10-Q 1 pxd-20150630.htm 10-Q PXD-2015.06.30
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 June 30, 2015
or 
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from  ________ to ________                     
Commission File Number: 1-13245
______________________________ 
PIONEER NATURAL RESOURCES COMPANY
(Exact name of Registrant as specified in its charter)
______________________________
Delaware
 
75-2702753
(State or other jurisdiction of
incorporation or organization)
 
(I.R.S. Employer
Identification No.)
 
 
5205 N. O'Connor Blvd., Suite 200, Irving, Texas
 
75039
(Address of principal executive offices)
 
(Zip Code)
(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 August 4                               149,307,983



PIONEER NATURAL RESOURCES COMPANY
TABLE OF CONTENTS 
 
 
Page
 
 
 
 
 
 
Item 1.
 
 
 
 
 
Consolidated Balance Sheets as of June 30, 2015 and December 31, 2014
 
 
 
 
Consolidated Statements of Operations for the three and six months ended June 30, 2015 and 2014
 
 
 
 
Consolidated Statement of Equity for the six months ended June 30, 2015
 
 
 
 
Consolidated Statements of Cash Flows for the six months ended June 30, 2015 and 2014
 
 
 
 
 
 
 
Item 2.
 
 
 
Item 3.
 
 
 
Item 4.
 
 
 
 
Item 1.
 
 
 
Item 1A.
 
 
 
Item 2.
 
 
 
Item 4.
 
 
 
Item 6.
 
 
 
 

2


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 and other Quarterly Reports on Form 10-Q 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, 2014 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


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


PART I. FINANCIAL INFORMATION
Item 1.    Financial Statements
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in millions)
 
 
 
June 30,
2015
 
December 31,
2014
 
 
(Unaudited)
 
 
ASSETS
Current assets:
 
 
 
 
Cash and cash equivalents
 
$
219

 
$
1,025

Accounts receivable:
 
 
 
 
Trade, net
 
388

 
436

Due from affiliates
 
2

 
4

Income taxes receivable
 
22

 
23

Inventories
 
269

 
241

Prepaid expenses
 
16

 
15

Derivatives
 
354

 
578

Other
 
35

 
37

Total current assets
 
1,305

 
2,359

Property, plant and equipment, at cost:
 
 
 
 
Oil and gas properties, using the successful efforts method of accounting:
 
 
 
 
Proved properties
 
16,375

 
15,662

Unproved properties
 
164

 
159

Accumulated depletion, depreciation and amortization
 
(6,044
)
 
(5,431
)
Total property, plant and equipment
 
10,495

 
10,390

Goodwill
 
272

 
272

Other property and equipment, net
 
1,466

 
1,391

Investment in unconsolidated affiliate
 
277

 
239

Derivatives
 
89

 
181

Other, net
 
98

 
94

 
 
$
14,002

 
$
14,926








The financial information included as of June 30, 2015 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


PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS (continued)
(in millions)
 
 
 
June 30,
2015
 
December 31,
2014
 
 
(Unaudited)
 
 
LIABILITIES AND EQUITY
Current liabilities:
 
 
 
 
Accounts payable:
 
 
 
 
Trade
 
$
771

 
$
1,197

Due to affiliates
 
58

 
123

Interest payable
 
62

 
40

Income taxes payable
 

 
1

Deferred income taxes
 
81

 
161

Derivatives
 

 
3

Other
 
61

 
55

Total current liabilities
 
1,033

 
1,580

Long-term debt
 
2,672

 
2,665

Derivatives
 
1

 
2

Deferred income taxes
 
1,714

 
1,803

Other liabilities
 
274

 
287

Equity:
 
 
 
 
Common stock, $.01 par value; 500 million shares authorized; 152 million shares issued as of June 30, 2015 and December 31, 2014, respectively
 
2

 
2

Additional paid-in capital
 
6,220

 
6,167

Treasury stock at cost: 3 million shares as of June 30, 2015 and December 31, 2014, respectively
 
(202
)
 
(171
)
Retained earnings
 
2,281

 
2,583

Total equity attributable to common stockholders
 
8,301

 
8,581

Noncontrolling interests in consolidating subsidiaries
 
7

 
8

Total equity
 
8,308

 
8,589

Commitments and contingencies
 


 


 
 
$
14,002

 
$
14,926








The financial information included as of June 30, 2015 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


PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per share data)
(Unaudited) 
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
Revenues and other income:
 
 
 
 
 
 
 
 
Oil and gas
 
$
596

 
$
938

 
$
1,113

 
$
1,828

Sales of purchased oil and gas
 
236

 
205

 
339

 
353

Interest and other
 
11

 
3

 
17

 
7

Derivative gains (losses), net
 
(197
)
 
(218
)
 
44

 
(322
)
Gain on disposition of assets, net
 
2

 
4

 
3

 
10

 
 
648

 
932

 
1,516

 
1,876

Costs and expenses:
 
 
 
 
 
 
 
 
Oil and gas production
 
163

 
167

 
343

 
325

Production and ad valorem taxes
 
37

 
56

 
76

 
111

Depletion, depreciation and amortization
 
329

 
243

 
639

 
460

Purchased oil and gas
 
237

 
198

 
345

 
341

Impairment of oil and gas properties
 

 

 
138

 

Exploration and abandonments
 
28

 
28

 
54

 
59

General and administrative
 
83

 
82

 
165

 
163

Accretion of discount on asset retirement obligations
 
3

 
3

 
6

 
6

Interest
 
46

 
47

 
92

 
92

Other
 
62

 
21

 
110

 
36

 
 
988

 
845

 
1,968

 
1,593

Income (loss) from continuing operations before income taxes
 
(340
)
 
87

 
(452
)
 
283

Income tax benefit (provision)
 
123

 
(32
)
 
160

 
(83
)
Income (loss) from continuing operations
 
(217
)
 
55

 
(292
)
 
200

Loss from discontinued operations, net of tax
 
(1
)
 
(54
)
 
(4
)
 
(76
)
Net income (loss) attributable to common stockholders
 
$
(218
)
 
$
1

 
$
(296
)
 
$
124

 
 
 
 
 
 
 
 
 
Basic and diluted earnings per share attributable to common stockholders:
 
 
 
 
 
 
 
 
Income (loss) from continuing operations
 
$
(1.45
)
 
$
0.38

 
$
(1.95
)
 
$
1.38

Loss from discontinued operations
 
(0.01
)
 
(0.37
)
 
(0.03
)
 
(0.52
)
Net income (loss)
 
$
(1.46
)
 
$
0.01

 
$
(1.98
)
 
$
0.86

 
 
 
 
 
 
 
 
 
Basic and diluted weighted average shares outstanding
 
149

 
143

 
149

 
143

 
 
 
 
 
 
 
 
 
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


PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENT OF EQUITY
(in millions, except 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
Balance as of December 31, 2014
 
149

 
$
2

 
$
6,167

 
$
(171
)
 
$
2,583

 
$
8

 
$
8,589

Dividends declared ($0.04 per share)
 

 

 

 

 
(6
)
 

 
(6
)
Purchases of treasury stock
 

 

 

 
(31
)
 

 

 
(31
)
Tax benefits related to stock-based compensation
 

 

 
6

 

 

 

 
6

Compensation costs included in net income
 

 

 
47

 

 

 

 
47

Cash distributions to noncontrolling interests
 

 

 

 

 

 
(1
)
 
(1
)
Net loss
 

 

 

 

 
(296
)
 

 
(296
)
Balance as of June 30, 2015
 
149

 
$
2

 
$
6,220

 
$
(202
)
 
$
2,281

 
$
7

 
$
8,308








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


PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
(Unaudited)
 
 
Six Months Ended
June 30,
 
 
2015
 
2014
Cash flows from operating activities:
 
 
 
 
Net income (loss)
 
$
(296
)
 
$
124

Adjustments to reconcile net income (loss) to net cash provided by operating activities:
 
 
 
 
Depletion, depreciation and amortization
 
639

 
460

Impairment of oil and gas properties
 
138

 

Impairment of inventory and other property and equipment
 
9

 
4

Exploration expenses, including dry holes
 
15

 
10

Deferred income taxes
 
(161
)
 
65

Gain on disposition of assets, net
 
(3
)
 
(10
)
Accretion of discount on asset retirement obligations
 
6

 
6

Discontinued operations
 
(3
)
 
179

Interest expense
 
9

 
9

Derivative related activity
 
312

 
298

Amortization of stock-based compensation
 
47

 
43

Other
 
(6
)
 
28

Change in operating assets and liabilities:
 
 
 
 
Accounts receivable, net
 
49

 
(59
)
Income taxes receivable
 
1

 
(2
)
Inventories
 
(44
)
 
(8
)
Prepaid expenses
 
(1
)
 
2

Other current assets
 
(8
)
 
(4
)
Accounts payable
 
(275
)
 
30

Interest payable
 
22

 

Income taxes payable
 
(1
)
 
1

Other current liabilities
 
(17
)
 
7

Net cash provided by operating activities
 
432

 
1,183

Cash flows from investing activities:
 
 
 
 
Proceeds from disposition of assets, net of cash sold
 
7

 
369

Additions to oil and gas properties
 
(1,083
)
 
(1,362
)
Additions to other assets and other property and equipment, net
 
(130
)
 
(110
)
Net cash used in investing activities
 
(1,206
)
 
(1,103
)
Cash flows from financing activities:
 
 
 
 
Borrowings under long-term debt
 

 
325

Principal payments on long-term debt
 

 
(325
)
Distributions to noncontrolling interests
 
(1
)
 

Exercise of long-term incentive plan stock options
 

 
7

Purchases of treasury stock
 
(31
)
 
(33
)
Tax benefits related to stock-based compensation
 
6

 
4

Dividends paid
 
(6
)
 
(6
)
Net cash used in financing activities
 
(32
)
 
(28
)
Net increase (decrease) in cash and cash equivalents
 
(806
)
 
52

Cash and cash equivalents, beginning of period
 
1,025

 
393

Cash and cash equivalents, end of period
 
$
219

 
$
445

  


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

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(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 southeastern 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 June 30, 2015 and for the three and six months ended June 30, 2015 and 2014 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, 2014.
Certain reclassifications have been made to the 2014 financial statement and footnote amounts in order to conform to the 2015 presentation.
Restructuring. On May 4, 2015, the Company announced plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pumping services operations. The Company is also relocating a number of employees from Denver to its corporate headquarters in Irving, Texas. This initiative is expected to be substantially completed by the end of the third quarter of 2015.
In connection therewith, during the three and six months ended June 30, 2015, the Company recognized $15 million of restructuring charges in other expense in the accompanying consolidated statement of operations. The Company estimates that it will incur an additional $10 million of restructuring charges during the third quarter of 2015. The aggregate $25 million estimate of restructuring charges includes approximately $16 million in employee severance costs, $6 million in lease-related costs and $3 million in employee relocation and other costs.
Employee severance costs. The $16 million of estimated employee severance costs is based on the number of employees that are expected to be impacted by the restructuring. Approximately $15 million is related to cash severance and $1 million is related to accelerated vesting of share-based grants, which are noncash charges.
Lease obligations and other. The $6 million of lease-related costs relates to certain Denver office space that will no longer be used as a part of the restructuring. Approximately $2 million represents the impairment of leasehold improvements and approximately $4 million represents the Company’s future obligations under the operating leases, net of anticipated sublease income.
As of June 30, 2015, the Company’s had $12 million of restructuring liabilities related to employee severance costs recorded in other current liabilities.
New accounting pronouncements. In July 2015, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2015-11, "Inventory (Topic 330): Simplifying the Measurement of Inventory." ASU 2015-11 requires an entity to measure inventory at the lower of cost and net realizable value rather than lower of cost or market as previously required by GAAP. ASU 2015-11 is effective for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. This update should be applied prospectively with early application permitted. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements.
In April 2015, the FASB issued ASU 2015-03, "Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs." ASU 2015-03 requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts.

10

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

Currently, debt issuance costs are recognized as deferred charges and recorded as assets. The guidance is effective for annual and interim periods beginning after December 15, 2015 with early adoption permitted and is to be implemented retrospectively. Adoption of the new guidance will only affect the presentation of the Company's consolidated balance sheets and will not have a material impact.
In May 2014, the FASB issued ASU 2014-09, "Revenue from Contracts with Customers (Topic 606)," which supersedes the revenue recognition requirements in Accounting Standards Codification ("ASC") Topic 605, "Revenue Recognition," and most industry-specific guidance. ASU 2014-09 is based on the principle that revenue is recognized to depict the transfer of goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 also requires additional disclosure about the nature, amount, timing and uncertainty of revenue and cash flows arising from customer contracts. ASU 2014-09 applies to all contracts with customers except those that are within the scope of other topics in the FASB ASC. The new guidance is effective for annual reporting periods beginning after December 15, 2016 for public companies, with early adoption not permitted. Entities have the option of using either a full retrospective or modified approach to adopt ASU 2014-09. In April 2015, the FASB issued an exposure draft proposing to defer the effective date until annual reports beginning after December 15, 2017. In July 2015, the FASB voted to approve the deferral, although a final ASU has not yet been issued. The Company is currently evaluating the new guidance and has not determined the impact this standard may have on its financial statements or decided upon the method of adoption.
NOTE C. Divestitures
Divestitures Recorded in Continuing Operations
For the three and six months ended June 30, 2015, the Company recorded net gains on disposition of assets in continuing operations of $2 million and $3 million, respectively, as compared to $4 million and $10 million for the same respective periods in 2014. The net gains attributable to the disposition of assets included the following:

Vertical drilling rigs. In March 2014, the Company completed the sale of Sendero Drilling Company, LLC ("Sendero") to Sendero's minority interest owner for cash proceeds of $31 million, which resulted in a gain of $1 million. As part of the sales agreement, the Company committed to a lease agreement with Sendero for 12 vertical rigs through December 31, 2015, and eight vertical rigs in 2016. During the three and six months ended June 30, 2015, the Company incurred $10 million and $20 million of idle drilling rig fees related to the leased Sendero rigs.

Permian Basin. During February 2014, the Company completed the sale of proved and unproved properties in Gaines and Dawson counties in the Spraberry field in West Texas for cash proceeds of $72 million, which resulted in a gain of $2 million.
Divestitures Recorded as Discontinued Operations
During 2014, the Company completed the sales of its (i) net assets in the Hugoton field in southwest Kansas for cash proceeds of $328 million, (ii) net assets in the Barnett Shale field in North Texas for cash proceeds of $150 million and (iii) capital stock in its Alaskan subsidiary ("Pioneer Alaska") for cash proceeds of $267 million. The Company has classified its Hugoton, Barnett Shale and Pioneer Alaska results of operations as loss from discontinued operations, net of tax, in the accompanying consolidated statements of operations.

11

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

The following table represents the components of the Company's discontinued operations for the three and six months ended June 30, 2015 and 2014:
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
 
 
 
 
 
 
 
 
 
Revenues and other income (a)
 
$

 
$
66

 
$

 
$
184

Costs and expenses (b)
 
(1
)
 
(148
)
 
(6
)
 
(300
)
Loss from discontinued operations before income taxes
 
(1
)
 
(82
)
 
(6
)
 
(116
)
Current tax provision
 

 

 

 
(1
)
Deferred tax benefit
 

 
28

 
2

 
41

Loss from discontinued operations
 
$
(1
)
 
$
(54
)
 
$
(4
)
 
$
(76
)
 ____________________
(a)
Primarily reflects oil and gas revenues and cash received associated with Alaskan Petroleum Production Tax credits on qualifying capital expenditures.
(b)
Costs and expenses during 2015 were primarily related to an arbitration award associated with plugging and abandonment obligations for two Gulf of Mexico wells from which Pioneer withdrew in 2009. Costs and expenses in 2014 were primarily comprised of oil and gas production costs and impairment charges. See Note D for information about impairment charges on the Barnett Shale assets and Pioneer Alaska.
NOTE D. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available without undue cost and effort. The three input levels of the fair value hierarchy are as follows:
Level 1 – quoted prices for identical assets or liabilities in active markets.
Level 2 – quoted prices for similar assets or liabilities in active markets, quoted prices for identical or similar assets or liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g., interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other means.
Level 3 – unobservable inputs for the asset or liability.

12

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(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 June 30, 2015 for each of the fair value hierarchy levels: 
 
 
Fair Value Measurement at June 30, 2015 Using
 
 
 
 
Quoted Prices
in Active
Markets for
Identical
Assets
(Level 1)
 
Significant
Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
 
Fair Value at June 30, 2015
 
 
(in millions)
Assets:
 
 
 
 
 
 
 
 
Commodity derivatives
 
$

 
$
443

 
$

 
$
443

Deferred compensation plan assets
 
73

 

 

 
73

Total assets
 
73

 
443

 

 
516

Liabilities:
 
 
 
 
 
 
 
 
Commodity derivatives
 

 
1

 

 
1

Total liabilities
 

 
1

 

 
1

Total recurring fair value measurements
 
$
73

 
$
442

 
$

 
$
515

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 June 30, 2015, the significant inputs to these asset values represented Level 1 independent active exchange market price inputs.
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 and six months ended June 30, 2015, the Company recorded charges in other expense in the Company's accompanying consolidated statements of operations of $3 million and $9 million to reduce the carrying value of inventory to fair value.
Proved oil and gas properties. During the three months ended March 31, 2015, reductions in management's longer-term commodity price outlooks ("Management's Price Outlooks") provided indications of possible impairment of the Company's oil and gas properties in the West Panhandle field. As a result of management's assessments, during the first quarter of 2015, the Company recognized a pretax noncash impairment charge of $138 million to reduce the carrying value of the West Panhandle field to its estimated fair value.
The Company calculated the fair value of the West Panhandle field as of March 31, 2015 using a discounted future cash flow model. Significant Level 3 assumptions associated with the calculation of the West Panhandle field's discounted future cash flows as of March 31, 2015 included Management's Price Outlooks for (i) oil prices of $65.02 per barrel ("Bbl") and (ii) gas prices

13

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

of $3.83 per million British thermal units ("MMBtu") and management's outlooks for (iii) production costs, (iv) capital expenditures, (v) production and (vi) estimated proved reserves and risk-adjusted probable reserves. Management's Price Outlooks are developed based on third-party futures price outlooks as of the measurement date. The expected future net cash flows were discounted using an annual rate of 10 percent to determine estimated fair value.
Assets associated with divestitures. Long-lived assets that are classified as held for sale are recorded at the lower of the asset's net carrying amount or estimated fair value less costs to sell. The Barnett Shale field assets and Pioneer Alaska were classified as held for sale at December 31, 2013 and carried as such until their divestitures in September 2014 and April 2014, respectively. Associated therewith, during the three and six months ended June 30, 2014, the Company recognized impairment charges of $114 million and $128 million, respectively, to reduce the carrying value of the Barnett Shale field assets to their estimated fair value, less costs to sell, at June 30, 2014, and during the three months ended March 31, 2014, the Company recognized impairment charges of $97 million to reduce the carrying value of Pioneer Alaska to its estimated fair value, less costs to sell, at March 31, 2014.
See Note C for additional information regarding the Company's divestitures of the Barnett Shale field assets and Pioneer Alaska.
Financial instruments not carried at fair value. Carrying values and fair values of financial instruments that are not carried at fair value in the consolidated balance sheets as of June 30, 2015 and December 31, 2014 are as follows: 

 
 
June 30, 2015
 
December 31, 2014
 
 
Carrying
Value
 
Fair
Value
 
Carrying
Value
 
Fair
Value
 
 
(in millions)
Long-term debt
 
$
2,672

 
$
2,949

 
$
2,665

 
$
2,938

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

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

The following table sets forth the volumes per day associated with the Company's outstanding oil derivative contracts as of June 30, 2015 and the weighted average oil prices for those contracts: 
 
 
Six Months Ending December 31,
 
Year Ending December 31,
 
 
2015
 
2016
 
2017
Swap contracts:
 
 
 
 
 
 
Volume (Bbl)
 
82,000

 

 

Price per Bbl
 
$
71.18

 
$

 
$

Collar contracts with short puts:
 
 
 
 
 
 
Volume (Bbl) (a)
 
15,000

 
100,514

 
15,000

Price per Bbl:
 
 
 
 
 
 
Ceiling
 
$
97.69

 
$
77.21

 
$
73.01

Floor
 
$
82.97

 
$
66.92

 
$
65.00

Short put
 
$
69.67

 
$
47.58

 
$
55.00

Rollfactor swap contracts:
 
 
 
 
 
 
Volume (Bbl)
 
37,000

 

 

NYMEX roll price (b)
 
$
0.06

 
$

 
$

 ____________________
(a)
Counterparties have the option to extend for an additional year 5,000 Bbls per day of 2015 collar contracts with short puts with a ceiling price of $100.08 per Bbl, a floor price of $90.00 per Bbl and a short put price of $80.00 per Bbl. The option to extend is exercisable on December 31, 2015. These contracts give the counterparties the option to extend the contracts under the same terms for an additional year if the option to extend is exercised by the counterparties on December 31, 2015.
(b)
Represents swaps that fix the difference between (i) each day's price per Bbl of WTI for the first nearby month less (ii) the price per Bbl of WTI for the second nearby NYMEX month, multiplied by .6667; plus (iii) each day's price per Bbl of WTI for the first nearby month less (iv) the price per Bbl of WTI for the third nearby NYMEX month, multiplied by .3333.
NGL production derivative activities. All material physical sales contracts governing the Company's NGL production are tied directly or indirectly to either Mont Belvieu or Conway fractionation facilities' NGL component product prices.
The following table sets forth the volumes per day associated with the Company's outstanding NGL derivative contracts as of June 30, 2015 and the weighted average NGL prices for those contracts: 
 
 
Six Months Ending December 31,
 
Year Ending December 31,
 
 
2015
 
2016
Ethane swap contracts:
 
 
 
 
Volume (Bbl) (a)
 
6,000

 
4,000

Price per Bbl
 
$
7.80

 
$
12.29

Propane swap contracts:
 
 
 
 
Volume (Bbl) (a)
 
11,000

 
4,500

Price per Bbl
 
$
21.62

 
$
22.12

____________________
(a) Subsequent to June 30, 2015, the Company entered into an additional (i) 1,000 Bbls per day of swap contracts for ethane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices for 2016 with a fixed price of $8.93 per Bbl and (ii) 3,000 Bbls per day of swap contracts for propane forecasted for sale by the Company at Mont Belvieu, Texas-posted prices for 2016 with a fixed price of $20.76 per Bbl.
Gas production derivative activities. All material physical sales contracts governing the Company's gas production are tied directly or indirectly to NYMEX Henry Hub ("HH") gas prices or regional index prices where the gas is sold. The Company uses

15

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

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.
The following table sets forth the volumes per day associated with the Company's outstanding gas derivative contracts as of June 30, 2015 and the weighted average gas prices for those contracts: 
 
 
Six Months Ending December 31,
 
Year Ending December 31,
 
 
2015
 
2016
 
2017
Swap contracts:
 
 
 
 
 
 
Volume (MMBtu)
 
20,000

 
70,000

 

Price per MMBtu
 
$
4.31

 
$
4.06

 
$

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

 
140,000

 

Price per MMBtu:
 
 
 
 
 
 
Ceiling
 
$
5.07

 
$
4.09

 
$

Floor
 
$
4.00

 
$
3.27

 
$

Short put
 
$
3.00

 
$
2.79

 
$

Basis swap contracts:
 
 
 
 
 
 
Gulf Coast index swap volume (b)
 
20,000

 
10,000

 

Price differential ($/MMBtu)
 
$

 
$

 
$

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

 
15,000

 
45,000

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

 

 

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

 
$

Permian Basin index swap volume (c)(d)
 
35,055

 

 

Price differential ($/MMBtu)
 
$
0.20

 
$

 
$

____________________
(a)
Subsequent to June 30, 2015, the Company entered into an additional 40,000 MMBtu per day of 2016 collar contracts with short puts with a ceiling price of $3.71 per MMBtu, a floor price of $3.15 per MMBtu and a short put price of $2.75 per MMBtu.
(b)
Represent swaps that fix the basis differentials between the index prices at which the Company sells its Gulf Coast, Mid-Continent and Permian Basin gas, respectively, and the NYMEX Henry Hub index price used in gas swap and collar contracts.
(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.
(d) Subsequent to June 30, 2015, the Company entered into gas index swap contracts for an additional 30,000 MMBtu per day of August 2015 gas with a price differential of $0.21 per MMBtu between Permian Basin index prices and southern California index prices.
Marketing and basis differential 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 June 30, 2015, the Company had marketing oil index swap contracts for 10,000 Bbl per day for the remainder of 2015 with a price differential of $2.99 per Bbl between Cushing WTI and Louisiana Light Sweet oil.
Interest rate derivative activities. During the three months ended June 30, 2015, the Company terminated its interest rate derivative contracts for cash proceeds of $2 million.
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

16

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

counterparty. The Company enters into derivatives under master netting arrangements, which, in an event of default, allows the Company to offset payables to and receivables from the defaulting counterparty.
The aggregate fair value of the Company's derivative instruments reported in the consolidated balance sheets by type and counterparty, including the classification between current and noncurrent assets and liabilities, consists of the following:
 
Fair Value of Derivative Instruments as of June 30, 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
 
$
357

 
$
(3
)
 
$
354

Commodity price derivatives
 
Derivatives - noncurrent
 
$
95

 
$
(6
)
 
89

 
 
 
 
 
 
 
 
$
443

Liability Derivatives:
 

 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
3

 
$
(3
)
 
$

Commodity price derivatives
 
Derivatives - noncurrent
 
$
7

 
$
(6
)
 
1

 
 
 
 
 
 
 
 
$
1


Fair Value of Derivative Instruments as of December 31, 2014
Type
 
Consolidated Balance Sheet
Location
 
Fair
Value
 
Gross Amounts Offset in the Consolidated Balance Sheet
 
Net Fair Value Presented in the Consolidated Balance Sheet
 
 
 
 
(in millions)
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Asset Derivatives:
 
 
 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
579

 
$
(1
)
 
$
578

Commodity price derivatives
 
Derivatives - noncurrent
 
$
182

 
$
(1
)
 
181

 
 
 
 
 
 
 
 
$
759

Liability Derivatives:
 
 
 
 
 
 
Commodity price derivatives
 
Derivatives - current
 
$
1

 
$
(1
)
 
$

Interest rate derivatives
 
Derivatives - current
 
$
3

 
$

 
3

Commodity price derivatives
 
Derivatives - noncurrent
 
$
3

 
$
(1
)
 
2

 
 
 
 
 
 
 
 
$
5


The 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

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(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
June 30,
 
Six Months Ended
June 30,
Instruments
 
Earnings on Derivatives
 
2015
 
2014
 
2015
 
2014
 
 
 
 
(in millions)
Commodity price derivatives
 
Derivative gains (losses), net
 
$
(212
)
 
$
(226
)
 
$
39

 
$
(340
)
Interest rate derivatives
 
Derivative gains (losses), net
 
15

 
8

 
5

 
18

Total
 
$
(197
)
 
$
(218
)
 
$
44

 
$
(322
)
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 and six months ended June 30, 2015:
 
Three Months Ended June 30, 2015
 
Six Months Ended June 30, 2015
 
(in millions)
Beginning capitalized exploratory costs
$
310

 
$
305

Additions to exploratory costs pending the determination of proved reserves
235

 
461

Reclassification due to determination of proved reserves
(265
)
 
(481
)
Exploratory well costs charged to exploration expense
(10
)
 
(15
)
Ending capitalized exploratory costs
$
270

 
$
270

As of June 30, 2015 and December 31, 2014, the Company had no exploratory projects for which exploratory costs have been capitalized for a period greater than one year from the date drilling was completed.
NOTE G. Long-term Debt
The Company's long-term debt consists of senior notes and a revolving corporate credit facility (the "Credit Facility"), including the effects of net deferred fair value hedge losses and issuance discounts. The Credit Facility is maintained with a syndicate of financial institutions and has aggregate loan commitments of $1.5 billion that expire in December 2017. As of June 30, 2015, the Company had no outstanding borrowings under the Credit Facility and was in compliance with its debt covenants.
NOTE H. Incentive Plans
Stock-based compensation
For the three and six months ended June 30, 2015, the Company recorded $32 million and $61 million, respectively, of stock-based compensation expense for all plans, as compared to $33 million and $62 million for the same respective periods of 2014. As of June 30, 2015, there was $164 million of unrecognized compensation expense related to unvested share-based compensation plan awards, including $30 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 June 30, 2015 and December 31, 2014, accounts payable – due to affiliates includes $11 million and $23 million, respectively, of liabilities attributable to Liability Awards.

18

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

The following table summarizes the activity that occurred during the six months ended June 30, 2015, 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, 2014
 
1,233,539

 
328,087

 
154,733

 
199,058

Awards granted
 
435,462

 
158,726

 
82,431

 

Awards vested
 
(508,335
)
 
(173,759
)
 

 

Awards forfeited
 
(10,859
)
 
(13,997
)
 

 

Outstanding as of June 30, 2015
 
1,149,807

 
299,057

 
237,164

 
199,058

NOTE I. Asset Retirement Obligations
The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and facilities. The following table summarizes the Company's asset retirement obligation activity during the three and six months ended June 30, 2015 and 2014: 
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Beginning asset retirement obligations
 
$
188

 
$
194

 
$
189

 
$
194

New wells placed on production
 

 
1

 
1

 
2

Changes in estimates
 

 

 

 
1

Dispositions
 

 

 

 
(1
)
Liabilities settled
 
(4
)
 
(5
)
 
(9
)
 
(9
)
Accretion of discount
 
3

 
3

 
6

 
6

Ending asset retirement obligations
 
$
187

 
$
193

 
$
187

 
$
193

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 June 30, 2015, the current portion of the Company's asset retirement obligations was $33 million, as compared to $28 million at December 31, 2014.
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 claims will not have a material adverse effect on the Company's consolidated financial position as a whole or on its liquidity, capital resources or future annual results of operations. The Company records reserves for contingencies when information available indicates that a loss is probable and the amount of the loss can be reasonably estimated.
Obligations following divestitures. In connection with its divestiture transactions, the Company may retain certain liabilities and provide the purchaser certain indemnifications, subject to defined limitations, which may apply to identified pre-closing matters, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The Company does not believe these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.

19

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

NOTE K. Interest and Other Income
The following table provides the components of the Company's interest and other income for the three and six months ended June 30, 2015 and 2014:
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Equity interest in income of EFS Midstream (a)
 
$
3

 
$
3

 
$
5

 
$
6

Income (loss) from vertical integration services (b)
 
5

 
(5
)
 
4

 
(7
)
Deferred compensation plan income
 

 

 
3

 
2

Other income
 
3

 
5

 
5

 
6

Total interest and other income
 
$
11

 
$
3

 
$
17

 
$
7

 ____________________
(a)
The Company accounts for its investment in EFS Midstream LLC ("EFS Midstream") using the equity method. EFS Midstream provides gathering, treating and transportation services for the Company. See Note O for additional information on the Company's sale of EFS Midstream in July 2015.
(b)
Income (loss) from vertical integration services primarily represents net margins 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 and six months ended June 30, 2015, these vertical integration net margins included $86 million and $198 million, respectively, of revenues and $81 million and $194 million, respectively, of costs and expenses. For the same period in 2014, these vertical integration net margins included $104 million and $196 million, respectively, of revenues and $109 million and $203 million, respectively, of costs and expenses.
 NOTE L. Other Expense
The following table provides the components of the Company's other expense for the three and six months ended June 30, 2015 and 2014:
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Idle drilling and well service equipment charges (a)
 
$
28

 
$

 
$
51

 
$

Transportation commitment charge (b)
 
13

 
12

 
27

 
22

Restructuring charges (c)
 
15

 

 
15

 

Impairment of inventory (d)
 
3

 
4

 
9

 
4

Other
 
3

 
5

 
8

 
10

Total other expense
 
$
62

 
$
21

 
$
110

 
$
36

 ____________________
(a)
Primarily represents expenses attributable to idle drilling rig fees, which are not chargeable to joint operations.
(b)
Primarily represents firm transportation payments on excess pipeline capacity commitments.
(c)
Represents one-time restructuring costs in connection with the Company's plans to restructure its operations in Colorado, including closing its office in Denver, Colorado and eliminating its Trinidad-based pumping services operations. See Note B for additional information on the restructuring charges.
(d)
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.

20

PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 2015
(Unaudited)

NOTE M. Income Taxes
The Company's income tax benefit (provision) attributable to income from continuing operations consisted of the following for the three and six months ended June 30, 2015 and 2014:
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Current tax provision
 
$
(1
)
 
$
(6
)
 
$
(1
)
 
$
(18
)
Deferred tax benefit (provision)
 
124

 
(26
)
 
161

 
(65
)
Income tax benefit (provision)
 
$
123

 
$
(32
)
 
$
160

 
$
(83
)
For the three and six months ended June 30, 2015, the Company's effective tax rates, excluding income attributable to noncontrolling interests, were 36 percent and 35 percent, as compared to effective rates of 37 percent and 29 percent for the same respective periods in 2014. The Company's effective tax rates differed from the U.S. statutory rate of 35 percent primarily due to state income tax apportionments, nondeductible expenses and, for the six months ended June 30, 2014, the recognition of a $21 million tax benefit resulting from the resolution during the first quarter of 2014 of a tax uncertainty related to net operating loss carryovers and alternative minimum tax credits obtained from the 2012 acquisition of Premier Silica. The Company has no unrecognized tax benefits as of June 30, 2015.
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 2012 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 2009. As of June 30, 2015, 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.
NOTE N. Net Income (Loss) Per Share
The following table reconciles the Company's income (loss) from continuing operations to basic and diluted net income (loss) attributable to common stockholders for the three and six months ended June 30, 2015 and 2014:
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
 
 
(in millions)
Income (loss) from continuing operations
 
$
(217
)
 
$
55

 
$
(292
)
 
$
200

Participating basic earnings
 

 

 

 
(1
)
Basic and diluted income (loss) from continuing operations
 
$
(217
)
 
$
55

 
(292
)
 
199

Basic and diluted loss from discontinued operations
 
$
(1
)
 
$
(54
)
 
$
(4
)
 
$
(76
)
Basic and diluted net income (loss) attributable to common stockholders
 
$
(218
)
 
$
1

 
$
(296
)
 
$
123

Basic and diluted weighted average common shares outstanding were 149 million for the three and six months ended June 30, 2015 and 143 million for the three and six months ended June 30, 2014.
NOTE O. Subsequent Events
EFS Midstream. During November 2014, the Company announced that it was pursuing the divestment of its 50.1 percent equity interest in EFS Midstream. The Company accounts for EFS Midstream under the equity method of accounting for investments in unconsolidated affiliates. In June 2015, the Company entered into a purchase and sale agreement to sell its interest in EFS Midstream to an unaffiliated third party. The sale closed in July 2015, with the Company receiving total consideration of $1.0 billion, of which $530 million was received at closing and the remaining approximately $500 million will be received in July 2016. Associated with the sale, the Company expects to record a pretax gain in excess of $725 million during the third quarter of 2015.

21

PIONEER NATURAL RESOURCES COMPANY

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 second quarter of 2015 included the following highlights:
Net loss attributable to common stockholders for the second quarter of 2015 was $218 million ($1.46 per diluted share), as compared to net income of $1 million ($0.01 per diluted share) for the second quarter of 2014. The decrease in net income attributable to common stockholders is comprised of a $272 million decrease in net income from continuing operations attributable to common stockholders, offset by a $53 million decrease in loss from discontinued operations, net of tax.
The primary components of the decrease in net income from continuing operations include:
a $342 million decrease in oil and gas revenues as a result of a 43 percent decrease in the average commodity prices per BOE, partially offset by a 12 percent increase in sales volumes;
an $86 million increase in DD&A expense, primarily attributable to the 12 percent increase in sales volumes and reductions in proved reserves as a result of the recent decline in commodity prices; and
a $41 million increase in other expense, primarily related to idle drilling rig charges and restructuring charges associated with the closing of the Company's Denver, Colorado office; partially offset by
a $23 million decrease in total oil and gas production costs and production and ad valorem taxes, primarily associated with the 43 percent decrease in average commodity prices per BOE;
a $21 million decrease in net derivative losses, primarily as a result of changes in forward commodity prices and the Company's portfolio of derivatives; and
a $155 million decrease in the Company's income tax provision as a result of the Company's decrease in income from continuing operations before taxes.
The loss from discontinued operations, net of tax, during the three months ended June 30, 2014 was attributable to the results of operations (prior to their sale) associated with the Company's sales of Pioneer Alaska in April 2014 and its Hugoton field assets and Barnett Shale field assets in September 2014.
During the second quarter of 2015, average daily sales volumes from continuing operations increased by 12 percent to 196,626 BOEPD, as compared to 175,834 BOEPD during the second quarter of 2014. The increase in second quarter 2015 average daily sales volumes, as compared to the second quarter of 2014, is primarily due to the Company's successful Spraberry/Wolfcamp and Eagle Ford Shale drilling programs.
Average oil, NGL and gas prices decreased during the second quarter of 2015 to $51.64 per Bbl, $14.03 per Bbl and $2.37 per Mcf, respectively, as compared to $95.87 per Bbl, $30.24 per Bbl and $4.33 per Mcf, respectively, in the second quarter of 2014.
Net cash provided by operating activities decreased to $327 million for the three months ended June 30, 2015, as compared to $718 million for the three months ended June 30, 2014. The $391 million decrease in net cash provided by operating activities is primarily due to the decrease in oil, NGL and gas prices, partially offset by an increase in net cash flows from derivative settlements and an increase in oil and gas sales volumes.
As of June 30, 2015, the Company's net debt to book capitalization increased to 23 percent, as compared to 16 percent at December 31, 2014, due to the use of cash and cash equivalents to fund the Company's drilling program.
Recent Developments
Commodity prices. North American and worldwide oil, NGL and gas prices remain under pressure given the current over supply of such commodities. In general, this imbalance between supply and demand reflects the significant supply growth achieved in the United States as a result of shale drilling and the recent OPEC oil production increases as part of an effort to retain market share combined with only modest demand growth in the United States and slowing 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 this overhang in storage levels begins to decline, prices are expected to remain under pressure. In addition, the possible lifting of economic sanctions on Iran has caused the market to anticipate increased supplies of oil from Iran in early 2016, further weakening the outlook for oil prices. The reduced demand for drilling rigs, oilfield supplies, drill pipe and utilities, for which prices had reached very high levels during a period of high utilization in 2014, has led to a decline of these costs. However, their declines have significantly lagged behind the declines in oil, NGL and gas prices. As a result of these circumstances, the Company experienced significant operating margin deterioration during the first half of 2015.

22

PIONEER NATURAL RESOURCES COMPANY

The duration and magnitude of the commodity price declines and the timing and amount of cost reductions cannot be accurately predicted.
 Low price environment initiatives. In the midst of the lower commodity price environment, the Company has implemented initiatives to improve drilling and completion efficiencies and reduce capital spending, operating costs and general and administrative expenses to minimize spending in excess of estimated cash flows for 2015 and to maintain significant financial flexibility. As a result of these initiatives, the Company has realized significant service cost reductions and efficiency gains that have resulted in (i) an estimated 20 percent to 25 percent decrease in drilling and completion costs compared to 2014 and (ii) a 17 percent reduction in second quarter lease operating expenses per BOE compared to 2014. Drilling and completion costs are expected to be reduced by more than 30 percent by early 2016 compared to 2014 levels as additional cost reductions and efficiency gains are achieved.
EFS Midstream. During November 2014, the Company announced that it was pursuing the divestment of its 50.1 percent equity interest of EFS Midstream. During June 2015, the Company entered into a purchase and sale agreement to sell its interest in EFS Midstream to an unaffiliated third party. The sale closed in July 2015, with the Company receiving total consideration of $1.0 billion, of which $530 million was received at closing and the remaining approximately $500 million will be received in July 2016. Associated with the sale, the Company expects to record a pretax gain in excess of $725 million during the third quarter of 2015. In conjunction with this transaction, the Company also extended its downstream processing and transportation contracts to 20 years, with improved terms.
Drilling Rig Additions. With the completion of the EFS Midstream sale, along with the benefits of the Company's cost savings and efficiency initiatives, the Company began adding horizontal rigs in the northern Spraberry/Wolfcamp area in July 2015, and plans to add an average of two horizontal rigs per month for the remainder of 2015. The Company plans to evaluate its decision to add drilling rigs each month based on the Company's outlook for commodity prices and continuing efficiency improvements, which are reducing the number of days required to place wells on production. This additional drilling activity is expected to increase the Company’s 2015 capital budget by approximately $350 million to a total of $2.2 billion. Due to the timing associated with multi-well pad drilling, the addition of the rigs is expected to have minimal impact on 2015 production.

 Third Quarter 2015 Outlook
Based on current estimates, the Company expects the following operating and financial results from continuing operations for the quarter ending September 30, 2015:
Production is forecasted to average 205,000 to 210,000 BOEPD.
Production costs (including production and ad valorem taxes and transportation costs) are expected to average $11.50 to $13.50 per BOE based on current NYMEX strip commodity prices and reflects a $0.75 per BOE to $1.00 per BOE increase from second quarter 2015 production costs as a result of the sale of EFS Midstream. DD&A expense is expected to average $18.00 to $20.00 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 $25 million to $35 million. General and administrative expense is expected to be $80 million to $85 million. Interest expense is expected to be $45 million to $50 million, and other expense is expected to be $45 million to $55 million, excluding anticipated nonrecurring restructuring charges during the quarter of approximately $10 million. Accretion of discount on asset retirement obligations is expected to be $3 million to $5 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 range from $45 million to $55 million and are primarily attributable to (i) estimated federal alternative minimum taxes associated with the sale of the Company's interest in EFS Midstream during July 2015 and (ii) state taxes.

23

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 six months ended June 30, 2015:
 
 
Oil (Bbls)
 
NGLs (Bbls)
 
Gas (Mcf)
 
Total (BOE)
Permian Basin
 
76,146

 
21,201

 
107,358

 
115,239

South Texas - Eagle Ford Shale
 
18,701

 
11,617

 
96,855

 
46,460

Raton Basin
 

 

 
115,323

 
19,221

West Panhandle
 
2,851

 
3,036

 
13,236

 
8,093

South Texas - Other
 
1,867

 
161

 
25,078

 
6,207

Other
 
2

 

 
51

 
12

   Total
 
99,567

 
36,015

 
357,901

 
195,232

The Company's total liquids production from continuing operations increased to 69 percent of total production, on a BOE basis, for the six months ended June 30, 2015, as compared to 67 percent for the same period last year.
 The following table summarizes by geographic area the Company's finding and development costs incurred during the six months ended June 30, 2015: 
 
 
Unproved
Acquisition
 
Exploration
 
Development
 
 
 
 
Costs
 
Costs
 
Costs
 
Total
 
 
(in millions)
Permian Basin
 
$
9

 
$
364

 
$
343

 
$
716

South Texas - Eagle Ford Shale
 

 
121

 
92

 
213

Raton Basin
 

 
1

 
1

 
2

West Panhandle
 

 

 
5

 
5

South Texas - Other
 

 
1

 

 
1

Other
 

 
8

 

 
8

   Total
 
$
9

 
$
495

 
$
441

 
$
945

The following table summarizes the Company's development and exploration/extension drilling activities for the six months ended June 30, 2015: 
 
 
Development Drilling
 
 
Beginning Wells
in Progress
 
Wells
Spud
 
Successful
Wells
 
Ending Wells
in Progress
Permian Basin
 
41

 
32

 
55

 
18

South Texas - Eagle Ford Shale
 
13

 
19

 
15

 
17

   Total
 
54

 
51

 
70

 
35

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

 
36

 
62

 

 
49

South Texas - Eagle Ford Shale
 
30

 
33

 
32

 
1

 
30

Other
 
1

 

 

 
1

 

Total
 
106

 
69

 
94

 
2

 
79

Permian Basin area. The Company reduced its rig count during the first six months of 2015 to 10 rigs in the Spraberry/Wolfcamp area, all of which were drilling horizontal wells. With the completion of the EFS Midstream sale, along with the benefit of the Company's cost savings and efficiency initiatives, the Company began adding horizontal rigs in the northern Spraberry/Wolfcamp area in July 2015, and plans to add an average of two horizontal rigs per month for the remainder of 2015. The Company plans to evaluate its decision to add drilling rigs each month based on the Company's outlook for commodity prices and continuing efficiency improvements, which are reducing the number of days required to place wells on production. During 2015, the Company expects to drill approximately 105 horizontal wells (60 horizontal wells in the northern portion of the play and 45 horizontal wells in the southern portion of the play), with the horizontal wells being predominantly drilled in the Wolfcamp B horizon. The Company

24

PIONEER NATURAL RESOURCES COMPANY

continues to drill utilizing two-well and three-well pads. The Company expects to spend $1.5 billion of drilling capital in the Spraberry/Wolfcamp area during 2015. During the first six months of 2015, the Company successfully completed 117 wells in the Permian Basin area, the majority of which were spud in 2014.
The Company continues to utilize its integrated services to control well costs and operating costs in addition to supporting the execution of its drilling and production activities in the Spraberry/Wolfcamp area. The Company is currently utilizing six Company-owned fracture stimulation fleets totaling approximately 307,000 horsepower in the Spraberry/Wolfcamp area. To support its operations, the Company also owns other field service equipment, including pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and fishing tools. In addition, Premier Silica (the Company's wholly-owned sand mining subsidiary) is supplying brown sand for proppant, which is being used by the Company to fracture stimulate horizontal wells in the Spraberry and Wolfcamp Shale intervals.
The Company has been aggressively pursuing initiatives to improve drilling and completion efficiencies and reduce costs. A 20 percent to 25 percent reduction in drilling and completion costs in 2015 compared to 2014 has already been realized associated with these initiatives. The most significant drilling and completion cost reductions to date have been for materials for drilling and fracture stimulation, fuel charges, labor and transportation, rental equipment and well services, while efficiency gains include optimizing completions, expanding the use of a modified three-string casing design in the Spraberry/Wolfcamp, testing of dissolvable plug technologies and testing fracture stimulation diversion technologies. The Company expects further drilling and completion cost reductions and efficiency gains to exceed 30 percent by early 2016 compared to 2014, with the key incremental cost reductions being attributable to casing, tubing and well stimulation costs.
The Company's long-term growth plan continues to be focused on optimizing the development of the field and addressing the future requirements for water, field infrastructure, gas processing, sand, pipeline takeaway, oilfield services, tubulars, electricity, systems, buildings and roads. However, much of the Company's front-end loaded infrastructure plans, which were expected to provide significant future cost savings and support the Company's long-term growth plan in the Spraberry/Wolfcamp area, have been deferred given the significant decline in oil prices. The Company plans to 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 cost reductions. Savings of 20 percent are now being realized in the cost of constructing new facilities, with efforts underway to achieve further cost reductions. By early 2016, costs to construct facilities, particularly horizontal tank batteries and saltwater disposal systems, are expected to be lower by 25 percent, compared to 2014.
Eagle Ford Shale area. In the Eagle Ford Shale play in South Texas, the horizontal rig count has been reduced to six rigs. The Company expects to drill approximately 95 horizontal wells in the Eagle Ford Shale during 2015. The Company plans to spend $390 million of drilling capital in 2015. The 2015 drilling program has been focused on liquids-rich drilling in the lower and upper Eagle Ford intervals in Karnes and DeWitt counties, where the Company has drilled its most productive wells in the Eagle Ford Shale. No wells are scheduled to be drilled in dry gas acreage. The Company completed 48 horizontal Eagle Ford Shale wells during the first six months of 2015, 47 of which were successful, with average lateral lengths of approximately 5,600 feet and, on average, 24-stage fracture stimulations. The Company has placed 25 upper target Eagle Ford Shale wells on production and estimates that approximately 25 percent of the Company's acreage is prospective for this interval in the Eagle Ford Shale play. The Company is operating two Pioneer-owned fracture stimulation fleets in the play.
The Company's drilling operations in the Eagle Ford Shale continue to focus on improving drilling and completion efficiencies and cost reductions. A 20 percent reduction in drilling and completion costs in 2015 compared to 2014 has already been realized associated with these initiatives. The Company expects drilling and completion cost reductions and further efficiency gains in excess of 25 percent in early 2016 as compared to 2014 as additional cost reduction initiatives and efficiencies are realized. During 2015, most Eagle Ford Shale wells have been drilled utilizing two to five-well pads. Pad drilling saves the Company a significant amount of capital costs per well, as compared to drilling single-well locations.
During November 2014, the Company announced that it was pursuing the divestment of its 50.1 percent equity interest in EFS Midstream. During June 2015, the Company entered into a purchase and sale agreement to sell its share of EFS Midstream to an unaffiliated third party. The sale was closed in July 2015, with the Company receiving total consideration of $1.0 billion, of which $530 million was received at closing and the remaining approximately $500 million will be received in July 2016. Associated with the sale, the Company expects to record a pretax gain in excess of $725 million during the third quarter of 2015. As a result of the sale, the Company will no longer receive its share of the cash flow generated by EFS Midstream, which will increase the Company's oil and gas production costs by $0.75 per BOE to $1.00 per BOE.
Results of Operations from Continuing Operations
Oil and gas revenues. Oil and gas revenues totaled $596 million and $1.1 billion for the three and six months ended June 30, 2015, respectively, as compared to $938 million and $1.8 billion for the same respective periods in 2014.

25

PIONEER NATURAL RESOURCES COMPANY

 The decrease in oil and gas revenues during the three months ended June 30, 2015, as compared to the same period in 2014, is primarily due to declines of 46 percent, 54 percent and 45 percent in average oil, NGL and gas prices, respectively, and a five percent decline in daily NGL sales volumes, partially offset by 26 percent and three percent increases in daily oil and gas sales volumes, respectively. The decrease in oil and gas revenues during the six months ended June 30, 2015, as compared to the same period in 2014, is primarily due to declines of 50 percent, 54 percent and 44 percent in average oil, NGL and gas prices, respectively, partially offset by 26 percent and seven percent increases in daily oil and gas sales volumes, respectively.
The following table provides average daily sales volumes for the three and six months ended June 30, 2015 and 2014: 
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
Oil (Bbls)
 
100,569

 
79,780

 
99,567

 
79,188

NGLs (Bbls)
 
36,659

 
38,572

 
36,015

 
36,049

Gas (Mcf)
 
356,391

 
344,889

 
357,901

 
333,210

Total (BOEs)
 
196,626

 
175,834

 
195,232

 
170,772

Average daily BOE sales volumes increased by 12 percent and 14 percent for the three and six months ended June 30, 2015, respectively, as compared to the same periods in 2014, principally due to the Company's successful Spraberry/Wolfcamp and Eagle Ford Shale drilling programs.
Production during the six months ended June 30, 2015 reflects a production loss of approximately 1,600 BOEPD in the Spraberry/Wolfcamp area due to heavy icing and low temperatures during January that resulted in extensive power outages, facility freeze-ups, trucking curtailments and limited access to production and drilling facilities. In addition, production for the six months ended June 30, 2015 reflects lower NGL production volumes of approximately 5,000 barrels per day due to voluntary reductions in recoveries of ethane since it had a higher value if sold as part of the gas stream.
The 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 and six months ended June 30, 2015 and 2014: 
 
 
Three Months Ended
June 30,
 
Six Months Ended
June 30,
 
 
2015
 
2014
 
2015
 
2014
Oil (per Bbl)
 
$
51.64

 
$
95.87

 
$
47.40

 
$
94.15

NGL (per Bbl)
 
$
14.03

 
$
30.24

 
$
14.50

 
$
31.43

Gas (per Mcf)
 
$
2.37

 
$
4.33

 
$
2.53

 
$
4.53

Total (per BOE)
 
$
33.32

 
$
58.63

 
$
31.50

 
$
59.14

Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure available oil, NGL and gas transportation capacity from the Company’s areas of production. The Company enters into purchase transactions with third parties and separate sale transactions with third parties to diversify a portion of the Company's WTI oil sales to a Gulf Coast 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. 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 further information on transportation commitment charges.
Interest and other income. Interest and other income for the three and six months ended June 30, 2015 was $11 million and $17 million, respectively, as compared to $3 million and $7 million for the same respective periods in 2014. The increase in interest and other income for both the three and six months ended June 30, 2015, as compared to the same respective periods in 2014, is primarily due to an increase in net margins that result from Company-provided fracture stimulation and related service operations that do not represent intercompany transactions, See Note K of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information.
Derivative gains (losses), 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 and six months ended June 30, 2015, the Company recorded $197 million of net derivative losses and $44 million of net derivative gains, respectively, on commodity price and interest rate derivatives, of which $150 million and $356

26

PIONEER NATURAL RESOURCES COMPANY

million represented net cash receipts, respectively. During the three and six months ended June 30, 2014, the Company recorded $218 million and $322 million of net derivative losses, respectively, of which $6 million and $24 million reflected net cash payments, respectively.
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 and six months ended June 30, 2015 and 2014:
 
 
Three Months Ended June 30, 2015
 
Six Months Ended June 30, 2015