
 
Fair
Value
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Fair Value Presented in the Consolidated Balance Sheet
 
 
 
 
(in millions)
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Asset Derivatives:
 
 
 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
540

 
$

 
$
540

Commodity price derivatives
 
Derivatives - noncurrent
 
$
54

 
$
(4
)
 
50

 
 
 
 
 
 
 
 
$
590

Liability Derivatives:
 

 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
2

 
$

 
$
2

Commodity price derivatives
 
Derivatives - noncurrent
 
$
8

 
$
(4
)
 
4

Interest rate derivatives
 
Derivatives - noncurrent
 
$
2

 
$

 
2

 
 
 
 
 
 
 
 
$
8


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

 
$
(1
)
 
$
694

Commodity price derivatives
 
Derivatives - noncurrent
 
$
64

 
$

 
64

 
 
 
 
 
 
 
 
$
758

Liability Derivatives:
 
 
 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
1

 
$
(1
)
 
$

Commodity price derivatives
 
Derivatives - noncurrent
 
$
1

 
$

 
1

 
 
 
 
 
 
 
 
$
1


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


17

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

The following table details the location of gains and losses recognized on the Company's derivative contracts in the accompanying consolidated statements of operations:
 
 
 
 
 
Derivatives Not Designated as Hedging
 
Location of Gain / (Loss) Recognized in
 
Three Months Ended
March 31,
Instruments
 
Earnings on Derivatives
 
2016
 
2015
 
 
 
 
(in millions)
Commodity price derivatives
 
Derivative gains, net
 
$
45

 
$
251

Interest rate derivatives
 
Derivative gains, net
 
(2
)
 
(10
)
Total
 
$
43

 
$
241

NOTE F. Exploratory Costs
The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the impaired costs are charged to exploration and abandonments expense.
The following table reflects the Company's capitalized exploratory well and project activity during the three months ended March 31, 2016:
 
Three Months Ended March 31, 2016
 
(in millions)
Beginning capitalized exploratory costs
$
306

Additions to exploratory costs pending the determination of proved reserves
350

Reclassification due to determination of proved reserves
(294
)
Exploratory well costs charged to exploration expense
(1
)
Ending capitalized exploratory costs
$
361

The following table provides an aging, as of March 31, 2016 and December 31, 2015 of capitalized exploratory costs and the number of projects for which exploratory well costs have been capitalized for a period greater than one year, based on the date drilling was completed:
 
March 31, 2016
 
December 31, 2015
 
(in millions, except well counts)
Capitalized exploratory well costs that have been suspended:
 
 
 
One year or less
$
345

 
$
303

More than one year
16

 
3

 
$
361

 
$
306

Number of projects with exploratory well costs that have been suspended for a period greater than one year
3

 
1

The three wells that were suspended for a period greater than one year as of March 31, 2016, which includes the project suspended as of December 31, 2015, were scheduled to be completed in the second quarter of 2016.
NOTE G. Long-term Debt
Credit facility. The Company's long-term debt consists of senior notes, a revolving corporate credit facility (the "Credit Facility") and the effects of issuance costs, issuance discounts and net deferred fair value hedge losses. The Credit Facility is maintained with a syndicate of financial institutions and has aggregate loan commitments of $1.5 billion that expire in August 2020. As of March 31, 2016, the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants.

18

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

Senior notes. The Company's 5.875% senior notes (the "5.875% Senior Notes") and 6.65% senior notes (the "6.65% Senior Notes"), with outstanding debt principal balances of $455 million and $485 million, respectively, are due to mature in July 2016 and March 2017, respectively. The Company intends to fund the payments due at maturity of the 5.875% Senior Notes and 6.65% Senior Notes with cash on hand. As such, the 5.875% Senior Notes and 6.65% Senior Notes are classified as current in the accompanying consolidated balance sheets.
NOTE H. Incentive Plans
Stock-based compensation
For the three months ended March 31, 2016, the Company recorded $25 million of stock-based compensation expense for all plans, as compared to $29 million for the same period of 2015. As of March 31, 2016, there was $176 million of unrecognized compensation expense related to unvested share-based compensation plan awards, including $38 million attributable to stock-based awards that are expected to be settled on their vesting date in cash, rather than in equity shares ("Liability Awards"). The unrecognized compensation expense will be recognized over the remaining vesting periods of the awards, which is a period of less than three years on a weighted average basis. As of March 31, 2016 and December 31, 2015, accounts payable – due to affiliates included $4 million and $16 million, respectively, of liabilities attributable to Liability Awards.
The following table summarizes the activity that occurred during the three months ended March 31, 2016 for each type of share-based incentive award issued by Pioneer: 
 
 
Restricted
Stock Equity
Awards
 
Restricted
Stock Liability
Awards
 
Performance
Units
 
Stock
Options
Outstanding as of December 31, 2015
 
1,081,650

 
271,031

 
148,547

 
199,058

Awards granted
 
474,894

 
175,988

 
104,114

 

Awards vested
 
(425,587
)
 
(133,814
)
 
(4,379
)
 

Awards forfeited
 
(12,981
)
 
(1,280
)
 
(4,821
)
 

Outstanding as of March 31, 2016
 
1,117,976

 
311,925

 
243,461

 
199,058

NOTE I. Asset Retirement Obligations
The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related facilities. The following table summarizes the Company's asset retirement obligation activity during the three months ended March 31, 2016 and 2015: 
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
 
 
(in millions)
Beginning asset retirement obligations
 
$
285

 
$
189

New wells placed on production
 

 
1

Liabilities settled
 
(5
)
 
(5
)
Accretion of discount
 
5

 
3

Ending asset retirement obligations
 
$
285

 
$
188

The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and other liabilities, respectively, in the accompanying consolidated balance sheets. As of March 31, 2016, the current portion of the Company's asset retirement obligations was $43 million, as compared to $40 million at December 31, 2015.
NOTE J. Commitments and Contingencies
The Company is a party to 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 such proceedings and

19

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)



claims will not have a material adverse effect on the Company's financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company does not believe these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.
NOTE K. Interest and Other Income
The following table provides the components of the Company's interest and other income for the three months ended March 31, 2016 and 2015:
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
 
 
(in millions)
Interest income
 
$
4

 
$

Deferred compensation plan income
 
2

 
3

Equity interest in income of EFS Midstream (a)
 

 
2

Other income
 
2

 
2

Total interest and other income
 
$
8

 
$
7

 ____________________
(a)
The Company accounted for its investment in EFS Midstream prior to its sale in July 2015 using the equity method. EFS Midstream provided gathering, treating and transportation services for the Company. See Note C for additional information on the Company's sale of EFS Midstream.

20

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)



 NOTE L. Other Expense
The following table provides the components of the Company's other expense for the three months ended March 31, 2016 and 2015:
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
 
 
(in millions)
Transportation commitment charges (a)
 
$
24

 
$
14

Idle drilling and well service equipment charges (b)
 
21

 
23

Terminated drilling rig charges (c)
 
15

 

Loss from vertical integration services (d)
 
13

 
1

Restructuring charges (e)
 
3

 

Impairment of inventory and other property and equipment (f)
 
4

 
6

Other
 
7

 
5

Total other expense
 
$
87

 
$
49

 ____________________
(a)
Primarily represents firm transportation payments on excess pipeline capacity commitments.
(b)
Primarily represents expenses attributable to idle drilling rig fees, which are not chargeable to joint operations.
(c)
Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.
(d)
Loss from vertical integration services primarily represents net margins (attributable to third party working interest owners) that result from Company-provided fracture stimulation and service operations, which are ancillary to and supportive of the Company's oil and gas joint operating activities, and do not represent intercompany transactions. For the three months ended March 31, 2016, these vertical integration net margins included $69 million of revenues and $82 million of costs and expenses. For the same period in 2015, these vertical integration net margins included $111 million of revenues and $112 million of costs and expenses.
(e)
Represents costs associated with the Company's restructuring of its pressure pumping operations in South Texas. See Note B for additional information on the restructuring charges.
(f)
Primarily represents charges to reduce excess material and supplies inventories to their market values. See Note D for additional information on the fair value of materials and supplies inventory.
NOTE M. Income Taxes
The Company's income tax benefit attributable to income from continuing operations consisted of the following for the three months ended March 31, 2016 and 2015:
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
 
 
(in millions)
Deferred tax benefit
 
$
141

 
$
37

For the three months ended March 31, 2016, the Company's effective tax rate, excluding income attributable to noncontrolling interests, was 35 percent, as compared to an effective rate of 33 percent for the same period in 2015. The Company's effective tax rate for the three months ended March 31, 2015 differed from the U.S. statutory rate of 35 percent primarily due to state income tax apportionments and nondeductible expenses. The Company has no unrecognized tax benefits as of March 31, 2016.
The Company files income tax returns in the U.S. federal and various state and foreign jurisdictions. The Internal Revenue Service has closed examinations of the 2013 and prior tax years and, with few exceptions, the Company believes that it is no longer subject to examinations by state and foreign tax authorities for years before 2010. As of March 31, 2016, no adjustments had been proposed in any jurisdiction that would have a significant effect on the Company's liquidity, future results of operations or financial position.

21

Table of Contents
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2016
(Unaudited)

NOTE N. Net Loss Per Share
The following table reconciles the Company's loss from continuing operations to basic and diluted net loss attributable to common stockholders for the three months ended March 31, 2016 and 2015:
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
 
 
(in millions)
Basic and diluted loss from continuing operations
 
$
(267
)
 
$
(74
)
Basic and diluted loss from discontinued operations
 
$

 
$
(4
)
Basic and diluted net loss attributable to common stockholders
 
$
(267
)
 
$
(78
)
Basic and diluted weighted average common shares outstanding were 162 million for the three months ended March 31, 2016 and 149 million for the three months ended March 31, 2015.



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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations
Financial and Operating Performance
The Company's financial and operating performance for the first quarter of 2016 included the following highlights:
Net loss attributable to common stockholders for the first quarter of 2016 was $267 million ($1.65 per diluted share), as compared to net loss of $78 million ($0.52 per diluted share) for the first quarter of 2015. The primary components of the increase in the net loss attributable to common stockholders include:
a $198 million decrease in net derivative gains, primarily as a result of changes in forward commodity prices and the Company's portfolio of derivatives;
a $108 million decrease in oil and gas revenues as a result of a 32 percent decrease in the average commodity prices per BOE, partially offset by a 14 percent increase in sales volumes;
a $43 million increase in DD&A expense, primarily attributable to the 14 percent increase in sales volumes and reductions in proved reserves as a result of the decline in commodity prices, partially offset by impairments of proved properties during 2015, which reduced the carrying value of the Company's oil and gas properties;
a $38 million increase in other expense, primarily related to terminated rig contract charges, increased unused firm transportation costs and restructuring charges;
a $34 million increase in exploration and abandonments expense, primarily due to the write-off of the Company's overriding royalty interest in the Nuna prospect in Alaska; and
a $15 million decrease in net margins attributable to purchases and sales of oil and gas used to fulfill transportation commitments; partially offset by
a $106 million reduction in noncash impairment charges related to the Company's West Panhandle field;
a $104 million increase in the Company's income tax benefit as a result of the Company's increase in loss from continuing operations before taxes; and
a $34 million decrease in total oil and gas production costs and production and ad valorem taxes, primarily due to the Company's cost saving initiatives and the decline in commodity prices.
During the first quarter of 2016, average daily sales volumes from continuing operations increased by 14 percent to 221,809 BOEPD, as compared to 193,823 BOEPD during the first quarter of 2015. The increase in first quarter 2016 average daily sales volumes, as compared to the first quarter of 2015, is primarily due to the Company's successful Spraberry/Wolfcamp horizontal drilling program.
Average oil, NGL and gas prices decreased during the first quarter of 2016 to $28.09 per Bbl, $10.33 per Bbl and $1.79 per Mcf, respectively, as compared to $43.02 per Bbl, $15.00 per Bbl and $2.70 per Mcf, respectively, in the first quarter of 2015.
Net cash provided by operating activities increased to $111 million for the three months ended March 31, 2016, as compared to $104 million for the three months ended March 31, 2015. The $7 million increase in net cash provided by operating activities is primarily due to reductions in operating costs and funds used to satisfy working capital obligations, partially offset by decreases in the Company's oil and gas revenues for the three months ended March 31, 2016 as a result of declines in commodity prices.
Issuance of 13.8 million shares of common stock during the first quarter of 2016 for net cash proceeds of $1.6 billion.
As of March 31, 2016, the Company's net debt to book capitalization decreased to 10 percent, as compared to 21 percent at December 31, 2015, primarily due to the Company's issuance of common stock during the first quarter of 2016.
Recent Developments
Commodity prices. North American and worldwide oil, NGL and gas prices remain under pressure given the current oversupply of such commodities. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and oil production increases by certain other countries, including Russia and Saudi Arabia, as part of an effort to retain market share combined with only modest demand growth in the United States and less-than-expected demand in other parts of the world, particularly in Europe and China. Although there has been a dramatic decrease in drilling activity in the industry, oil and NGL storage levels in the United States remain at historically high levels. Until supply and demand balance and the overhang in storage levels begins to decline, prices are expected to remain under pressure. In addition, the lifting of economic sanctions on Iran has resulted in increasing supplies of oil from Iran, adding further downward

23

PIONEER NATURAL RESOURCES COMPANY

pressure to oil prices. The reduced demand for drilling rigs, fracture-stimulation services and oilfield supplies during 2015 and thus far into 2016, has led to a decline of these costs. However, despite these cost savings, the Company experienced a significant deterioration in its operating margins during 2015, which have further deteriorated in 2016. The duration and magnitude of the commodity price declines and the timing and amount of cost reductions cannot be accurately predicted. However, the Company does expect adverse charges associated with the decline in commodity prices, including (i) stacked rig charges, (ii) charges associated with excess firm gathering and transportation commitments and (iii) increased depletion, depreciation and amortization expense due to expected declines in the trailing twelve month average oil and gas prices, resulting in reductions in proved reserves as a result of shortening the economic productive lives of the Company's producing wells, partially offset by reserve additions as a results of successful drilling.
Low price environment initiatives. Based on the Company's outlook for continuing weak oil prices, the Company is in the process of reducing its Company-wide horizontal drilling activity from 24 rigs at year-end 2015 to 12 rigs by the middle of 2016. The Company currently has 14 horizontal drilling rigs running, all of which are in the Permian Basin. The Company's capital expenditures budget for 2016 is expected to be $2.0 billion, including $1.85 billion for drilling and completions (includes tank batteries, salt water disposal facilities and gas processing facilities) and $150 million for vertical integration, systems upgrades and field facilities.
As a result of the reduction in drilling activities, the Company will continue to incur stacked drilling rig charges and charges associated with excess firm gathering and transportation commitments until commodity prices improve, allowing the Company to increase its drilling activities, or the contractual obligations expire. Further, an extended commodity price decline could adversely affect the amount of oil, NGLs and gas that the Company can economically produce, which could result in the Company having to make further downward adjustments to its estimated proved reserves. Reductions in estimated proved reserves could increase the amount of depletion, depreciation and amortization expense the Company recognizes as a result of shortening the economic productive lives of the Company's producing wells. It is also possible that the Company's estimates of production or other economic factors could change to such an extent that the Company may be required to impair, as a noncash charge to earnings, the carrying value of the Company's oil and gas properties. The Company performs impairment tests on proved oil and gas properties whenever events or changes in circumstances indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of the Company's oil and gas properties, the carrying value may not be recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their fair value.
In conjunction with its decision to no longer run any drilling rigs in the Eagle Ford Shale play until commodity prices improve, the Company relocated its two Eagle Ford Shale pressure pumping fleets to the Spraberry/Wolfcamp area. This initiative is expected to be substantially completed by the end of the second quarter of 2016. In connection therewith, during the three months ended March 31, 2016, the Company recognized $3 million of restructuring charges in other expense in the accompanying consolidated statements of operations. The Company estimates that it will incur an additional $2 million of restructuring charges related thereto during the remainder of 2016.

 Second Quarter 2016 Outlook
Based on current estimates, the Company expects the following operating and financial results from continuing operations for the quarter ending June 30, 2016:
Production is forecasted to average 224,000 to 229,000 BOEPD.
Production costs (including production and ad valorem taxes and transportation costs) are expected to average $9.00 to $11.00 per BOE based on current NYMEX strip commodity prices. DD&A expense is expected to average $17.50 to $19.50 per BOE, reflecting an anticipated further decline in proved reserves as a result of lower commodity prices reducing the economic lives of the Company's producing wells.
Total exploration and abandonment expense is expected to be $20 million to $30 million. General and administrative expense is expected to be $75 million to $80 million. Interest expense is expected to be $55 million to $60 million, and other expense is expected to be $65 million to $75 million. Other expense includes (i) $15 million to $20 million of expected charges for stacked drilling rig charges, (ii) $25 million to $30 million of expected charges associated with excess firm gathering and transportation commitments and (iii) $10 million to $15 million of estimated losses (principally noncash) associated with the portion of vertical integration services provided to nonaffiliated working interest owners, including joint venture partners, in wells operated by the Company. Accretion of discount on asset retirement obligations is expected to be $4 million to $7 million.
The Company's effective income tax rate is expected to range from 35 percent to 40 percent assuming current capital spending plans and no significant mark-to-market changes in the Company's derivative position. Current income taxes are expected to be $1 million to $5 million and are primarily attributable to state taxes.

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PIONEER NATURAL RESOURCES COMPANY

Operations and Drilling Highlights
The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during the three months ended March 31, 2016:
 
 
Oil (Bbls)
 
NGLs (Bbls)
 
Gas (Mcf)
 
Total (BOE)
Permian Basin
 
102,016

 
24,802

 
132,029

 
148,823

South Texas - Eagle Ford Shale
 
16,020

 
10,544

 
90,290

 
41,612

Raton Basin
 

 

 
100,358

 
16,726

West Panhandle
 
3,360

 
3,734

 
13,567

 
9,354

South Texas - Other
 
1,404

 
151

 
22,366

 
5,283

Other
 
2

 
1

 
41

 
11

   Total
 
122,802

 
39,232

 
358,651

 
221,809

The Company's total liquids production from continuing operations increased to 73 percent of total production, on a BOE basis, for the three months ended March 31, 2016, as compared to 69 percent for the same period last year.
 The following table summarizes by geographic area the Company's finding and development costs incurred during the three months ended March 31, 2016: 
 
 
Acquisition Costs
 
Exploration
 
Development
 
 
 
 
Proved
 
Unproved
 
Costs
 
Costs
 
Total
 
 
(in millions)
Permian Basin
 
$

 
$
4

 
$
333

 
$
155

 
$
492

South Texas - Eagle Ford Shale
 

 

 
33

 
19

 
52

West Panhandle
 

 

 

 
1

 
1

South Texas - Other
 

 

 

 
2

 
2

Other
 

 


 
2

 

 
2

   Total
 

 
$
4

 
$
368

 
$
177

 
$
549

The following table summarizes the Company's development and exploration/extension drilling activities for the three months ended March 31, 2016: 
 
 
Development Drilling
 
 
Beginning Wells
in Progress
 
Wells
Spud
 
Successful
Wells
 
Ending Wells
in Progress
Permian Basin
 
27

 
8

 
24

 
11

South Texas - Eagle Ford Shale
 
6

 

 
2

 
4

   Total
 
33

 
8

 
26

 
15

 
 
 
Exploration/Extension Drilling
 
 
Beginning Wells
in Progress
 
Wells
Spud
 
Successful
Wells
 
Unsuccessful
Wells
 
Ending Wells
in Progress
Permian Basin
 
77

 
49

 
44

 

 
82

South Texas - Eagle Ford Shale
 
23

 
1

 
9

 

 
15

Total
 
100

 
50

 
53

 

 
97

Permian Basin area. The Company reduced its rig count during the first quarter of 2016 to 14 rigs in the Spraberry/Wolfcamp area, all of which are drilling horizontal wells. The Company expects to further reduce the rig count to 12 rigs during the second quarter of 2016. During 2016, the Company expects to complete approximately 230 horizontal wells (190 horizontal wells in the northern portion of the play and 40 horizontal wells in the southern portion of the play). Approximately 60% of the horizontal wells are planned to be drilled in the Wolfcamp B interval, 25% in the Wolfcamp A interval and 15% in the Lower Spraberry Shale interval. The Company continues to drill utilizing two-well and three-well pads and expects to spend $1.77 billion of drilling and completion capital in the Spraberry field during 2016. During the first quarter of 2016, the Company placed on production 42 horizontal wells in the northern portion of the play and 13 horizontal wells in the southern portion of the play. In the northern portion of the play, approximately 60% of the wells placed on production were Wolfcamp B interval wells, and the remaining 40

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PIONEER NATURAL RESOURCES COMPANY

percent were split predominantly between Wolfcamp A interval wells and Lower Spraberry Shale wells. In the southern portion of the play, all of the wells placed on production were Wolfcamp B interval wells.
The Company continues to utilize its integrated services to control well costs and operating costs in addition to supporting the execution of its drilling and production activities in the Spraberry field. The Company is currently utilizing six Company-owned fracture stimulation fleets totaling approximately 350,000 horsepower to support its drilling operations in the Spraberry field. In April 2016, the Company idled two of its eight fracture stimulation fleets due to reduced demand for fracture stimulation services as a result of the Company's reduced rig count. These assets will not be depreciated while temporarily idled. The Company also owns other field service equipment that supports its drilling and production operations, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, Premier Silica (the Company's wholly-owned sand mining subsidiary) is supplying high-quality and logistically advantaged brown sand for proppant, which is being used by the Company to fracture stimulate horizontal wells in the Spraberry and Wolfcamp Shale intervals.
The Company has been and continues to aggressively pursue initiatives to improve drilling and completion efficiencies and reduce costs. The most significant drilling and completion cost reductions to date have been for casing, tubing, materials for drilling and fracture stimulation, fuel charges, labor and transportation, rental equipment and well services, while efficiency gains include optimizing completions in the Spraberry and Wolfcamp Shale intervals.
The Company's long-term growth plan continues to be focused on optimizing the development of the field and addressing the future requirements for water, field infrastructure, gas processing, sand, pipeline takeaway, oilfield services, tubulars, electricity, buildings and roads. However, much of the Company's front-end loaded infrastructure plans, which were expected to provide significant future cost savings and support the Company's long-term growth plan in the Spraberry/Wolfcamp area, have been minimized given the significant decline in oil prices. The Company plans to continue to evaluate its infrastructure plans for a field-wide water distribution network, additional gas processing facilities and expansion of Premier Silica's Brady sand mine based on the Company's outlook for commodity prices and/or incremental cost reductions.
Eagle Ford Shale area. In the Eagle Ford Shale play in South Texas, the rig count has been reduced to zero rigs given current commodity prices that continue to adversely affect well returns. The Company plans to spend $60 million of capital in 2016 to complete 18 Eagle Ford Shale wells and add field compression to reduce wellhead pressures. Due to the forecasted reduction in drilling activity, the Company expects to incur additional expense associated with unused firm purchase, gathering, processing, transportation and fractionation commitments in 2016.
In July 2015, the Company closed on the sale of its 50.1 percent interest in EFS Midstream to an unaffiliated third party, with the Company receiving total consideration of $1.0 billion, of which $530 million was received at closing and the remaining approximately $500 million will be received in July 2016. As a result of the sale, the Company no longer receives its share of the cash flow generated by EFS Midstream, which had the effect of increasing the Company's third-party transportation component of oil and gas production costs by approximately $0.75 per BOE. In conjunction with this transaction, the Company also extended its downstream processing and transportation contracts to 20 years, with improved terms.
Results of Operations from Continuing Operations
Oil and gas revenues. Oil and gas revenues totaled $409 million for the three months ended March 31, 2016, as compared to $517 million for the same period in 2015.
 The decrease in oil and gas revenues during the three months ended March 31, 2016, as compared to the same period in 2015, is primarily due to declines of 35 percent, 31 percent and 34 percent in average oil, NGL and gas prices, respectively, partially offset by 25 percent and 11 percent increases in daily oil and NGL sales volumes, respectively.
The following table provides average daily sales volumes for the three months ended March 31, 2016 and 2015: 
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Oil (Bbls)
 
122,802

 
98,554

NGLs (Bbls)
 
39,232

 
35,364

Gas (Mcf)
 
358,651

 
359,428

Total (BOEs)
 
221,809

 
193,823

Average daily BOE sales volumes increased by 14 percent for the three months ended March 31, 2016, as compared to the same period in 2015, principally due to the Company's successful Spraberry/Wolfcamp horizontal drilling program. Production

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for the three months ended March 31, 2016 and March 31, 2015 reflects lower NGL production volumes of approximately 5,000 barrels per day and 4,600 barrels per day, respectively, due to voluntary reductions in recoveries of ethane since it had a higher value if sold as part of the gas stream.
The oil, NGL and gas prices that the Company reports are based on the market prices received for each commodity. The following table provides the Company's average prices for the three months ended March 31, 2016 and 2015: 
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Oil (per Bbl)
 
$
28.09

 
$
43.02

NGL (per Bbl)
 
$
10.33

 
$
15.00

Gas (per Mcf)
 
$
1.79

 
$
2.70

Total (per BOE)
 
$
20.28

 
$
29.63

Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure oil, NGL and gas transportation capacity from the Company’s areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to a Gulf Coast oil price and to satisfy unused pipeline capacity commitments. Revenues and expenses from these transactions are presented on a gross basis as the Company acts as a principal in the transaction by assuming the risk and rewards of ownership, including credit risk, of the commodities purchased and assuming responsibility to deliver the commodities sold. The net effect of third party purchases and sales of oil and gas for the three months ended March 31, 2016 was a loss of $20 million, as compared to a loss of $5 million for the same period in 2015. Firm transportation payments on excess pipeline capacity commitments are included in other expense in the accompanying consolidated statements of operations. See Note L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information on transportation commitment charges.
Interest and other income. Interest and other income for the three months ended March 31, 2016 was $8 million, as compared to $7 million for the same period in 2015. See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.
Derivative gains, net. The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. During the three months ended March 31, 2016, the Company recorded $43 million of net derivative gains on commodity price and interest rate derivatives, of which $218 million represented net cash receipts. During the three months ended March 31, 2015, the Company recorded $241 million of net derivative gains, of which $206 million represented net cash receipts.
The following tables detail the net cash receipts (payments) on the Company's commodity derivatives and the relative price impact (per Bbl or Mcf) for the three months ended March 31, 2016 and 2015:
 
 
Three Months Ended March 31, 2016
 
 
Net cash receipts
 
Price impact
 
 
(in millions)
 
 
 
Oil derivative receipts
 
$
194

 
$
17.26

per Bbl
NGL derivative receipts
 
4

 
$
1.09

per Bbl
Gas derivative receipts
 
20

 
$
0.61

per Mcf
Total net commodity derivative receipts
 
$
218

 
 
 

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PIONEER NATURAL RESOURCES COMPANY

 
 
Three Months Ended March 31, 2015
 
 
Net cash receipts (payments)
 
Price impact
 
 
(in millions)
 
 
 
Oil derivative receipts
 
$
181

 
$
20.35

per Bbl
NGL derivative payments
 
(1
)
 
$
(0.29
)
per Bbl
Gas derivative receipts
 
26

 
$
0.82

per Mcf
Total net commodity derivative receipts
 
$
206

 
 
 
See Notes D and E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative and Qualitative Disclosures About Market Risk" for additional information regarding the Company's derivative activities and market risks associated with those activities.
Gain on disposition of assets, net. The Company recorded net gains on the disposition of assets of $2 million for the three months ended March 31, 2016, as compared to $1 million for the same period in 2015.
Oil and gas production costs. The Company recorded oil and gas production costs of $156 million during the three months ended March 31, 2016, as compared to $180 million during the same period in 2015. Lease operating expenses and workover costs represent the components of oil and gas production costs over which the Company has management control, while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from the gathering and processing of third-party gas in Company-owned facilities.
Total oil and gas production costs per BOE for the three months ended March 31, 2016 decreased by 25 percent, as compared to the same period in 2015. The decrease in lease operating expenses per BOE during the three months ended March 31, 2016, as compared to the same period in 2015, is primarily due to a greater proportion of the Company's production coming from horizontal wells in Spraberry/Wolfcamp area that have lower per BOE lease operating costs, cost reduction initiatives and lower electricity and fuel costs, which are impacted by lower commodity prices. The increase in third-party transportation charges reflects the Company no longer receiving cash flow generated by EFS Midstream as a result of its sale in July 2015.
The following table provides the components of the Company's oil and gas production costs per BOE for the three months ended March 31, 2016 and 2015: 
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Lease operating expenses
 
$
5.20

 
$
7.83

Third-party transportation charges
 
2.01

 
1.56

Net natural gas plant charges
 
0.22

 
0.31

Workover costs
 
0.28

 
0.62

Total production costs
 
$
7.71

 
$
10.32

Production and ad valorem taxes. The Company's production and ad valorem taxes were $29 million during the three months ended March 31, 2016, as compared to $39 million for the same period in 2015. In general, production and ad valorem taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity prices, whereas production taxes are based upon current year commodity prices.

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The following table provides the Company's production and ad valorem taxes per BOE for the three months ended March 31, 2016 and 2015:
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Production taxes
 
$
0.80

 
$
1.22

Ad valorem taxes
 
0.66

 
1.02

Total production and ad valorem taxes
 
$
1.46

 
$
2.24

Depletion, depreciation and amortization expense. The Company's DD&A expense was $353 million ($17.49 per BOE) for the three months ended March 31, 2016, as compared to $310 million ($17.77 per BOE) during the same period in 2015. The change in per BOE DD&A expense during the three months ended March 31, 2016, as compared to the same period in 2015, is primarily due to a decrease in depletion expense on oil and gas properties.
Depletion expense on oil and gas properties was $16.94 per BOE during the three months ended March 31, 2016, as compared to $17.15 per BOE during the same period in 2015. The change in per BOE depletion expense during the three months ended March 31, 2016, as compared to the same period in 2015, is primarily due to proved oil and gas property impairment charges during 2015 that had the effect of reducing the carrying value of the Company's oil and gas properties, partially offset by declines in commodity prices during 2015 and 2016 that led to a reduction in proved reserves as a result of shortening the economic productive lives of the Company's producing wells. See Note D of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's proved oil and gas property impairment charges.
Impairment of oil and gas properties. The Company performs assessments of its long-lived assets to be held and used, including oil and gas properties, whenever events or circumstances indicate that the carrying value of those assets may not be recoverable.
The cash flow model the Company uses to assess proved properties for impairment includes numerous assumptions. The primary factors that may affect estimates of future cash flows are (i) future reserve adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves (ii) results of future drilling activities, (iii) Management's Price Outlook and (iv) increases or decreases in production costs and capital costs associated with those fields. All inputs to the cash flow model must be evaluated at each measurement date.
As a result of the Company's proved property impairment assessments, the Company recognized pretax, noncash impairment charges to reduce the carrying values of (i) its West Panhandle Field during the three months ended March 31, 2016 ($32 million impairment charge) and (ii) the Eagle Ford Shale field ($846 million impairment charge), the West Panhandle field ($138 million impairment charge) and South Texas - Other field ($72 million impairment charge) during the year ended December 31, 2015 to their estimated fair values. See Note D of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's proved oil and gas property impairment charges.
Although the Company's estimates of undiscounted future net cash flows attributable to its Permian Basin oil and gas properties indicated on March 31, 2016 that its carrying amount was expected to be recovered, the Company's impairment assessment indicated that the assets are at risk for impairment if estimates of future cash flows decline. For example, the Company estimates that the carrying values of its Permian Basin assets may become partially impaired if the average oil price in Management's Price Outlook of $49.77 per Bbl as of March 31, 2016 were to decline by approximately $3.00 to $8.00 per Bbl. The Company's Permian Basin oil and gas properties are long-lived assets that had a carrying value of $8.9 billion as of March 31, 2016. If the Company's Permian Basin oil and gas properties were to become impaired in a future period, the Company could recognize impairment charges in that period that could range from $5 billion to $7 billion. In addition, the Company could recognize noncash, pretax impairment charges that could range from $500 million to $700 million to reduce the carrying value of its vertical integration assets that provide services for the Permian Basin assets. The carrying values of those assets are included in "other property and equipment, net" in the accompanying consolidated balance sheets. Also, if Management's Price Outlook were to decline further, it may constitute significant negative evidence as to whether it is more likely than not that all of the Company's deferred tax assets can be realized prior to their expirations.

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Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs, exploratory dry holes expenses and lease abandonments and other exploration expenses for the three months ended March 31, 2016 and 2015 (in millions): 
 
 
Three Months Ended
March 31,
 
 
2016
 
2015
Geological and geophysical
 
$
19

 
$
20

Exploratory dry holes
 
1

 
5

Leasehold abandonments and other
 
39

 

 
 
$
59

 
$
25

During the three months ended March 31, 2016, the Company incurred leasehold abandonments primarily related to the abandonment of unproved properties in the Permian Basin and unproved acreage in Alaska in which the Company held an overriding royalty interest.
During the three months ended March 31, 2016, the Company drilled and evaluated 53 exploration/extension wells, all of which were successfully completed as discoveries. During the same period in 2015, the Company drilled and evaluated 52 exploration/extension wells, 51 of which were successfully completed as discoveries.
General and administrative expense. General and administrative expense for the three months ended March 31, 2016 was $74 million ($3.66 per BOE), as compared to $82 million ($4.70 per BOE) for the same period in 2015. The decrease in general and administrative expense during the three months ended March 31, 2016, as compared to the same period in 2015, was primarily due to the Company's cost reduction initiatives, including not replacing personnel who have left the Company and reduced contractor activity.
Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations was $5 million and $3 million for the three months ended March 31, 2016 and 2015, respectively. See Note I of Notes to Consolidated Financial Statements in "Item 1. Financial Statements" for information regarding the Company's asset retirement obligations.
 Interest expense. Interest expense was $55 million and $46 million for the three months ended March 31, 2016, and 2015, respectively. The increase in interest expense during the three months ended March 31, 2016, as compared to the same period in 2015, was primarily due to the Company's December 2015 issuance of $500 million of 3.45% Senior Notes due 2021 and $500 million of 4.45% Senior Notes due 2026. The weighted average interest rate on the Company's indebtedness for the three months ended March 31, 2016, including the effects of capitalized interest, was 5.7 percent, as compared to 6.6 percent for the same period in 2015.
Other expense. Other expense was $87 million for the three months ended March 31, 2016, as compared to $49 million during the same period in 2015. The increase in other expense for the three months ended March 31, 2016, as compared to the same period in 2015, is primarily due to (i) an increase of $15 million in terminated rig contract charges, (ii) a $12 million increase in the net loss from Company-provided fracture stimulation and related service operations that are provided to third party working interest owners, (iii) an increase of $10 million in unused firm transportation costs and (iv) restructuring charges of $3 million associated with the Company's relocation of its pressure pumping operations in South Texas to the Spraberry/Wolfcamp area. See Notes B and L of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.
Income tax benefit. The Company recorded an income tax benefit from continuing operations of $141 million for the three months ended March 31, 2016, as compared to an income tax benefit of $37 million for the same period in 2015. The Company's effective tax rate for the three months ended March 31, 2016 was 35 percent, as compared to 33 percent for the same period in 2015. The difference between the effective tax rate and the statutory tax rate during the three months ended March 31, 2015 was primarily due to state income tax apportionments and nondeductible expenses. See Note M of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding the Company's income taxes.
Loss from discontinued operations, net of tax. The Company reported no income or loss from discontinued operations, net of tax, for the three months ended March 31, 2016. For the three months ended March 31, 2015, the Company reported a loss from discontinued operations, net of tax, of $4 million, which was primarily comprised of an arbitration award related to plugging and abandonment obligations associated with two Gulf of Mexico wells from which Pioneer withdrew in 2009.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures on oil and gas properties and related vertical integration assets and facilities, payment of contractual obligations, including debt

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PIONEER NATURAL RESOURCES COMPANY

maturities, dividends and working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow, cash and cash equivalents on hand, sales of investments in commercial paper, corporate bonds and time deposits that are classified as short-term and long-term investments in the accompanying consolidated balance sheets, proceeds from divestitures or external financing sources as discussed in "Capital resources" below.
The Company's capital budget for 2016 is $2.0 billion (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs), which includes approximately $1.85 billion for drilling operations and $150 million for water infrastructure, vertical integration system upgrades and field facilities. The Company's capital expenditures during the three months ended March 31, 2016 were $600 million, consisting of $527 million for drilling operations (excluding acquisitions, asset retirement obligations, capitalized interest and geological and geophysical administrative costs) and $73 million for buildings, vertical integration and other plant and equipment additions. Based on results for the three months ended March 31, 2016 and Management's Price Outlook, the Company expects its net cash flows from operating activities, cash and cash equivalents on hand, the recei