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BEYOND EXPECTATIONS
2013 10-K and Annual Report
Operating Areas
CO
Rockies
KS
Mid-Continent
Mid-Continent
Northern Spraberry/Wolfcamp
TX
Southern Wolfcamp
Eagle Ford Shale
Except for historical information contained herein, the statements in this document are forward-looking statements that are made pursuant to the Safe Harbor
Provisions of the Private Securities Litigation Reform Act of 1995. Forward-looking statements and the business prospects of Pioneer Natural Resources Company
are subject to a number of risks and uncertainties that may cause Pioneer’s actual results in future periods to differ materially from the forward-looking statements.
These risks and uncertainties are described in Items 1, 1A, 7 and 7A and on page 5 of Pioneer’s Form 10-K included with this report.
“Drill bit finding and development cost per BOE” means the summation of exploration and development costs incurred divided by the summation of annual proved
reserves, on a BOE basis, attributable to technical revisions of previous estimates (excluding proved undeveloped (PUD) reserves removed and price revisions),
discoveries and extensions and improved recovery. Consistent with industry practice, future capital costs to develop proved undeveloped reserves are not included
in costs incurred.
“Drill bit reserve replacement” is the summation of annual proved reserves, on a BOE basis, attributable to revisions of previous estimates (excluding PUD reserves
removed and price revisions), discoveries and extensions and improved recovery divided by annual production of oil, natural gas liquids and gas, on a BOE basis.
Cautionary Note — In this report, Pioneer includes estimates of quantities of oil and gas using certain terms, such as “resource,” “resource potential,”
“recoverable resource potential” and “recoverable reserves,” which terms include quantities that may not meet the definitions of “reserves” established by the
U.S. Securities and Exchange Commission (“SEC”) and which the SEC prohibits companies from including in SEC filings. These estimates are by their nature subject
to substantially greater risk of being recovered by Pioneer than are proved reserves. You are urged to consider closely the disclosures in the Company’s periodic
filings with the SEC, which are available from the Company at the address on the back cover of this report and on the Company’s website at www.pxd.com.
1
Fellow Shareholders:
We entered 2013 with high expectations for
Pioneer, our industry and U.S. energy growth. To
reach Pioneer’s goals, we expected much from
our people and from our assets, especially our
acreage positions in two of the most prolific plays
in the U.S., the Spraberry/Wolfcamp Shale in the
Midland Basin of West Texas and the Eagle Ford
Annual Production Growth
from Continuing Operations
in thousands BOEPD
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Scott D. Sheffield
Chairman and CEO
Shale in South Texas. We also expected the U.S.
energy renaissance to continue—that our industry
would continue to support our country’s economic
recovery, provide strong job growth and advance
U.S. energy security. I’m very pleased to report that
results for 2013 were well beyond our expectations.
I consider 2013 to be the best year in Pioneer’s
17-year history. Pioneer’s stock price increased by
73%, and we were once again the top-performing
energy stock in the S&P 500 Index. Our successful
horizontal drilling programs in West Texas and
South Texas contributed to another year of
strong production growth and proved oil and
natural gas reserve additions from the drill bit.
The drilling program and continued emphasis
on science activities in the Spraberry/Wolfcamp
and Eagle Ford Shales significantly advanced our
understanding of the resource potential within
these two prolific plays, optimized our future
development plans and added significant net
asset value for our shareholders. These plays
offer exceptional returns and tremendous growth
opportunities for many years to come.
Drilling results in 2013, combined with geologic
data from thousands of existing wells, allowed
our geoscience team to further refine the potential
of multiple prospective horizontal targets
throughout Pioneer’s approximate 825,000 gross
acre Spraberry/Wolfcamp Shale position. The
team now estimates that our acreage position has
an aggregate estimated resource potential of more
2013 Annual Report 2
Spraberry/Wolfcamp Shale Intervals
Upper Spraberry
Middle Spraberry
Jo Mill
Jo Mill Silt
Lower Spraberry
Dean
Wolfcamp A
Wolfcamp B
Wolfcamp C1
Wolfcamp C2
Wolfcamp D
Strawn
Mississippian/Atoka
than 10 billion barrels oil equivalent (BOE),
up almost 50% from the year-ago estimate of
7 billion BOE.
The U.S. upstream oil and natural gas industry
has defied previous forecasts that our country’s
energy production had reached its peak and
would be in constant decline. The U.S. energy
renaissance continues to exceed expectations
for production growth, economic stimulus and
job creation. Oil production in the U.S. rose by a
record 992,000 barrels a day, or more than 15%, to
average 7.5 million barrels a day in 2013, according
to the International Energy Agency, significantly
exceeding its initial forecast.
During 2012, the United States overtook Russia
as the world’s top natural gas producer, and
U.S. natural gas production again increased in
2013, averaging more than 70 billion cubic feet
per day, according to the Energy Information
Administration. As our industry expands U.S.
oil and natural gas production beyond what is
required for U.S. energy security, the discussion
is appropriately shifting to the opportunity
for exporting domestic oil and natural gas for
the benefit of our international allies, thereby
stabilizing and strengthening global energy
supply while continuing to create jobs and
economic benefits here at home.
Exceptional Progress in 2013
Spraberry/Wolfcamp Shale
Pioneer has a long history in the Midland Basin’s
Spraberry field and has been the field’s most
active driller for many years. The oil-rich Wolfcamp
Shale lies below the Spraberry formation, and
in 2010, Pioneer began successfully utilizing
2013 Annual Report 3
hydraulic fracturing and horizontal drilling to
Pioneer also utilized an average of 15 rigs to
access the resource potential of multiple stacked
drill approximately 380 vertical wells in the
unconventional tight-rock zones, first within
Spraberry field during 2013, principally to meet
the Wolfcamp Shale formations and later within
continuous drilling obligations. The Company’s
the Spraberry Shale formations. The wells drilled
daily production from the Midland Basin increased
in 2013 continue to exceed expectations, further
approximately 19% from the prior year to an
increasing our estimate of oil-in-place and the
average of 79,500 BOE per day (BOEPD) in 2013.
percentage of oil that can be recovered from
these tight-rock formations.
Pioneer has a number of advantages in the
Spraberry/Wolfcamp Shale as a result of our long
Pioneer wells hold the record for highest initial
history there. In addition to our geoscience team’s
production rates in several of the shale intervals,
deep understanding of the stacked pay intervals,
and early production data indicates that some
we have long been the largest employer in Midland
single-interval wells have resource potential of
among upstream companies and have a strong,
more than 1 million BOE. Wells pay out quickly,
experienced workforce. Our existing operations
many in one year or less.
During 2013, Pioneer closed a $1.8 billion joint
interest transaction with a U.S. subsidiary of
the Sinochem Group, which provides funding to
infrastructure, midstream transportation and
processing assets, and integrated well and
pumping services also contribute to our success
and help us reduce costs.
accelerate horizontal development in the southern
Eagle Ford Shale
207,000 acres of the Wolfcamp Shale play.
We utilized an average of seven rigs and drilled
approximately 100 horizontal wells on this acreage
during 2013, including wells drilled during the
second half of the year to test downspacing to
optimize ultimate oil recoveries.
In 2009, Pioneer completed its first horizontal
well in the Eagle Ford Shale and was the second
company to announce a discovery in this exciting
play. We have held leases in South Texas for many
years and currently hold approximately 215,000
gross acres, principally in the Eagle Ford Shale play,
To the north, Pioneer’s Spraberry/Wolfcamp Shale
where we are drilling our most liquids-rich acreage.
horizontal drilling program focused on appraising
During 2013, we drilled 132 horizontal Eagle Ford
six shale target zones known to have substantial
Shale wells, running ten rigs, and increased our
oil-in-place. The program involved increasing the
average Eagle Ford Shale production by 35% to
horizontal rig count from one to five by midyear
approximately 37,600 BOEPD.
and included extensive scientific data capture
such as coring, open-hole logging, micro-seismic
and 3-D seismic. We placed 21 horizontal wells on
production during the year, successfully appraising
four of six targeted stacked pay intervals and
confirming our geologic maps.
To maximize the total liquids ultimately recovered
from our acreage position, we are focused
on optimizing the spacing between wells and
improving our well completion practices.
During 2013, we tested downspacing, reducing
the spacing between wells, and added 300
2013 Annual Report 4
Once again, we are entering the year with high expectations. Our main
objective is to translate the resource growth we delivered in 2013 to
strong production and cash flow per share growth in 2014 and beyond,
potentially doubling Pioneer’s production over the next five years.
well locations to our drilling inventory. Further
with minimal incremental capital investment.
downspacing tests are underway.
We continue to drill multiple wells from a single
Over the past two years, we have worked to
improve our well completion practices and have
increased recoverable reserves by 20% to 30%
pad to reduce costs and improve efficiencies,
and our gathering and midstream strategy has
also contributed to stronger returns.
Proved Reserves and Recoverable Resource Potential
Proved Reserves
845 million BOE (MMBOE)
Additional Net Recoverable Resource Potential
10.2 billion BOE (BBOE)
180 MMBOE
450 MMBOE
9.6 BBOE
70 MMBOE
93 MMBOE
119 MMBOE
131 MMBOE
432 MMBOE
Spraberry/Wolfcamp
Eagle Ford Shale
Rockies
Mid-Continent
Other
62% of proved reserves are oil and natural
gas liquids and 38% are natural gas.
2013 Annual Report 5
We drilled our first Upper Eagle Ford Shale well
Index and the S&P E&P Index were 128% and
and are very encouraged with production rates
92%, respectively. In addition to being the top-
that are consistent with offset wells drilled into the
performing energy stock in the S&P 500 Index
Lower Eagle Ford Shale. We believe approximately
for 2013, Pioneer was the best-performing energy
25% of our acreage is prospective for the Upper
stock in the index for the past five years.
Eagle Ford Shale interval.
Other Operations
Maximizing production and minimizing costs
were the focus of our operations in the Rockies
and Mid-Continent areas, which produce
Companywide, Pioneer drilled 698 wells with
99% success. Average production from continuing
operations was up 12% for 2013 compared to 2012,
reflecting production from Alaska and the Barnett
Shale Combo area as discontinued operations.
predominantly dry natural gas. In the Barnett
Through the drill bit, Pioneer added 141 million BOE
Shale Combo play, a section of the Barnett Shale
(MMBOE) from discoveries, extensions, improved
that holds oil, natural gas liquids and natural
recovery and technical revisions of previous
gas, Pioneer drilled 40 wells, running two
estimates (excludes revisions of previous estimates
rigs and increasing average daily production
of 319 MMBOE of proved undeveloped reserves
from 7,300 BOEPD in 2012 to approximately
that are no longer expected to be drilled and
8,600 BOEPD in 2013.
30 MMBOE of positive price revisions), replacing
In order to allocate more capital to higher-
return horizontal drilling in the Spraberry/
Wolfcamp Shale, we are divesting our assets in
Alaska and the Barnett Shale Combo area. The
sale of our Alaska subsidiary for $300 million,
subject to normal closing adjustments, plus
other consideration, is expected to close during
the second quarter of 2014. The sale continues
to be subject to certain conditions, including
governmental approvals. We also announced
our intention to divest our Barnett Shale Combo
assets in February 2014.
211% of full-year 2013 production at a drill bit
finding and development cost of $19.70 per
BOE. As a result of the Company continuing to
shift its future drilling activity in the Spraberry/
Wolfcamp area from vertical drilling to more
capital-efficient horizontal drilling, we reduced
our proved undeveloped reserves related to future
vertical drilling during 2013. We expect to more
than replace the vertical reserves removed with
horizontal reserves over the next few years as we
collect additional production and well control data
from our increasing horizontal drilling activity.
Pioneer’s year-end 2013 proved reserves totaled
We continued to be among the top performers in
845 million BOE.
our peer group in total shareholder return in 2013.
Over the past five years, Pioneer’s cumulative
return to shareholders was 1,046%, significantly
ahead of both of our benchmarks—the S&P 500
Index and the S&P E&P Index. For the five-year
period, the cumulative returns for the S&P 500
Execution is Key for 2014
Once again, we are entering the year with high
expectations. Our main objective is to translate
the resource growth we delivered in 2013 to strong
production and cash flow per share growth in
2013 Annual Report 6
2014 and beyond, potentially doubling Pioneer’s
exclusively focused on meeting our continuous
production over the next five years.
drilling obligations in order to maintain our
During 2014, we expect to invest approximately
acreage position.
$3.3 billion in drilling and other capital projects,
We are increasing our horizontal rig count in the
which is almost entirely allocated to Texas-based
northern Spraberry/Wolfcamp Shale from five
activities. The capital budget is expected to be
rigs at the end of 2013 to 16 rigs by the end of
funded from forecasted operating cash flow,
the first quarter and plan to drill approximately
cash on the balance sheet and proceeds from the
140 horizontal wells while transitioning from a
planned divestitures.
Across the Spraberry/Wolfcamp Shale area, we
plan to drill approximately 250 horizontal wells
and 200 vertical wells. We expect our vertical
horizontal appraisal program to a horizontal
development program. To maximize efficiency
and reduce costs, we will utilize three-well pads to
batch drill and complete the wells.
drilling to further decline over the coming years
Pioneer plans to drill approximately 115 wells
as we continue to ramp up our horizontal drilling
in the southern joint interest area during 2014.
program. The vertical well drilling program is
We are currently testing downspacing and working
to optimize completion techniques to maximize
resource recovery. Three-well pads and batch
drilling and completions will also be used in the
south to maximize efficiency and reduce costs.
In the Eagle Ford Shale, Pioneer plans to drill
approximately 110 horizontal wells in the liquids-
rich area of the play in 2014. Most of these wells
will be drilled utilizing three-well and four-well
pads. Based on strong results in 2013, the 2014
wells will have longer lateral lengths and larger
fracture stimulations. The ability to drill more wells
with fewer rigs reflects the success of our efforts
to control costs.
In the Rockies and Mid-Continent areas, we plan
to continue our activities to control costs and
maximize production as we continue to rely on
these long-lived natural gas assets to provide
significant cash flow to fund our growth plans in
higher-returning assets.
2014 Drilling Capital by Asset
$3 billion
Northern Spraberry/Wolfcamp
Southern Wolfcamp
Eagle Ford Shale
Other
2013 Annual Report Delivering consistently strong results in the midst of rapid growth
requires talented employees who are committed to excellence.
They, too, continue to deliver beyond expectations.
7
Focus on Safety and the Environment
Valued Employees
Pioneer dedicates substantial resources to ensure
We are very pleased to be able to create jobs and
that our business and operations are performed in a
welcome new employees to the Pioneer team.
manner that respects the environment and protects
Delivering consistently strong results in the midst
people. While we have a solid track record in this
of rapid growth requires talented employees who
regard, considering our rapid growth, we realized
are committed to excellence, and we appreciate
that we needed to further enhance our focus.
their outstanding performance during 2013.
We now have three separate departments, staffed
They, too, continue to deliver beyond expectations.
We also appreciate the support of our employees
for the communities where we live and work, their
commitment to a respect-based corporate culture
and upholding our values. Pioneer was again
recognized as a top company to work for in the
Dallas/Fort Worth area, based on employee survey
results. We consider this one of our highest honors.
Pioneer is well positioned with leading acreage
holdings in two world-class unconventional plays
in Texas. These and other unconventional plays
have changed the U.S. energy landscape and offer
our country a more secure energy future. We are
proud to be a part of what was beyond anyone’s
expectations just a few years ago, and as always,
we appreciate your support.
Scott D. Sheffield
Chairman and CEO
with top-notch professionals, focusing on our
Safety, Environment and Sustainable Development
initiatives. We also established multiple committees
comprised of our Board of Directors and senior
management to provide oversight and leadership
for Pioneer’s health, safety and environmental
practices and to monitor Pioneer’s efforts to
continually promote our culture of safety and
environmental stewardship.
But our actions will speak louder than any
organizational structure, and I’m proud to say
that 2013 was a year of action, which will provide
momentum for the future. We are already seeing
improvements in safety behaviors as a result
of our Drive to Zero initiative, in which Pioneer’s
leadership is creating a workplace that strives
to be free of incidents and injuries. Our new
environmental team is kicking off a number
of initiatives, and our sustainable development
team is hard at work to reduce fresh water use
and to better quantify and minimize methane
and other emissions.
Pioneer employees are involved in a number
of collaborative efforts within our industry
and with third parties to evaluate and minimize
the environmental impact of oil and natural
gas operations, better educate those who
are interested and enhance information we
disclose publicly.
2013 Annual Report 8
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Officers
Scott D. Sheffield
Chairman and
Chief Executive Officer
Timothy L. Dove
President and
Chief Operating Officer
Mark S. Berg
Executive Vice President,
Chief of Staff
Danny L. Kellum
Executive Vice President,
Permian Operations
Denny B. Bullard
Vice President,
Operations Services
J. D. Hall
Senior Vice President,
South Texas Operations
Frank E. Hopkins
Senior Vice President,
Investor Relations
John C. Distaso
Vice President, Marketing
Robert C. Hagens
Vice President, Land
Margaret M. Montemayor
Vice President and
Chief Accounting Officer
Thomas D. Spalding
Vice President, Geoscience
Susan A. Spratlen
Vice President, Communication
Roger W. Wallace
Vice President, Federal Policy
Chris J. Cheatwood
Executive Vice President, Business
Development and Geoscience
Mark H. Kleinman
Senior Vice President, General
Counsel and Corporate Secretary
Richard P. Dealy
Executive Vice President and
Chief Financial Officer
William F. Hannes
Executive Vice President,
Southern Wolfcamp Operations
Larry N. Paulsen
Senior Vice President,
Administration and
Risk Management
Kenneth H. Sheffield, Jr.
Senior Vice President,
Operations and Engineering
Board of Directors
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(left to right) seated: Frank Risch Scott Sheffield Phoebe Wood standing: Larry Grillot Harty Gardner Ted Buchanan
Stacy Methvin Jim Watson Charles Ramsey Andy Cates Tom Arthur Tim Dove Ken Thompson
Scott D. Sheffield
Chairman and
Chief Executive Officer
Thomas D. Arthur 2,4
Former President and CEO
Havatampa Incorporated
Edison C. Buchanan 3,4
Former Managing Director
Credit Suisse First Boston
Andrew F. Cates 3,4
Managing Member
Value Acquisition Fund
Timothy L. Dove
President and
Chief Operating Officer
R. Hartwell Gardner 2,4
Retired Treasurer
Mobil Corporation
Larry R. Grillot 2,4
Dean, Mewbourne College
of Earth and Energy
The University of Oklahoma
Stacy P. Methvin 3,4
Retired Vice President
Shell Oil Company
Charles E. Ramsey, Jr. 1,3,4
Retired Energy Industry
Executive
Frank A. Risch 2,4
Retired Vice President
and Treasurer
Exxon Mobil Corporation
J. Kenneth Thompson 3,4
President and CEO
Pacific Star Energy LLC
Jim A. Watson 2,4
Senior Counsel
Carrington, Coleman,
Sloman & Blumenthal, L.L.P.
Phoebe A. Wood 2,4
Retired Vice Chairman and
Chief Financial Officer
Brown-Forman Corporation
Committee Membership:
1 Lead Director
2 Audit Committee
3 Compensation and Management
Development Committee
4 Nominating and Corporate
Governance Committee
10
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Stock Performance
The information included in the remainder of this document, including this “Stock Performance” section
of the 2013 Annual Report, is not a part of Pioneer’s Annual Report on Form 10-K for the fiscal year
ended December 31, 2013, and shall not be deemed to be “soliciting material” or to be “filed” with the
Securities and Exchange Commission (SEC). Such information shall not be deemed to be incorporated
by reference into any filing under the Securities Act of 1933 or the Securities Exchange Act of 1934,
except to the extent that Pioneer specifically incorporates such information.
The following graph and chart compare Pioneer’s cumulative total stockholder return on common stock
during the five-year period ended December 31, 2013, with cumulative total return during the same
period for the Standard & Poor’s 500 Index (“S&P 500 Index”) and the Standard & Poor’s Oil & Gas
Exploration & Production Index (the “S&P E&P Index”), as prescribed by the SEC rules. The following
graph and chart show the value, at December 31, in each of 2009, 2010, 2011, 2012 and 2013 of $100
invested at December 31, 2008, and assumes the reinvestment of all dividends:
Comparison of Five-Year Cumulative Total Return
Among Pioneer, the S&P 500 Index and the S&P E&P Index (a)
$1,200
$1,000
$800
$600
$400
$200
$0
2008
2009
2010
2011
2012
2013
Year ended December 31,
2008
2009
2010
2011
2012
2013
Pioneer
$ 100.00
$ 298.70
$ 539.10
$ 556.16
$ 663.01
$ 1,145.57
S&P 500 Index
$ 100.00
$ 126.46
$ 145.51
$ 148.59
$ 172.37
$ 228.19
S&P E&P Index
$ 100.00
$ 142.10
$ 155.28
$ 145.29
$ 150.59
$ 191.99
(a) Assumes $100 invested at December 31, 2008, in stock or index, including reinvestment of dividends.
2013 Form 10-K
BEYOND EXPECTATIONS
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT
OF 1934
For the fiscal year ended December 31, 2013
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
(State or other jurisdiction of
incorporation or organization)
5205 N. O'Connor Blvd., Suite 200, Irving, Texas
(Address of principal executive offices)
75-2702753
(I.R.S. Employer
Identification No.)
75039
(Zip Code)
Registrant's telephone number, including area code: (972) 444-9001
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Common Stock, par value $.01
Name of each exchange on which registered
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes
No
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
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
No
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and
will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this
Form 10-K or any amendment to this Form 10-K.
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.
See the definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.
Large accelerated filer
Accelerated filer
Non-accelerated filer
(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 Act). Yes
No
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by
reference to the price at which the common equity was last sold, or the average bid and asked price of such
common equity, as of the last business day of the registrant's most recently completed second fiscal quarter $ 19,865,703,072
142,916,619
Number of shares of Common Stock outstanding as of February 20, 2014
DOCUMENTS INCORPORATED BY REFERENCE:
(1) Portions of the Definitive Proxy Statement for the Company's 2013 Annual Meeting of Shareholders to be held during May 2014 are incorporated
into Part III of this report.
TABLE OF CONTENTS
Definitions of Certain Terms and Conventions Used Herein ..............................................................................................
Cautionary Statement Concerning Forward-Looking Statements.......................................................................................
PART I
Item 1.
Item 1A.
Item 1B.
Item 2.
Item 3.
Item 4.
Business..............................................................................................................................................................
General.............................................................................................................................................................
Available Information ......................................................................................................................................
Mission and Strategies .....................................................................................................................................
Business Activities...........................................................................................................................................
Marketing of Production ..................................................................................................................................
Competition, Markets and Regulations............................................................................................................
Risk Factors........................................................................................................................................................
Unresolved Staff Comments ..............................................................................................................................
Properties............................................................................................................................................................
Reserve Estimation Procedures and Audits .....................................................................................................
Proved Reserves...............................................................................................................................................
Description of Properties .................................................................................................................................
Selected Oil and Gas Information....................................................................................................................
Legal Proceedings ..............................................................................................................................................
Mine Safety Disclosures.....................................................................................................................................
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity
PART II
Securities ............................................................................................................................................................
Purchases of Equity Securities by the Issuer and Affiliated Purchasers..........................................................
Item 6.
Selected Financial Data ......................................................................................................................................
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations .............................
Financial and Operating Performance .............................................................................................................
First Quarter 2014 Outlook..............................................................................................................................
2014 Capital Budget ........................................................................................................................................
Acquisitions .....................................................................................................................................................
Divestitures and Discontinued Operations.......................................................................................................
Results of Operations.......................................................................................................................................
Capital Commitments, Capital Resources and Liquidity.................................................................................
Critical Accounting Estimates..........................................................................................................................
New Accounting Pronouncements...................................................................................................................
Quantitative and Qualitative Disclosures About Market Risk ...........................................................................
Quantitative Disclosures ..................................................................................................................................
Qualitative Disclosures ....................................................................................................................................
Financial Statements and Supplementary Data ..................................................................................................
Index to Consolidated Financial Statements....................................................................................................
Report of Independent Registered Public Accounting Firm............................................................................
Consolidated Financial Statements ..................................................................................................................
Notes to Consolidated Financial Statements....................................................................................................
Unaudited Supplementary Information............................................................................................................
Changes in and Disagreements With Accountants on Accounting and Financial Disclosure............................
Controls and Procedures.....................................................................................................................................
Management's Report on Internal Control Over Financial Reporting .............................................................
Report of Independent Registered Public Accounting Firm............................................................................
Other Information...............................................................................................................................................
Item 9.
Item 9A.
Item 7A.
Item 9B.
Item 8.
Page
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TABLE OF CONTENTS
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
Directors, Executive Officers and Corporate Governance.................................................................................
Executive Compensation....................................................................................................................................
Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters..........
Securities Authorized for Issuance Under Equity Compensation Plans ..........................................................
Certain Relationships and Related Transactions, and Director Independence...................................................
Principal Accounting Fees and Services ............................................................................................................
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PART IV
Item 15.
Exhibits, Financial Statement Schedules ...........................................................................................................
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Definitions of Certain Terms and Conventions Used Herein
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Within this Report, the following terms and conventions have specific meanings:
"BBL" means a standard barrel containing 42 United States gallons.
"BCF" means one billion cubic feet.
"BOE" means a barrel of oil equivalent and is a standard convention used to express oil and gas volumes on a comparable
oil equivalent basis. Gas equivalents are determined under the relative energy content method by using the ratio of six
thousand cubic feet of gas to one BBL of oil or natural gas liquid.
"BOEPD" means BOE per day.
"BTU" means British thermal unit, which is a measure of the amount of energy required to raise the temperature of one
pound of water one degree Fahrenheit.
"CBM" means coal bed methane.
"Conway" means the daily average natural gas liquids components as priced in Oil Price Information Services ("OPIS")
in the table "U.S. and Canada LP – Gas Weekly Averages" at Conway, Kansas.
"DD&A" means depletion, depreciation and amortization.
"Proved developed reserves" mean reserves that can be expected to be recovered through existing wells with existing
equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost
of a new well.
"Field fuel" means gas consumed to operate field equipment (primarily compressors) prior to the gas being delivered to a
sales point.
"GAAP" means accounting principles that are generally accepted in the United States of America.
"LIBOR" means London Interbank Offered Rate, which is a market rate of interest.
"MBBL" means one thousand BBLs.
"MBOE" means one thousand BOEs.
"MCF" means one thousand cubic feet and is a measure of gas volume.
"MMBBL" means one million BBLs.
"MMBOE" means one million BOEs.
"MMBTU" means one million BTUs.
"MMCF" means one million cubic feet.
"Mont Belvieu" means the daily average natural gas liquids components as priced in OPIS in the table "U.S. and Canada
LP – Gas Weekly Averages" at Mont Belvieu, Texas.
"NGL" means natural gas liquid.
"NYMEX" means the New York Mercantile Exchange.
"NYSE" means the New York Stock Exchange.
"Pioneer" or the "Company" means Pioneer Natural Resources Company and its subsidiaries.
"Pioneer Southwest" means Pioneer Southwest Energy Partners L.P. and its subsidiaries.
"Proved reserves" mean the quantities of oil and gas, which, by analysis of geosciences and engineering data, can be
estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and
under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts
providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether
deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have
commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.
(i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts,
if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous
with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.
(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons
("LKH") as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes
a lower contact with reasonable certainty.
(iii) Where direct observation from well penetrations has defined a highest known oil ("HKO") elevation and the potential
exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only
if geoscience, engineering or performance data and reliable technology establish the higher contact with reasonable certainty.
4
(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.
"SEC" means the United States Securities and Exchange Commission.
"Standardized Measure" means the after-tax present value of estimated future net cash flows of proved reserves, determined
in accordance with the rules and regulations of the SEC, using prices and costs employed in the determination of proved
reserves and a ten percent discount rate.
"Proved undeveloped reserves" means reserves that are expected to be recovered from new wells on undrilled acreage, or
from existing wells where a relatively major expenditure is required for recompletion.
(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably
certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of
economic producibility at greater distances.
(ii) Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted
indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.
(iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable to any acreage for which an
application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved
effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology
establishing reasonable certainty.
"U.S." means United States.
"VPP" means volumetric production payment.
"WTI" means West Texas intermediate, a light, sweet blend of oil produced from fields in western Texas.
With respect to information on the working interest in wells, drilling locations and acreage, "net" wells, drilling locations
and acres are determined by multiplying "gross" wells, drilling locations and acres by the Company's working interest in
such wells, drilling locations or acres. Unless otherwise specified, wells, drilling locations and acreage statistics quoted
herein represent gross wells, drilling locations or acres.
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Unless otherwise indicated, all currency amounts are expressed in U.S. dollars.
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (this "Report") contains forward-looking statements that involve risks and uncertainties.
When used in this document, the words "believes," "plans," "expects," "anticipates," "forecasts," "intends," "continue," "may,"
"will," "could," "should," "future," "potential," "estimate," or the negative of such terms and similar expressions as they relate to
the Company are intended to identify forward-looking statements, which are generally not historical in nature. The forward-
looking statements are based on the Company's current expectations, assumptions, estimates and projections about the Company
and the industry in which the Company operates. Although the Company believes that the expectations and assumptions reflected
in the forward-looking statements are reasonable as and when made, they involve risks and uncertainties that are difficult to
predict and, in many cases, beyond the Company's control. In addition, the Company may be subject to currently unforeseen risks
that may have a materially adverse effect on it. Accordingly, no assurances can be given that the actual events and results will
not be materially different from the anticipated results described in the forward-looking statements. See "Item 1. Business —
Competition, Markets and Regulations," "Item 1A. Risk Factors," "Item 7. Management's Discussion and Analysis of Financial
Condition and Results of Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for a description
of various factors that could materially affect the ability of Pioneer to achieve the anticipated results described in the forward-
looking statements. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the
date hereof. The Company undertakes no duty to publicly update these statements except as required by law.
5
PIONEER NATURAL RESOURCES COMPANY
PART I
ITEM 1.
BUSINESS
General
The Company is a large independent oil and gas exploration and production company with operations in the United States.
Pioneer is a holding company whose assets consist of direct and indirect ownership interests in, and whose business is conducted
substantially through, its subsidiaries. Pioneer's common stock is listed and traded on the NYSE under the ticker symbol "PXD."
The Company is a Delaware corporation formed in 1997. The Company's executive offices are located at 5205 N. O'Connor
Blvd., Suite 200, Irving, Texas 75039. The Company's telephone number is (972) 444-9001. The Company maintains other offices
in Anchorage, Alaska; Denver, Colorado; and Midland, Texas. At December 31, 2013, the Company had 4,203 employees, 1,985
of whom were employed in other field and plant operations and 894 of whom were employed in vertical integration activities.
Available Information
Pioneer files or furnishes annual, quarterly and current reports, proxy statements and other documents with the SEC under
the Securities Exchange Act of 1934 (the "Exchange Act"). The public may read and copy any materials that Pioneer files with
the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information
on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains an Internet website
that contains reports, proxy and information statements, and other information regarding issuers, including Pioneer, that file
electronically with the SEC. The public can obtain any documents that Pioneer files with the SEC at http://www.sec.gov.
The Company also makes available free of charge through its internet website (www.pxd.com) its Annual Reports on Form
10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or
furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after it electronically files such material
with, or furnishes it to, the SEC.
Mission and Strategies
The Company's mission is to enhance shareholder investment returns through strategies that maximize Pioneer's long-term
profitability and net asset value. The strategies employed to achieve this mission are predicated on maintaining financial flexibility,
capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions.
These strategies are anchored by the Company's interests in the long-lived Spraberry/Wolfcamp oil field; the liquid-rich Eagle
Ford Shale play; the Hugoton and West Panhandle fields; and the Raton gas field; which together have an estimated remaining
productive life in excess of 40 years. Underlying these fields are 92 percent of the Company's total proved oil and gas reserves as
of December 31, 2013.
Business Activities
The Company is an independent oil and gas exploration and production company. Pioneer's purpose is to competitively
and profitably explore for, develop and produce oil and gas reserves. In so doing, the Company sells homogenous oil, NGL and
gas units that, except for geographic and relatively minor quality differences, cannot be significantly differentiated from units
offered for sale by the Company's competitors. Competitive advantage is gained in the oil and gas exploration and development
industry by employing well-trained and experienced personnel who make prudent capital investment decisions based on
management direction, embrace technological innovation and are focused on price and cost management.
Petroleum industry. North American oil prices have been fairly consistent during the past three years despite the significant
increase in United States oil production from unconventional shale plays. The growth in North American oil production has been
offset by reduced oil imports, keeping supply and demand fairly balanced. Continued oil production growth in United States from
unconventional shale plays is expected to outpace the decline in oil imports and increase oil price volatility. The growth of
unconventional shale drilling has also substantially increased the supply of NGLs, resulting in a significant decline in NGL
component prices as the supply of such products has grown. While more export facilities have been built and NGL exports are
increasing, the overall United States demand for NGL products has not kept pace with the remaining supply of such products;
consequently, prices for NGL products have generally declined over the past three years. North American gas prices have remained
volatile and they trended lower from 2009 through 2012, but improved steadily throughout 2013. The decline in North American
gas prices was primarily a result of significant discoveries of gas and associated gas reserves in United States gas, oil and liquid-
rich shale plays, combined with the warmer than normal recent winters, which resulted in gas storage levels being at historically
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PIONEER NATURAL RESOURCES COMPANY
high levels, and minimal economic demand growth in the United States. The increases in gas prices during 2013 were primarily
related to reduced drilling activity in gas shale plays and demand increases in the latter part of the year as a result of colder weather.
Oil prices continue to be primarily driven by world supply and demand fundamentals; however, recent increases in United
States oil, NGL and gas production volumes from the Permian Basin, Eagle Ford, Bakken and Marcellus areas have been met
with lower demand, higher storage levels and pipeline, gas plant and NGL fractionation infrastructure capacity limitations, which
has led to a reduction in United States NYMEX oil, NGL and gas prices compared to international prices for similar commodities,
including Brent oil prices.
Since 2010, the economies in the United States and certain other countries have continued to stabilize with resulting
improvements in industrial demand and consumer confidence. However, other economies, such as those of certain European and
Asian nations, continue to face economic struggles or slowing economic growth. While the outlook for a continued worldwide
economic recovery remains cautiously optimistic, it is still uncertain; therefore, the sustainability of the recovery in worldwide
demand for energy is difficult to predict. As a result, the Company believes it is likely that commodity prices will continue to be
volatile during 2014.
Significant factors that will affect 2014 commodity prices include: the ongoing effect of economic stimulus initiatives;
fiscal challenges facing the United States federal government and potential changes to the tax laws in the United States; continuing
economic struggles in European and Asian nations; political and economic developments in North Africa and the Middle East;
demand from Asian and European markets; the extent to which members of the Organization of Petroleum Exporting Countries
("OPEC") and other oil exporting nations are able to manage oil supply through export quotas; the capacity of United States
refiners to absorb increasing domestic supplies of oil and condensate; potential export regulatory changes in the United States;
the supply and demand fundamentals for NGLs in the United States and the pace at which export capacity grows; and overall
North American gas supply and demand fundamentals, including refilling gas storage that is anticipated to be lower than normal
at the end of the winter draw season.
Pioneer uses commodity derivative contracts to mitigate the effect of commodity price volatility on the Company's net cash
provided by operating activities and its net asset value. Although the Company has entered into commodity derivative contracts
for a large portion of its forecasted production through 2015, a sustained lower commodity price environment would result in
lower realized prices for unprotected volumes and reduce the prices at which the Company could enter into derivative contracts
on additional volumes in the future. As a result, the Company's internal cash flows would be reduced for affected periods. A
sustained decline in commodity prices could result in a shortfall in expected cash flows, which could negatively affect the Company's
liquidity, financial position and future results of operations. See "Item 7A. Quantitative and Qualitative Disclosures About Market
Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for information regarding the Company's open derivative positions as of December 31, 2013.
The Company. The Company's growth plan is primarily anchored by horizontal drilling in the Spraberry/Wolfcamp oil
field located in West Texas and the liquid-rich Eagle Ford Shale field located in South Texas. Complementing these growth areas,
the Company has oil and gas production activities and development opportunities in the Raton gas field located in southern
Colorado, the Hugoton gas and liquid field located in southwest Kansas, the West Panhandle gas and liquid field located in the
Texas Panhandle and the Edwards gas field located in South Texas. Combined, these assets create a portfolio of resources and
opportunities that are well balanced and diversified among oil, NGL and gas, and that are also well balanced among long-lived,
dependable production and lower-risk exploration and development opportunities. The Company has a team of dedicated employees
who represent the professional disciplines and sciences that the Company believes are necessary to allow Pioneer to maximize
the long-term profitability and net asset value inherent in its physical assets.
Production. The Company focuses its efforts towards maximizing its average daily production of oil, NGLs and gas through
development drilling, production enhancement activities and acquisitions of producing properties, while minimizing the
controllable costs associated with the production activities. For the year ended December 31, 2013, the Company's production
from continuing operations of 58.9 MMBOE, excluding field fuel usage, represented a 12 percent increase over production from
continuing operations during 2012. Production, price and cost information with respect to the Company's properties for 2013,
2012 and 2011 is set forth in "Item 2. Properties — Selected Oil and Gas Information — Production, price and cost data."
Development activities. The Company seeks to increase its proved oil and gas reserves, production and cash flow through
development drilling and by conducting other production enhancement activities, such as well recompletions. During the three
years ended December 31, 2013, the Company drilled 1,850 gross (1,655 net) development wells, 99 percent of which were
successfully completed as productive wells, at a total drilling cost (net to the Company's interest) of $4.8 billion.
The Company believes that its current property base provides a substantial inventory of prospects for future reserve,
production and cash flow growth. The Company's proved reserves as of December 31, 2013 include proved undeveloped reserves
and proved developed reserves that are behind pipe of 102.5 MMBBLs of oil, 41.9 MMBBLs of NGLs and 328.9 BCF of gas.
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PIONEER NATURAL RESOURCES COMPANY
The Company believes that its proved reserves represent a significant portfolio of development opportunities. The timing of the
development of these reserves will be dependent upon commodity prices, drilling and operating costs and the Company's expected
operating cash flows and financial condition.
Exploratory activities. The Company has devoted significant efforts and resources to hiring and developing a highly skilled
geoscience staff as well as acquiring a significant portfolio of lower-risk exploration opportunities that are expected to be evaluated
and tested over the next decade and beyond. Exploratory and extension drilling involve greater risks of dry holes or failure to find
commercial quantities of hydrocarbons than development drilling or enhanced recovery activities. See "Item 1A. Risk Factors —
Exploration and development drilling may not result in commercially productive reserves" below.
Integrated services. The Company continues to expand its integrated services to control drilling and operating costs and
support the execution of its drilling program and operating activities. The Company has Company-owned fracture stimulation
fleets totaling approximately 300,000 horsepower supporting drilling operations in the Spraberry/Wolfcamp and Eagle Ford Shale
areas. 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 April 2012, Pioneer acquired a large U.S.
industrial sands company, which was renamed Premier Silica (see Note C of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for more information about the acquisition of Premier Silica). That
acquisition secured a high-quality, low-cost and logistically advantaged brown sand supply for Pioneer to use for its growing
fracture stimulation requirements in the Spraberry field.
Acquisition activities. The Company regularly seeks to acquire properties that complement its operations, provide
exploration and development opportunities and potentially provide superior returns on investment. In addition, the Company
pursues strategic acquisitions that will allow the Company to expand into new geographical areas that provide future exploration/
exploitation opportunities. During 2013, 2012 and 2011, the Company spent $76.0 million, $157.5 million and $131.9 million,
respectively, to purchase primarily undeveloped acreage for future exploitation and exploration activities.
In addition, on December 17, 2013, the Company completed the acquisition of all of the outstanding common units of
Pioneer Southwest not already owned by the Company, through a merger of a wholly-owned subsidiary of the Company into
Pioneer Southwest, the result of which was that Pioneer Southwest became a wholly-owned subsidiary of the Company. The
Pioneer Southwest merger was effected pursuant to an Agreement and Plan of Merger dated August 9, 2013, as amended on
October 25, 2013 (as amended, the "Merger Agreement"), and was approved by the holders of the common units of Pioneer
Southwest at a special meeting held on December 17, 2013. Pursuant to the Merger Agreement, all of the common units outstanding
as of the closing of the merger were canceled and converted into the right to receive 0.2325 of a share of common stock of the
Company per common unit. In December 2013 the Company issued an aggregate of 3.96 million shares of its common stock to
Pioneer Southwest unitholders. The merger is expected to facilitate the Company's plans to fully and optimally develop the
Company's Spraberry/Wolfcamp properties in the Midland Basin in West Texas utilizing horizontal drilling and is expected to
enhance the Company's organizational, operational and administrative efficiencies.
The Company periodically evaluates and pursues acquisition opportunities (including opportunities to acquire particular
oil and gas assets or entities owning oil and gas assets and opportunities to engage in mergers, consolidations or other business
combinations with such entities) and at any given time may be in various stages of evaluating such opportunities. Such stages may
take the form of internal financial analyses, oil and gas reserve analyses, due diligence, the submission of indications of interest,
preliminary negotiations, negotiation of letters of intent or negotiation of definitive agreements. The success of any acquisition is
uncertain and depends on a number of factors, some of which are outside the Company's control. See "Item 1A. Risk Factors —
The Company may be unable to make attractive acquisitions and any acquisition it completes is subject to substantial risks that
could adversely affect its business."
Asset divestitures and discontinued operations. The Company regularly reviews its asset base for the purpose of identifying
nonstrategic assets, the disposition of which would increase capital resources available for other activities and create organizational
and operational efficiencies. While the Company generally does not dispose of assets solely for the purpose of reducing debt, such
dispositions can have the result of furthering the Company's objective of increasing financial flexibility through reduced debt
levels.
During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in Pioneer's
Alaska subsidiary, representing all the Company's net assets in Alaska ("Pioneer Alaska"). The sale of Pioneer Alaska continues
to be subject to ongoing negotiations and certain other conditions, such as governmental approvals and buyer's arrangement of
financing. Associated with the planned sale of Pioneer Alaska, the Company recorded a noncash impairment charge of $539.8
million during December 2013 to reduce the carrying value of Pioneer Alaska to its estimated fair value less costs to sell of $350.6
million. The Company has classified Pioneer Alaska assets and liabilities as held for sale in the accompanying consolidated balance
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PIONEER NATURAL RESOURCES COMPANY
sheet as of December 31, 2013 and has reported Pioneer Alaska's historical results of operations, and the related impairment loss,
as discontinued operations, net of tax in the Company's accompanying consolidated statements of operations.
During the fourth quarter of 2013, the Company also committed to a plan to divest of its net assets in the Barnett Shale
field in North Texas. The plan is expected to result in the sale of the Barnett Shale net assets during 2014. Associated with the
plan to sell the Company's net assets in the Barnett Shale field, the Company recorded a noncash impairment charge of $189.5
million during December 2013 to reduce the carrying value of the Barnett Shale field net assets to their estimated fair value less
costs to sell. The Company has classified Barnett Shale assets and liabilities as held for sale in the accompanying consolidated
balance sheet as of December 31, 2013 and has reported Barnett Shale historical results of operations, and the related impairment
loss, as discontinued operations, net of tax in the Company's accompanying consolidated statements of operations.
During December 2013, the Company committed to a plan to sell its majority interest in Sendero Drilling Company, LLC
("Sendero"), the Company's vertical drilling rig subsidiary, to Sendero's minority interest owner for $31.0 million, subject to
negotiating a definitive sales agreement and the buyer completing its financing arrangements. Associated with the planned sale
of Sendero, the Company recorded a noncash loss of $25.5 million during December 2013 to reduce the carrying value of Sendero's
net assets to their estimated fair value. As part of the sales negotiations, the Company plans to commit to lease 12 Sendero rigs
through December 31, 2015 and to lease eight Sendero rigs in 2016. The Company has classified Sendero assets and liabilities
as held for sale in the accompanying consolidated balance sheet as of December 31, 2013.
The Company's plans to sell Pioneer Alaska, the Barnett Shale net assets and Sendero are in various stages of marketing
or negotiation. No assurance can be given that the sales will be completed in accordance with the Company's plans.
In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC ("Sinochem"), a U.S. subsidiary
of the Sinochem Group, an unaffiliated third party, to sell 40 percent of Pioneer's interest in 207,000 net acres leased by the
Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for consideration of $1.8 billion.
In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $623.8 million, resulting in a gain of $181.3
million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2 billion of the
transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's
joint operations with Sinochem in the horizontal Wolfcamp Shale play.
During December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest its net assets
in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell Pioneer South Africa to
an unaffiliated third party, effective January 1, 2012, for $60.0 million of cash proceeds before normal closing and other adjustments,
and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In August 2012, the Company completed
the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal closing adjustments for cash revenues
and costs and expenses from the effective date through the date of the sale, resulting in a gain of $28.6 million. The Company
classified Pioneer South Africa's results of operations as discontinued operations, net of tax in the accompanying consolidated
statements of operations.
In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources Tunisia
Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third party
for cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting in a gain of $645.2 million. The Company
classified the results of operations of Pioneer Tunisia as discontinued operations, net of tax in the accompanying consolidated
statements of operations.
The Company anticipates that it will continue to sell nonstrategic properties or other assets from time to time to increase
capital resources available for other activities, to achieve operating and administrative efficiencies and to improve profitability.
See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data"
for specific information regarding the Company's asset divestitures and discontinued operations. Also see "Item1A. Risk Factors
- The Company's ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond its control, and
in certain cases the Company may be required to retain liabilities for certain matters" for discussion of risk factors associated with
the completion of divestitures.
Marketing of Production
General. Production from the Company's properties is marketed using methods that are consistent with industry practices.
Sales prices for oil, NGL and gas production are negotiated based on factors normally considered in the industry, such as an index
or spot price, price regulations, distance from the well to the pipeline, commodity quality and prevailing supply and demand
conditions. See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for additional discussion of operations
and price risk.
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PIONEER NATURAL RESOURCES COMPANY
Significant purchasers. During 2013, the Company's significant purchasers of oil, NGLs and gas were Plains Marketing
LP (26 percent), Enterprise Products Partners L.P. (12 percent) and Occidental Energy Marketing Inc. (12 percent). The Company
believes that the loss of a significant purchaser or an inability to secure adequate pipeline, gas plant and NGL fractionation
infrastructure in its key producing areas could have a material adverse effect on its ability to sell its oil, NGL and gas production.
See "Item 1A. Risk Factors" and Note L of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for more information about significant customer and infrastructure capacity risks.
Derivative risk management activities. The Company primarily utilizes commodity swap contracts, collar contracts and
collar contracts with short puts to (i) reduce the effect of price volatility on the commodities the Company produces and sells or
consumes, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk
associated with certain capital projects. The Company also, from time to time, utilizes interest rate contracts to reduce the effect
of interest rate volatility on the Company's indebtedness. The Company accounts for its derivative contracts using the mark-to-
market ("MTM") method of accounting. See "Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations" for a description of the Company's derivative risk management activities, "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk," and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for information about the impact of commodity derivative activities on oil, NGL and gas
revenues and net derivative gains and losses during 2013, 2012 and 2011, as well as the Company's open commodity derivative
positions at December 31, 2013.
Competition, Markets and Regulations
Competition. The oil and gas industry is highly competitive. A large number of companies, including major integrated and
other independent companies, and individuals engage in the exploration for and development of oil and gas properties, and there
is a high degree of competition for oil and gas properties suitable for development or exploration. Acquisitions of oil and gas
properties have been an important element of the Company's growth. The Company intends to continue acquiring oil and gas
properties that complement its operations, provide exploration and development opportunities and potentially provide superior
returns on investment. The principal competitive factors in the acquisition of oil and gas properties include the staff and data
necessary to identify, evaluate and acquire such properties and the financial resources necessary to acquire and develop the
properties. Some of the Company's competitors are substantially larger and have financial and other resources greater than those
of the Company.
Markets. The Company's ability to produce and market oil, NGLs and gas profitably depends on numerous factors beyond
the Company's control. The effect of these factors cannot be accurately predicted or anticipated. Although the Company cannot
predict the occurrence of events that may affect these commodity prices or the degree to which these prices will be affected, the
prices for any commodity that the Company produces will generally approximate current market prices in the geographic region
of the production.
Securities regulations. Enterprises that sell securities in public markets are subject to regulatory oversight by agencies such
as the SEC and the NYSE. This regulatory oversight imposes on the Company the responsibility for establishing and maintaining
disclosure controls and procedures and internal controls over financial reporting, and ensuring that the financial statements and
other information included in submissions to the SEC do not contain any untrue statement of a material fact or omit to state a
material fact necessary to make the statements made in such submissions not misleading. Failure to comply with the rules and
regulations of the SEC could subject the Company to litigation from public or private plaintiffs. Failure to comply with the rules
of the NYSE could result in the de-listing of the Company's common stock, which would have an adverse effect on the market
price and liquidity of the Company's common stock. Compliance with some of these rules and regulations is costly, and regulations
are subject to change or reinterpretation.
Environmental and occupational health and safety matters. The Company's operations are subject to stringent and complex
federal, state and local laws and regulations governing environmental protection, worker health and safety, and the discharge of
materials into the environment. Numerous governmental entities, including the U.S. Environmental Protection Agency (the "EPA")
and analogous state agencies have the power to enforce compliance with these laws and regulations and the permits issued under
them, often requiring difficult and costly actions to achieve and maintain compliance and imposing sanctions, including
administrative, civil and criminal penalties, for any failure to comply.
These laws and regulations may, among other things:
•
•
•
require the acquisition of various permits before drilling or other regulated activity commences;
enjoin some or all of the operations of facilities deemed in noncompliance with permits;
restrict the types, quantities and concentration of various substances that can be released into the environment in
connection with oil and gas drilling, production and transportation activities;
10
PIONEER NATURAL RESOURCES COMPANY
•
•
•
•
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas;
impose specific criteria addressing worker protection;
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close
pits and plug abandoned wells; and
impose substantial liabilities for pollution resulting from operations.
These laws and regulations may also restrict the rate of oil and gas production below the rate that would otherwise be
possible. The regulatory burden on the oil and gas industry increases the cost of doing business in the industry and consequently
affects profitability. Additionally, the U.S. Congress, state legislatures and federal and state regulatory agencies frequently revise
environmental laws and regulations, and the trend in environmental regulation is to place more restrictions and limitations on
activities that may affect the environment. Any changes that result in more stringent and costly drilling, completion, construction
or water management activities, or waste handling, disposal and cleanup requirements for the oil and gas industry could have a
significant effect on the Company's capital and operating costs.
The following is a summary of some of the more significant laws and regulations to which the Company's business operations
are or may be subject.
Waste handling. The federal Resource Conservation and Recovery Act ("RCRA") and comparable state statutes regulate
the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Under the auspices
of the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own,
more stringent requirements. Drilling fluids, produced waters and most of the other wastes associated with the exploration,
development and production of oil or gas are currently regulated under RCRA's non-hazardous waste provisions. It is possible
that certain oil and gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes
in the future. Any such change could result in an increase in the Company's costs to manage and dispose of wastes, which could
have a material adverse effect on the Company's results of operations and financial position. In the course of its operations, the
Company generates some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be
regulated as hazardous wastes.
Wastes containing naturally occurring radioactive materials ("NORM") may also be generated in connection with the
Company's operations. NORM is subject primarily to individual state radiation control regulations. In addition, NORM handling
and management activities are governed by regulations promulgated by the Occupational Safety and Health Administration
("OSHA"). These state and OSHA regulations impose certain requirements concerning worker protection, with respect to NORM,
the treatment, storage and disposal of NORM waste, the management of waste piles, containers and tanks containing NORM and
restrictions on the uses of land with NORM contamination.
Comprehensive Environmental Response, Compensation, and Liability Act. The federal Comprehensive Environmental
Response, Compensation and Liability Act ("CERCLA"), also known as the Superfund law, and analogous state laws impose joint
and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for
the release of a "hazardous substance" into the environment. These persons include the current and past owner or operator of the
site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the
site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances
that have been released into the environment, for damages to natural resources and for the costs of certain health studies. CERCLA
also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment
and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring
landowners and other third-parties to file claims for personal injury and property damage allegedly caused by the hazardous
substances released into the environment.
The Company currently owns or leases numerous properties that have been used for oil and gas exploration and production
for many years. Although the Company believes it has used operating and waste disposal practices that were standard in the
industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on or under the properties
owned or leased by the Company, or on or under other locations, including off-site locations, where such substances have been
taken for recycling or disposal. In addition, some of the Company's properties have been operated by previous owners or operators
whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons were not under the Company's control.
Certain of these properties have had historical petroleum spills or releases. All of such properties and the substances disposed or
released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, the Company could be required
to remove previously disposed substances and wastes, remediate contaminated property or perform remedial plugging or pit closure
operations to prevent future contamination. If a surface spill or release were to occur, the Company expects that it would be
controlled, contained and remediated in accordance with the applicable requirements of state oil and gas commissions and by
using the Company's spill prevention, control and countermeasure ("SPCC") plans or other spill or emergency contingency plans
that it maintains in accordance with EPA requirements.
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PIONEER NATURAL RESOURCES COMPANY
Water discharges and use. The federal Water Pollution Control Act, also known as the Clean Water Act (the "CWA"), and
analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks
of oil and other substances, into waters of the United States and state waters. The discharge of pollutants into regulated waters is
prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The CWA and regulations
implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including wetlands, unless
authorized by an appropriately issued permit. SPCC planning requirements of federal laws require appropriate containment berms
and similar structures to help prevent the contamination of navigable waters by a petroleum hydrocarbon tank spill, rupture or
leak. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge
permits or other requirements of the CWA and analogous state laws and regulations.
The primary federal law imposing liability for oil spills is the Oil Pollution Act ("OPA"), which sets minimum standards
for prevention, containment and cleanup of oil spills. OPA applies to vessels, offshore facilities and onshore facilities, including
exploration and production facilities that may affect waters of the United States. Under OPA, responsible parties, including owners
and operators of onshore facilities, may be subject to oil spill cleanup costs and natural resource damages as well as a variety of
public and private damages that may result from oil spills. If an oil spill subject to the requirements of OPA were to occur at a
Company property, the Company expects that it would be controlled, contained and remediated in accordance with the applicable
requirements of OPA and by using the Company's OPA spill response plan together with the assistance of trained first responders
and any oil spill response contractor that the Company would have engaged pursuant to OPA to address such oil spills.
Operations associated with the Company's properties also produce wastewaters that are disposed by injection in underground
wells. These injection wells are regulated by the federal Safe Drinking Water Act (the "SDWA") and analogous state and local
laws. The underground injection well program under the SDWA requires permits from the EPA or analogous state agency for the
Company's disposal wells, establishes minimum standards for injection well operations, and restricts the types and quantities of
fluids that may be injected. Currently, the Company believes that disposal well operations on the Company's properties substantially
comply with all applicable requirements under the SDWA. However, a change in the regulations or the inability to obtain permits
for new injection wells in the future may affect the Company's ability to dispose of produced waters and ultimately increase the
cost of the Company's operations. For example, in some areas of Texas, there has been concern that certain formations into which
disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing Texas
regulatory agency is reviewing the data to determine whether any action is necessary to address this issue. If the Texas state agency
were to decline to issue permits for new injection wells into the formations currently utilized by the Company, the Company may
be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could
increase its costs. In addition, in response to recent seismic events near underground injection wells used for the disposal of
wastewaters, some federal and state agencies have been investigating whether such wells have caused increased seismic activity.
It is possible that federal or state agencies will seek to regulate more stringently the underground injection of oil and gas wastewaters
as a result of these events. Nevertheless, the Company is not aware of any imminent actions by federal or state agencies that would
affect its use or operation of underground injection wells due to the concern about seismic activity.
The Company also uses hydraulic fracturing techniques in virtually all of its drilling and completion programs and
development of its properties is dependent on the Company's ability to hydraulically fracture the producing formations. The process
involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and gas
production. The process is typically regulated by state oil and gas commissions, but, the EPA has asserted federal regulatory
authority over hydraulic fracturing involving diesel fuels under the SDWA Underground Injection Control Program and published
final permitting guidance in February 2014 addressing the performance of such activities. In 2011, the EPA announced its intent
to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding
the chemicals used in hydraulic fracturing, and in its Semi-annual Regulatory Agenda published in July 2013, the agency continues
to project the future issuance of an Advance Notice of Proposed Rulemaking that would seek public input on the design and scope
of such disclosure regulations. The EPA published final rules under the federal Clean Air Act ("CAA") that, among other things,
require producers to reduce volatile organic compound emissions from certain subcategories of fractured and refractured gas wells
for which well completion operations are being conducted by routing flowback emissions to a gathering line or capturing and
combusting flowback emissions using a combustion device, such as a flare, until January 1, 2015 and performing reduced emission
completions, also known as "green completions," with or without combustion devices, on or after January 1, 2015. Also, in May
2013, the federal Bureau of Land Management (the "BLM") published a supplemental notice of proposed rulemaking governing
hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals used in hydraulic
fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and development of
appropriate plans for managing flowback water that returns to the surface. In addition, the U.S. Congress, from time to time, has
considered adopting legislation intended to provide for federal regulation of hydraulic fracturing and to require disclosure of the
chemicals used in the hydraulic-fracturing process.
Certain states in which the Company operates, including Colorado and Texas, have adopted, and other states are considering
adopting, regulations that could impose new or more stringent permitting, disclosure and well-construction requirements on
12
PIONEER NATURAL RESOURCES COMPANY
hydraulic fracturing operations. In addition to state laws, local land use restrictions, such as city ordinances, may restrict or prohibit
drilling in general or hydraulic fracturing in particular. The Company believes that it follows applicable standard industry practices
and legal requirements for groundwater protection in its hydraulic fracturing activities. Nonetheless, in the event federal, state or
local restrictions are adopted in areas where the Company is currently conducting, or in the future plans to conduct operations,
the Company may incur additional costs to comply with such requirements that may be significant in nature, experience delays
or curtailment in the pursuit of exploration, development or production activities, and be limited or precluded in the drilling of
wells or in the amounts that the Company is ultimately able to produce from its reserves.
Certain governmental reviews were recently conducted or are underway that focus on environmental aspects of hydraulic
fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of
hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on
drinking water and groundwater and a draft report is expected to be available for public comments and peer review in 2014.
Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic
fracturing activities and is expected to propose these standards in 2014. These studies, or future studies, depending on their degree
of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or
other regulatory mechanisms.
The water produced by the Company's CBM operations also may be subject to the state laws and regulations of regulatory
bodies regarding the ownership and use of water. For example, in connection with the Company's CBM operations in the Raton
Basin in Colorado, water is removed from coal seams to reduce pressure and allow the methane to be recovered. Historically,
these operations have been regulated by the state agency responsible for regulating oil and gas activity in the state. Nevertheless,
in 2009, the Colorado Supreme Court affirmed a state court holding that water produced in connection with the CBM operations
should be subject to state water-use regulations administered by a different agency that regulates other uses of water in the state,
including requirements to obtain permits for diversion and use of surface and subsurface water, an evaluation of potential competing
uses of the water, and a possible requirement to provide mitigation water for other water users. The Colorado legislature and state
agency adopted laws and regulations in response to this ruling. These and other resulting changes in the regulation of water
produced from CBM operations may have an adverse effect on the costs of doing business and the ability to expand operations
by the Company or other CBM producers.
Air emissions. The CAA and comparable state laws regulate emissions of various air pollutants through air emissions
permitting programs and the imposition of other requirements. Such laws and regulations may require a facility to obtain pre-
approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the
increase of existing air emissions; obtain or strictly comply with air permits containing various emissions and operational
limitations; or utilize specific emission control technologies to limit emissions of certain air pollutants. In addition, the EPA has
developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources.
Moreover, states may impose their own air emissions limitations, which may be more stringent than the federal standards imposed
by the EPA. Federal and state regulatory agencies can also impose administrative, civil and criminal penalties for noncompliance
with air permits or other requirements of the CAA and associated state laws and regulations. The adoption of laws, regulations,
orders or other legally enforceable mandates governing oil and gas drilling and operating activities in the areas where the Company
conducts business that result in more stringent drilling or operating conditions or limit or prohibit the drilling of new wells for
any extended period of time could increase the Company's costs or reduce its production, which could have a material adverse
effect on the Company's results of operations and cash flows.
Permits and related compliance obligations under the CAA, as well as changes to state implementation plans for controlling
air emissions in regional non-attainment areas, may require the Company to incur future capital expenditures in connection with
the addition or modification of existing air emission control equipment and strategies for oil and gas exploration and production
operations. For example, in 2012, the EPA published final rules under the CAA that subject oil and gas production, processing,
transmission and storage operations to regulation under the New Source Performance Standards and National Emission Standards
for Hazardous Air Pollutants programs. With regard to production activities, these final rules require, among other things, the
reduction of volatile organic compound emissions from three subcategories of fractured and refractured gas wells for which well
completion operations are conducted: wildcat (exploratory) and delineation gas wells; low reservoir pressure non-wildcat and
non-delineation gas wells; and all "other" fractured and refractured gas wells. All three subcategories of wells must route flowback
emissions to a gathering line or capture and combust flowback emissions using a combustion device, such as a flare. However,
the "other" wells must use reduced emission completions, also known as "green completions," with or without combustion devices,
on or after January 1, 2015. These regulations also establish specific new requirements regarding emissions from production-
related wet seal and reciprocating compressors, effective October 15, 2012 and from pneumatic controllers and storage vessels,
beginning as early as October 15, 2013. Compliance with these requirements could increase the Company's costs of development
and production, which costs could be significant.
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PIONEER NATURAL RESOURCES COMPANY
Endangered species. The federal Endangered Species Act (the "ESA") and analogous state laws regulate activities that
could have an adverse effect on threatened or endangered species. Some of the Company's operations are conducted in areas where
protected species or their habitats are known to exist. In these areas, the Company may be obligated to develop and implement
plans to avoid potential adverse effects to protected species and their habitats, and the Company may be prohibited from conducting
operations in certain locations or during certain seasons, such as breeding and nesting seasons, when the Company's operations
could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling
activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The
presence of a protected species in areas where the Company performs activities could result in increased costs or limitations on
the Company's ability to perform operations and thus have an adverse effect on the Company's business.
Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011,
the U.S. Fish and Wildlife Service is required to make a determination on the potential listing of numerous species as endangered
or threatened under the ESA before completion of the agency's 2017 fiscal year. The designation of previously unprotected species
as threatened or endangered in areas where the Company operates could cause the Company to incur increased costs arising from
species protection measures or could result in limitations on the Company's drilling and production activities that could have an
adverse effect on the Company's ability to develop and produce its proved reserves.
Activities on Federal Lands. Oil and gas exploration, development and production activities on federal lands, including
Indian lands and lands administered by the BLM, are subject to the National Environmental Policy Act, as amended ("NEPA").
NEPA requires federal agencies, including the BLM, to evaluate major agency actions having the potential to significantly impact
the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential
direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact
Statement that may be made available for public review and comment. Currently, the Company has minimal exploration and
production activities on federal lands. However, for those current activities as well as for future or proposed exploration and
development plans on federal lands, governmental permits or authorizations that are subject to the requirements of NEPA are
required. This process has the potential to delay or limit, or increase the cost of, the development of oil and gas projects.
Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects.
Occupational health and safety. The Company's operations are subject to the requirements of OSHA and comparable state
statutes. These laws and the related regulations strictly govern the protection of the health and safety of employees. The OSHA
hazard communication standard, EPA community right-to-know regulations under Title III of CERCLA and similar state statues
require that the Company organize or disclose information about hazardous materials used or produced in the Company's operations.
In addition, the Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, as amended
by the Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on
numerous aspects of mineral extraction and processing operations, including the training of personnel, operating procedures,
operating equipment and other matters. The Company believes that it is in substantial compliance with these applicable standards
and with OSHA and comparable requirements.
Climate change. In 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse
gases ("GHGs") present an endangerment to public health and the environment because emissions of such gases are, according
to the EPA, contributing to warming of the Earth's atmosphere and other climatic changes. Based on these findings, the EPA has
adopted regulations under the CAA establishing Title V and Prevention of Significant Deterioration ("PSD") permitting
requirements for large sources of GHGs. The Company could become subject to these permitting requirements and be required
to install "best available control technology" to limit emissions of GHGs from any new or significantly modified facilities that the
Company may seek to construct in the future if they would otherwise emit large volumes of GHGs. The EPA has also adopted
rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the United States,
including certain oil and gas production facilities, which includes certain of the Company's facilities. The Company is monitoring
GHG emissions from its operations in accordance with these GHG emissions reporting rules and believes its monitoring activities
are in substantial compliance with applicable reporting obligations.
While the U.S. Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been
significant activity in the form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence
of federal climate legislation in the United States, a number of state and regional efforts have emerged that are aimed at tracking
or reducing GHG emissions by means of cap and trade programs that typically require major sources of GHG emissions, such as
electric power plants, to acquire and surrender emission allowances in return for emitting those GHGs. If the U.S. Congress
undertakes comprehensive tax reform in the coming year, it is possible that such reform may include a carbon tax, which could
impose additional direct costs on the Company's operations.
Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG
emissions would affect the Company's business, any such future laws and regulations could require the Company to incur increased
14
PIONEER NATURAL RESOURCES COMPANY
operating costs, such as costs to purchase and operate emissions control systems, acquire emissions allowances or comply with
new regulatory or reporting requirements including the imposition of a carbon tax. Any such legislation or regulatory programs
could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could reduce the demand for the
oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have
an adverse effect on the Company's business, financial condition and results of operations.
Some scientists have concluded that increasing concentrations of GHGs in the Earth's atmosphere may produce climate
changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods and other
climatic events. If any such effects were to occur, they could have an adverse effect on the Company's financial condition and
results of operations.
Other regulation of the oil and gas industry. The oil and gas industry is regulated by numerous federal, state and local
authorities. Legislation affecting the oil and gas industry is under constant review for amendment or expansion, frequently increasing
the regulatory burden. Also, numerous federal and state departments and agencies are authorized by statute to issue rules and
regulations binding on the oil and gas industry and its individual members, some of which carry substantial penalties for failure
to comply. Although the regulatory burden on the oil and gas industry may increase the Company's cost of doing business by
increasing the cost of production, the Company believes that these burdens generally do not affect the Company any differently
or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of
production.
Development and production. Development and production operations are subject to various types of regulation at federal,
state and local levels. These types of regulation include requiring permits for the drilling of wells, the posting of bonds in connection
with various types of activities and filing reports concerning operations. Most states, and some counties and municipalities, in
which the Company operates also regulate one or more of the following:
•
•
•
•
•
•
the location of wells;
the method of drilling and casing wells;
the method and ability to fracture stimulate wells;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and gas
properties. Some states allow forced pooling or integration of tracts to facilitate development while other states rely on voluntary
pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce
the Company's interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from
oil and gas wells, generally prohibit the venting or flaring of gas and impose requirements regarding the ratability of production.
These laws and regulations may limit the amount of oil and gas the Company can produce from the Company's wells or limit the
number of wells or the locations at which the Company can drill. Moreover, each state generally imposes a production or severance
tax with respect to the production and sale of oil, NGL and gas within its jurisdiction. States do not regulate wellhead prices or
engage in other similar direct regulation, but there can be no assurance that they will not do so in the future. The effect of such
future regulations may be to limit the amounts of oil and gas that may be produced from the Company's wells, negatively affect
the economics of production from these wells, or limit the number of locations the Company can drill.
Regulation of transportation and sale of gas. The availability, terms and cost of transportation significantly affect sales of
gas. Federal and state regulations govern the price and terms for access to gas pipeline transportation. Intrastate gas pipeline
transportation activities are subject to various state laws and regulations, as well as orders of state regulatory bodies. The interstate
transportation and sale of gas is subject to federal regulation, including regulation of the terms, conditions and rates for interstate
transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission ("FERC"). FERC
endeavors to make gas transportation more accessible to gas buyers and sellers on an open-access and non-discriminatory basis.
Pursuant to the Energy Policy Act of 2005 ("EPAct 2005") it is unlawful for "any entity," including producers such as the
Company, that are otherwise not subject to FERC's jurisdiction under the Natural Gas Act (the "NGA"), to use any deceptive or
manipulative device or contrivance in connection with the purchase or sale of gas or the purchase or sale of transportation services
subject to regulation by FERC, in contravention of rules prescribed by FERC. FERC's rules implementing this provision make it
unlawful, in connection with the purchase or sale of gas subject to the jurisdiction of FERC, or the purchase or sale of transportation
services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to use or employ any device, scheme or artifice
to defraud; to make any untrue statement of material fact or omit to make any such statement necessary to make the statements
made not misleading; or to engage in any act or practice that operates as a fraud or deceit upon any person. EPAct 2005 also gives
FERC authority to impose civil penalties of up to $1.0 million per day for each violation of the NGA or the Natural Gas Policy
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PIONEER NATURAL RESOURCES COMPANY
Act of 1978. The anti-manipulation rule applies to activities of entities not otherwise subject to FERC's jurisdiction to the extent
the activities are conducted "in connection with" gas sales, purchases or transportation subject to FERC jurisdiction, which includes
the annual reporting requirements under Order 704 (defined below).
In December 2007, FERC issued a final rule on the annual gas transaction reporting requirements, as amended by subsequent
orders on rehearing ("Order 704"). Under Order 704, any market participant, including a producer such as the Company, that
engages in wholesale sales or purchases of gas that equal or exceed 2.2 million MMBTUs of physical gas in the previous calendar
year must annually report such sales and purchases to FERC on Form No. 552 on May 1 of each year. Form No. 552 contains
aggregate volumes of gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute
to or may contribute to the formation of price indices. It is the responsibility of the reporting entity to determine which individual
transactions should be reported based on the guidance of Order 704. Order 704 is intended to increase the transparency of the
wholesale gas markets and to assist FERC in monitoring those markets and in detecting market manipulation.
Additional proposals and proceedings that might affect the gas industry are considered from time to time by the U.S.
Congress, FERC, state regulatory bodies and the courts. The Company cannot predict when or if any such proposals might become
effective or their effect, if any, on its operations. The Company does not believe that it will be affected by any action taken in a
materially different way than other gas producers, gatherers and marketers with which it competes.
Natural gas processing. The Company's gas processing operations are not subject to FERC or state regulation. There can
be no assurance that the Company's processing operations will continue to be exempt from regulation in the future. However,
although the processing facilities may not be directly related, other laws and regulations may affect the availability of gas for
processing, such as state regulation of production rates and maximum daily production allowable from gas wells, which could
impact the Company's processing business.
Gas gathering. Section 1(b) of the NGA exempts gas gathering facilities from FERC's jurisdiction. The Company believes
that its gathering facilities meet the traditional tests FERC has used to establish a pipeline system's status as a non-jurisdictional
gatherer. There is, however, no bright-line test for determining the jurisdictional status of pipeline facilities. Moreover, the
distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of litigation
from time to time, so the classification and regulation of some of the Company's gathering facilities may be subject to change
based on future determinations by FERC and the courts. Thus, the Company cannot guarantee that the jurisdictional status of its
gas gathering facilities will remain unchanged.
While the Company owns or operates some gas gathering facilities, the Company also depends on gathering facilities owned
and operated by third parties to gather production from its properties, and therefore the Company is affected by the rates charged
by these third parties for gathering services. To the extent that changes in federal or state regulation affect the rates charged for
gathering services, the Company also may be affected by these changes. Accordingly, the Company does not anticipate that the
Company would be affected any differently than similarly situated gas producers.
Regulation of transportation and sale of oil and NGLs. The liquids industry is also extensively regulated by numerous
federal, state and local authorities. In a number of instances, the ability to transport and sell such products on interstate pipelines
is dependent on pipelines whose rates, terms and conditions of service are subject to FERC jurisdiction under the Interstate
Commerce Act (the "ICA"). The Company does not believe these regulations affect it any differently than other producers.
The ICA requires that pipelines maintain a tariff on file with FERC. The tariff sets forth the established rates as well as the
rules and regulations governing the service. The ICA requires, among other things, that rates and terms and conditions of service
on interstate common carrier pipelines be "just and reasonable." Such pipelines must also provide jurisdictional service in a manner
that is not unduly discriminatory or unduly preferential. Shippers have the power to challenge new and existing rates and terms
and conditions of service before FERC.
Rates of interstate liquids pipelines are currently regulated by FERC primarily through an annual indexing methodology,
under which pipelines increase or decrease their rates in accordance with an index adjustment specified by FERC. For the five-
year period beginning in 2010, FERC established an annual index adjustment equal to the change in the producer price index for
finished goods plus 2.65 percent. This adjustment is subject to review every five years. Under FERC's regulations, a liquids
pipeline can request a rate increase that exceeds the rate obtained through application of the indexing methodology by using a
cost-of-service approach, but only after the pipeline establishes that a substantial divergence exists between the actual costs
experienced by the pipeline and the rates resulting from application of the indexing methodology. Increases in liquids transportation
rates may result in lower revenue and cash flows for the Company.
In addition, due to common carrier regulatory obligations of liquids pipelines, capacity must be prorated among shippers
in an equitable manner in the event there are nominations in excess of capacity by current shippers or capacity requests are received
from a new shipper. Therefore, new shippers or increased volume by existing shippers may reduce the capacity available to the
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PIONEER NATURAL RESOURCES COMPANY
Company. Any prolonged interruption in the operation or curtailment of available capacity of the pipelines that the Company relies
upon for liquids transportation could have a material adverse effect on its business, financial condition, results of operations and
cash flows. However, the Company believes that access to liquids pipeline transportation services generally will be available to
it to the same extent as to its similarly-situated competitors.
Intrastate liquids pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for
intrastate liquids pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate liquids pipeline rates,
varies from state to state. The Company believes that the regulation of liquids pipeline transportation rates will not affect its
operations in any way that is materially different from the effects on its similarly-situated competitors.
In November 2009, the Federal Trade Commission ("FTC") issued regulations pursuant to the Energy Independence and
Security Act of 2007 intended to prohibit market manipulation in the petroleum industry. Violators of the regulations face civil
penalties of up to $1.0 million per violation per day. In July 2010, the U.S. Congress passed the Dodd-Frank Wall Street Reform
and Consumer Protection Act, which incorporated an expansion of the authority of the Commodity Futures Trading Commission
("CFTC") to prohibit market manipulation in the markets regulated by the CFTC. This authority, with respect to oil swaps and
futures contracts, is similar to the anti-manipulation authority granted to the FERC with respect to anti-manipulation in the gas
industry and the FTC with respect to oil purchases and sales, as described above. In July 2011, the CFTC issued final rules to
implement their new anti-manipulation authority. The rules subject violators to a civil penalty of up to the greater of $1.0 million
or triple the monetary gain to the person for each violation.
Energy commodity prices. Sales prices of oil, condensate, NGLs and gas are not currently regulated and are made at market
prices. Although prices of these energy commodities are currently unregulated, the U.S. Congress historically has been active in
their regulation. The Company cannot predict whether new legislation to regulate oil and gas might actually be enacted by the
U.S. Congress or the various state legislatures, and what effect, if any, the proposals might have on the Company's operations.
Transportation of hazardous materials. The federal Department of Transportation has adopted regulations requiring that
certain entities transporting designated hazardous materials develop plans to address security risks related to the transportation of
hazardous materials. The Company does not believe that these requirements will have an adverse effect on the Company or its
operations. The Company cannot provide any assurance that the security plans required under these regulations would protect
against all security risks and prevent an attack or other incident related to the Company's transportation of hazardous materials.
ITEM 1A. RISK FACTORS
The nature of the business activities conducted by the Company subjects it to certain hazards and risks. The following is a
summary of some of the material risks relating to the Company's business activities. Other risks are described in "Item 1. Business
— Competition, Markets and Regulations," "Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations" and "Item 7A. Quantitative and Qualitative Disclosures About Market Risk." These risks are not the only risks
facing the Company. The Company's business could also be affected by additional risks and uncertainties not currently known to
the Company or that it currently deems to be immaterial. If any of these risks actually occurs, it could materially harm the Company's
business, financial condition or results of operations and impair the Company's ability to implement business plans or complete
development activities as scheduled. In that case, the market price of the Company's common stock could decline.
The prices of oil, NGL and gas are highly volatile. A sustained decline in these commodity prices could adversely affect the
Company's financial condition and results of operations.
The Company's revenues, profitability, cash flow and future rate of growth are highly dependent on commodity prices.
Commodity prices may fluctuate widely in response to relatively minor changes in the supply of and demand for oil, NGL and
gas, market uncertainty and a variety of additional factors that are beyond the Company's control, such as:
domestic and worldwide supply of and demand for oil, NGL and gas;
inventory levels at Cushing, Oklahoma, the benchmark for WTI oil prices;
oil, NGL and gas inventory levels in the United States;
the capacity of U.S. refiners to absorb increasing domestic supplies of oil and condensate;
•
•
•
•
• weather conditions;
•
overall domestic and global political and economic conditions, including laws, regulations and administrative policies
that restrict the export of the Company's products;
actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
the effect of liquefied natural gas deliveries to and exports from the United States;
technological advances affecting energy consumption and energy supply;
domestic and foreign governmental regulations and taxation;
•
•
•
•
17
PIONEER NATURAL RESOURCES COMPANY
•
•
•
the effect of energy conservation efforts;
the proximity, capacity, cost and availability of pipelines and other transportation facilities; and
the price and availability of alternative fuels.
In the past, commodity prices have been extremely volatile, and the Company expects this volatility to continue. For example,
during 2013, oil prices fluctuated from a low of $86.68 per BBL in April to a high of $110.53 per BBL in September, while gas
prices fluctuated from a low of $3.11 per MCF in January to a high of $4.46 per MCF in December. During 2012, oil prices
fluctuated from a high of $109.77 per BBL in February to a low of $77.69 per BBL in June, while gas prices fluctuated from a
low of $1.91 per MCF in April to a high of $3.90 per MCF in November. The Company makes price assumptions that are used
for planning purposes, and a significant portion of the Company's cash outlays, including rent, salaries and noncancelable capital
commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments
were based, the Company's financial results are likely to be adversely and disproportionately affected because these cash outlays
are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
Significant or extended price declines could also adversely affect the amount of oil, NGL and gas that the Company can
produce economically. A reduction in production could result in a shortfall in expected cash flows and require the Company to
reduce capital spending or borrow funds to cover any such shortfall. Any of these factors could negatively affect the Company's
ability to replace its production and its future rate of growth.
The Company could experience periods of higher costs if commodity prices rise. These increases could reduce the Company's
profitability, cash flow and ability to complete development activities as planned.
Historically, the Company's capital and operating costs have risen during periods of increasing oil, NGL and gas prices.
These cost increases result from a variety of factors beyond the Company's control, such as increases in the cost of electricity,
steel and other raw materials that the Company and its vendors rely upon; increased demand for labor, services and materials as
drilling activity increases; and increased taxes. Increased levels of drilling activity in the oil and gas industry in recent periods
have led to increased costs of some drilling equipment, materials and supplies. Such costs may rise faster than increases in the
Company's revenue, thereby negatively impacting the Company's profitability, cash flow and ability to complete development
activities as scheduled and on budget. This impact may be magnified to the extent that the Company's ability to participate in the
commodity price increases is limited by its derivative risk management activities.
The Company's derivative risk management activities could result in financial losses.
To mitigate the effect of commodity price volatility on the Company's net cash provided by operating activities, support
the Company's annual capital budgeting and expenditure plans and reduce commodity price risk associated with certain capital
projects, the Company's strategy is to enter into derivative arrangements covering a portion of its oil, NGL and gas production.
These derivative arrangements are subject to MTM accounting treatment, and the changes in fair market value of the contracts
are reported in the Company's statements of operations each quarter, which may result in significant noncash gains or losses. These
derivative contracts may also expose the Company to risk of financial loss in certain circumstances, including when:
•
•
•
production is less than the contracted derivative volumes;
the counterparty to the derivative contract defaults on its contract obligations; or
the derivative contracts limit the benefit the Company would otherwise receive from increases in commodity prices.
On the other hand, failure to protect against declines in commodity prices exposes the Company to reduced liquidity when
prices decline.
The failure by counterparties to the Company's derivative risk management activities to perform their obligations could have
a material adverse effect on the Company's results of operations.
The use of derivative risk management transactions involves the risk that the counterparties will be unable to meet the
financial terms of such transactions. If any of these counterparties were to default on its obligations under the Company's derivative
arrangements, such a default could have a material adverse effect on the Company's results of operations, and could result in a
larger percentage of the Company's future production being subject to commodity price changes.
Exploration and development drilling may not result in commercially productive reserves.
Drilling involves numerous risks, including the risk that no commercially productive oil or gas reservoirs will be encountered.
The cost of drilling, completing and operating wells is often uncertain and drilling operations may be curtailed, delayed or canceled,
or become costlier, as a result of a variety of factors, including:
•
unexpected drilling conditions;
18
PIONEER NATURAL RESOURCES COMPANY
•
•
•
•
•
•
unexpected pressure or irregularities in formations;
equipment failures or accidents;
fracture stimulation accidents or failures;
adverse weather conditions;
restricted access to land for drilling or laying pipelines; and
access to, and the cost and availability of, the equipment, services, resources and personnel required to complete the
Company's drilling, completion and operating activities.
The Company's future drilling activities may not be successful and, if unsuccessful, such failure could have an adverse
effect on the Company's future results of operations and financial condition. While all drilling, whether developmental, extension
or exploratory, involves these risks, exploratory and extension drilling involves greater risks of dry holes or failure to find
commercial quantities of hydrocarbons. The Company expects that it will continue to experience exploration and abandonment
expense in 2014.
Future price declines could result in a reduction in the carrying value of the Company's proved oil and gas properties, which
could adversely affect the Company's results of operations.
Declines in commodity prices may result in the Company having to make substantial downward adjustments to its estimated
proved reserves. If this occurs, or if the Company's estimates of production or economic factors change, accounting rules may
require the Company to impair, as a noncash charge to earnings, the carrying value of the Company's oil and gas properties. The
Company is required to perform impairment tests on proved oil and gas properties whenever events or changes in circumstances
indicate that the carrying value of proved properties may not be recoverable. To the extent such tests indicate a reduction of the
estimated useful life or estimated future cash flows of the Company's oil and gas properties, the carrying value may not be
recoverable and therefore an impairment charge would be required to reduce the carrying value of the proved properties to their
fair value. For example, during 2013, 2012 and 2011, the Company recognized impairment charges of $1.5 billion, $532.6 million
and $354.4 million, respectively, due to the impairment of the Company's Raton field, Barnett Shale field, and Edwards and Austin
Chalk gas fields in South Texas, respectively, due to declines in long-term gas prices and downward adjustments to the economically
recoverable resource potential. The Company may incur impairment charges in the future, which could materially affect the
Company's results of operations in the period incurred.
The Company periodically evaluates its unproved oil and gas properties and could be required to recognize noncash charges
in the earnings of future periods.
At December 31, 2013, the Company carried unproved oil and gas property costs of $123.4 million. GAAP requires periodic
evaluation of these costs on a project-by-project basis. These evaluations are affected by the results of exploration activities,
commodity price outlooks, planned future sales or expiration of all or a portion of the leases, and contracts and permits appurtenant
to such projects. If the quantity of potential reserves determined by such evaluations is not sufficient to fully recover the cost
invested in each project, the Company will recognize noncash charges in the earnings of future periods.
The Company periodically evaluates its goodwill for impairment and could be required to recognize noncash charges in the
earnings of future periods.
At December 31, 2013, the Company carried goodwill of $274.3 million. Goodwill is assessed for impairment annually
during the third quarter and whenever facts or circumstances indicate that the carrying value of the Company's goodwill may be
impaired, which may require an estimate of the fair values of the reporting unit's assets and liabilities. Those assessments may be
affected by (a) additional reserve adjustments both positive and negative, (b) results of drilling activities, (c) management's outlook
for commodity prices and costs and expenses, (d) changes in the Company's market capitalization, (e) changes in the Company's
weighted average cost of capital and (f) changes in income taxes. If the fair value of the reporting unit's net assets is not sufficient
to fully support the goodwill balance in the future, the Company will reduce the carrying value of goodwill for the impaired value,
with a corresponding noncash charge to earnings in the period in which goodwill is determined to be impaired.
The Company may be unable to make attractive acquisitions, and any acquisition it completes is subject to substantial risks
that could adversely affect its business.
Acquisitions of producing oil and gas properties have from time to time contributed to the Company's growth. The Company's
growth following the full development of its existing property base could be impeded if it is unable to acquire additional oil and
gas reserves on a profitable basis. Acquisition opportunities in the oil and gas industry are very competitive, which can increase
the cost of, or cause the Company to refrain from, completing acquisitions. The success of any acquisition will depend on a number
of factors and involves potential risks, including among other things:
19
PIONEER NATURAL RESOURCES COMPANY
•
•
•
•
•
•
the inability to estimate accurately the costs to develop the reserves, the recoverable volumes of reserves, rates of future
production and future net cash flows attainable from the reserves;
the assumption of unknown liabilities, losses or costs for which the Company is not indemnified or for which the
indemnity the Company receives is inadequate;
the validity of assumptions about costs, including synergies;
the effect on the Company's liquidity or financial leverage of using available cash or debt to finance acquisitions;
the diversion of management's attention from other business concerns; and
an inability to hire, train or retain qualified personnel to manage and operate the Company's growing business and
assets.
All of these factors affect whether an acquisition will ultimately generate cash flows sufficient to provide a suitable return
on investment. Even though the Company performs a review of the properties it seeks to acquire that it believes is consistent with
industry practices, such reviews are often limited in scope. As a result, among other risks, the Company's initial estimates of
reserves may be subject to revision following an acquisition, which may materially and adversely affect the desired benefits of
the acquisition.
The Company's ability to complete dispositions of assets, or interests in assets, may be subject to factors beyond its control,
and in certain cases the Company may be required to retain liabilities for certain matters.
From time to time, the Company sells an interest in a strategic asset for the purpose of assisting or accelerating the asset's
development. In addition, the Company regularly reviews its property base for the purpose of identifying nonstrategic assets, the
disposition of which would increase capital resources available for other activities and create organizational and operational
efficiencies. Various factors could materially affect the ability of the Company to dispose of such interests or nonstrategic assets
or complete announced dispositions, including the receipt of approvals of governmental agencies or third parties and the availability
of purchasers willing to acquire the interests or purchase the nonstrategic assets on terms and at prices acceptable to the Company.
Sellers typically retain certain liabilities or indemnify buyers for certain matters. The magnitude of any such retained liability
or indemnification obligation may be difficult to quantify at the time of the transaction and ultimately may be material. Also, as
is typical in divestiture transactions, third parties may be unwilling to release the Company from guarantees or other credit support
provided prior to the sale of the divested assets. As a result, after a divestiture, the Company may remain secondarily liable for
the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.
The Company's gas processing operations are subject to operational risks, which could result in significant damages and the
loss of revenue.
As of December 31, 2013, the Company owned interests in six gas processing plants and nine treating facilities. The
Company is the operator of two of the gas processing plants and all nine of the treating facilities. There are significant risks
associated with the operation of gas processing plants. Gas and NGLs are volatile and explosive and may include carcinogens.
Damage to or improper operation of a gas processing plant or facility could result in an explosion or the discharge of toxic gases,
which could result in significant damage claims in addition to interrupting a revenue source.
The Company's operations involve many operational risks, some of which could result in unforeseen interruptions to the
Company's operations and substantial losses to the Company for which the Company may not be adequately insured.
The Company's operations, including well stimulation and completion activities, such as hydraulic fracturing, are subject
to all the risks normally incident to the oil and gas development and production business, including:
•
•
•
•
•
•
•
•
•
•
•
blowouts, cratering, explosions and fires;
adverse weather effects;
environmental hazards, such as gas leaks, oil spills, pipeline and vessel ruptures, encountering NORM, and unauthorized
discharges of toxic gases, brine, well stimulation and completion fluids or other pollutants into the surface and subsurface
environment;
high costs, shortages or delivery delays of equipment, labor or other services or water for hydraulic fracturing;
facility or equipment malfunctions, failures or accidents;
title problems;
pipe or cement failures or casing collapses;
compliance with environmental and other governmental requirements;
lost or damaged oilfield workover and service tools;
unusual or unexpected geological formations or pressure or irregularities in formations; and
natural disasters.
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PIONEER NATURAL RESOURCES COMPANY
The Company's overall exposure to operational risks may increase as its drilling activity expands and as it seeks to directly
provide drilling, fracture stimulation and other services internally. Any of these risks could result in substantial losses to the
Company due to injury or loss of life, damage to or destruction of wells, production facilities or other property, clean-up
responsibilities, regulatory investigations and penalties and suspension of operations.
The Company is not fully insured against certain of the risks described above, either because such insurance is not available
or because of the high premium costs and deductibles associated with obtaining such insurance. Additionally, the Company relies
to a large extent on facilities owned and operated by third-parties, and damage to or destruction of those third-party facilities could
affect the ability of the Company to produce, transport and sell its hydrocarbons.
Part of the Company's strategy involves using some of the latest available horizontal drilling and completion techniques, which
involve risks and uncertainties in their application.
The Company's operations involve utilizing some of the latest drilling and completion techniques as developed by it and
its service providers. Risks that the Company faces while drilling horizontal wells include, but are not limited to, the following:
•
•
•
•
landing the wellbore in the desired drilling zone;
staying in the desired drilling zone while drilling horizontally through the formation;
running casing the entire length of the wellbore; and
being able to run tools and other equipment consistently through the horizontal wellbore.
Risks that the Company faces while completing wells include, but are not limited to, the following:
•
•
•
the ability to fracture stimulate the planned number of stages;
the ability to run tools the entire length of the wellbore during completion operations; and
the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.
The results of drilling in emerging areas are more uncertain initially than drilling results in areas that are more developed
and have a longer history of established production. New discoveries and emerging formations have limited or no production
history and, consequently, the Company is more limited in assessing future drilling results in these areas. If the Company's drilling
results are worse than anticipated, the return on investment for a particular project may not be as attractive as anticipated and the
Company may recognize noncash impairment charges to reduce the carrying value of its unproved properties.
The Company's expectations for future drilling activities will be realized over several years, making them susceptible to
uncertainties that could materially alter the occurrence or timing of such activities.
The Company has identified drilling locations and prospects for future drilling opportunities, including development,
exploratory and infill drilling activities. These drilling locations and prospects represent a significant part of the Company's future
drilling plans. For example, the Company's proved reserves as of December 31, 2013 include proved undeveloped reserves and
proved developed reserves that are behind pipe of 102.5 MMBBLs of oil, 41.9 MMBBLs of NGLs and 328.9 BCF of gas. The
Company's ability to drill and develop these locations depends on a number of factors, including the availability of capital, seasonal
conditions, regulatory approvals, negotiation of agreements with third parties, commodity prices, costs, access to and availability
of equipment, services, resources and personnel and drilling results. Changes in the laws or regulations on which the Company
relies in planning and executing its drilling programs could adversely impact the Company's ability to successfully complete those
programs. For example, under current Texas laws and regulations the Company may receive permits to drill, and may drill and
complete, certain horizontal wells that traverse one or more units and/or leases; a change in those laws or regulations could adversely
impact the Company's ability to drill those wells. Because of these uncertainties, the Company cannot give any assurance as to
the timing of these activities or that they will ultimately result in the realization of proved reserves or meet the Company's
expectations for success. As such, the Company's actual drilling activities may materially differ from the Company's current
expectations, which could have a significant adverse effect on the Company's proved reserves, financial condition and results of
operations.
The Company may not be able to obtain access on commercially reasonable terms or otherwise to pipelines and storage facilities,
gas gathering systems and other transportation, processing, fractionation and refining facilities to market its oil, NGL and gas
production; the Company relies on a limited number of purchasers for a majority of its products.
The marketing of oil, NGL and gas production depends in large part on the availability, proximity and capacity of pipelines
and storage facilities, gas gathering systems and other transportation, processing, fractionation and refining facilities, as well as
the existence of adequate markets. If there were insufficient capacity available on these systems, if these systems were unavailable
to the Company, or if access to these systems were to become commercially unreasonable, the price offered for the Company's
production could be significantly depressed, or the Company could be forced to shut in some production or delay or discontinue
21
PIONEER NATURAL RESOURCES COMPANY
drilling plans and commercial production following a discovery of hydrocarbons while it constructs its own facility or awaits the
availability of third party facilities. The Company also relies (and expects to rely in the future) on facilities developed and owned
by third parties in order to store, process, transport, fractionate and sell its oil, NGL and gas production. The Company's plans to
develop and sell its oil and gas reserves could be materially and adversely affected by the inability or unwillingness of third parties
to provide sufficient transportation, storage or processing and fractionation facilities to the Company, especially in areas of planned
expansion where such facilities do not currently exist.
For example, following Hurricanes Gustav and Ike in 2008, certain Permian Basin gas processors were forced to shut down
their plants due to the shutdown of the Texas Gulf Coast NGL fractionators. The Company was able to produce its oil wells and
vent or flare the associated gas; however, there is no certainty the Company will be able to vent or flare gas in the future due to
potential changes in regulations. The amount of oil and gas that can be produced is subject to limitation in certain circumstances,
such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering,
transportation, refining or processing facilities, or lack of capacity on such facilities. The Company has periodically experienced
high line pressure at its tank batteries, which has occasionally led to the flaring of gas due to the inability of the gas gathering
systems in the areas to support the increased gas production. The curtailments arising from these and similar circumstances may
last from a few days to several months, and in many cases, the Company may be provided only limited, if any, notice as to when
these circumstances will arise and their duration.
To the extent that the Company enters into transportation contracts with gas pipelines that are subject to FERC regulation,
the Company is subject to FERC requirements related to use of such capacity. Any failure on the Company's part to comply with
FERC's regulations and policies or with an interstate pipeline's tariff could result in the imposition of civil and criminal penalties.
A limited number of companies purchase a majority of the Company's oil, NGLs and gas. The loss of a significant purchaser
could have a material adverse effect on the Company's ability to sell its production.
The Company is growing production in areas of high industry activity, which may affect its ability to obtain the personnel,
equipment, services, resources and facilities access needed to complete its development activities as planned or result in increased
costs.
The Company's operations and drilling activity are concentrated in areas in which industry activity has increased rapidly,
particularly in the Spraberry field in West Texas and the Eagle Ford Shale play in South Texas. As a result, demand for personnel,
equipment, power, services and resources, as well as access to transportation, processing and refining facilities in these areas, has
increased, as have the costs for those items. In addition, hydraulic fracturing and other operations require significant quantities of
water, which supply may be affected by drought conditions. Any delay or inability to secure the personnel, equipment, power,
services, resources and facilities access necessary for the Company to complete its planned development activities, including the
result of any changes in laws or regulations applicable to the Company's operations relating to water usage, could result in oil and
gas production volumes being below the Company's forecasted volumes. In addition, any such negative effect on production
volumes, or significant increases in costs, could have a material adverse effect on the Company's cash flow and profitability.
The refining industry may be unable to absorb rising U.S. oil and condensate production; in such a case, the resulting surplus
could depress prices and restrict the availability of markets.
Under U.S. law and regulations, the export of oil and certain condensates is restricted. Absent a change in this law or an
expansion of U.S. refining capacity, rising U.S. production of oil and condensate could result in a surplus of these products, which
would likely cause prices for these commodities to fall and markets to constrict. In such circumstances, the returns on the Company’s
capital projects would decline, possibly to levels that would make execution of the Company’s drilling plans uneconomical, and
a lack of market for the Company's products could require that the Company shut in some portion of its production. If this were
to occur, the Company’s production and cash flow could decrease, or could increase less than forecasted, which could have a
material adverse effect on the Company's cash flow and profitability.
The nature of the Company's assets and production operations exposes it to significant costs and liabilities with respect to
environmental and occupational health and safety matters.
The oil and gas business involves the production, handling, sale and disposal of environmentally sensitive materials and is
subject to environmental hazards, such as oil spills, produced water spills, gas leaks, pipeline and vessel ruptures and unauthorized
discharges of substances or gases, that could expose the Company to substantial liability due to pollution and other environmental
damage. Pollution and similar environmental risks generally are not fully insurable either because such insurance is not available
or because of the high premium costs and deductible associated with obtaining such insurance. A variety of federal, state and local
laws and regulations govern the environmental aspects of the oil and gas business. Noncompliance with these laws and regulations
may subject the Company to administrative, civil or criminal penalties, remedial cleanups, and natural resource damages or other
liabilities, and compliance with these laws and regulations may increase the cost of the Company's operations. Such laws and
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PIONEER NATURAL RESOURCES COMPANY
regulations may also affect the costs of acquisitions. See "Item 1. Business — Competition, Markets and Regulations —
Environmental and occupational health and safety matters" above for additional discussion related to environmental risks.
Environmental laws and regulations are subject to amendment or replacement by more stringent laws and regulations and
no assurance can be given that continued compliance with existing or future environmental laws and regulations will not result
in a curtailment of production or processing activities, result in a material increase in the costs of production, development,
exploration or processing operations or adversely affect the Company's future operations and financial condition.
The Company could incur significant costs and liabilities in responding to contamination that occurs at its properties or as a
result of its operations.
There is inherent risk of incurring significant environmental costs and liabilities in operations upon the Company's properties
due to its handling of petroleum hydrocarbons and wastes, because of air emissions and water discharges related to its operations,
and as a result of historical operations and waste disposal practices by prior owners and operators. The Company currently owns,
leases or operates properties that for many years have been used for oil and gas exploration and production activities, and petroleum
hydrocarbons, hazardous substances and wastes have been released on or under such properties and could be released during future
operations. Joint and several strict liabilities may be incurred in connection with such releases of petroleum hydrocarbons and
wastes on, under or from the Company's properties. Private parties, including lessors of properties on which the Company operates
and the owners or operators of properties adjacent to the Company's operations and facilities where the Company's petroleum
hydrocarbons or wastes are taken for reclamation or disposal, may also have the right to pursue legal actions to enforce compliance
as well as seek damages for noncompliance with environmental laws and regulations or for personal injury or property damage.
The Company may not be able to recover some or any of these costs from insurance or other sources of contractual indemnity.
The Company's credit facility and debt instruments have substantial restrictions and financial covenants that may restrict its
business and financing activities.
The Company is a borrower under fixed rate senior notes and a credit facility. The terms of the Company's borrowings
specify scheduled debt repayments and require the Company to comply with certain associated covenants and restrictions. The
Company's ability to comply with the debt repayment terms, associated covenants and restrictions is dependent on, among other
things, factors outside the Company's direct control, such as commodity prices and interest rates. See Note G of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding
the Company's outstanding debt as of December 31, 2013 and the terms associated therewith.
The Company's ability to obtain additional financing is also affected by the Company's debt credit ratings and competition
for available debt financing.
The Company faces significant competition, and some of its competitors have resources in excess of the Company's
available resources.
The oil and gas industry is highly competitive. The Company competes with a large number of companies, producers and
operators in a number of areas such as:
seeking to acquire oil and gas properties suitable for development or exploration;
•
• marketing oil, NGL and gas production; and
•
seeking to acquire the equipment and expertise, including trained personnel, necessary to evaluate, operate and develop
properties.
Some of the Company's competitors are larger and have substantially greater financial and other resources than the Company.
See "Item 1. Business — Competition, Markets and Regulations" for additional discussion regarding competition.
The Company is subject to regulations that may cause it to incur substantial costs.
The Company's business is regulated by a variety of federal, state and local laws and regulations. For instance, in connection
with the Company's CBM operations in the Raton Basin in Colorado, the Colorado Supreme Court affirmed a state water court
holding that water produced in connection with CBM operations should be subject to state water-use regulations, including
regulations requiring permits for diversion and use of surface and subsurface water, an evaluation of potential competing permits,
possible uses of the water and a possible requirement to provide augmentation water supplies for water rights owners with more
senior rights. As another example, the underground injection well program under the SDWA requires permits from the EPA or an
analogous state agency for the Company's disposal wells, establishes minimum standards for injection well operations, and restricts
the types and quantities of fluids that may be injected. In some areas of Texas, there has been concern that certain formations into
which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the governing
Texas regulatory agency is reviewing the data to determine whether any action is necessary to address this issue. If the Texas state
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PIONEER NATURAL RESOURCES COMPANY
agency were to decline to issue permits for new injection wells into the formations currently utilized by the Company, the Company
may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which
could increase its costs. There can be no assurance that present or future regulations will not adversely affect the Company's
business and operations, including that the Company may be required to suspend drilling operations or shut in production pending
compliance. See "Item 1. Business — Competition, Markets and Regulations" for additional discussion regarding government
regulation.
The Company's sales of oil, gas, NGLs or other energy commodities, and any derivative activities related to such energy
commodities, expose the Company to potential regulatory risks.
FERC, the FTC and the CFTC hold statutory authority to monitor certain segments of the physical and futures energy
commodities markets relevant to the Company's business. These agencies have imposed broad regulations prohibiting fraud and
manipulation of such markets. With regard to the Company's physical sales of oil, gas, NGLs or other energy commodities, and
any derivative activities related to these energy commodities, the Company is required to observe the market-related regulations
enforced by these agencies, which hold substantial enforcement authority. Failure to comply with such regulations, as interpreted
and enforced, could materially and adversely affect the Company's business results of operations and financial condition.
Estimates of proved reserves and future net cash flows are not precise. The actual quantities and net cash flows of the Company's
proved reserves may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. The estimates
of proved reserves and related future net cash flows set forth in this Report are based on various assumptions, which may ultimately
prove to be inaccurate.
Petroleum engineering is a subjective process of estimating underground accumulations of oil and gas that cannot be
measured in an exact manner. Estimates of economically recoverable oil and gas reserves and estimates of future net cash flows
depend upon a number of variable factors and assumptions, including the following:
•
•
•
•
•
•
historical production from the area compared with production from other producing areas;
the quality and quantity of available data;
the interpretation of that data;
the assumed effects of regulations by governmental agencies;
assumptions concerning future commodity prices; and
assumptions concerning future operating costs, severance, ad valorem and excise taxes, development costs,
transportation costs and workover and remedial costs.
Because all proved reserve estimates are to some degree subjective, each of the following items may differ materially from
those assumed in estimating proved reserves:
•
•
•
•
the quantities of oil and gas that are ultimately recovered;
the production costs incurred to recover the reserves;
the amount and timing of future development expenditures; and
future commodity prices.
Furthermore, different reserve engineers may make different estimates of proved reserves and cash flows based on the same
available data. The Company's actual production, revenues and expenditures with respect to proved reserves will likely be different
from estimates, and the differences may be material.
As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on average prices
preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially
higher or lower. Actual future net cash flows also will be affected by factors such as:
•
•
•
•
the amount and timing of actual production;
levels of future capital spending;
increases or decreases in the supply of or demand for oil, NGLs and gas; and
changes in governmental regulations or taxation.
Standardized Measure is a reporting convention that provides a common basis for comparing oil and gas companies subject
to the rules and regulations of the SEC. In general, it requires the use of commodity prices that are based upon a 12-month
unweighted average, as well as operating and development costs being incurred at the end of the reporting period. Consequently,
it may not reflect the prices ordinarily received or that will be received for oil and gas production because of seasonal price
fluctuations or other varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the
24
PIONEER NATURAL RESOURCES COMPANY
oil and gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future
net cash flows that are ultimately received. In addition, the ten percent discount factor, which is required by the SEC to be used
in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on
interest rates in effect from time to time and risks associated with the Company or the oil and gas industry in general. Therefore,
the estimates of discounted future net cash flows or Standardized Measure in this Report should not be construed as accurate
estimates of the current market value of the Company's proved reserves.
The Company's actual production could differ materially from its forecasts.
From time to time, the Company provides forecasts of expected quantities of future oil and gas production. These forecasts
are based on a number of estimates, including expectations of production from existing wells and the outcome of future drilling
activity. Should these estimates prove inaccurate, actual production could be adversely affected. In addition, the Company's
forecasts assume that none of the risks associated with the Company's oil and gas operations summarized in this "Item 1A. Risk
Factors" occur, such as facility or equipment malfunctions, adverse weather effects, or downturns in commodity prices or significant
increases in costs, which could make certain drilling activities or production uneconomical.
The Company's business could be negatively affected by security threats, including cybersecurity threats, and other disruptions.
As an oil and gas producer, the Company faces various security threats, including cybersecurity threats to gain unauthorized
access to sensitive information or to render data or systems unusable; threats to the security of the Company's facilities and
infrastructure or third party facilities and infrastructure, such as processing plants and pipelines; and threats from terrorist acts.
The potential for such security threats has subjected the Company's operations to increased risks that could have a material adverse
effect on the Company's business. In particular, the Company's implementation of various procedures and controls to monitor and
mitigate security threats and to increase security for the Company's information, facilities and infrastructure may result in increased
capital and operating costs. Moreover, there can be no assurance that such procedures and controls will be sufficient to prevent
security breaches from occurring. If any of these security breaches were to occur, they could lead to losses of sensitive information,
critical infrastructure or capabilities essential to the Company's operations and could have a material adverse effect on the Company's
reputation, financial position, results of operations or cash flows. Cybersecurity attacks in particular are becoming more
sophisticated and include, but are not limited to, malicious software, attempts to gain unauthorized access to data and systems,
and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or
otherwise protected information, and corruption of data. These events could damage the Company's reputation and lead to financial
losses from remedial actions, loss of business or potential liability.
A failure by purchasers of the Company's production to perform their obligations to the Company could require the
Company to recognize a pre-tax charge in earnings and have a material adverse effect on the Company's results of
operation.
The Company relies on a limited number of purchasers to purchase a majority of its products. To the extent that purchasers
of the Company's production rely on access to the credit or equity markets to fund their operations, there is a risk that those
purchasers could default in their contractual obligations to the Company if such purchasers were unable to access the credit or
equity markets for an extended period of time. If for any reason the Company were to determine that it was probable that some
or all of the accounts receivable from any one or more of the purchasers of the Company's production were uncollectible, the
Company would recognize a pre-tax charge in the earnings of that period for the probable loss.
Declining general economic, business or industry conditions could have a material adverse effect on the Company's results of
operations.
The worldwide economic outlook has been improving steadily since 2010, but if there are renewed concerns about global
economic growth or government debt in Europe or the United States, there could be a significant adverse effect on global financial
markets and commodity prices. If the economic climate in the United States or abroad were to deteriorate, demand for petroleum
products could diminish, which could depress the prices at which the Company could sell its oil, NGLs and gas and ultimately
decrease the Company's net revenue and profitability.
Certain U.S. federal income tax deductions currently available with respect to oil and gas exploration and development may
be eliminated as a result of future legislation.
In recent years, legislation has been proposed that would, if enacted into law, make significant changes to U.S. tax laws,
including the elimination of certain key U.S. federal income tax incentives currently available to oil and gas companies. Such tax
legislation changes include, but are not limited to, (i) the repeal of the percentage depletion allowance for oil and gas properties,
(ii) the elimination of current deductions for intangible drilling and development costs, (iii) the elimination of the deduction for
certain domestic production activities and (iv) an extension of the amortization period for certain geological and geophysical
25
PIONEER NATURAL RESOURCES COMPANY
expenditures. It is unclear whether these or similar changes will be enacted and, if enacted, how soon any such changes could
become effective. The passage of any legislation as a result of these proposals or any other similar changes in U.S. federal income
tax laws could eliminate or postpone certain tax deductions that are currently available with respect to oil and gas exploration and
development, and any such change could have an adverse effect on the Company's financial position, results of operations and
cash flows.
Climate change legislation and regulatory initiatives restricting emissions of GHGs could result in increased operating costs
and reduced demand for the oil, NGLs and gas the Company produces.
In 2009, the EPA officially published its findings that emissions of GHGs present an endangerment to public health and
the environment because emissions of such gases are, according to the EPA, contributing to warming of the Earth's atmosphere
and other climatic changes. Based on these findings, the EPA adopted regulations under the CAA establishing Title V and PSD
permitting requirements for large sources of GHGs. The Company could become subject to these permitting requirements and
be required to install "best available control technology" to limit emissions of GHGs from any new or significantly modified
facilities that the Company may seek to construct in the future if they would otherwise emit large volumes of GHGs. The EPA has
also adopted rules requiring the reporting of GHG emissions on an annual basis from specified GHG emission sources in the
United States, including certain oil and gas production facilities, which include certain of the Company's facilities. While the U.S.
Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the
form of adopted legislation to reduce GHG emissions at the federal level in recent years. In the absence of federal climate legislation
in the United States, a number of state and regional efforts have emerged that are aimed at tracking or reducing GHG emissions
by means of cap and trade programs that typically require major sources of GHG emissions, such as electric power plants, to
acquire and surrender emission allowances in return for emitting those GHGs. If the U.S. Congress undertakes comprehensive
tax reform in the coming year, it is possible that such reform may include a carbon tax, which could impose additional direct costs
on the Company's operations. Although it is not possible at this time to predict how legislation or new regulations that may be
adopted to address GHG emissions would affect the Company's business, any such future laws and regulations could require the
Company to incur increased operating costs, such as costs to purchase and operate emissions control systems, acquire emissions
allowances or comply with new regulatory or reporting requirements, including the imposition of a carbon tax. Any such legislation
or regulatory programs could also increase the cost to the consumer, and thereby reduce demand for oil and gas, which could
reduce the demand for the oil and gas the Company produces. Consequently, legislation and regulatory programs to reduce emissions
of GHGs could have an adverse effect on the Company's business, financial condition and results of operations. See "Item 1.
Business - Competition, Markets and Regulations - Environmental and occupational health and safety matters - Climate change"
for additional discussion relating to climate change.
The enactment of derivatives legislation could have an adverse effect on the Company's ability to use derivative instruments
to reduce the effect of commodity price, interest rate and other risks associated with its business.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the "Dodd-Frank Act") enacted on July 21, 2010,
established federal oversight and regulation of the over-the-counter derivatives market and entities, such as the Company, that
participate in that market. The Dodd-Frank Act requires the CFTC and the SEC to promulgate rules and regulations for its
implementation. In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in
the major energy markets and for swaps that are their economic equivalents. The initial position limits rule was vacated by the
United States District Court for the District of Colombia in September 2012. However, in November 2013, the CFTC proposed
new rules that would place limits on positions in certain core futures and equivalent swaps contracts for or linked to certain physical
commodities, subject to exceptions for certain bona fide derivative transactions. As these new position limit rules are not yet final,
the impact of those provisions on the Company is uncertain at this time. The CFTC has designated certain interest rate swaps and
credit default swaps for mandatory clearing and the associated rules also will require the Company, in connection with covered
derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such
requirements. Although the Company believes it qualifies for the end-user exception from the mandatory clearing requirements
for swaps entered to mitigate its commercial risks, the application of the mandatory clearing and trade execution requirements to
other market participants, such as swap dealers, may change the cost and availability of the Company's derivatives. Although the
CFTC has finalized certain regulations, others remain to be finalized or implemented and it is not possible at this time to predict
when this will be accomplished or what the effect of any such regulations will be on the Company. For example, for uncleared
swaps, the CFTC or federal banking regulators may require end-users to enter into credit support documentation and/or post initial
and variation margin. Posting of collateral could impact liquidity and reduce cash available to the Company for capital expenditures,
therefore reducing its ability to execute derivatives to reduce risk and protect cash flows. The proposed margin rules are not yet
final, and therefore the impact of those provisions to the Company is uncertain at this time. The Dodd-Frank Act also may require
the counterparties to the Company's derivative instruments to spin off some of their derivatives activities to a separate entity, which
may not be as creditworthy as the current counterparty. The full impact of the Dodd-Frank Act and related regulatory requirements
upon the Company's business will not be known until the regulations are implemented and the market for derivatives contracts
has adjusted. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially
26
PIONEER NATURAL RESOURCES COMPANY
alter the terms of derivative contracts, reduce the availability of derivatives to protect against risks the Company encounters, reduce
the Company's ability to monetize or restructure its existing derivative contracts, and increase the Company's exposure to less
creditworthy counterparties. If the Company reduces its use of derivatives as a result of the Dodd-Frank Act and regulations, the
Company's results of operations may become more volatile and its cash flows may be less predictable, which could adversely
affect the Company's ability to plan for and fund capital expenditures. Finally, the Dodd-Frank Act was intended, in part, to reduce
the volatility of oil and gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments
related to oil and gas. The Company's revenues could therefore be adversely affected if a consequence of the Dodd-Frank Act and
implementing regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on the
Company, its financial condition and its results of operations.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews
of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect the
Company's production.
Hydraulic fracturing is a common practice that is used to stimulate production of hydrocarbons from tight formations. The
Company routinely utilizes hydraulic fracturing techniques in the majority of its drilling and completion programs. The process
involves the injection of water, sand and additives under pressure into targeted subsurface formations to stimulate oil and gas
production. The process is typically regulated by state oil and gas commissions, but the EPA has asserted federal regulatory
authority over hydraulic fracturing involving diesel fuels under the SDWA's Underground Injection Control Program and published
final permitting guidance in February 2014 addressing the performance of such activities. In 2011, the EPA announced its intent
to develop and issue regulations under the Toxic Substances Control Act to require companies to disclose information regarding
the chemicals used in hydraulic fracturing, and in its Semi-annual Regulatory agenda published in July 2013, the agency continues
to project the future issuance of an Advance Notice of Proposed Rulemaking that would seek public input on the design and scope
of such disclosure regulations. The EPA has published final rules under the CAA that, among other things, require producers to
reduce volatile organic compound emissions from certain subcategories of fractured and refractured gas wells for which well
completion operations are being conducted by routing flowback emissions to a gathering line or capturing and combusting flowback
emissions using a combustion device, such as a flare, until January 1, 2015 and performing green completions, with or without
combustion devices, on or after January 1, 2015. Also, in May 2013, the BLM published a supplemental notice of proposed
rulemaking governing hydraulic fracturing on federal and Indian oil and gas leases that would require public disclosure of chemicals
used in hydraulic fracturing, confirmation that wells used in fracturing operations meet appropriate construction standards, and
development of appropriate plans for managing flowback water that returns to the surface.
In addition, the U.S. Congress, from time to time, has considered adopting legislation intended to provide for federal
regulation of hydraulic fracturing and to require disclosure of the chemicals used in the hydraulic-fracturing process. Certain states
in which the Company operates, including Colorado and Texas have adopted, and other states are considering adopting, regulations
that could impose new or more stringent permitting, disclosure, and well-construction requirements on hydraulic-fracturing
operations. In addition, local land use restrictions, such as city ordinances, may restrict or prohibit drilling in general or hydraulic
fracturing in particular. In the event federal, state or local restrictions are adopted in areas where the Company is currently
conducting, or in the future plan to conduct operations, the Company may incur additional costs to comply with such requirements
that may be significant in nature, experience delays or curtailment in the pursuit of exploration, development, or production
activities, and perhaps be limited or precluded in the drilling of wells or in the amounts that the Company is ultimately able to
produce from its reserves.
Certain governmental reviews were recently conducted or are underway that focus on environmental aspects of hydraulic
fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of
hydraulic fracturing practices. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing on
drinking water and groundwater and a draft report is expected to be available for public comment and peer review in 2014.
Moreover, the EPA is developing effluent limitations for the treatment and discharge of wastewater resulting from hydraulic
fracturing activities and is expected to propose these standards in 2014. These studies, or future studies, depending on their degree
of pursuit and any meaningful results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or
other regulatory mechanisms. See "Item 1. Business - Competition, Markets and Regulations - Environmental and occupational
health and safety matters" for additional discussion related to environmental risks associated with the Company's hydraulic
fracturing activities.
Laws and regulations pertaining to threatened and endangered species could delay or restrict the Company's operations and
cause it to incur substantial costs.
Various federal and state statutes prohibit certain actions that adversely affect endangered or threatened species and their
habitats, migratory birds, wetlands and natural resources. These statutes include the ESA, the Migratory Bird Treaty Act, the CWA
and CERCLA. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are
27
PIONEER NATURAL RESOURCES COMPANY
necessary for survival of threatened or endangered species. A critical habitat or suitable habitat designation could result in further
material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development.
If harm to species or damages to wetlands, habitat or natural resources occur or may occur, government entities or, at times, private
parties may act to prevent oil and gas exploration or development activities or seek damages for harm to species, habitat or natural
resources resulting from drilling or construction or releases of oil, wastes, hazardous substances or other regulated materials, and,
in some cases, may seek criminal penalties. Moreover, as a result of a settlement approved by the U.S. District Court for the District
of Columbia in September 2011, the U.S. Fish and Wildlife Service is required to make a determination on the listing of numerous
species as endangered or threatened under the ESA before completion of the agency's 2017 fiscal year. The designation of previously
unprotected species as threatened or endangered in areas where the Company conducts operations could cause the Company to
incur increased costs arising from species protection measures or could result in limitations on its development and production
activities that could have an adverse effect on the Company's ability to develop and produce reserves.
Provisions of the Company's charter documents and Delaware law may inhibit a takeover, which could limit the price investors
might be willing to pay in the future for the Company's common stock.
Provisions in the Company's certificate of incorporation and bylaws may have the effect of delaying or preventing an
acquisition of the Company or a merger in which the Company is not the surviving company and may otherwise prevent or slow
changes in the Company's board of directors and management. In addition, because the Company is incorporated in Delaware, it
is governed by the provisions of Section 203 of the Delaware General Corporation Law. These provisions could discourage an
acquisition of the Company or other change in control transaction and thereby negatively affect the price that investors might be
willing to pay in the future for the Company's common stock.
The Company's sand mining operations are subject to operating risks that are often beyond the Company's control, and such
risks may not be covered by insurance.
Ownership of industrial sand mining operations are subject to risks, many of which are beyond the Company's control.
These risks include:
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
unusual or unexpected geological formations or pressures;
cave-ins, pit wall failures or rock falls;
unanticipated ground, grade or water conditions;
inclement or hazardous weather conditions, including flooding, and the physical impacts of climate change;
environmental hazards, such as unauthorized spills, releases and discharges of wastes, vessel ruptures and emission of
unpermitted levels of pollutants;
changes in laws and regulations;
inability to acquire or maintain necessary permits or mining or water rights;
restrictions on blasting operations;
inability to obtain necessary production equipment or replacement parts;
reduction in the amount of water available for processing;
technical difficulties or failures;
labor disputes;
late delivery of supplies;
fires, explosions or other accidents; and
facility interruptions or shutdowns in response to environmental regulatory actions.
Any of these risks could result in damage to, or destruction of, the Company's mining properties or production facilities,
personal injury, environmental damage, delays in mining or processing, losses or possible legal liability. Not all of these risks are
insurable, and the Company's insurance coverage contains limits, deductibles, exclusions and endorsements. The Company's
insurance coverage may not be sufficient to meet its needs in the event of loss and any such loss may have a material adverse
effect on the Company.
The Company's estimates of sand reserves and resource deposits are imprecise and actual reserves could be less than estimated.
The Company bases its sand reserve and resource estimates on engineering, economic and geological data assembled and
analyzed by engineers and geologists, which are periodically reviewed by outside firms. However, commercial sand reserve
estimates are necessarily imprecise and depend to some extent on statistical inferences drawn from available drilling data, which
may prove unreliable. There are numerous uncertainties inherent in estimating quantities and qualities of commercial sand reserves
and costs to mine recoverable reserves, including many factors beyond the Company's control. Estimates of economically
recoverable commercial sand reserves necessarily depend on a number of factors and assumptions, all of which may vary
considerably from actual results, such as:
28
PIONEER NATURAL RESOURCES COMPANY
•
•
•
geological and mining conditions or effects from prior mining that may not be fully identified by available data or that
may differ from experience;
assumptions concerning future prices of commercial sand products, operating costs, mining technology improvements,
development costs and reclamation costs; and
assumptions concerning future effects of regulation, including the issuance of required permits and taxes by
governmental agencies.
The Company's sand mining operations are subject to extensive environmental and occupational health and safety regulations
that impose significant costs and potential liabilities.
The Company's sand mining operations are subject to a variety of federal, state and local environmental requirements
affecting the mining and mineral processing industry, including, among others, those relating to employee health and safety,
environmental permitting and licensing, air emissions and water discharges, GHG emissions, water pollution, waste management
and disposal, remediation of soil and groundwater contamination, land use restrictions, reclamation and restoration of properties,
hazardous materials and natural resources. Some environmental laws impose substantial penalties for noncompliance, and others,
such as the CERCLA, impose strict, retroactive and joint and several liability for the remediation of releases of hazardous substances.
Failure to properly handle, transport, store or dispose of hazardous materials or otherwise conduct the Company's sand mining
operations in compliance with environmental laws could expose the Company to liability for governmental penalties, cleanup
costs and civil or criminal liability associated with releases of such materials into the environment, damages to property or natural
resources and other damages, as well as potentially impair the Company's ability to conduct its sand mining operations. In addition,
environmental laws and regulations are subject to amendment, replacement or interpretation by more stringent and comprehensive
legal requirements. The Company's continued compliance with existing or future laws and regulations could restrict the Company's
ability to expand its facilities or extract mineral deposits or could require the Company to acquire costly equipment or to incur
other significant expenses in connection with its sand mining operations, which restrictions or costs could have a material adverse
effect on the Company's sand mining operations.
Any failure by the Company to comply with applicable environmental laws and regulations in connection with its sand
mining operations may cause governmental authorities to take actions that could adversely affect the Company, including:
•
•
•
•
issuance of administrative, civil and criminal penalties;
denial, modification or revocation of permits or other authorizations;
imposition of injunctive obligations or other limitations on the Company's operations, including interruptions or
cessation of operations; and
requirements to perform site investigatory, remedial or other corrective actions.
In addition to environmental regulation, the Company's sand mining operations are subject to laws and regulations relating
to worker health and safety, including such matters as human exposure to crystalline silica dust. Several federal and state regulatory
authorities, including the U.S. Mining Safety and Health Administration, may continue to propose changes in their regulations
regarding workplace exposure to crystalline silica, such as permissible exposure limits and required controls and personal protective
equipment.
The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, which imposes stringent
health and safety standards on numerous aspects of the Company's sand mining operations.
The Company's sand mining operations are subject to the Federal Mine Safety and Health Act of 1977, as amended by the
Mine Improvement and New Emergency Response Act of 2006, which imposes stringent health and safety standards on numerous
aspects of mineral extraction and processing operations, including the training of personnel, operating procedures, operating
equipment and other matters. The Company's failure to comply with such standards, or changes in such standards or the interpretation
or enforcement thereof, could have a material adverse effect on the Company's sand mining operations or otherwise impose
significant restrictions on the Company's ability to conduct mineral extraction and processing operations.
The Company's sand mining operations are subject to extensive other regulations that impose significant costs and liabilities.
In addition to the environmental and occupational health and safety regulation discussed above, the Company's sand
mining operations are also subject to extensive governmental regulation on matters such as permitting and licensing requirements,
reclamation and restoration of mining properties after mining is completed, and the effects that mining have on groundwater quality
and availability. Also, the Company's sand mining operations require numerous governmental, environmental, mining and other
permits, water rights and approvals authorizing operations at each sand mining facility.
In order to obtain permits and renewals of permits in the future for its sand mining operations, the Company may be required
to prepare and present data to governmental authorities pertaining to the effect that any such activities may have on the environment.
29
PIONEER NATURAL RESOURCES COMPANY
Obtaining or renewing required permits may be delayed or prevented due to opposition by neighboring property owners, members
of the public or other third parties and other factors beyond the Company's control. A decision by a governmental agency or other
third party to deny or delay issuing a new or renewed permit or approval, or to revoke or substantially modify an existing permit
or approval, could have a material adverse effect on the Company's sand mining operations at the affected facility. Current or
future regulations could have a material adverse effect on the Company's sand mining operations and the Company may not be
able to renew or obtain permits in the future.
The Company's sand mining operations entail silica-related health issues and litigation that could have a material adverse
effect on the Company.
The inhalation of respirable crystalline silica dust is associated with the lung disease silicosis. There is evidence of an
association between crystalline silica exposure or silicosis and lung cancer and a possible association with other diseases, including
immune system disorders, such as scleroderma. These health risks have been, and may continue to be, a significant issue confronting
the commercial sand industry. The actual or perceived health risks of mining, processing and handling sand could materially and
adversely affect the Company through the threat of product liability or employee lawsuits and increased scrutiny by federal, state
and local regulatory authorities.
Premier Silica is named as a defendant, usually among many defendants, in numerous products liability lawsuits brought
by or on behalf of current or former employees of Premier Silica's customers alleging damages caused by silica exposure. As of
December 31, 2013, Premier Silica was the subject of approximately 2,200 silica exposure claims, the great majority of which
have been inactive for many years due to the plaintiffs' failure to meet specific legal requirements to advance their claims. Almost
all of the claims pending against Premier Silica arise out of the alleged use of Premier Silica's sand products in foundries or as an
abrasive blast media and have been filed in the states of Texas, Florida and Missouri, although some cases have been brought in
many other jurisdictions over the years.
It is possible that Premier Silica will continue to have silica-related products liability claims filed against it, including claims
that allege silica exposure for periods for which there is not insurance coverage. Any pending or future claims or inadequacies of
insurance coverage or indemnification from the seller could have a material adverse effect on the Company's results of operations.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 2.
PROPERTIES
Reserve Estimation Procedures and Audits
The information included in this Report about the Company's proved reserves as of December 31, 2013, 2012 and 2011 is
based on evaluations prepared by the Company's engineers and (i) audited by Netherland, Sewell & Associates, Inc. ("NSAI"),
with respect to the Company's major properties included in its continuing operations for all periods, and (ii) with respect to the
Company's Oooguruk field properties in Alaska, audited by Ryder Scott Company, L.P. ("RSC"), as of December 31, 2012. The
Company has no oil and gas reserves from non-traditional sources. Additionally, the Company does not provide optional disclosure
of probable or possible reserves.
Reserve estimation procedures. The Company has established internal controls over reserve estimation processes and
procedures to support the accurate and timely preparation and disclosure of reserve estimates in accordance with SEC and GAAP
requirements. These controls include oversight of the reserves estimation reporting processes by Pioneer's Corporate Reserves
Group ("Corporate Reserves"), and annual external audits of substantial portions of the Company's proved reserves by NSAI.
Individual asset teams are responsible for the day-to-day management of the oil and gas activities in each of the Company's
Permian Basin, Rockies, Mid-Continent, South Texas, Barnett Shale and Alaska asset areas (the "Asset Teams"). The Company's
Asset Teams are each staffed with reservoir engineers and geoscientists who prepare reserve estimates at the end of each calendar
quarter for the assets that they manage, using reservoir engineering information technology. There is shared oversight of the Asset
Teams' reservoir engineers by the Asset Teams' managers and the Vice President of Corporate Reserves, each of whom is in turn
subject to direct or indirect oversight by the Company's management committee ("MC"). The Company's MC is comprised of its
Chief Executive Officer, Chief Operating Officer, Chief Financial Officer and other Executive Vice Presidents. The Asset Teams'
reserve estimates are reviewed by the Asset Team reservoir engineers before being submitted to Corporate Reserves for further
review.
30
PIONEER NATURAL RESOURCES COMPANY
The reserve estimates are summarized in reserve reconciliations that quantify reserve changes since the previous year end
as revisions of previous estimates, purchases of minerals-in-place, improved recovery, extensions and discoveries, production and
sales of minerals-in-place. All reserve estimates, material assumptions and inputs used in reserve estimates and significant changes
in reserve estimates are reviewed for engineering and financial appropriateness and compliance with SEC and GAAP standards
by Corporate Reserves, in consultation with the Company's accounting and financial management personnel. Annually, the MC
reviews the reserve estimates and any differences with the reserve auditors (for the portion of the reserves audited by NSAI or
RSC) on a consolidated basis before these estimates are approved. The engineers and geoscientists who participate in the reserve
estimation and disclosure process periodically attend training provided by external consultants and/or through internal Pioneer
programs. Additionally, Corporate Reserves has prepared and maintains written policies and guidelines for the Asset Teams to
reference on reserve estimation and preparation to promote objectivity in the preparation of the Company's reserve estimates and
SEC and GAAP compliance in the reserve estimation and reporting process.
Proved reserves audits. The proved reserve audits performed by NSAI for 2013, 2012 and 2011, and by RSC for 2012, in
the aggregate represented 94 percent, 95 percent and 90 percent of the Company's 2013, 2012 and 2011 proved reserves, respectively;
and 92 percent, 99 percent and 91 percent of the Company's 2013, 2012 and 2011 associated pre-tax present value of proved
reserves discounted at ten percent, respectively.
NSAI follows the general principles set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas
Reserve Information" promulgated by the Society of Petroleum Engineers (the "SPE"). A reserve audit as defined by the SPE is
not the same as a financial audit. The SPE's definition of a reserve audit includes the following concepts:
• A reserve audit is an examination of reserve information that is conducted for the purpose of expressing an opinion as
to whether such reserve information, in the aggregate, is reasonable and has been presented in conformity with the
2007 SPE publication entitled "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves
Information."
• The estimation of reserves is an imprecise science due to the many unknown geologic and reservoir factors that cannot
be estimated through sampling techniques. Since reserves are only estimates, they cannot be audited for the purpose
of verifying exactness. Instead, reserve information is audited for the purpose of reviewing in sufficient detail the
policies, procedures and methods used by a company in estimating its reserves so that the reserve auditors may express
an opinion as to whether, in the aggregate, the reserve information furnished by a company is reasonable.
• The methods and procedures used by a company, and the reserve information furnished by a company, must be reviewed
in sufficient detail to permit the reserve auditor, in its professional judgment, to express an opinion as to the
reasonableness of the reserve information. The auditing procedures require the reserve auditor to prepare its own
estimates of reserve information for the audited properties.
In conjunction with the audit of the Company's proved reserves and associated pre-tax present value discounted at ten
percent, Pioneer provided to NSAI its external and internal engineering and geoscience technical data and analyses. Following
NSAI's review of that data, it had the option of honoring Pioneer's interpretations, or making its own interpretations. No data was
withheld from NSAI. NSAI accepted without independent verification the accuracy and completeness of the historical information
and data furnished by Pioneer with respect to ownership interest, oil and gas production, well test data, commodity prices, operating
and development costs, and any agreements relating to current and future operations of the properties and sales of production.
However, if in the course of its evaluations something came to its attention that brought into question the validity or sufficiency
of any such information or data, NSAI did not rely on such information or data until it had satisfactorily resolved its questions
relating thereto or had independently verified such information or data.
In the course of its evaluations, NSAI prepared, for all of the audited properties, its own estimates of the Company's proved
reserves and the pre-tax present values of such reserves discounted at ten percent. NSAI reviewed its audit differences with the
Company, and, in a number of cases, held meetings with the Company to review additional reserves work performed by the
Company's technical teams and any updated performance data related to the proved reserve differences. Such data was incorporated,
as appropriate, by both parties into the proved reserve estimates. NSAI's estimates, including any adjustments resulting from
additional data, of those proved reserves and the pre-tax present value of such reserves discounted at ten percent did not differ
from Pioneer's estimates by more than ten percent in the aggregate. However, when compared on a lease-by-lease, field-by-field
or area-by-area basis, some of the Company's estimates were greater than those of the reserve auditors and some were less than
the estimates of the reserve auditors. When such differences do not exceed ten percent in the aggregate and NSAI is satisfied that
the proved reserves and pre-tax present values of such reserves discounted at ten percent are reasonable and that its audit objectives
have been met, NSAI will issue an unqualified audit opinion. Remaining differences are not resolved due to the limited cost benefit
of continuing such analyses by the Company and the reserve auditors. At the conclusion of the audit process, it was NSAI's opinion,
as set forth in its audit letter, which is included as an exhibit to this Report, that Pioneer's estimates of the Company's proved oil
and gas reserves and associated pre-tax present values discounted at ten percent are, in the aggregate, reasonable and have been
31
PIONEER NATURAL RESOURCES COMPANY
prepared in accordance with the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information"
promulgated by the SPE.
See "Item 1A. Risk Factors," "Critical Accounting Estimates" in "Item 7. Management's Discussion and Analysis and Results
of Operations" and "Item 8. Financial Statements and Supplementary Data" for additional discussions regarding proved reserves
and their related cash flows.
Qualifications of reserves preparers and auditors. Corporate Reserves is staffed by petroleum engineers with extensive
industry experience and is managed by the Vice President of Corporate Reserves, the technical person that is primarily responsible
for overseeing the Company's reserves estimates. These individuals meet the professional qualifications of reserves estimators
and reserves auditors as defined by the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information,"
promulgated by the SPE. The qualifications of the Vice President of Corporate Reserves include 36 years of experience as a
petroleum engineer, with 29 years focused on reserves reporting for independent oil and gas companies, including Pioneer. His
educational background includes an undergraduate degree in Chemical Engineering and a Masters of Business Administration
degree in Finance. He is also a Chartered Financial Analyst Charterholder.
NSAI provides worldwide petroleum property analysis services for energy clients, financial organizations and government
agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional
Engineers Registration No. F-2699. The technical person primarily responsible for auditing the Company's reserves estimates has
been a practicing consulting petroleum engineer at NSAI since 1983 and has over 35 years of practical experience in petroleum
engineering, including over 33 years of experience in the estimation and evaluation of proved reserves. He graduated with a
Bachelor of Science degree in Chemical Engineering in 1978 and meets or exceeds the education, training and experience
requirements set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information"
promulgated by the board of directors of the SPE.
RSC provides worldwide petroleum property analysis services for energy clients, financial organizations and government
agencies. RSC was founded in 1937 and performs consulting petroleum engineering services under Texas Board of Professional
Engineers Registration No. F-1580. The technical person primarily responsible for auditing the Company's Alaska reserves
estimates in 2012 was a practicing consulting petroleum engineer at RSC since 2000 with over 29 years of practical experience
in petroleum engineering. He graduated with a Bachelor of Science degree in Petroleum Engineering and a Master of Business
Administration degree and at the time of the reserves audit he met or exceeded the education, training and experience requirements
set forth in the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information" promulgated by the
board of directors of the SPE.
Technologies used in reserves estimates. Proved undeveloped reserves include those reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for
completion. Undeveloped reserves may be classified as proved reserves on undrilled acreage directly offsetting development areas
that are reasonably certain of production when drilled, or where reliable technology provides reasonable certainty of economic
producibility. Undrilled locations may be classified as having undeveloped proved reserves only if an ability and intent has been
established to drill the reserves within five years, unless specific circumstances justify a longer time period.
In the context of reserves estimations, reasonable certainty means a high degree of confidence that the quantities will be
recovered and reliable technology means a grouping of one or more technologies (including computational methods) that has been
field-tested and has been demonstrated to provide reasonable certain results with consistency and repeatability in the formation
being evaluated or in an analogous formation. In estimating proved reserves, the Company uses several different traditional methods
such as performance-based methods, volumetric-based methods and analogy with similar properties. In addition, the Company
utilizes additional technical analysis such as seismic interpretation, wireline formation tests, geophysical logs and core data to
provide incremental support for more complex reservoirs. Information from this incremental support is combined with the
traditional technologies outlined above to enhance the certainty of the Company's proved reserve estimates.
32
PIONEER NATURAL RESOURCES COMPANY
Proved Reserves
As of December 31, 2013 and 2012, the Company's oil and gas proved reserves are located entirely in the United States.
The Company's proved reserves as of December 31, 2011 were almost exclusively located in the United States, except for less
than one percent that were associated with discontinued operations in South Africa. See Note C of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for additional details of the Company's discontinued
operations. The following table provides information regarding the Company's proved reserves as of December 31, 2013, 2012
and 2011:
Summary of Oil and Gas Reserves as of Fiscal Year-End
Based on Average Fiscal-Year Prices
Reserve Volumes
Oil
(MBBLs)
NGLs
(MBBLs)
Gas
(MMCF) (a)
Total
(MBOE)
%
December 31, 2013:
Developed ...................................................................................
Undeveloped ...............................................................................
Total proved reserves................................................................
Less proved reserves associated with discontinued operations...
Total proved reserves associated with continuing operations...
December 31, 2012:
Developed ...................................................................................
Undeveloped ...............................................................................
Total proved reserves................................................................
Less proved reserves associated with discontinued operations...
Total proved reserves associated with continuing operations...
December 31, 2011:
Developed ...................................................................................
Undeveloped ...............................................................................
Total proved reserves................................................................
Less proved reserves associated with discontinued operations...
Total proved reserves associated with continuing operations...
256,638
85,467
342,105
24,128
317,977
230,700
256,138
486,838
48,274
438,564
190,206
239,799
430,005
32,301
397,704
148,161
37,261
185,422
10,210
1,703,667
202,674
1,906,341
80,113
175,212
1,826,228
688,743
156,507
845,250
47,690
797,560
134,637
97,939
232,576
24,137
1,605,209
592,271
2,197,480
158,307
632,872
452,789
1,085,661
98,796
208,439
2,039,173
986,865
120,405
90,630
211,035
13,011
1,853,363
677,675
2,531,038
117,299
619,506
443,375
1,062,881
64,862
198,024
2,413,739
998,019
81%
19%
100%
6%
94%
58%
42%
100%
9%
91%
58%
42%
100%
6%
94%
______________________
(a)
Total proved gas reserves contain 240,093 MMCF, 280,344 MMCF and 301,123 MMCF of gas that the Company expected
to be produced and used as field fuel (primarily for compressors) before the gas is delivered to a sales point, as of December
31, 2013, 2012 and 2011, respectively.
The Company's Standardized Measure of total proved reserves as of December 31, 2013 was $7.3 billion, including $6.3
billion and $1.0 billion of proved developed and proved undeveloped, respectively. The Company's Standardized Measure of total
proved reserves as of December 31, 2012 was $6.4 billion, including $5.0 billion and $1.4 billion of proved developed and proved
undeveloped, respectively. The Company's Standardized Measure of total proved reserves as of December 31, 2011 was $7.8
billion, including $5.5 billion and $2.3 billion of proved developed and proved undeveloped, respectively.
See the "Unaudited Supplementary Information" section included in "Item 8. Financial Statements and Supplementary
Data" for additional details of the estimated quantities of the Company's proved reserves, including explanations for material
changes in proved developed and proved undeveloped reserves.
33
PIONEER NATURAL RESOURCES COMPANY
Description of Properties
The following tables summarize the Company's development and exploration/extension drilling activities during 2013:
Beginning Wells
In Progress
Wells
Spud
Development Drilling
Successful
Wells
Unsuccessful
Wells
Ending Wells
In Progress
Permian Basin ................................................
South Texas—Eagle Ford Shale ....................
Mid-Continent................................................
Total continuing operations.........................
Barnett Shale..................................................
Alaska ............................................................
Total including discontinued operations......
136
11
—
147
—
4
151
311
45
11
367
4
3
374
387
40
11
438
3
3
444
1
—
—
1
—
—
1
59
16
—
75
1
4
80
Exploration/Extension Drilling
Beginning Wells
In Progress
Wells
Spud
Successful
Wells
Unsuccessful
Wells
Wells
Sold
Ending
Wells In
Progress
Permian Basin ...........................................
South Texas—Eagle Ford Shale................
South Texas—Edwards and Austin Chalk
Other..........................................................
Total continuing operations ....................
Barnett Shale .............................................
Alaska........................................................
Total including discontinued operations.
17
21
—
—
38
9
2
49
128
95
1
5
229
52
1
282
114
92
1
—
207
37
—
244
—
—
—
2
2
6
1
9
—
—
—
—
—
1
—
1
31
24
—
3
58
17
2
77
The following table summarizes the Company's average daily oil, NGL, gas and total production by asset area during 2013:
Oil (BBLs)
NGLs (BBLs)
Gas (MCF) (a)
Total (BOE)
Permian Basin ..................................................................
South Texas—Eagle Ford Shale.......................................
Raton Basin ......................................................................
Mid-Continent ..................................................................
South Texas—Edwards and Austin Chalk........................
Other.................................................................................
Total continuing operations............................................
Barnett Shale ....................................................................
Alaska...............................................................................
Total including discontinued operations........................
52,596
13,737
—
3,020
171
3
69,527
1,492
4,201
75,220
_____________________
(a) Gas production excludes gas produced and used as field fuel.
15,196
10,421
—
6,801
2
2
32,422
3,193
—
35,615
70,766
80,458
134,591
40,475
30,685
69
357,044
23,443
—
380,487
79,586
37,568
22,432
16,567
5,287
16
161,456
8,592
4,201
174,249
34
PIONEER NATURAL RESOURCES COMPANY
The following table summarizes the Company's costs incurred by asset area during 2013:
Property
Acquisition Costs
Proved
Unproved
Exploration
Costs
Development
Costs
(in thousands)
Asset
Retirement
Obligations
Total
Permian Basin ............................................. $
Mid-Continent .............................................
Raton Basin .................................................
South Texas—Eagle Ford Shale..................
South Texas—Edwards and Austin Chalk..
Other............................................................
3,550
18
—
35
(32)
10
3,581
9,280
—
Total including discontinued operations... $ 12,861
Barnett Shale ...............................................
Alaska..........................................................
Total continuing operations ...................... $
$ 50,082
218
—
1,711
(17)
3,527
$ 55,521
7,641
—
$ 63,162
$ 677,528
2,633
5,119
372,065
3,171
23,351
$1,083,867
135,441
68,604
$1,287,912
$
$ 1,043,600
17,561
7,582
208,507
3,892
1
$ 1,281,143
$
49,664
140,557 (a)
$ 1,471,364
$
28,921
983
(15,847)
589
3,032
74
17,752
(109)
(5,129)
12,514
$ 1,803,681
21,413
(3,146)
582,907
10,046
26,963
$ 2,441,864
201,917
204,032
$ 2,847,813
____________________
(a)
Includes $7.1 million of capitalized interest associated with the Oooguruk development project.
Permian Basin
Spraberry field. The Spraberry field was discovered in 1949, encompasses eight counties in West Texas and the Company
believes it is the largest oil field in the United States. The field is approximately 150 miles long and 75 miles wide at its widest
point. The oil produced is West Texas Intermediate Sweet, and the gas produced is casinghead gas with an average energy content
of 1,400 BTU. The oil and gas are produced primarily from six formations, the upper and lower Spraberry, the Dean, the Wolfcamp,
the Strawn and the Atoka, at depths ranging from 6,700 feet to 11,300 feet. The Company believes the Spraberry and Wolfcamp
formations offer excellent horizontal drilling opportunities to grow oil and gas production because of the significant resource in
place and numerous undeveloped drilling locations. The Company expects to improve the incremental recovery rates in the
Spraberry field through horizontal, infill and deeper formation drilling while containing operating expenses and drilling costs
through economies of scale and vertical integration of field services.
During 2013, the Company drilled 502 wells in the Spraberry field and its total acreage position now approximates 823,000
gross acres (717,000 net acres). The Company currently has 29 rigs operating in the Spraberry field, of which 11 are drilling
vertical wells and 18 are drilling horizontal wells, and has plans to add an additional six horizontal drilling rigs by the end of the
first quarter of 2014. During 2014, the Company expects to drill approximately 200 vertical wells and 255 horizontal wells, with
the horizontal wells being principally drilled in the Wolfcamp Shale horizon. The Company expects to spend $2.4 billion of drilling
capital in the Spraberry field during 2014.
The Company believes it has significant resource potential within its acreage based on its extensive geologic data covering
the Spraberry and Wolfcamp A, B, C and D intervals and its drilling results to-date. During 2013, the Company completed 21
wells in the northern portion of the play and 100 horizontal wells in the southern portion of the play. In 2014, the Company expects
to drill 140 horizontal wells in the northern portion of the play and 115 horizontal wells in the southern portion of the play.
During 2013, the Company initiated horizontal Wolfcamp Shale drilling activities in the northern portion of its Spraberry
acreage position to delineate the area. Wells drilled in the northern portion of the play were expected to benefit from greater original
oil in place and higher reservoir pressures associated with deeper drilling depths. During 2013, the Company placed on production
nine Wolfcamp B interval wells, four Wolfcamp D interval wells, five Lower Spraberry Shale interval wells, two Jo Mill Shale
interval wells and one Wolfcamp A interval well with encouraging results. The Company’s drilling is currently focused in Midland,
Martin, Glasscock and Andrews counties. The wells in these areas are expected to be drilled on three-well pads to gain efficiencies;
therefore, the wells will not be completed until after the last well on each pad is drilled and, accordingly, production from these
wells is not expected until all wells on the pad are ready to produce. With the addition of drilling rigs during the first quarter of
2014, combined with the effects of pad drilling, the Company expects production growth to be weighted towards the second half
of 2014.
The Company continues to drill vertically to deeper intervals in the Spraberry field below the Wolfcamp interval, including
the Strawn and Atoka intervals. The 2013 drilling program reflected 90 percent of the vertical wells being deepened below the
Wolfcamp interval. The Company expects to drill approximately 200 vertical wells targeting deeper intervals during 2014. These
wells are also being drilled to meet continuous drilling obligations.
35
PIONEER NATURAL RESOURCES COMPANY
In January 2013, the Company signed an agreement with Sinochem, an unaffiliated third party, to sell 40 percent of Pioneer's
interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry
field for consideration of $1.8 billion. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $623.8
million, resulting in a 2013 gain of $181.3 million related to the unproved property interests conveyed to Sinochem. Sinochem is
paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and
facilities costs attributable to the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play. Associated
with the closing of the joint venture transaction, the Company conveyed a 40 percent interest in the producing horizontal Wolfcamp
Shale wells in the joint venture area.
The Company plans to drill 115 horizontal wells during 2014 in the joint interest area. The Company drilled 100 horizontal
Wolfcamp Shale wells during 2013 and had capital expenditures of $454.1 million in 2013. The 2014 drilling program will be
focused on drilling in the higher return areas in northern Upton and Reagan counties, with approximately two-thirds of the wells
being completed in the Wolfcamp B interval and the remainder being a mix of Wolfcamp A, C and D interval wells.
Sinochem also elected to participate in certain vertical wells that were drilled in the joint interest area after the December
1, 2012 effective date and received its share of production and costs from the Wolfcamp and deeper horizons based on the reserve
contribution from the Wolfcamp and deeper intervals relative to reserves from all completed intervals. Pioneer's and Sinochem's
participation in vertical wells is based on each party's interest without any drilling carry applied. Pioneer retained 100 percent of
its vertical production in the joint interest area for wells drilled before the December 1, 2012 effective date. Pioneer also retained
its current working interests in all horizons shallower than the Wolfcamp horizon and continues as operator of the properties in
the joint interest area.
The Company continues to benefit from its integrated services to control drilling and operating costs and support the
execution of its drilling and production activities in the Spraberry field. The Company owns 15 vertical drilling rigs and is currently
utilizing seven Company-owned fracture stimulation fleets totaling approximately 170,000 horsepower in the Spraberry field (see
Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for
additional information about the Company's plan to sell its vertical drilling rig business). To support its growing 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 to fracture stimulate vertical and horizontal
wells in the Spraberry and Wolfcamp Shale intervals.
Mid-Continent
Hugoton field. The Hugoton field in southwest Kansas is one of the largest producing gas fields in the continental United
States. The gas is produced from the Chase and Council Grove formations at depths ranging from 2,700 feet to 3,000 feet. The
Company's Hugoton properties are located on 268,000 gross acres (235,000 net acres), covering approximately 400 square miles.
The Company has working interests in approximately 1,200 wells in the Hugoton field, approximately 1,000 of which it operates.
The Company operates substantially all of the gathering and processing facilities, including the Satanta plant, which
processes the production from the Hugoton field. In January 2011, the Company sold a 49 percent interest in the Satanta plant to
an unaffiliated third party for the third party's commitment to dedicate gas volumes to the Satanta plant. This agreement has
increased the Satanta plant's processing volumes and is expected to increase its economic longevity. The Company is also exploring
opportunities to process other gas production in the Hugoton area at the Satanta plant. By maintaining operatorship of the gathering
and processing facilities, the Company is able to control the production, gathering, processing and sale of its Hugoton field gas
and NGL production.
West Panhandle field. The West Panhandle properties are located in the panhandle region of Texas. These stable, long-
lived reserves are attributable to the Red Cave, Brown Dolomite, Granite Wash and fractured Granite formations at depths no
greater than 3,500 feet. The Company's gas has an average energy content of 1,365 BTU and is produced from approximately 700
wells on more than 246,000 gross acres (239,000 net acres) covering over 375 square miles. The Company controls 100 percent
of the wells, production equipment, gathering system and the Fain gas processing plant for the field. As this field is characterized
by very low reservoir pressure, Pioneer continually works to improve compressor and gathering system efficiency.
Raton Basin
The Raton Basin properties are located in the southeast portion of Colorado. The Company owns 198,000 gross acres
(178,000 net acres) in the center of the Raton Basin and produces CBM gas from the coal seams in the Vermejo and Raton formations
from approximately 2,300 wells. The Company owns the majority of the well servicing and fracture stimulation equipment that
it utilizes in the Raton field, allowing it to control costs and ensure availability. See Note D of Notes to Consolidated Financial
36
PIONEER NATURAL RESOURCES COMPANY
Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information about the impairment
charge recorded during 2013 to reduce the carrying value of the Company's gas properties in the Raton field.
South Texas Eagle Ford Shale
The Company's drilling activities in the South Texas area during 2013 continued to be primarily focused on delineation and
development of Pioneer's substantial acreage position in the Eagle Ford Shale play. The 2013 drilling program was focused on
liquids-rich drilling, with no wells drilled in dry gas acreage.
The Company completed 132 horizontal Eagle Ford Shale wells during 2013, all of which were successful, with average
lateral lengths of 5,300 feet and, on average, 15-stage fracture stimulations. Additionally, the Company completed its first successful
Upper Eagle Ford Shale well and estimates that approximately 25 percent of the Company's acreage is prospective for this interval
in the Eagle Ford Shale play. The Company plans to spend $545 million of drilling capital in 2014 to drill approximately 110
Eagle Ford Shale wells. The Company has been using two Pioneer-owned fracture stimulation fleets during 2013 in the Eagle
Ford Shale area and plans to continue that usage in 2014.
The Company's drilling operations in the Eagle Ford Shale continue to focus on improving drilling efficiencies. The
Company has added approximately 300 drilling locations in the liquids-rich area of the play as a result of downspacing from 1,000
feet between wells (120-acre spacing) to 500 feet (60-acre spacing) between wells. Further downspacing and staggered testing to
175 feet between wells is underway in the liquids-rich areas where the 500-foot spacing was successful. Some areas will include
testing of the Lower Eagle Ford Shale interval only, while others will include a combination of the Lower and Upper intervals.
Early results from the initial 300-foot downspacing and staggered test in the Lower Eagle Ford Shale continue to be encouraging
with five downspaced wells performing consistently with offset 500-foot spaced wells. The number of wells drilled from pads, as
opposed to single-well locations, increased from about 45 percent of the Eagle Ford Shale wells during 2012 to about 80 percent
in 2013, reflecting that most of the Company's acreage is now held by production. Pad drilling saves the Company a significant
amount of capital costs per well, as compared to single-well location drilling. Pad sizes generally range from two wells to six
wells. In 2014, most Eagle Ford Shale wells will be drilled utilizing three-well and four-well pads. None of the wells are completed
until all of the wells on a pad are drilled. Therefore, the time between when the first well on a pad is spud and when the pad is
placed on production is dependent on how many wells are drilled from the pad.
Over the past two years, the Company has been testing the use of lower-cost white sand instead of ceramic proppant to
fracture stimulate wells drilled in shallower areas of the field. The Company is expanding the use of white sand proppant to deeper
areas of the field to further define its performance limits. Early well performance has been similar to direct offset ceramic-stimulated
wells. The Company fracture stimulated 100 wells with white sand proppant during 2013, with significant capital savings per well.
The Company is continuing to monitor the performance of these wells and expects that the majority of its 2014 drilling program
in the Eagle Ford Shale area will use lower-cost white sand proppant.
During June 2010, the Company entered into an Eagle Ford Shale joint venture transaction. Pursuant to the transaction,
the Company entered into a purchase and sale agreement to sell 45 percent of its Eagle Ford Shale proved and unproved oil and
gas properties to an unaffiliated third party for $212.0 million of cash proceeds. Under the terms of the transaction, the purchaser
also paid a 75 percent carry obligation of $886.8 million to cover a portion of the Company's share of exploration, drilling and
completion costs attributable to the Eagle Ford Shale assets during the period from June 2010 through December 2012. As of
December 31, 2012, the purchaser's carry obligation was satisfied.
The Company owns a 50.1 percent member interest in EFS Midstream LLC ("EFS Midstream"), an entity formed by the
Company to own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play. The
Company does not have control of EFS Midstream and accounts for its investment in EFS Midstream under the equity method of
accounting for investments in unconsolidated affiliates. EFS Midstream is obligated to construct midstream assets in the Eagle
Ford Shale area. The majority of the construction of the midstream assets has been completed. Eleven of the 13 planned central
gathering plants were completed as of December 31, 2013. EFS Midstream is providing gathering, treating and transportation
services for the Company during a 20-year contractual term. During 2011, EFS Midstream entered into a $300 million, five-year
revolving credit facility that is available to fund infrastructure investments, distributions or working capital needs to the extent
such uses exceed EFS Midstream's operating cash flows.
Barnett Shale
During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in
North Texas. The plan is expected to result in the sale of the Barnett Shale net assets during 2014. The Company classified the
Barnett Shale field assets and liabilities as held for sale in the Company's accompanying consolidated balance sheet as of December
31, 2013. Associated with the plan to sell the Barnett Shale field, the Company recorded a noncash impairment charge of $189.5
million during December 2013 to reduce the carrying value of the Barnett Shale net assets to their estimated fair value less costs
37
PIONEER NATURAL RESOURCES COMPANY
to sell. Historical results of operations from the Company's Barnett Shale field, and the related impairment loss, are reported as
discontinued operations, net of tax in the Company's accompanying consolidated statements of operations.
See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information about the Company's plan to sell its Barnett Shale assets.
Alaska
During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in Pioneer
Alaska, representing all the Company's net assets in Alaska including the Company's 70 percent working interest in the Oooguruk
project. The sale of Pioneer Alaska continues to be subject to ongoing negotiations and certain other conditions, such as
governmental approvals and buyer's arrangement of financing. The assets and liabilities of Pioneer Alaska are classified as held
for sale in the Company's accompanying consolidated balance sheet as of December 31, 2013. Associated with the planned sale
of Pioneer Alaska, the Company recorded a noncash impairment charge of $539.8 million during December 2013 to reduce the
carrying value of the Pioneer Alaska assets to their estimated fair value less costs to sell of $350.6 million. Pioneer Alaska's
historical results of operations, and the related impairment loss, are reported as discontinued operations, net of tax in the Company's
accompanying consolidated statements of operations.
See Notes C and F of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information about the Company's planned divestiture and exploration projects in Alaska,
respectively.
The Company's plans to sell the Barnett Shale net assets and Pioneer Alaska are in differing stages of marketing and
negotiation. No assurance can be given that the sales will be completed in accordance with the Company's plans.
International
During August 2012 and February 2011, the Company completed the sales of Pioneer South Africa and Pioneer Tunisia,
respectively, to different unaffiliated third parties. See Note C of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for information regarding the sale of Pioneer South Africa and Pioneer Tunisia.
As a result of these sales, the Company no longer has operations outside the United States.
Selected Oil and Gas Information
The following tables set forth selected oil and gas information for the Company as of and for each of the years ended
December 31, 2013, 2012 and 2011. Because of normal production declines, increased or decreased drilling activities and the
effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of
future results.
Production, price and cost data. The price that the Company receives for the oil and gas it produces is largely a function
of market supply and demand. Demand is affected by general economic conditions, weather and other seasonal conditions, including
hurricanes and tropical storms. Over or under supply of oil or gas can result in substantial price volatility. Historically, commodity
prices have been volatile and the Company expects that volatility to continue in the future. A substantial or extended decline in
oil or gas prices or poor drilling results could have a material adverse effect on the Company's financial position, results of
operations, cash flows, quantities of oil and gas reserves that may be economically produced and the Company's ability to access
capital markets.
The following tables set forth production, price and cost data with respect to the Company's properties for 2013, 2012 and
2011. These amounts represent the Company's historical results from operations without making pro forma adjustments for any
acquisitions, divestitures or drilling activity that occurred during the respective years. The production amounts will not match the
proved reserve volume tables in the "Unaudited Supplementary Information" section included in "Item 8. Financial Statements
and Supplementary Data" because field fuel volumes are included in the proved reserve volume tables.
38
PIONEER NATURAL RESOURCES COMPANY
PRODUCTION, PRICE AND COST DATA
Year Ended December 31, 2013
Included in
Continuing Operations
Spraberry
Field
Eagle Ford
Shale Field
Raton
Field
Total
Company
Fields
Included in
Discontinued
Operations
United States
Total
Production information:
Annual sales volumes:
Oil (MBBLs) ................................................
NGLs (MBBLs)............................................
Gas (MMCF) ................................................
Total (MBOE)...............................................
Average daily sales volumes:
Oil (BBLs) ....................................................
NGLs (BBLs) ...............................................
Gas (MCF)....................................................
Total (BOE) ..................................................
Average prices:
19,176
5,410
24,679
28,699
52,537
14,822
67,614
78,627
Oil (per BBL)................................................ $
NGL (per BBL)............................................. $
Gas (per MCF).............................................. $
Revenue (per BOE) ...................................... $
93.30
30.34
3.23
70.84
$
$
$
$
Average costs (per BOE):
Production costs:
Lease operating .......................................... $
Third-party transportation charges.............
Net natural gas plant/gathering ..................
Workover....................................................
Total ........................................................... $
Production and ad valorem taxes:
Ad valorem................................................. $
Production ..................................................
Total ........................................................... $
Depletion expense ....................................... $
11.38
$
0.24
(1.11)
1.45
11.96
1.70
3.45
5.15
18.47
$
$
$
$
5,014
3,804
29,367
13,712
13,737
10,421
80,458
37,568
91.74
26.72
3.63
48.73
3.23
3.86
0.01
0.20
7.30
0.65
1.31
1.96
8.80
—
—
49,126
8,188
—
—
134,591
22,432
25,377
11,834
130,321
58,931
69,527
32,422
357,044
161,456
$
$
$
$
$
$
$
$
$
— $
— $
3.27
19.61
6.25
3.02
1.90
—
11.17
0.42
0.35
0.77
18.97
$
$
$
$
$
$
$
92.62
30.24
3.43
53.55
8.00
1.56
0.10
0.77
10.43
1.22
2.20
3.42
14.70
$
$
$
$
$
$
$
$
$
2,078
1,165
8,557
4,669
5,693
3,193
23,443
12,793
98.81
25.31
3.00
55.79
$
$
$
$
15.93
$
1.67
(0.95)
2.70
19.35
1.68
0.50
2.18
21.49
$
$
$
$
27,455
12,999
138,878
63,601
75,220
35,615
380,487
174,249
93.09
29.79
3.41
53.71
8.58
1.57
0.02
0.91
11.08
1.25
2.07
3.32
15.20
39
PIONEER NATURAL RESOURCES COMPANY
PRODUCTION, PRICE AND COST DATA - (Continued)
Year Ended December 31, 2012
Included in
Continuing Operations
Included in
Discontinued Operations
Spraberry
Field
Eagle Ford
Shale Field
Raton
Field
Total
Company
Fields
United
States
South
Africa
Total
Production information:
Annual sales volumes:
Oil (MBBLs) ...........................................
NGLs (MBBLs) ......................................
Gas (MMCF) ...........................................
Total (MBOE) .........................................
Average daily sales volumes:
Oil (BBLs)...............................................
NGLs (BBLs) ..........................................
Gas (MCF) ..............................................
Total (BOE).............................................
Average prices, including hedge results
and amortization of deferred VPP
revenue (a):
Oil (per BBL) .......................................... $
NGL (per BBL) ....................................... $
Gas (per MCF) ........................................ $
Revenue (per BOE) ................................. $
Average prices, excluding hedge results
and amortization of deferred VPP
revenue (a):
Oil (per BBL) .......................................... $
NGL (per BBL) ....................................... $
Gas (per MCF) ........................................ $
Revenue (per BOE) ................................. $
Average costs (per BOE):
Production costs:
Lease operating..................................... $
Third-party transportation charges .......
Net natural gas plant/gathering.............
Workover ..............................................
Total...................................................... $
Production and ad valorem taxes:
Ad valorem ........................................... $
Production.............................................
Total...................................................... $
Depletion expense .................................. $
16,096
4,451
21,345
24,104
43,978
12,160
58,319
65,858
90.57
32.23
2.58
68.72
87.95
32.23
2.58
66.97
$
$
$
$
$
$
$
$
11.33
$
0.17
(0.49)
1.71
12.72
1.78
3.47
5.25
15.58
$
$
$
$
3,613
2,683
23,182
10,160
9,871
7,332
63,338
27,759
93.84
31.81
2.81
48.18
93.84
31.81
2.81
48.18
3.21
3.00
—
0.08
6.29
0.71
2.00
2.71
5.51
—
—
54,822
9,137
—
—
149,787
24,965
20,922
9,904
131,132
52,682
57,165
27,060
358,284
143,939
2,006
1,009
7,351
4,239
5,480
2,756
20,085
11,583
157
—
3,784
787
428
—
10,340
2,151
23,085
10,913
142,267
57,708
63,073
29,816
388,709
157,673
$
$
$
$
$
$
$
$
$
$
$
$
$
— $
— $
2.41
14.48
$
$
90.67
34.04
2.60
48.88
— $
— $
2.41
14.48
6.47
3.12
1.82
—
11.41
0.17
0.11
0.28
19.52
$
$
$
$
$
$
$
88.81
34.04
2.60
48.15
7.91
1.31
0.54
0.83
10.59
1.22
2.17
3.39
12.82
$
$
$
$
$
$
$
$
93.20
30.86
2.49
55.75
93.20
30.86
2.49
55.75
$
$
$
$
$
$
$
$
108.62
$
— $
8.50
62.48
$
$
91.01
33.75
2.75
49.57
108.62
$
— $
8.50
62.48
$
$
89.32
33.75
2.75
48.90
$
16.28
$
2.86
$
1.33
(0.40)
1.10
18.31
1.69
0.44
2.13
23.37
$
$
$
$
$
$
$
$
—
—
—
8.46
1.29
0.47
0.84
2.86
$
11.06
— $
—
— $
— $
1.24
2.01
3.25
13.42
_____________________
(a)
The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging
activities at a field level. As of December 31, 2012, the Company had no further obligation to deliver oil under the VPP
and did not have any hedging activities.
40
PIONEER NATURAL RESOURCES COMPANY
PRODUCTION, PRICE AND COST DATA - (Continued)
Year Ended December 31, 2011
Included in
Continuing Operations
Included in
Discontinued Operations
Spraberry
Field
Eagle Ford
Shale Field
Raton
Field
Total
Company
Fields
United
States
South
Africa
Tunisia
Total
10,011
3,844
15,899
16,505
27,428
10,530
43,559
45,218
1,600
1,088
10,227
4,393
4,383
2,982
28,020
12,035
—
—
12,989
7,708
58,601
121,496
9,767
40,947
—
—
35,587
21,119
1,836
500
4,020
3,006
5,031
1,368
193
—
7,508
1,445
530
—
160,550
332,866
11,013
20,570
26,758
112,184
8,234
3,958
201
—
181
229
547
—
496
630
15,219
8,208
133,205
45,627
41,695
22,487
364,945
125,006
Production information:
Annual sales volumes:
Oil (MBBLs)..........................................
NGLs (MBBLs) .....................................
Gas (MMCF)..........................................
Total (MBOE)........................................
Average daily sales volumes:
Oil (BBLs) .............................................
NGLs (BBLs).........................................
Gas (MCF) .............................................
Total (BOE)............................................
Average prices, including hedge results
and amortization of deferred VPP
revenue (a):
Oil (per BBL)......................................... $
NGL (per BBL)...................................... $
Gas (per MCF) ....................................... $
Revenue (per BOE)................................ $
95.93
42.38
3.44
71.37
Average prices, excluding hedge
results and amortization of deferred
VPP revenue (a):
Oil (per BBL)......................................... $
NGL (per BBL)...................................... $
Gas (per MCF) ....................................... $
Revenue (per BOE)................................ $
91.44
42.38
3.44
68.65
$
$
$
$
$
$
$
$
Average costs (per BOE):
Production costs:
Lease operating ................................... $
Third-party transportation charges ......
Net natural gas plant/gathering ...........
Workover.............................................
10.40
$
—
(1.45)
1.74
Total..................................................... $
10.69
Production and ad valorem taxes:
Ad valorem.......................................... $
Production ...........................................
Total..................................................... $
Depletion expense................................. $
1.73
3.87
5.60
11.41
$
$
$
$
89.02
48.21
3.93
53.51
89.02
48.21
3.93
53.51
5.45
2.77
—
0.02
8.24
0.27
2.64
2.91
6.40
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
— $
96.60
$ 96.58
$ 108.14
$ 99.03
$
96.78
— $
46.31
$ 45.64
— $ — $
46.27
3.81
22.86
$
$
3.86
$
3.41
7.62
$ 13.04
50.80
$ 71.15
$ 54.09
$ 96.29
$
$
4.07
52.48
— $
90.61
$ 96.58
$ 108.14
$ 99.03
$
91.67
— $
46.31
$ 45.64
— $ — $
46.27
3.86
$
3.41
7.62
$ 13.04
48.90
$ 71.15
$ 54.09
$ 96.29
3.81
22.86
6.49
3.01
2.15
—
11.65
0.41
0.31
0.72
14.46
$
$
$
$
$
$
$
7.59
1.14
0.16
0.80
9.69
1.17
2.23
3.40
$ 14.75
$
2.35
$
0.86
—
1.08
—
—
—
7.61
1.91
—
(0.27)
$ 16.69
$
$
2.22
0.52
2.74
$
$
$
2.35
$
9.25
$
10.04
— $ — $
—
—
— $ — $
1.20
2.04
3.24
11.33
$ 29.15
$ 29.00
$ — $
13.01
$
$
$
4.07
50.77
7.90
1.22
0.14
0.78
____________________
(a)
The Company records the amortization of deferred VPP revenue at a field level but does not record the results of its hedging
activities at a field level.
41
PIONEER NATURAL RESOURCES COMPANY
Productive wells. Productive wells consist of producing wells and wells capable of production, including shut-in wells and
gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. One
or more completions in the same well bore are counted as one well. Any well in which one of the multiple completions is an oil
completion is classified as an oil well.
The following table sets forth the number of productive oil and gas wells attributable to the Company's properties as of
December 31, 2013:
PRODUCTIVE WELLS
Continuing operations...................................
Discontinued operations ...............................
Total............................................................
Gross Productive Wells
Gas
Oil
6,928
28
6,956
4,989
125
5,114
Total
11,917
153
12,070
Net Productive Wells
Gas
Oil
6,146
20
6,166
4,430
119
4,549
Total
10,576
139
10,715
Leasehold acreage. The following table sets forth information about the Company's developed, undeveloped and royalty
leasehold acreage as of December 31, 2013:
LEASEHOLD ACREAGE
Continuing operations .......................................
Discontinued operations....................................
Total................................................................
Developed Acreage
Undeveloped Acreage
Gross Acres
1,612,060
79,953
1,692,013
Net Acres
1,376,615
64,558
1,441,173
Gross Acres
Net Acres
1,144,877
48,854
1,193,731
773,134
39,494
812,628
Royalty
Acreage
298,443
10,497
308,940
The following table sets forth the expiration dates of the leases on the Company's gross and net undeveloped acres as of
December 31, 2013:
2014..........................................................................................................................................
2015..........................................................................................................................................
2016..........................................................................................................................................
2017..........................................................................................................................................
2018 ..........................................................................................................................................
Thereafter .................................................................................................................................
Total...................................................................................................................................
_____________________
(a) Acres expiring are based on contractual lease maturities.
Acres Expiring (a)
Gross
147,435
107,383
764,845
112,794
36,966
24,308
1,193,731
Net
104,929
72,453
500,980
77,613
34,562
22,091
812,628
42
PIONEER NATURAL RESOURCES COMPANY
Drilling and other exploratory and development activities. The following table sets forth the number of gross and net wells
drilled by the Company during 2013, 2012 and 2011 that were productive or dry holes. This information should not be considered
indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells
drilled and the oil and gas reserves generated thereby or the costs to the Company of productive wells compared to the costs of
dry holes.
DRILLING ACTIVITIES
Productive wells:
Development ..................................................
Exploratory ....................................................
Dry holes:
Development ..................................................
Exploratory ....................................................
Total..................................................................
Success ratio (a) ...............................................
Gross Wells
Year Ended December 31,
2012
2013
2011
2013
Net Wells
Year Ended December 31,
2012
2011
444
244
1
9
698
99%
659
223
10
6
898
98%
725
167
11
1
904
99%
382
164
1
6
553
99%
595
144
6
6
751
98%
661
115
10
1
787
99%
______________________
(a)
Represents the ratio of those wells that were successfully completed as producing wells or wells capable of producing to
total wells drilled and evaluated.
Present activities. The following table sets forth information about the Company's wells that were in process of being drilled
as of December 31, 2013:
Development ......................................................................................................................................
Exploratory ........................................................................................................................................
Total ...................................................................................................................................................
Gross Wells
80
77
157
Net Wells
62
55
117
ITEM 3.
LEGAL PROCEEDINGS
The Company is party to various proceedings and claims incidental to its business. While many of these matters involve
inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect to 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. See Note J of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding legal proceedings
involving the Company.
ITEM 4.
MINE SAFETY DISCLOSURES
The Company's sand mines are subject to regulation by the Federal Mine Safety and Health Administration under the Federal
Mine Safety and Health Act of 1977, as amended by the Mine Improvement and New Emergency Response Act of 2006. Information
concerning mine safety violations or other regulatory matters required by Section 1503(a) of the Dodd-Frank Wall Street Reform
and Consumer Protection Act and Item 104 of Regulation S-K is included in Exhibit 95.1 to this Annual Report filed on Form 10-
K.
43
PIONEER NATURAL RESOURCES COMPANY
PART II
ITEM 5.
MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND
ISSUER PURCHASES OF EQUITY SECURITIES
The Company's common stock is listed and traded on the NYSE under the symbol "PXD." The Company's board of directors
(the "Board") declared dividends to the holders of the Company's common stock of $0.04 per share during each of the first and
third quarters of the years ended December 31, 2013 and 2012. The Board intends to consider the payment of dividends to the
holders of the Company's common stock in the future. The declaration and payment of future dividends, however, will be at the
discretion of the Board and will depend on, among other things, the Company's earnings, financial condition, capital requirements,
level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that the
Board deems relevant.
The following table sets forth quarterly high and low prices of the Company's common stock and dividends declared per
share for the years ended December 31, 2013 and 2012:
Year ended December 31, 2013
Fourth quarter ......................................................................................................... $
Third quarter........................................................................................................... $
Second quarter........................................................................................................ $
First quarter ............................................................................................................ $
Year ended December 31, 2012
Fourth quarter ......................................................................................................... $
Third quarter........................................................................................................... $
Second quarter........................................................................................................ $
First quarter ............................................................................................................ $
High
Low
Dividends
Declared
Per Share
227.42
190.15
157.81
133.68
110.67
115.69
117.05
119.19
$
$
$
$
$
$
$
$
172.60
146.19
109.19
107.29
99.75
82.18
77.41
90.26
$
$
$
$
$
$
$
$
—
0.04
—
0.04
—
0.04
—
0.04
On February 20, 2014, the last reported sales price of the Company's common stock, as reported in the NYSE composite
transactions, was $189.60 per share.
As of February 20, 2014, the Company's common stock was held by 13,527 holders of record.
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes the Company's purchases of its common stock during the three months ended December
31, 2013:
Period
October 2013 ......................................................
November 2013 ..................................................
December 2013 ..................................................
Total....................................................................
Total Number of
Shares (or Units)
Purchased (a)
Average Price
Paid per Share
(or Unit)
243
$
— $
— $
$
243
201.35
—
—
201.35
Total Number of
Shares (or Units)
Purchased as
Part of Publicly
Announced Plans
or Programs
Approximate Dollar
Amount of Shares
that May Yet Be
Purchased under
Plans or Programs
—
—
—
—
—
—
—
— $
______________________
(a)
Consists of shares purchased from employees in order for the employees to satisfy tax withholding payments related to
share-based awards that vested during the period.
44
PIONEER NATURAL RESOURCES COMPANY
ITEM 6.
SELECTED FINANCIAL DATA
The following selected consolidated financial data of the Company as of and for each of the five years ended December
31, 2013 should be read in conjunction with "Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations" and "Item 8. Financial Statements and Supplementary Data."
Statements of Operations Data:
2013
Year Ended December 31,
2012
2010
2011
(in millions, except per share data)
2009
Oil and gas revenues............................................................ $ 3,155.7
Total revenues and other income......................................... $ 3,719.5
Total costs and expenses (a) ................................................ $ 4,281.2
Income (loss) from continuing operations........................... $
Income (loss) from discontinued operations, net of tax (b). $
Net income (loss) attributable to common stockholders........ $
(349.9) $
(449.6) $
(838.4) $
Income (loss) from continuing operations attributable to
common stockholders per share:
Basic.................................................................................. $
Diluted............................................................................... $
(2.86) $
(2.86) $
Net income (loss) attributable to common stockholders
per share:
Basic.................................................................................. $
Diluted............................................................................... $
Dividends declared per share............................................... $
(6.16) $
(6.16) $
$
0.08
Balance Sheet Data (as of December 31):
$ 2,575.3
$ 2,080.2
$ 1,528.0
$ 1,283.5
$ 3,072.5
$ 2,513.2
$ 2,143.7
$ 1,076.4
$ 2,235.0
$ 1,917.2
$ 1,329.4
547.0
$
(304.2) $
$
192.3
407.8
474.1
834.5
4.02
3.91
1.54
1.50
0.08
$
$
$
$
$
3.03
2.97
7.01
6.88
0.08
$
$
$
$
$
$
$
$
$
$ 1,354.5
(178.6)
136.3
(52.1)
$
$
545.2
100.8
605.2
4.29
4.24
5.14
5.08
0.08
$
$
$
$
$
(1.65)
(1.65)
(0.46)
(0.46)
0.08
Total assets........................................................................... $ 12,292.8
Long-term obligations ......................................................... $ 4,427.9
Total stockholders' equity.................................................... $ 6,614.8
$ 13,069.0
$ 11,447.2
$ 9,679.1
$ 8,867.3
$ 6,166.9
$ 4,726.5
$ 4,683.9
$ 4,653.0
$ 5,867.3
$ 5,651.1
$ 4,226.0
$ 3,643.0
______________________
(a) During 2013 and 2011, the Company recognized impairment charges of $1.5 billion related to dry gas properties in the
Raton field and $354.4 million related to its Edwards and Austin Chalk net assets in South Texas, respectively. See "Item
7. Management's Discussion and Analysis of Financial Condition and Results of Operations" and Note D of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information
about the Company's impairment charges.
(b) During 2013, the Company committed to separate plans to divest of Pioneer Alaska and its assets in the Barnett Shale field.
The Company recorded noncash impairment charges of $729.3 million during 2013 associated with the planned sales and
$532.6 million during 2012 related to dry gas properties in the Barnett Shale field. During December 2011, the Company
committed to a plan to divest Pioneer South Africa. During December 2010, the Company committed to a plan to sell
Pioneer Tunisia and in February 2011 completed the sale of the Company's share holdings in Pioneer Tunisia, resulting in
a gain of $645.2 million. During 2009, the Company recorded $119.3 million of income for the recovery of the excess
royalties related to its Gulf of Mexico shelf properties, which were sold in 2006. The results of these operations which are
in the process of being sold or were sold during the periods presented are classified as discontinued operations in accordance
with GAAP. See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for more information about the Company's discontinued operations.
45
PIONEER NATURAL RESOURCES COMPANY
ITEM 7.
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS
Financial and Operating Performance
Pioneer's financial and operating performance for 2013 included the following highlights:
•
Net loss attributable to common stockholders was $838.4 million ($6.16 per diluted share) for the year ended December
31, 2013, as compared to net income attributable to common stockholders of $192.3 million ($1.50 per diluted share) in
2012. The $1.0 billion decrease in net income attributable to common stockholders is primarily comprised of an $897.0
million decrease in income from continuing operations and a $145.4 million increase in loss from discontinued operations,
net of tax.
The primary components of the decrease in net income from continuing operations include:
•
•
•
•
•
•
•
•
•
a $1.5 billion impairment charge to reduce the carrying value of the Company’s Raton gas field assets based on
reductions in management's long-term gas price outlook (see Note D of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" and "Results of Operations" below);
a $326.2 million decrease in net derivative gains, primarily as a result of changes in forward commodity prices and
changes in the Company's portfolio of derivatives;
a $79.1 million increase in total oil and gas production costs and production and ad valorem taxes, primarily due to
a 12 percent increase in sales volumes;
a $198.8 million increase in DD&A expense, primarily attributable to the aforementioned increase in sales volumes
coupled with a decrease in Spraberry field proved undeveloped reserves as a result of removing vertical well locations
that are no longer expected to be drilled as the Company shifts its capital resources to higher-rate-of-return horizontal
drilling (see Supplementary Information included in "Item 8. Financial Statements and Supplementary Data");
a $51.7 million increase in general and administrative expenses primarily due to growth in employee headcount in
support of the Company's capital expansion initiatives, performance-related compensation expense and higher stock-
based compensation expense associated with cash-settled restricted stock awards, which are classified as liabilities,
as a result of increases in the market value of the Company's common stock; and
a $23.2 million increase in other expense, primarily due to increases in impairment of inventory and other assets;
partially offset by
a $580.4 million increase in oil and gas revenues as a result of a 12 percent increase in total sales volumes and a 10
percent increase in average commodity prices received per BOE;
a $502.3 million decrease in income tax provision due to the decline in income from continuing operations before
income taxes;
a $163.1 million increase in gain on disposition of assets, primarily due to the gain recorded on the Company's sale
of a 40 percent interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry
field in West Texas to Sinochem; and
•
a $20.5 million decrease in interest expense, primarily due to a decline in outstanding borrowings.
The primary components of the increase in the loss from discontinued operations, net of tax, include:
•
•
•
a $196.7 million increase in impairment provisions associated with the planned sales of Pioneer Alaska and the
Company's Barnett Shale field assets ($729.3 million) as compared to the 2012 impairment of Barnett Shale field
assets included in discontinued operations ($532.6 million); and
a $32.0 million decrease in net gains on sales of portions of the Company's discontinued operations in the Barnett
Shale, Alaska and South Africa assets; partially offset by
a $68.4 million increase in income tax benefit.
During December 2013, the Company committed to a plan to sell Pioneer Alaska and the Company's Barnett Shale
field assets. In accordance with GAAP, the Company has classified Pioneer Alaska and the Barnett Shale field assets and
liabilities as discontinued operations held for sale in the Company's accompanying consolidated balance sheet as of December
31, 2013, and has recast Pioneer Alaska and the Barnett Shale field asset's results of operations as loss from discontinued
operations, net of associated income taxes, in the accompanying consolidated statements of operations included in "Item
8. Financial Statements and Supplementary Data." Loss from discontinued operations, net of tax for the year ended December
31, 2013 includes (i) recognized noncash impairment charges totaling $729.3 million representing adjustments to reduce
the carrying values of Pioneer Alaska and the Company's Barnett Shale field assets to their estimated fair values, partially
offset by (ii) the results of discontinued operations (see Note C of Notes to Consolidated Financial Statements included in
"Item 8. Financial Statements and Supplementary Data" for more information about the Company's discontinued operations);
46
PIONEER NATURAL RESOURCES COMPANY
•
•
•
•
•
Daily sales volumes from continuing operations increased on a BOE basis by 12 percent to 161,456 BOEPD during 2013,
as compared to 143,939 BOEPD during 2012, primarily due to the success of the Company's drilling programs;
Average reported oil and gas prices from continuing operations increased during 2013 to $92.62 per BBL and $3.43 per
MCF, respectively, as compared to respective average reported prices of $90.67 per BBL and $2.60 per MCF during 2012.
Average reported NGL prices from continuing operations decreased during 2013 to $30.24 per BBL, as compared to an
average reported price of $34.04 per BBL during 2012;
Average oil and gas production costs per BOE from continuing operations decreased during 2013 to $10.43 as compared
to per BOE costs of $10.59 during 2012, primarily due to a decrease in net natural gas plant charges as a result of higher
gas prices being realized on third-party volumes that are retained as processing fees in Company-owned facilities, partially
offset by higher third-party transportation charges incurred on increasing sales volumes in the Eagle Ford Shale field. See
"Results of Operations" below for more information about changes in production costs;
Net cash provided by operating activities increased by $307.7 million, or 17 percent, to $2.1 billion for 2013, as compared
to $1.8 billion during 2012, primarily due to the increases in oil and gas sales volumes and prices, partially offset by a
$227.6 million decrease in cash receipts on settled derivative instruments; and
As of December 31, 2013, the Company's net debt to book capitalization declined to 25 percent, as compared to 37 percent
as of December 31, 2012, primarily due to (i) the February 2013 issuance of 10.35 million shares of the Company's common
stock for $1.3 billion of cash proceeds, net of associated underwriting and offering expenses, and (ii) the May 2013 completion
of the sale of a 40 percent interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in
the southern portion of the Spraberry field in West Texas for $623.8 million of cash proceeds. The Company utilized a
portion of the proceeds from these items to reduce long-term debt by $1.1 billion during 2013 and increase cash and cash
equivalents by $163.3 million. The long-term debt reduction during 2013 included (i) the conversion of the Company's
2.875% Convertible Senior Notes (the "Convertible Senior Notes"), (ii) the repayment and termination of Pioneer Southwest's
credit facility and (iii) the repayment of all amounts outstanding on the Company's credit facility.
First Quarter 2014 Outlook
Based on current estimates, the Company expects that first quarter 2014 production will average 166,000 to 171,000 BOEPD.
First quarter production costs (including production and ad valorem taxes and transportation costs) are expected to average
$13.50 to $15.50 per BOE, based on current NYMEX strip prices for oil and gas. DD&A expense is expected to average $13.50
to $15.50 per BOE.
Total exploration and abandonment expense for the quarter is expected to be $25 million to $35 million. General and
administrative expense is expected to be $70 million to $75 million. Interest expense is expected to be $44 million to $49 million,
and other expense is expected to be $25 million to $35 million. Accretion of discount on asset retirement obligations is expected
to be $3 million to $5 million.
The Company's first quarter effective income tax rate is expected to range from 35 percent to 40 percent, assuming current
capital spending plans and no significant derivative MTM changes in the Company's derivative position. Cash income taxes are
expected to be $5 million to $10 million and are primarily attributable to federal alternative minimum tax and state taxes.
2014 Capital Budget
Pioneer's capital program for 2014 totals $3.3 billion, consisting of $3.0 billion for drilling operations, including budgeted
land capital for existing assets, and $285 million for other property and equipment. The 2014 budget excludes acquisitions, asset
retirement obligations, capitalized interest, geological and geophysical general and administrative expense and capital expenditures
associated with Pioneer Alaska and Barnett Shale field assets prior to their sale.
The 2014 drilling capital of $3.0 billion continues to be focused on oil- and liquids-rich drilling, with 97 percent of the
capital allocated to the Spraberry field and the Eagle Ford Shale play. Following is a breakdown of the forecasted spending by
asset area:
•
Spraberry field - $2.4 billion, including (i) $205 million for drilling and facilities capital in the southern Wolfcamp
joint interest area and (ii) $2.2 billion of capital in the northern Spraberry/Wolfcamp acreage, which includes $1.2
billion of horizontal drilling capital, $440 million of vertical drilling capital, $400 million for infrastructure, land and
science and $100 million for gas processing facilities;
• Eagle Ford Shale – $545 million, including $480 million of horizontal drilling capital and $65 million for infrastructure
and land; and
47
PIONEER NATURAL RESOURCES COMPANY
• Other spending – $100 million for other existing assets.
Pioneer's budgeted expenditures for other property and equipment in 2014 include:
• Buildings and other facilities – $160 million;
• Vertical integration capital – $100 million; and
• Vehicles and other equipment – $25 million.
The 2014 capital budget is expected to be funded from a combination of cash and cash equivalents, operating cash flow,
proceeds from the sale of assets held for sale or from the sale of other nonstrategic assets and, if necessary, borrowings under the
Company's credit facility.
Acquisitions
During 2013, 2012 and 2011, the Company spent $76.0 million, $157.5 million and $131.9 million, respectively, to acquire
primarily undeveloped acreage for future exploitation and exploration activities. The 2013 and 2012 acquisitions primarily
increased the Company's acreage positions in the West Texas Spraberry field. The 2011 acquisitions primarily increased the
Company's acreage positions in the South Texas Eagle Ford Shale play, Barnett Shale play and West Texas Spraberry field. During
2013, the Company completed the acquisition of all of the outstanding common units of Pioneer Southwest not already owned by
the Company in exchange for 0.2325 of a share of common stock of the Company per Pioneer Southwest common unit. Additionally,
in 2012, the Company acquired Premier Silica for $297.1 million. See Note C of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional information about the Company's acquisitions.
Divestitures and Discontinued Operations
Alaska. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in
Pioneer Alaska. The sale of Pioneer Alaska continues to be subject to ongoing negotiations and certain other conditions, such as
governmental approvals and buyer's arrangement of financing. Associated with the planned sale of Pioneer Alaska, the Company
recorded a noncash impairment charge of $539.8 million in discontinued operations during December 2013 to reduce the carrying
value of Pioneer Alaska to its estimated fair value less costs to sell of $350.6 million. The Company has classified Pioneer Alaska
assets and liabilities as held for sale in the accompanying consolidated balance sheet as of December 31, 2013 and has reported
Pioneer Alaska's historical results of operations, and the related impairment loss, as discontinued operations, net of tax in the
Company's accompanying consolidated statements of operations.
Barnett Shale. During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett
Shale field in North Texas. The plan is expected to result in the sale of the Company's Barnett Shale net assets during 2014. The
Company has classified its Barnett Shale field assets and liabilities as held for sale in the accompanying consolidated balance
sheet as of December 31, 2013 and has reported the Company's Barnett Shale field historical results of operations, and the related
impairment loss, as discontinued operations, net of tax in the Company's accompanying consolidated statements of operations.
Associated with the plan to sell its net assets in the Barnett Shale field, the Company recorded a noncash impairment charge
of $189.5 million in discontinued operations during December 2013 to reduce the carrying value of its net assets in the Barnett
Shale to their estimated fair value less costs to sell. Also included in discontinued operations in 2013 is the sale of the Company's
interest in certain proved and unproved oil and gas properties in the Barnett Shale field for net cash proceeds of $33.8 million,
which resulted in a gain of $8.7 million on the unproved properties sold.
Sendero. During December 2013, the Company committed to a plan to sell its majority interest in Sendero (the Company's
vertical drilling rig subsidiary) to Sendero's minority interest owner for $31.0 million, subject to negotiating a definitive sales
agreement and the buyer completing its financing arrangements. The Company classified these assets and liabilities as held for
sale in the Company's accompanying consolidated balance sheet as of December 31, 2013.
The Company's plans to sell Pioneer Alaska, the Barnett Shale net assets and Sendero are in various stages of marketing
or negotiation. No assurance can be given that the sales will be completed in accordance with the Company's plans.
Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem to sell 40 percent of Pioneer's
interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry
field for total consideration of $1.8 billion. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of
$623.8 million, resulting in a gain of $181.3 million. Sinochem is paying the remaining $1.2 billion of the transaction price by
carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to the Company's joint operations with
Sinochem in the horizontal Wolfcamp Shale play.
48
PIONEER NATURAL RESOURCES COMPANY
Pioneer South Africa. During December 2011, the Company committed to a plan to sell Pioneer South Africa. During the
first quarter of 2012, the Company agreed to sell Pioneer South Africa to an unaffiliated third party, effective January 1, 2012, for
$60.0 million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of
the Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for net cash
proceeds of $15.9 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date
through the date of the sale, resulting in a gain of $28.6 million. Pioneer South Africa's historical results of operations, and the
related gain recorded on the disposition of Pioneer South Africa, are reported as discontinued operations, net of tax in the Company's
accompanying consolidated statements of operations.
Pioneer Tunisia. During December 2010, the Company committed to a plan to sell Pioneer Tunisia. In February 2011, the
Company sold its share holdings in Pioneer Tunisia for cash proceeds of $802.5 million, excluding cash and cash equivalents sold,
resulting in a gain of $645.2 million. Pioneer Tunisia's historical results of operations, and the related gain recorded on the disposition
of Pioneer Tunisia, are reported as discontinued operations, net of tax in the Company's accompanying consolidated statements
of operations.
See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information about the Company's divestitures and discontinued operations.
Results of Operations
Oil and gas revenues. Oil and gas revenues from continuing operations totaled $3.2 billion, $2.6 billion and $2.1 billion
during 2013, 2012 and 2011, respectively.
The increase in 2013 oil and gas revenues relative to 2012 is reflective of 22 percent and 20 percent increases in oil and
NGL sales volumes, respectively, and two percent and 32 percent increases in average reported oil and gas prices, respectively.
Partially offsetting the effects of these increases was a decline of 11 percent in average reported NGL prices.
The increase in 2012 oil and gas revenues relative to 2011 is reflective of 61 percent, 28 percent and 8 percent increases in
oil, NGL, and gas sales volumes, respectively. Partially offsetting the effects of these production increases were declines of six
percent, 26 percent and 33 percent in average reported oil, NGL and gas prices, respectively.
The following table provides average daily sales volumes from continuing operations for 2013, 2012 and 2011:
Oil (BBLs).........................................................................................................................
NGLs (BBLs) ....................................................................................................................
Gas (MCF) ........................................................................................................................
Total (BOE).......................................................................................................................
Year Ended December 31,
2013
69,527
32,422
357,044
161,456
2012
57,165
27,060
358,284
143,939
2011
35,587
21,119
332,866
112,184
Average daily BOE sales volumes from continuing operations in 2013 and 2012 increased by 12 percent and 28 percent,
respectively, as compared to the daily sales volumes in the respective prior years, principally due to the Company's successful
drilling programs. In 2012, the increase in average daily BOE sales was also attributable to declines in scheduled VPP deliveries.
All VPP production volumes were delivered as of December 31, 2012 and there are no further obligations under the VPP contracts.
Production for the year ended December 31, 2013 was negatively impacted by (i) gas processing capacity limitations in
the Spraberry field as a result of wet gas production for the Company and other industry participants growing faster than anticipated
and (ii) severe winter weather during the fourth quarter. New Spraberry field gas processing facilities were completed and began
processing gas in mid-April 2013. The gas processing capacity limitations negatively impacted sales volumes by approximately
600 BOEPD for the year ended December 31, 2013. Additionally, 2013 production was reduced by approximately 1,500 BOEPD,
related to heavy icing and low temperatures during the fourth quarter primarily across Pioneer's leasehold position in the Spraberry/
Wolfcamp area that resulted in extensive power outages, facility freeze-ups, trucking curtailments and limited access to production
and drilling facilities. All of the affected wells have since been returned to production.
Production growth for 2012, as compared to 2011, was negatively impacted by gas processing capacity limitations in the
Spraberry field as a result of wet gas production for the Company and other industry participants growing faster than anticipated.
The gas processing capacity limitations negatively impacted average 2012 sales volumes by approximately 1,450 BOEPD.
49
PIONEER NATURAL RESOURCES COMPANY
The following table provides average daily sales volumes from discontinued operations by geographic area and in total
during 2013, 2012 and 2011:
Year Ended December 31,
2012
2011
2013
Oil (BBLs):
United States...................................................................................................................
South Africa....................................................................................................................
Tunisia ............................................................................................................................
Worldwide.......................................................................................................................
NGL (BBLs):
United States...................................................................................................................
Worldwide.......................................................................................................................
Gas (MCF):
United States...................................................................................................................
South Africa....................................................................................................................
Tunisia ............................................................................................................................
Worldwide.......................................................................................................................
Total (BOE):
United States...................................................................................................................
South Africa....................................................................................................................
Tunisia ............................................................................................................................
Worldwide.......................................................................................................................
5,693
—
—
5,693
3,193
3,193
23,443
—
—
23,443
12,793
—
—
12,793
5,480
428
—
5,908
2,756
2,756
20,085
10,340
—
30,425
11,583
2,151
—
13,734
5,031
530
547
6,108
1,368
1,368
11,013
20,570
496
32,079
8,234
3,958
630
12,822
The oil, NGL and gas prices that the Company reports are based on the market prices received for the commodities. The
following table provides the Company's average prices from continuing operations for 2013, 2012 and 2011:
Year Ended December 31,
2013
2012 (a)
2011 (a)
Oil (per BBL) .................................................................................................................... $
NGL (per BBL) ................................................................................................................. $
Gas (per MCF) .................................................................................................................. $
Total (per BOE)................................................................................................................. $
92.62
30.24
3.43
53.55
$
$
$
$
90.67
34.04
2.60
48.88
$
$
$
$
96.60
46.31
3.86
50.80
____________________
(a)
For the years ended December 31, 2012 and 2011, the Company's average realized oil prices per BBL were $88.81 and
$90.61, respectively, and the average realized prices per BOE for the years ended December 31, 2012 and 2011 were $48.15
and $48.90, respectively. The average realized prices do not include the impact of transfers of the Company's deferred hedge
gains and losses from Accumulated Other Comprehensive Income ("AOCI-Hedging") and the amortization of deferred
VPP revenue. During the year ended December 31, 2012 and 2011, the Company transferred $3.2 million of deferred oil
hedge losses and $32.9 million of deferred oil hedge gains, respectively, from AOCI-Hedging to oil revenue. The 2012
transfer represented all of the remaining AOCI-Hedging transfers to earnings. Amortization of deferred VPP revenue
increased oil revenues by $42.1 million and $45.0 million during the years ended December 31, 2012 and 2011, respectively.
As of December 31, 2012, all VPP production volumes had been delivered and there are no further obligations under VPP
contracts.
Sales of purchased oil and gas. The Company periodically enters into pipeline capacity commitments in order to secure
available oil and gas transportation capacity from the Company’s areas of production. The Company enters into oil and gas purchase
transactions with third parties and separate sale transactions with third parties to satisfy unused pipeline capacity commitments
and to diversify a portion of the Company's WTI oil sales to a Gulf Coast oil price. 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 oil and gas purchased and assuming responsibility to deliver the oil and gas volumes sold. Deficiency
payments on excess pipeline capacity are included in other expense in the accompanying consolidated statements of operations.
See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data"
for further information on transportation commitment charges.
50
PIONEER NATURAL RESOURCES COMPANY
Interest and other income. The Company's interest and other income from continuing operations was $17.0 million and
$29.4 million during 2013 and 2011, respectively, and a loss of $1.0 million in 2012. The $18.0 million increase during 2013, as
compared to 2012, is primarily attributable to a $7.1 million reduction in losses from vertical integration services, a $5.1 million
increase in equity in earnings of EFS Midstream and $4.1 million of gains on deferred compensation plan assets. The $30.4 million
decrease during 2012, as compared to 2011, is primarily attributable to a $27.9 million decrease in income from vertical integration
services. See Note M of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for more information about the Company's interest and other income.
Derivative gains (losses), net. The Company utilizes commodity swap contracts, collar contracts and collar contracts with
short puts in order to (i) reduce the effect of price volatility on the commodities the Company produces, 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. In 2009, the Company discontinued hedge accounting on all of its then-existing derivative contracts.
Changes in the fair value of effective cash flow hedges prior to the Company's discontinuance of hedge accounting were recorded
as a component of AOCI – Hedging in the equity section of the Company's consolidated balance sheets, and were transferred to
earnings during the same periods in which the hedged transactions were recognized in the Company's earnings. Since 2009, the
Company has recognized all changes in the fair values of its derivative contracts as gains or losses in the earnings of the periods
in which they occur. All deferred oil hedge losses were transferred from AOCI-Hedging to earnings during the year ended December
31, 2012. Transfers of deferred hedge gains and losses associated with oil cash flow hedges from AOCI – Hedging to oil revenues
for the years ended December 31, 2012 and 2011 resulted in a decrease of $3.2 million and an increase of $32.9 million, respectively,
to oil revenue.
The following table summarizes the Company's net derivative gains or losses for the years ending December 31, 2013,
2012 and 2011 (in thousands):
Year Ended December 31,
2013
2012
2011
Noncash changes in fair value:
Oil derivative gains (losses)............................................................................................ $ (18,855) $ 217,765
1,209
NGL derivative gains (losses).........................................................................................
(290,058)
Gas derivative gains (losses) ..........................................................................................
(270)
Diesel derivative gains (losses) ......................................................................................
(22)
Marketing derivative gains (losses) ................................................................................
5,930
Interest rate derivative gains (losses)..............................................................................
(65,446)
Total noncash derivative gains (losses), net.................................................................
(616)
(153,993)
—
22
9,321
(164,121)
$
68,376
10,243
179,787
270
—
(33,206)
225,470
Net cash receipts (payments) on settled derivative instruments:
Oil derivative receipts (payments)..................................................................................
NGL derivative receipts (payments)...............................................................................
Gas derivative receipts....................................................................................................
Diesel derivative receipts................................................................................................
Marketing derivative receipts (payments) ......................................................................
Interest rate derivative receipts (payments)....................................................................
Total cash receipts on settled derivative instruments, net ............................................
Total derivative gains, net.......................................................................................... $
11,579
1,224
155,014
—
(168)
482
168,131
4,010
4,139
13,403
402,981
3,497
36
(28,359)
395,697
$ 330,251
(36,664)
(15,418)
183,010
67
(17)
36,304
167,282
$ 392,752
The Company's open derivative contracts are subject to continuing market risk. See "Item 7A. Quantitative and Qualitative
Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for more information about the Company's derivative contracts.
Gain (loss) on disposition of assets. The Company recorded net gains of $209.0 million and $45.9 million during 2013 and
2012, respectively, and a net loss on the disposition of assets of $3.6 million during 2011.
During 2013, the Company's primary gains on disposition of assets included a $181.3 million gain on the sale of a 40 percent
interest in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas to Sinochem
and a gain of $22.4 million on the sale of the Company's interest in unproved oil and gas properties adjacent to the Company's
West Panhandle field operations. During 2012, the Company recorded a $42.6 million gain on the sale of a portion of its interest
51
PIONEER NATURAL RESOURCES COMPANY
in an unproved oil and gas property in the Eagle Ford Shale field. During 2011, the net loss was primarily associated with losses
on the sales of excess materials and supplies inventory, partially offset by gains on the sale of certain unproved properties.
Oil and gas production costs. The Company's oil and gas production costs from continuing operations totaled $614.7
million, $558.0 million and $397.0 million during 2013, 2012 and 2011, respectively. In general, lease operating expenses and
workover expenses represent the components of oil and gas production costs over which the Company has management control,
while third-party transportation charges represent the cost to transport volumes produced to a sales point. Net natural gas plant/
gathering charges represent the net costs to gather and process the Company's gas, reduced by net revenues earned from gathering
and processing of third party gas in Company-owned facilities.
Total oil and gas production costs per BOE for the year ended December 31, 2013 decreased by two percent as compared
to 2012. The decrease in production costs per BOE during 2013 is primarily reflective of a $0.44 per BOE decrease in net natural
gas plant charges as a result of higher gas prices being realized on third-party volumes that are retained as processing fees in
Company-owned facilities. Partially offsetting the decrease in per BOE net natural gas plant charges was a $0.25 per BOE increase
in third-party transportation charges, primarily associated with increasing Eagle Ford Shale sales volumes.
During 2012, total production costs per BOE increased by nine percent as compared to 2011. The increase in production
costs per BOE during 2012 is primarily reflective of increases in lease operating expenses, third-party transportation charges and
net natural gas plant/gathering charges. Lease operating costs increased by $0.32 per BOE during 2012 primarily due to an increase
in salt water disposal costs (principally comprised of water hauling fees). The $0.17 per BOE increase in third-party transportation
charges during 2012 is primarily due to gathering, treating and transportation costs associated with increasing sales volumes from
the Company's successful drilling program in the Eagle Ford Shale field. Net natural gas plant charges increased by $0.38 per
BOE during 2012 primarily due to a reduction in third-party revenues from processing third-party gas volumes in Company-owned
facilities as a result of lower gas and NGL prices being realized on the volumes retained as a processing fee.
The following table provides the components of the Company's total production costs per BOE for 2013, 2012 and 2011:
Year Ended December 31,
2013
2012
2011
Lease operating expenses.................................................................................................. $
Third-party transportation charges....................................................................................
Net natural gas plant/gathering charges ............................................................................
Workover costs..................................................................................................................
Total production costs ....................................................................................................... $
8.00
1.56
0.10
0.77
10.43
$
$
7.91
1.31
0.54
0.83
10.59
$
$
7.59
1.14
0.16
0.80
9.69
Production and ad valorem taxes. The Company recorded production and ad valorem taxes of $201.2 million during 2013,
as compared to $178.7 million and $139.4 million for 2012 and 2011, respectively. In general, production taxes and ad valorem
taxes are directly related to commodity price changes; however, Texas ad valorem taxes are based upon prior year commodity
prices, whereas production taxes are based upon current year commodity prices. Production and ad valorem taxes on a per BOE
basis have been relatively stable since 2011.
The following table provides the Company's production and ad valorem taxes per BOE from continuing operations and
total production and ad valorem taxes per BOE from continuing operations for 2013, 2012 and 2011:
Year Ended December 31,
2012
2011
2013
Production taxes ................................................................................................................ $
Ad valorem taxes ..............................................................................................................
Total ad valorem and production taxes ............................................................................. $
2.20
1.22
3.42
$
$
2.17
1.22
3.39
$
$
2.23
1.17
3.40
Depletion, depreciation and amortization expense. The Company's total DD&A expense from continuing operations
was $907.1 million ($15.39 per BOE), $708.3 million ($13.44 per BOE), and $489.6 million ($11.96 per BOE) for 2013, 2012
and 2011, respectively. Depletion expense on oil and gas properties, the largest component of DD&A expense, was $14.70,
$12.82 and $11.33 per BOE during 2013, 2012 and 2011, respectively.
During 2013, the 15 percent increase in per BOE depletion expense, as compared to that of 2012, is primarily due to (i)
capital expenditures to develop proved undeveloped locations, primarily in the Company's successful Spraberry and Eagle Ford
Shale fields programs and (ii) a 22 percent decline in total proved reserves. The decline in total proved reserves is primarily
52
PIONEER NATURAL RESOURCES COMPANY
comprised of negative revisions of previous estimates to remove undeveloped vertical well locations that are no longer expected
to be drilled as the Company shifts its planned capital expenditures to higher-rate-of-return horizontal drilling, partially offset by
a nine percent increase in proved developed reserves.
During 2012, the 13 percent increase in per BOE depletion expense was primarily due to (i) increased drilling expenditures
on proved undeveloped locations, primarily in the Spraberry field and (ii) declines in proved gas reserves due to lower first-day-
of-the-month gas prices during the twelve month period ending on December 31, 2012, partially offset by (iii) the impairment
effects of reducing carrying values of the South Texas Edwards Trend/Austin Chalk fields during 2012 and 2011, respectively (see
the discussion below for more information on the Company's impairment charges).
Impairment of oil and gas properties and other long-lived assets. The Company recorded impairment expense in continuing
operations to reduce the carrying values of oil and gas properties by $1.5 billion and $354.4 million during the years ended
December 31, 2013 and 2011, respectively.
The Company performs assessments of its long-lived assets to be held and used, including oil and gas properties, whenever
events or circumstances indicate that the carrying values of those assets may not be recoverable. In order to perform these
assessments, management uses various observable and unobservable inputs, including management's outlooks for (i) commodity
prices, (ii) production costs, (iii) capital expenditures and (iv) production, based upon current estimates of proved reserves and
risk-adjusted probable reserves.
Management's commodity price outlooks represent longer-term outlooks that are developed based on third-party longer-
term commodity futures price outlooks as of a measurement date ("Management's Price Outlooks"). During 2013, 2012 and 2011,
declines in Management's Price Outlooks for gas provided indications of possible impairment of the Company's predominantly
dry gas properties in the Raton field in southeastern Colorado, the Barnett Shale field in North Texas (classified as held for sale
as of December 31, 2013) and the Edwards Trend and Austin Chalk fields in South Texas, respectively. During the years ended
December 31, 2013 and 2012, Management's Price Outlook for gas declined by 10 percent and four percent, respectively, and
Management's Price Outlook for oil declined by seven percent for both periods. The trend of Management's Price Outlooks by
quarter during 2013 is as follows:
Management's gas outlook.......
Management's oil outlook........
December 31, 2013
$4.43
September 30, 2013
$4.93
$80.40
$83.24
June 30, 2013
$5.43
$80.65
March 31, 2013
$4.81
December 31, 2012
$4.92
$85.13
$86.40
As a result of management's assessments, during 2013, 2012 and 2011, the Company recognized noncash impairment
charges of $1.5 billion, $532.6 million and $354.4 million to reduce the carrying values of the Company's Raton field assets, the
Company's Barnett Shale field assets (which are now classified as discontinued operations in the accompanying statements of
operations) and the Edwards Trend/Austin Chalk field assets, respectively, to their estimated fair values.
Declines in Management's Price Outlooks during 2013 also provided an indication that the Company's Hugoton field assets
in southwest Kansas may have been impaired. The Company's estimates of undiscounted future net cash flows attributable to the
Hugoton field assets indicated that on December 31, 2013 their carrying amounts are expected to be recovered, but continue to
be at risk for impairment if estimates of future cash flows decline. For example, the Company estimates that the carrying value
of the Hugoton field may become partially impaired if the average price in Management's Price Outlook for gas were to decline
by approximately $0.30 to $0.50 per MCF. The Company estimates that if the Hugoton field were to become impaired in a future
period, the Company would recognize noncash impairment charges in that period that could range from $200 million to $250
million.
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 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 Outlooks and (iv) increases or decreases in
production and capital costs associated with these fields.
See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information about the Company's impairment assessments.
53
PIONEER NATURAL RESOURCES COMPANY
Exploration and abandonments expense. The following table provides the Company's geological and geophysical costs,
exploratory dry holes expense and leasehold abandonments and other exploration expense from continuing operations for 2013,
2012 and 2011 (in thousands):
Geological and geophysical .............................................................................................. $
Exploratory dry holes........................................................................................................
Leasehold abandonments and other ..................................................................................
$
$
Year Ended December 31,
2012
66,908
9,016
22,361
98,285
2013
77,005
5,876
15,567
98,448
$
$
$
2011
48,092
2,864
29,735
80,691
During 2013, the Company's exploration and abandonment expense was primarily attributable to $77.0 million of geological
and geophysical costs, of which $58.0 million was geological and geophysical administrative costs; $5.9 million of dry hole
provisions; and $15.5 million of leasehold abandonment expense, which included $14.3 million associated with the Company's
unproved dry gas properties in the Eagle Ford Shale and other unproved property abandonments. During 2013, the Company
completed and evaluated 253 exploration/extension wells, 244 of which were successfully completed as discoveries.
During 2012, the Company's exploration and abandonment expense was primarily attributable to $66.9 million of geological
and geophysical costs, of which $42.0 million was geological and geophysical administrative costs; $9.0 million of dry hole
provisions; and $22.2 million of leasehold abandonment expense. The significant components of the Company's 2012 leasehold
abandonment expense included $9.5 million in the Eagle Ford Shale area, $4.8 million in the Rockies area and $4.7 million in the
Permian Basin. During 2012, the Company completed and evaluated 229 exploration/extension wells, 223 of which were
successfully completed as discoveries.
During 2011, the Company's exploration and abandonment expense was primarily attributable to $48.1 million of geological
and geophysical costs, of which $32.0 million was geological and geophysical administrative costs, and $29.7 million of leasehold
abandonment expense. The significant components of the Company's 2011 leasehold abandonment expense included dry gas
unproved acreage abandonments of $9.3 million in the South Texas area and $9.1 million in the Rockies area. During 2011, the
Company completed and evaluated 168 exploration/extension wells, 167 of which were successfully completed as discoveries.
General and administrative expense. General and administrative expense from continuing operations totaled $295.9 million,
$244.2 million and $190.0 million during 2013, 2012 and 2011, respectively. The increase in 2013, as compared to 2012, is
primarily due to increases of $42.7 million and $3.3 million in compensation and occupancy expenses, respectively, related to
staffing increases in support of the Company's capital expansion and integrated services initiatives. The $42.7 million increase
in compensation expense includes a $7.6 million increase in stock-based compensation expense associated with Liability Awards,
primarily due to increases in the market value of the Company's common stock during 2013, and an $18.9 million increase in cash
bonus expense payable to employees as a result of the accomplishments of the Company during 2013.
The increase in general and administrative expense during 2012, as compared to 2011, was also primarily due to increases
of $45.7 million and $4.7 million in compensation and occupancy expenses, respectively, related to staffing increases in support
of the Company's capital expansion and integrated services initiatives.
Accretion of discount on asset retirement obligations. Accretion of discount on asset retirement obligations from continuing
operations was $11.9 million, $8.7 million and $7.5 million during 2013, 2012 and 2011, respectively. The 37 percent and 16
percent increases in accretion of discount on asset retirement obligations during 2013 and 2012, respectively, are primarily due
to additional well completions resulting from the Company's drilling activities. See Note I of Notes to Consolidated Financial
Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's
asset retirement obligations.
Interest expense. Interest expense was $183.8 million, $204.2 million and $181.6 million during 2013, 2012 and 2011,
respectively. The weighted average interest rate on the Company's indebtedness for the year ended December 31, 2013 was 6.5
percent, as compared to 6.0 percent and 7.2 percent for the years ended December 31, 2012 and 2011, respectively.
The decrease in interest expense during 2013, as compared to 2012, was primarily due to a decrease in debt as a result of
the repayment of amounts outstanding under Pioneer Southwest's credit facility and conversions of Convertible Senior Notes, and
a decrease of $18.3 million in noncash amortization of financing fees, debt issuance discounts and deferred hedge losses.
54
PIONEER NATURAL RESOURCES COMPANY
The $22.6 million increase in interest expense during 2012, as compared to 2011, is primarily due to an $868.9 million
increase in the Company's average outstanding indebtedness, partially offset the 1.2 percent decline in weighted average interest
on indebtedness.
See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information about the Company's long-term debt and interest expense.
Other expenses. Other expenses from continuing operations were $137.4 million during 2013, as compared to $114.2
million during 2012 and $63.1 million during 2011. The $23.2 million increase in other expense during 2013, as compared to
2012, is primarily associated with (i) $25.5 million of impairment associated with the planned sale of the Company's majority
interest in Sendero, (ii) a $30.6 million increase in inventory valuation allowances and (iii) an $8.8 million increase in contingency
and environmental accrual adjustments, partially offset by (iv) a $23.4 million decrease in above market and idle drilling and well
service equipment charges and (v) a $14.7 million decrease in terminated drilling rig contract charges.
The $51.1 million increase in other expense during 2012, as compared to 2011, is primarily due to $15.7 million of contract
rig termination fees incurred during 2012, a $15.0 million increase in unused gas transportation commitment charges and a $13.0
million increase in above market and idle drilling and well service equipment charges, which are not chargeable to joint operations.
See Note N of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding the Company's other expenses.
Income tax provision. The Company recognized an income tax benefit attributable to earnings from continuing operations
of $211.8 million during 2013, as compared to income tax provisions of $290.5 million and $188.3 million during 2012 and 2011,
respectively. The Company's effective tax rates on earnings from continuing operations, excluding income from noncontrolling
interest, for 2013, 2012 and 2011 were 35 percent, 37 percent and 34 percent, respectively, as compared to the combined United
States federal and state statutory rates of approximately 36 percent.
See "Critical Accounting Estimates" below and Note O of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information regarding the Company's income tax rates and
attributes.
Income (loss) from discontinued operations, net of tax. The Company recognized a loss from discontinued operations,
net of tax, of $449.6 million in 2013 as compared to a loss of $304.2 million for 2012 and income of $474.1 million for 2011.
Income (loss) from discontinued operations, net of tax includes the operations of the following:
Pioneer Alaska which was placed into assets held for sale and discontinued operation in December 2013,
•
• The Barnett Shale field assets which were placed into assets held for sale and discontinued operation in December
2013,
Pioneer South Africa which was placed into assets held for sale and discontinued operation in December 2011; and
Pioneer Tunisia which was placed into assets held for sale and discontinued operations in December 2010.
•
•
The $145.4 million increase in loss from discontinued operations, net of tax during 2013, as compared to 2012 is primarily
attributable to the increase in impairments of net assets. In 2013, the Company had total impairments of Pioneer Alaska and
Barnett Shale assets of $729.3 million, compared to impairment charges of $532.6 million on Barnett Shale assets in 2012. The
$778.3 million decrease in income from discontinued operations, net of tax during 2012, as compared to 2011 is primarily
attributable to the after tax gain on the sale of Pioneer Tunisia recorded in 2011 and the 2012 impairment of Barnett Shale field
assets.
See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding the Company's discontinued operations.
Net income attributable to noncontrolling interest. Net income attributable to noncontrolling interests was $38.9 million,
$50.5 million and $47.4 million for the years ended December 31, 2013, 2012 and 2011, respectively. The Company's net income
attributable to noncontrolling interest is primarily associated with the net income of Pioneer Southwest that was allocated to limited
partners, through December 17, 2013, the date of the Pioneer Southwest merger. The $11.6 million decrease in net income
attributable to noncontrolling interest in 2013, as compared to 2012, is primarily due to decreases in Pioneer Southwest's noncash
derivative gains, higher production costs and higher depletion expense, partially offset by increased revenues.
The $3.1 million increase in net income attributable to noncontrolling interest in 2012, as compared to 2011, is primarily
due to a 10 percent increase in noncontrolling interest in Pioneer Southwest during November 2011 as a result of an offering by
Pioneer Southwest of 4.4 million common units, representing limited partnership units, of which 1.8 million common units were
55
PIONEER NATURAL RESOURCES COMPANY
sold by the Company. Partially offsetting the increase in noncontrolling interest in Pioneer Southwest was a $15.3 million decline
in Pioneer Southwest's net income during 2012, as compared to 2011. See Note B of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding Pioneer Southwest and
the Company's noncontrolling interest in consolidated subsidiaries' net income.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. The Company's primary needs for cash are for capital expenditures and acquisition expenditures on
oil and gas properties and related vertical integration assets and facilities, payments of contractual obligations, dividends and
working capital obligations. Funding for these cash needs may be provided by any combination of internally-generated cash flow,
cash and cash equivalents on hand, proceeds from the sale of nonstrategic assets or external financing sources as discussed in
"Capital resources" below. During 2014, the Company expects that it will be able to fund its needs for cash (excluding acquisitions,
if any) with a combination of internally generated cash flows, cash and cash equivalents on hand, proceeds from the divestiture
of assets held for sale, proceeds from the sale of other nonstrategic assets and, if necessary, availability under the Company's credit
facility. Although the Company expects that these sources of funding will be adequate to fund capital expenditures and dividend
payments and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate
to meet the Company's future needs.
During 2014, the Company plans to continue to focus its capital spending primarily on liquids-rich drilling activities. The
Company's 2014 capital budget totals $3.3 billion (excluding acquisitions, asset retirement obligations, capitalized interest,
geological and geophysical administrative costs and capital expenditures associated with Pioneer Alaska and Barnett Shale field
assets prior to their sale), consisting of $3.0 billion for drilling operations and $285 million for buildings, vertical integration and
other plant and equipment additions. Based on the Company's current Management Price Outlooks, Pioneer expects its net cash
flows from operating activities, cash and cash equivalents on hand, proceeds from the divestiture of assets held for sale, proceeds
from other nonstrategic assets sales and, if necessary, availability under the Company's credit facility to be sufficient to fund its
planned capital expenditures and contractual obligations.
Investing activities. Net cash used in investing activities during 2013 was $2.1 billion, as compared to net cash used in
investing activities of $3.3 billion and $1.6 billion during 2012 and 2011, respectively. The decrease in net cash flow used in
investing activities during 2013, as compared to 2012, is primarily due to (i) a $615.5 million increase in proceeds from disposition
of assets, which resulted from $623.8 million of net cash proceeds from the May 2013 sale to Sinochem of a 40 percent interest
in the Company's horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas, (ii) a $297.1 million
decrease in payments for acquisitions due to the acquisition of Premier Silica during 2012, (iii) a $119.3 million decrease in
additions to oil and gas properties, partially due to the drilling carry being paid by Sinochem in the southern portion of the horizontal
Wolfcamp Shale play, (iv) a $59.7 million decrease in additions to other assets and other property and equipment and (v) a $25.1
million distribution from EFS Midstream during December 2013. In addition to the aforementioned proceeds from disposition of
assets, the Company's investing activities during the year ended December 31, 2013 were funded by net cash provided by operating
activities.
The increase in net cash flow used in investing activities during 2012, as compared to 2011, was primarily due to (i) an
$831.1 million increase in additions to oil and gas properties associated with the Company's capital programs, (ii) a $723.5 million
decrease in proceeds from disposition of assets (primarily attributable to the 2011 sale of Pioneer Tunisia, partially offset by
proceeds from the sales of Pioneer South Africa and a partial interest in certain Eagle Ford Shale unproved leaseholds during
2012) and (iii) the $297.1 million of cash used for the acquisition of Premier Silica, partially offset by (iv) an $89.6 million decrease
in investments in EFS Midstream and (v) a $66.4 million decrease in additions to other assets and other property and equipment.
See "Results of Operations" above and Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding asset divestitures.
Dividends/distributions. During each of the years ended December 31, 2013, 2012 and 2011, the Board declared semiannual
dividends of $0.04 per common share. Associated therewith, the Company paid $11.1 million, $10.0 million and $9.6 million,
respectively, of aggregate dividends. Future dividends are at the discretion of the Board, and, if declared, the Board may change
the dividend amount based on the Company's liquidity and capital resources at the time.
During January, April, July and October of 2013, 2012 and 2011, the board of directors of the general partner of Pioneer
Southwest declared quarterly distributions aggregating annually to $2.08, $2.07 and $2.03 per limited partner unit, respectively.
Associated therewith, Pioneer Southwest paid aggregate distributions to noncontrolling unitholders of $35.3 million, $35.2 million
and $25.6 million during the years ended December 31, 2013, 2012 and 2011, respectively.
Off-balance sheet arrangements. From time-to-time, the Company enters into off-balance sheet arrangements and
transactions that can give rise to material off-balance sheet obligations of the Company. As of December 31, 2013, the material
56
PIONEER NATURAL RESOURCES COMPANY
off-balance sheet arrangements and transactions that the Company has entered into include (i) operating lease agreements,
(ii) drilling commitments (iii) firm transportation and fractionation commitments, (iv) open purchase commitments and (v)
contractual obligations for which the ultimate settlement amounts are not fixed and determinable, such as derivative contracts that
are sensitive to future changes in commodity prices or interest rates, gathering, treating, fractionation and transportation
commitments on uncertain volumes of future throughput, open delivery commitments and indemnification obligations following
certain divestitures. Other than the off-balance sheet arrangements described above, the Company has no transactions, arrangements
or other relationships with unconsolidated entities or other persons that are reasonably likely to materially affect the Company's
liquidity or availability of or requirements for capital resources. See "Contractual obligations" below and Note J of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for more information
regarding the Company's off-balance sheet arrangements.
Contractual obligations. The Company's contractual obligations include long-term debt, operating leases, drilling
commitments (including commitments to pay day rates for drilling rigs), capital funding obligations, derivative obligations, other
liabilities (including postretirement benefit obligations), firm transportation and fractionation commitments and minimum annual
gathering, treating and transportation commitments. Other joint owners in the properties operated by the Company will incur
portions of the costs represented by these commitments.
The following table summarizes by period the payments due by the Company for contractual obligations estimated as of
December 31, 2013:
Payments Due by Year
2014
2015 and 2016
2017 and 2018
Thereafter
(in thousands)
Long-term debt (a)............................................................................... $
Operating leases (b).............................................................................
Drilling commitments (c) ....................................................................
Derivative obligations (d)....................................................................
Open purchase commitments (e) .........................................................
Other liabilities (f) ...............................................................................
Firm gathering, processing and transportation commitments (g)........
$
— $
25,305
189,987
11,626
232,351
46,873
353,167
859,309
455,385
34,630
172,846
—
5,084
44,576
823,157
$ 1,535,678
$
934,600
31,055
—
2,357
—
41,767
527,327
$ 1,537,106
$ 1,300,000
26,569
—
7,576
—
166,685
773,868
$ 2,274,698
_____________________
(a)
See "Item 7A. Quantitative and Qualitative Disclosures About Market Risk" for information regarding estimated future
interest payment obligations under long-term debt obligations. The amounts included in the table above represent principal
maturities only.
See Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for more information about the Company's operating leases.
(b)
(c) Drilling commitments represent future minimum expenditure commitments for drilling rig services and well commitments
under contracts to which the Company was a party on December 31, 2013.
(d) Derivative obligations represent net liabilities determined in accordance with master netting arrangements for commodity
and interest rate derivatives that were valued as of December 31, 2013. The ultimate settlement amounts of the Company's
derivative obligations are unknown because they are subject to continuing market risk. See "Item 7A. Quantitative and
Qualitative Disclosures About Market Risk" and Note E of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information regarding the Company's derivative obligations.
(e) Open purchase commitments primarily represent expenditure commitments for inventory, materials and other property and
(f)
equipment ordered, but not received, as of December 31, 2013.
The Company's other liabilities represent current and noncurrent other liabilities that are comprised of postretirement benefit
obligations, litigation and environmental contingencies, asset retirement obligations and other obligations for which neither
the ultimate settlement amounts nor their timings can be precisely determined in advance. See Notes H, I and J of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional
information regarding the Company's postretirement benefit obligations, asset retirement obligations and litigation and
environmental contingencies, respectively.
(g) Gathering, processing and transportation commitments represent estimated fees on production throughput commitments
and demand fees associated with volume delivery commitments of up to 50,000 BOEPD through August 2017 that are
related to the Company's Permian Basin operations. The Company does not expect to be able to fulfill all of its short-term
and long-term delivery obligations from projected production of available reserves; consequently, the Company plans to
57
PIONEER NATURAL RESOURCES COMPANY
purchase third party volumes to satisfy its commitments if it is economic to do so; otherwise, it will pay demand fees for
commitment shortfalls. See "Item 2. Properties" and Note J of Notes to Consolidated Financial Statements included in "Item
8. Financial Statements and Supplementary Data" for additional information regarding the Company's gathering, processing
and transportation commitments.
Capital resources. The Company's primary capital resources are cash and cash equivalents, net cash provided by operating
activities, proceeds from sales of joint interests and nonstrategic assets and proceeds from financing activities (principally
borrowings under the Company's credit facility or issuances of debt or equity securities). If internal cash flows and cash on hand
do not meet the Company's expectations, the Company may reduce its level of capital expenditures, and/or fund a portion of its
capital expenditures using availability under the Company's credit facility, issue debt or equity securities or obtain capital from
other sources, such as through sales of nonstrategic assets.
Operating activities. Net cash provided by operating activities for the years ended December 31, 2013, 2012 and 2011 was
$2.1 billion, $1.8 billion and $1.5 billion, respectively. The increase in net cash flow provided by operating activities in 2013 was
primarily due to an increase in oil and gas sales, partially offset by a decrease in net cash receipts from derivative settlements. The
increase in net cash flow provided by operating activities in 2012 was primarily due to increases in oil and gas sales and net cash
receipts from derivative settlements.
Asset divestitures. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital
stock in Pioneer Alaska. The sale of Pioneer Alaska continues to be subject to ongoing negotiations and certain other conditions,
such as governmental approvals and buyer's arrangement of financing. Associated with the planned sale of Pioneer Alaska, the
Company recorded a noncash impairment charge of $539.8 million in discontinued operations during December 2013 to reduce
the carrying value of the Pioneer Alaska assets to their estimated fair value less costs to sell of $350.6 million. The Company has
classified Pioneer Alaska assets and liabilities as held for sale in the accompanying consolidated balance sheet as of December
31, 2013 and has reported Pioneer Alaska's historical results of operations, and the related impairment loss, as discontinued
operations, net of tax in the Company's accompanying consolidated statements of operations.
During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett Shale field in
North Texas. The plan is expected to result in the sale of the Barnett Shale net assets during 2014. The Company has classified
Barnett Shale assets and liabilities as held for sale in the accompanying consolidated balance sheet as of December 31, 2013 and
has reported Barnett Shale historical results of operations, and the related impairment loss, as discontinued operations, net of tax
in the Company's accompanying consolidated statements of operations.
Associated with the plan to sell its net assets in the Barnett Shale field, the Company recorded a noncash impairment charge
of $189.5 million in discontinued operations during December 2013 to reduce the carrying value of its net assets in the Barnett
Shale field to their estimated fair value less costs to sell. See Note D for more information about the impairment of the Company's
Barnett Shale field net assets. Also included in discontinued operations in 2013 is the sale of the Company's interest in certain
proved and unproved oil and gas properties in the Barnett Shale field for net cash proceeds of $33.8 million, which resulted in a
gain of $8.7 million on the unproved properties sold.
During December 2013, the Company committed to a plan to sell its majority interest in Sendero (the Company's vertical
drilling rig subsidiary) to Sendero's minority interest owner for $31.0 million, subject to negotiating a definitive sales agreement
and the buyer completing its financing arrangements. The Company classified these assets and liabilities as held for sale in the
Company's accompanying consolidated balance sheet as of December 31, 2013.
The Company's plans to sell Pioneer Alaska, the Barnett Shale net assets and Sendero are in various stages of marketing
or negotiation. No assurance can be given that the sales will be completed in accordance with the Company's plans.
In January 2013, the Company signed an agreement with Sinochem to sell 40 percent of Pioneer's interest in 207,000 net
acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field for consideration
of $1.8 billion. In May 2013, the Company completed the sale to Sinochem for net cash proceeds of $623.8 million, resulting in
a gain of $181.3 million related to the unproved property interests conveyed to Sinochem. Sinochem is paying the remaining $1.2
billion of the transaction price by carrying 75 percent of Pioneer's portion of ongoing drilling and facilities costs attributable to
the Company's joint operations with Sinochem in the horizontal Wolfcamp Shale play.
During the first quarter of 2012, the Company agreed to sell Pioneer South Africa to an unaffiliated third party for $60.0
million of cash proceeds before normal closing and other adjustments, and the buyer's assumption of certain liabilities of the
Company's South Africa subsidiaries. In August 2012, the Company completed the sale of Pioneer South Africa for net cash
proceeds of $15.9 million, including normal closing adjustments for cash revenues and costs and expenses from the effective date
through the date of the sale, resulting in a gain of $28.6 million. During 2011, the Company completed the sale of Pioneer Tunisia
58
PIONEER NATURAL RESOURCES COMPANY
to an unaffiliated party for cash proceeds of $802.5 million, excluding cash and cash equivalents sold, resulting in a gain of $645.2
million.
See Note C of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for more information regarding the Company's divestitures.
Financing activities. Net cash provided by financing activities during 2013 was $157.8 million, as compared to net cash
provided by financing activities during 2012 and 2011 of $1.1 billion and $457.4 million, respectively. During 2013, the significant
components of financing activities included $1.1 billion of net payments on long-term debt, the Company's completion of an
offering of 10.35 million shares of its common stock in February 2013 at a per-share price, after underwriting and offering expenses,
of $123.76 for a total of $1.3 billion of realized net proceeds and $47.2 million of dividend payments and distributions to
noncontrolling interests. During 2012, the significant components of financing activities included $1.2 billion of net borrowings
on long-term debt and $45.9 million of dividend payments and distributions to noncontrolling interests. During 2011, significant
components of financing activities included $484.2 million of net proceeds received from the offering of 5.5 million shares of the
Company's common stock and $123.0 million of net proceeds received from the sale of 4.4 million common units representing
limited partner interests in Pioneer Southwest, partially offset by $98.3 million of net principal payments on long-term debt and
$36.3 million of dividend payments and distributions to noncontrolling interests.
The following provides a description of the Company's significant financing activities during 2013, 2012 and 2011:
• During December 2012 and March 2013, respectively, the Company's stock price met the price threshold that caused
the Convertible Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders
into a combination of cash and the Company's common stock based on a formula set forth in the indenture supplement
pursuant to which the Convertible Senior Notes were issued. On April 15, 2013, the Company announced that it would
exercise its option to redeem all Convertible Senior Notes that had not been converted by the holders before May 16,
2013. Holders of $479.1 million principal amount of the Convertible Senior Notes exercised their right to convert their
Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering
holders $479.1 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock
in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16, 2013, the Company
paid $845 thousand in principal and interest to redeem all Convertible Senior Notes that remained outstanding.
• During February 2013, the Company completed the sale of 10.35 million shares of its common stock for $1.3 billion
of net cash proceeds.
• During December 2012, the Company amended its credit facility with a syndicate of financial institutions to increase
the aggregate loan commitments to $1.5 billion from $1.25 billion and extend its maturity to December 2017;
• During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds, net of
$8.5 million of offering discounts and costs, of $591.5 million;
• During December 2011, Pioneer Southwest completed the public offering of 4.4 million common units of Pioneer
Southwest, representing limited partnership interests, at a per-unit price of $29.20, before offering costs. Of the
4.4 million common units, Pioneer sold 1.8 million of its Pioneer Southwest common unit holdings for net proceeds
of $50.5 million and Pioneer Southwest issued 2.6 million new common units for net proceeds of $72.5 million,
including offering costs. Pioneer Southwest used its net proceeds to reduce its credit facility borrowings; and
• During November 2011, the Company completed the sale of 5.5 million shares of its common stock for $484.2 million
of net proceeds.
See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding the significant financing activities.
As the Company pursues its strategy, it may utilize various financing sources, including fixed and floating rate debt,
convertible securities, preferred stock or common stock. The Company cannot predict the timing or ultimate outcome of any such
actions as they are subject to market conditions, among other factors. The Company may also issue securities in exchange for oil
and gas properties, stock or other interests in other oil and gas companies or related assets. Additional securities may be of a class
preferred to common stock with respect to such matters as dividends and liquidation rights and may also have other rights and
preferences as determined by the Board.
Liquidity. The Company's principal sources of short-term liquidity are cash and cash equivalents and unused borrowing
capacity under the Company's credit facility. As of December 31, 2013, the Company had no outstanding borrowings under the
credit facility, leaving $1.5 billion of unused borrowing capacity. The Company was in compliance with all of its debt covenants.
The Company's credit facility contains certain financial covenants, which include the maintenance of a ratio of total debt to book
capitalization, subject to certain adjustments, not to exceed .60 to 1.0, which is above the Company's December 31, 2013 ratio
of .24 to 1.0. If internal cash flows and cash on hand do not meet the Company's expectations, the Company may reduce its level
59
PIONEER NATURAL RESOURCES COMPANY
of capital expenditures, reduce dividend payments, and/or fund a portion of its capital expenditures using borrowings under the
Company's credit facility, issuances of debt or equity securities or other sources, such as sales of joint interests or nonstrategic
assets. The Company cannot provide any assurance that needed short-term or long-term liquidity will be available on acceptable
terms or at all. Although the Company expects that the combination of internal operating cash flows, cash and cash equivalents
on hand, proceeds from the divestiture of assets held for sale, proceeds from the sales of other nonstrategic assets and, if necessary,
available capacity under the Company's credit facility will be adequate to fund 2014 capital expenditures and dividend payments
and provide adequate liquidity to fund other needs, no assurances can be given that such funding sources will be adequate to meet
the Company's future needs.
Debt ratings. The Company is rated as investment grade by three credit rating agencies. The Company receives debt credit
ratings from several of the major ratings agencies, which are subject to regular reviews. The Company believes that each of the
rating agencies considers many factors in determining the Company's ratings, including: production growth opportunities, liquidity,
debt levels, asset composition and proved reserve mix. A reduction in the Company's debt ratings could increase the interest rates
that the Company incurs on credit facility borrowings and could negatively affect the Company's ability to obtain additional
financing or the interest rate, fees and other terms associated with such additional financing.
Book capitalization and current ratio. The Company's net book capitalization at December 31, 2013 was $8.9 billion,
consisting of $392.6 million of cash and cash equivalents, debt of $2.7 billion and stockholders' equity of $6.6 billion. The
Company's debt to book capitalization decreased to 25 percent at December 31, 2013 from 37 percent at December 31, 2012,
primarily due to an increase in cash and cash equivalents of $163.3 million and a decrease in long-term debt of $1.1 billion, partially
offset by a net loss of $799.5 million during 2013. The Company's ratio of current assets to current liabilities increased to 1.38 to
1.00 at December 31, 2013, as compared to 1.02 to 1.00 at December 31, 2012, primarily due to the reclassification of long-term
assets to assets held for sale.
Critical Accounting Estimates
The Company prepares its consolidated financial statements for inclusion in this Report in accordance with GAAP. See
Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for a
comprehensive discussion of the Company's significant accounting policies. GAAP represents a comprehensive set of accounting
and disclosure rules and requirements, the application of which requires management judgments and estimates including, in certain
circumstances, choices between acceptable GAAP alternatives. The following is a discussion of the Company's most critical
accounting estimates, judgments and uncertainties that are inherent in the Company's application of GAAP.
Asset retirement obligations. The Company has significant obligations to remove tangible equipment and facilities and to
restore the land at the end of oil and gas production operations. The Company's removal and restoration obligations are primarily
associated with plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires
management to make estimates and judgments because most of the removal obligations are many years in the future and contracts
and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly
changing, as are regulatory, political, environmental, safety and public relations considerations.
Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts,
credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments.
To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligations, a
corresponding adjustment is generally made to the oil and gas property balance. See Notes B and I of Notes to Consolidated
Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the
Company's asset retirement obligations.
Successful efforts method of accounting. The Company utilizes the successful efforts method of accounting for oil and
gas producing activities as opposed to the alternate acceptable full cost method. In general, the Company believes that net assets
and net income are more conservatively measured under the successful efforts method of accounting for oil and gas producing
activities than under the full cost method, particularly during periods of active exploration. The critical difference between the
successful efforts method of accounting and the full cost method is as follows: under the successful efforts method, exploratory
dry holes and geological and geophysical exploration costs are charged against earnings during the periods in which they occur;
whereas, under the full cost method of accounting, such costs and expenses are capitalized as assets, pooled with the costs of
successful wells and charged against the earnings of future periods as a component of depletion expense. During 2013, 2012 and
2011, the Company recognized exploration, abandonment, geological and geophysical expense from continuing operations of
$98.4 million, $98.3 million and $80.7 million, respectively. During 2013, 2012 and 2011, the Company recognized exploration,
abandonment, geological and geophysical expense from discontinued operations of $52.7 million, $108.1 million and $44.9 million,
respectively, under the successful efforts method.
60
PIONEER NATURAL RESOURCES COMPANY
Proved reserve estimates. Estimates of the Company's proved reserves included in this Report are prepared in accordance
with GAAP and SEC guidelines. The accuracy of a reserve estimate is a function of:
•
•
•
•
the quality and quantity of available data;
the interpretation of that data;
the accuracy of various mandated economic assumptions; and
the judgment of the persons preparing the estimate.
The Company's proved reserve information included in this Report as of December 31, 2013, 2012 and 2011 was prepared
by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major properties.
Estimates prepared by third parties may be higher or lower than those included herein.
Because these estimates depend on many assumptions, all of which may substantially differ from future actual results,
proved reserve estimates will be different from the quantities of oil and gas that are ultimately recovered. In addition, results of
drilling, testing and production after the date of an estimate may justify, positively or negatively, material revisions to the estimate
of proved reserves.
It should not be assumed that the Standardized Measure included in this Report as of December 31, 2013 is the current
market value of the Company's estimated proved reserves. In accordance with SEC requirements, the Company based the 2013
Standardized Measure on a twelve month average of commodity prices on the first day of the month and prevailing costs on the
date of the estimate. Actual future prices and costs may be materially higher or lower than the prices and costs utilized in the
estimate. See "Item 1A. Risk Factors," "Item 2. Properties" and Supplementary Information included in "Item 8. Financial
Statements and Supplementary Data" for additional information regarding estimates of proved reserves.
The Company's estimates of proved reserves materially impact depletion expense. If the estimates of proved reserves decline,
the rate at which the Company records depletion expense will increase, reducing future net income. Such a decline may result
from lower commodity prices, which may make it uneconomical to drill for and produce higher cost fields. In addition, a decline
in proved reserve estimates may impact the outcome of the Company's assessment of its proved properties and goodwill for
impairment.
Impairment of proved oil and gas properties. The Company reviews its proved properties to be held and used whenever
management determines that events or circumstances indicate that the recorded carrying value of the properties may not be
recoverable. Management assesses whether or not an impairment provision is necessary based upon estimated future recoverable
proved and risk-adjusted probable and possible reserves, Management's Price Outlooks, production and capital costs expected to
be incurred to recover the reserves; discount rates commensurate with the nature of the properties and net cash flows that may be
generated by the properties. Proved oil and gas properties are reviewed for impairment at the level at which depletion of proved
properties is calculated. See Notes B and D of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for information regarding the Company's impairment assessments.
Impairment of unproved oil and gas properties. At December 31, 2013, the Company carried unproved property costs of
$123.4 million. Management assesses unproved oil and gas properties for impairment on a project-by-project basis. Management's
impairment assessments include evaluating the results of exploration activities, Management's Price Outlooks and planned future
sales or expiration of all or a portion of such projects.
Suspended wells. The Company suspends the costs of exploratory wells that discover hydrocarbons pending a final
determination of the commercial potential of the discovery. The ultimate disposition of these well costs is dependent on the results
of future drilling activity and development decisions. If the Company decides not to pursue additional appraisal activities or
development of these fields, the costs of these wells will be charged to exploration and abandonment expense.
The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following
the completion of drilling unless both of the following conditions are met:
(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.
(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the
project.
Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time
to evaluate the future potential of an exploration project and economics associated with making a determination on its commercial
viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but
rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on
well information, gaining access to other companies' production, transportation or processing facilities and/or getting partner
61
PIONEER NATURAL RESOURCES COMPANY
approval to drill additional appraisal wells. These activities are ongoing and being pursued constantly. Consequently, the Company's
assessment of suspended exploratory well costs is continuous until a decision can be made that the well has found proved reserves
to sanction the project or is noncommercial and is impaired. See Note F of Notes to Consolidated Financial Statements included
in "Item 8. Financial Statements and Supplementary Data" for additional information regarding the Company's suspended
exploratory well costs.
Deferred tax asset valuation allowances. The Company continually assesses both positive and negative evidence to
determine whether it is more likely than not that its deferred tax assets, if any, will be realized prior to their expiration. Pioneer
monitors Company-specific, oil and gas industry and worldwide economic factors and reassesses the likelihood that the Company's
net operating loss carryforwards and other deferred tax attributes in each jurisdiction will be utilized prior to their expiration.
There can be no assurance that facts and circumstances will not materially change and require the Company to establish deferred
tax asset valuation allowances in certain jurisdictions in a future period.
Goodwill impairment. The Company reviews its goodwill for impairment at least annually. During the third and fourth
quarters of 2013, the Company performed qualitative assessments of goodwill to assess whether it is more likely than not that the
fair value of a reporting unit is less than its carrying amount as a basis for determining whether it is necessary to perform the two-
step goodwill impairment test. The Company determined that it was not likely that the Company's goodwill was impaired.
For assessments prior to 2012, the Company was required to estimate the fair value of the assets and liabilities of the
reporting units that have goodwill. There is considerable judgment involved in estimating fair values, particularly in determining
the valuation methodologies to utilize, the estimation of proved reserves as described above and the weighting of different valuation
methodologies applied. See Note B of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for additional information regarding goodwill and assessments of goodwill for impairment.
Litigation and environmental contingencies. The Company makes judgments and estimates in recording liabilities for
ongoing litigation and environmental remediation. Actual costs can vary from such estimates for a variety of reasons. The costs
to settle litigation can vary from estimates based on differing interpretations of laws and opinions and assessments on the amount
of damages. Similarly, environmental remediation liabilities are subject to change because of changes in laws and regulations,
developing information relating to the extent and nature of site contamination and improvements in technology. A liability is
recorded for these types of contingencies if the Company determines the loss to be both probable and reasonably estimable. See
Note J of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for
additional information regarding the Company's commitments and contingencies.
Valuation of stock-based compensation. The Company calculates the fair value of stock-based compensation using various
valuation methods. The valuation methods require the use of estimates to derive the inputs necessary to determine fair value. The
Company utilizes (a) the Black-Scholes option pricing model to measure the fair value of stock options, (b) the closing stock price
on the day prior to the date of grant for the fair value of restricted stock awards, (c) the closing stock price at the balance sheet
date for restricted stock awards that are expected to be settled wholly or partially in cash on their vesting date, (d) the Monte Carlo
simulation method for the fair value of performance unit awards and (e) a probability forecasted fair value method for Series B
unit awards issued by Sendero. See Note H of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" for information regarding the Company's stock-based compensation.
Valuation of other assets and liabilities at fair value. The Company periodically measures and records certain assets and
liabilities at fair value. The assets and liabilities that the Company periodically measures and records at fair value include trading
securities, commodity derivative contracts and interest rate contracts. The Company also measures and discloses certain financial
assets and liabilities at fair value, such as long-term debt. The valuation methods used by the Company to measure the fair values
of these assets and liabilities require considerable management judgment and estimates to derive the inputs necessary to determine
fair value estimates, such as future prices, credit-adjusted risk-free rates and current volatility factors. See Note D of Notes to
Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary Data" for information regarding
the methods used by management to estimate the fair values of these assets and liabilities.
New Accounting Pronouncements
The effects of new accounting pronouncements are discussed in Note B of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data."
62
PIONEER NATURAL RESOURCES COMPANY
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The following quantitative and qualitative information is provided about financial instruments to which the Company was
a party as of December 31, 2013, and from which the Company may incur future gains or losses from changes in commodity
prices or interest rates.
The fair values of the Company's long-term debt and derivative contracts are determined based on observable inputs and
utilizing the Company's valuation models and applications. As of December 31, 2013, the Company was a party to commodity
swap contracts, interest rate swap contracts, commodity collar contracts and commodity collar contracts with short put options.
See Notes D and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and Supplementary
Data" for additional information regarding the Company's fair value measurements and derivative contracts. The following table
reconciles the changes that occurred in the fair values of the Company's open derivative contracts during 2013:
Fair value of contracts outstanding as of December 31, 2012 .................................... $
Changes in contract fair values (a)..............................................................................
Contract maturities ......................................................................................................
Contract terminations ..................................................................................................
Fair value of contracts outstanding as of December 31, 2013 .................................... $
318,377
(5,793)
(167,164)
(485)
144,935
$
(9,724) $
9,803
—
(482)
(403) $
308,653
4,010
(167,164)
(967)
144,532
Commodities
Derivative Contract Net Assets (Liabilities)
Interest Rate
(in thousands)
$
Total
_____________________
(a) At inception, new derivative contracts entered into by the Company generally have no intrinsic value.
Quantitative Disclosures
Interest rate sensitivity. See Note G of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements
and Supplementary Data" and Capital Commitments, Capital Resources and Liquidity included in "Item 7. Management's Discussion
and Analysis of Financial Condition and Results of Operations" for information regarding the Company's outstanding debt and debt
transactions.
The following table provides information about financial instruments to which the Company was a party as of December 31,
2013 and that are sensitive to changes in interest rates. The table presents debt maturities by expected maturity dates, the weighted
average interest rates expected to be paid on the debt given current contractual terms and market conditions, and the aggregate
estimated fair value of the Company's outstanding debt. For fixed rate debt, the weighted average interest rates represent the contractual
fixed rates that the Company was obligated to periodically pay on the debt as of December 31, 2013. The Company had no outstanding
variable rate debt as of December 31, 2013, but presents for the readers' information the average variable contractual rates for its
credit facility projected forward proportionate to the forward yield curve for LIBOR on February 20, 2014.
63
PIONEER NATURAL RESOURCES COMPANY
INTEREST RATE SENSITIVITY
DEBT OBLIGATIONS AND DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2013
Total Debt:
Fixed rate principal
maturities (a) .......................
Weighted average fixed
interest rate ..........................
Year Ending December 31,
Liability Fair
Value at
December 31,
2014
2015
2016
2017
2018
Thereafter
Total
2013
(in thousands, except percentages)
$—
$—
$455,385
$485,100
$449,500
$1,300,000
$2,689,985
$ 3,018,830
6.15%
6.15%
6.17%
6.11%
5.91%
5.81%
Weighted average variable
interest rate ..........................
Interest Rate Swaps:
Notional debt amount.......... $400,000
Fixed rate payable (%) ........
1.77%
3.95%
Variable rate receivable (%)
1.39%
2.19%
3.15%
4.17%
—%
—%
$400,000
$400,000
$400,000
$400,000
$354,167
$
403
3.95%
1.80%
3.95%
2.76%
3.95%
3.79%
3.95%
4.60%
3.95%
5.60%
_______________________
(a)
Represents maturities of principal amounts excluding debt issuance discounts and net deferred fair value hedge losses.
Commodity derivative instruments and price sensitivity. The following table provides information about the Company's oil,
NGL and gas derivative financial instruments that were sensitive to changes in commodity prices as of December 31, 2013. Although
the cash flow effects are mitigated by the Company's derivative instruments, declines in oil, NGL and gas prices reduce the Company's
sales revenues.
The Company manages commodity price risk with derivative contracts, such as swaps, collar contracts and collar contracts
with short put options. Swap contracts provide a fixed price for a notional amount of sales volumes. Collar contracts provide minimum
("floor" or "long put") and maximum ("ceiling" or "short call") prices on a notional amount of sales volumes, thereby allowing some
price participation if the relevant index price closes above the floor price. Collar contracts with short put options differ from other
collar contracts by virtue of the short put option price, below which the Company's realized price will exceed the variable market
prices by the floor-to-short put price differential.
See Notes B, D and E of Notes to Consolidated Financial Statements included in "Item 8. Financial Statements and
Supplementary Data" for a description of the accounting procedures followed by the Company relative to its derivative financial
instruments and for specific information regarding the terms of the Company's derivative financial instruments that are sensitive to
changes in oil, NGL or gas prices.
64
PIONEER NATURAL RESOURCES COMPANY
DERIVATIVE FINANCIAL INSTRUMENTS AS OF DECEMBER 31, 2013
Year Ending December 31,
2014
2015
2016
Asset (Liability)
Fair Value at
December 31,
2013 (a)
(in thousands)
Oil Derivatives: (b)
Average daily notional BBL volumes:
Swap contracts.........................................................................
Weighted average fixed price per BBL................................. $
Collar contracts with short puts...............................................
Weighted average ceiling price per BBL .............................. $
Weighted average floor price per BBL.................................. $
Weighted average short put price per BBL........................... $
Average forward NYMEX oil prices (c).................................... $
NGL Derivatives: (d)
Average daily notional BBL volumes:
Collar contracts with short puts (e) .........................................
Weighted average ceiling price per BBL .............................. $
Weighted average floor price per BBL.................................. $
Weighted average short put price per BBL........................... $
Average forward NGL prices (f)................................................ $
Collar contracts (g) ..................................................................
Weighted average ceiling price per BBL .............................. $
Weighted average floor price per BBL.................................. $
Average forward NGL prices (f)................................................ $
Gas Derivatives:
Average daily notional MMBTU volumes:
10,000
93.87
69,000
114.05
93.70
77.61
99.28
1,000
109.50
95.00
80.00
86.99
3,000
13.72
10.78
13.31
Swap contracts.........................................................................
Weighted average fixed price per MMBTU.......................... $
Collar contracts with short puts...............................................
Weighted average ceiling price per MMBTU....................... $
Weighted average floor price per MMBTU.......................... $
Weighted average short put price per MMBTU.................... $
Average forward NYMEX gas prices (h) .................................. $
Basis swap contracts (i) ...........................................................
195,000
4.04
115,000
4.70
4.00
3.00
4.85
85,082
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
(6,283)
136,697
—
— $
85,000
98.98
88.06
73.06
90.13
$
$
$
$
$
— $
—
25,000
93.30
85.00
70.00
84.10
—
— $
— $
— $
— $
—
— $
— $
— $
20,000
4.31
285,000
5.07
4.00
3.00
4.22
30,000
$
$
$
$
$
1,010
270
(9,105)
18,098
4,248
— $
—
—
—
—
— $
—
—
—
$
— $
—
20,000
5.36
4.00
3.00
4.10
— $
—
—
Weighted average fixed price per MMBTU.......................... $
Average forward basis differential prices (j).............................. $
(0.20) $
(0.22) $
(0.18) $
(0.32) $
_____________________
(a)
In accordance with Financial Accounting Standards Board Accounting Standards Codification ("ASC") 210-20 and ASC
815-10, the Company classifies the fair value amounts of derivative assets and liabilities executed under master netting
arrangements as net derivative assets or net derivative liabilities, as the case may be. The net asset and liability amounts shown
above have been provided on a commodity contract-type basis, which may differ from their master netting arrangements
classifications.
Subsequent to December 31, 2013, the Company entered into rollfactor swap contracts for 5,000 BBLs per day of the Company's
March through December 2014 production with a NYMEX roll price of $0.82 per BBL and 5,000 BBLs per day of the
Company's 2015 production with a NYMEX roll price of $0.60 per BBL. Rollfactor swap contracts 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.
The average forward NYMEX oil prices are based on February 20, 2014 market quotes.
(b)
(c)
65
PIONEER NATURAL RESOURCES COMPANY
(d)
(e)
(f)
Subsequent to December 31, 2013, the Company entered into propane swap contracts for 1,000 BBLs per day of March
through December 2014 production with a price of $47.57 per BBL and 2,000 BBLs per day of April through October 2014
production with a price of $48.51 per BBL.
Represent collar contracts with short puts that reduce the price volatility of natural gasoline forecasted for sale by the Company
at Mont Belvieu, Texas-posted prices.
Forward component NGL prices are derived from respective active-market NGL component price quotes on February 20,
2014.
(g) Represent collar contracts that reduce the price volatility of ethane forecasted for sale by the Company at Mont Belvieu, Texas-
(h)
(i)
(j)
posted prices.
The average forward NYMEX gas prices are based on February 20, 2014 market quotes.
Subsequent to December 31, 2013, the Company entered into additional basis swap contracts for 35,000 MMBTU per day of
April through December 2014 production with a negative price differential of $0.27 per MMBTU between the relevant index
price and the NYMEX price.
The average forward basis differential prices are based on February 20, 2014 market quotes for basis differentials between
the relevant index prices and NYMEX-quoted forward prices.
Marketing and basis transfer derivatives. The Company enters into buy and sell marketing arrangements to fulfill firm pipeline
transportation commitments. Associated with these marketing arrangements, the Company may enter into index swaps to mitigate
price risk. As of December 31, 2013, the Company had no open marketing derivative positions. Subsequent to December 31, 2013,
the Company entered into marketing gas index swap contracts for 20,000 MMBTU per day of March 2014 volumes with a price
differential of $0.34 per MMBTU, 10,000 MMBTU per day of April through October 2014 volumes with a price differential of $0.36
per MMBTU and 30,000 MMBTU per day of April through December 2014 volumes with a price differential of $0.30 per MMBTU.
Qualitative Disclosures
The Company's primary market risk exposures are to changes in commodity prices and interest rates. These risks did not
change materially from December 31, 2012 to December 31, 2013.
Non-derivative financial instruments. The Company is a borrower under fixed rate debt instruments and, from time to
time, under a variable rate debt instrument that gives rise to interest rate risk. The Company's objective in borrowing under fixed
or variable rate debt is to satisfy capital requirements while minimizing the Company's costs of capital. The Company also enters
into oil and gas purchase and sale transactions with third parties to satisfy unused pipeline capacity commitments and to diversify
a portion of the Company's WTI oil sales to a Gulf Coast oil price. See Note G of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a discussion of the Company's debt instruments.
Derivative financial instruments. The Company, from time to time, utilizes commodity price and interest rate derivative
contracts to mitigate commodity price and interest rate risks in accordance with policies and guidelines approved by the Board.
In accordance with those policies and guidelines, the Company's executive management determines the appropriate timing and
extent of derivative transactions.
66
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Index to Consolidated Financial Statements
Consolidated Financial Statements of Pioneer Natural Resources Company:
Report of Independent Registered Public Accounting Firm ................................................................................................
Consolidated Balance Sheets as of December 31, 2013 and 2012.......................................................................................
Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011.....................................
Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2013, 2012 and 2011 .....
Consolidated Statements of Equity for the Years Ended December 31, 2013, 2012 and 2011............................................
Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011....................................
Notes to Consolidated Financial Statements........................................................................................................................
Unaudited Supplementary Information ................................................................................................................................
Page
68
69
71
72
73
75
76
114
67
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The Board of Directors and Stockholders of
Pioneer Natural Resources Company
We have audited the accompanying consolidated balance sheets of Pioneer Natural Resources Company (the "Company")
as of December 31, 2013 and 2012, and the related consolidated statements of operations, comprehensive income (loss), equity
and cash flows for each of the three years in the period ended December 31, 2013. These financial statements are the responsibility
of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates
made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial
position of Pioneer Natural Resources Company at December 31, 2013 and 2012, and the consolidated results of its operations
and its cash flows for each of the three years in the period ended December 31, 2013, in conformity with U.S. generally accepted
accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
Pioneer Natural Resources Company's internal control over financial reporting as of December 31, 2013, based on criteria
established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (1992 framework) and our report dated February 26, 2014 expressed an unqualified opinion thereon.
Dallas, Texas
February 26, 2014
/s/ Ernst & Young LLP
68
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands)
December 31,
2013
2012
Current assets:
ASSETS
Cash and cash equivalents............................................................................................................. $
Accounts receivable:
392,646
$
229,396
Trade, net ....................................................................................................................................
Due from affiliates......................................................................................................................
Income taxes receivable ................................................................................................................
Inventories.....................................................................................................................................
Prepaid expenses ...........................................................................................................................
Assets held for sale .......................................................................................................................
Other current assets:
430,732
2,753
4,784
220,125
15,852
583,750
316,854
3,299
7,447
197,056
13,438
—
Derivatives..................................................................................................................................
Other ...........................................................................................................................................
Total current assets...................................................................................................................
75,237
2,555
1,728,434
279,119
3,746
1,050,355
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method of accounting:
Proved properties ........................................................................................................................
Unproved properties ...................................................................................................................
Accumulated depletion, depreciation and amortization................................................................
Total property, plant and equipment.........................................................................................
13,406,135
123,382
(4,903,122)
8,626,395
14,259,708
231,555
(4,412,913)
10,078,350
Goodwill ..........................................................................................................................................
Other property and equipment, net..................................................................................................
Other assets:
Investment in unconsolidated affiliate ..........................................................................................
Derivatives ....................................................................................................................................
Other, net.......................................................................................................................................
274,329
1,224,153
298,142
1,217,694
224,850
90,854
123,773
$ 12,292,788
204,129
55,257
165,103
$ 13,069,030
The accompanying notes are an integral part of these consolidated financial statements.
69
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS (Continued)
(in thousands, except share data)
Current liabilities:
Accounts payable:
LIABILITIES AND EQUITY
Trade ........................................................................................................................................... $
Due to affiliates...........................................................................................................................
Interest payable .............................................................................................................................
Income taxes payable ....................................................................................................................
Deferred income taxes ..................................................................................................................
Liabilities held for sale..................................................................................................................
Other current liabilities:
Derivatives..................................................................................................................................
Other ...........................................................................................................................................
Total current liabilities..............................................................................................................
Long-term debt ................................................................................................................................
Derivatives.......................................................................................................................................
Deferred income taxes.....................................................................................................................
Other liabilities ................................................................................................................................
Equity:
Common stock, $.01 par value; 500,000,000 shares authorized; 145,833,707 and 134,966,740
shares issued at December 31, 2013 and 2012, respectively .................................................
Additional paid-in capital..............................................................................................................
Treasury stock, at cost: 3,206,054 and 11,611,093 shares at December 31, 2013 and 2012,
respectively ............................................................................................................................
Retained earnings ..........................................................................................................................
Total equity attributable to common stockholders......................................................................
Noncontrolling interest in consolidating subsidiaries ...................................................................
Total equity.................................................................................................................................
Commitments and contingencies
December 31,
2013
2012
$
910,393
150,164
62,374
165
19,169
38,562
729,942
96,935
68,083
208
86,481
—
11,626
57,653
1,250,106
2,653,059
9,933
1,472,717
292,215
13,416
39,725
1,034,790
3,721,193
12,307
2,140,416
293,016
1,458
5,079,821
1,350
3,683,934
(144,776)
1,665,081
6,601,584
13,174
6,614,758
(510,570)
2,514,640
5,689,354
177,954
5,867,308
$ 12,292,788
$ 13,069,030
The accompanying notes are an integral part of these consolidated financial statements.
70
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
Year Ended December 31,
2012
2011
2013
Revenues and other income:
Oil and gas ................................................................................................................ $ 3,155,696
333,822
Sales of purchased oil and gas ..................................................................................
16,961
Interest and other ......................................................................................................
Derivative gains, net .................................................................................................
4,010
209,021
Gain (loss) on disposition of assets, net....................................................................
3,719,510
$ 2,575,311
122,093
(1,032)
330,251
45,898
3,072,521
$ 2,080,215
14,542
29,382
392,752
(3,644)
2,513,247
Costs and expenses:
Oil and gas production..............................................................................................
Production and ad valorem taxes..............................................................................
Depletion, depreciation and amortization.................................................................
Purchased oil and gas................................................................................................
Impairment of oil and gas properties ........................................................................
Exploration and abandonments.................................................................................
General and administrative .......................................................................................
Accretion of discount on asset retirement obligations..............................................
Interest ......................................................................................................................
Other .........................................................................................................................
Income (loss) from continuing operations before income taxes .................................
Income tax benefit (provision) ....................................................................................
Income (loss) from continuing operations ..................................................................
Income (loss) from discontinued operations, net of tax..............................................
Net income (loss) ........................................................................................................
Net income attributable to noncontrolling interests..................................................
614,676
201,186
907,077
335,734
1,495,242
98,448
295,868
11,862
183,750
137,386
4,281,229
(561,719)
211,775
(349,944)
(449,605)
(799,549)
(38,865)
Net income (loss) attributable to common stockholders............................................. $ (838,414) $
Basic earnings per share attributable to common stockholders:
558,045
178,723
708,270
120,408
—
98,285
244,196
8,677
204,222
114,175
2,235,001
837,520
(290,488)
547,032
(304,210)
242,822
(50,537)
192,285
Income (loss) from continuing operations................................................................ $
Income (loss) from discontinued operations.............................................................
Net income (loss)...................................................................................................... $
Diluted earnings per share attributable to common stockholders:
Income (loss) from continuing operations................................................................ $
Income (loss) from discontinued operations.............................................................
Net income (loss)...................................................................................................... $
(2.86) $
(3.30)
(6.16) $
(2.86) $
(3.30)
(6.16) $
4.02
(2.48)
1.54
3.91
(2.41)
1.50
Weighted average shares outstanding:
396,961
139,425
489,579
13,949
354,408
80,691
189,985
7,506
181,604
63,071
1,917,179
596,068
(188,278)
407,790
474,124
881,914
(47,425)
834,489
3.03
3.98
7.01
2.97
3.91
6.88
$
$
$
$
$
Basic .........................................................................................................................
Diluted ......................................................................................................................
136,130
136,130
122,966
126,320
116,904
119,215
Amounts attributable to common stockholders:
Income (loss) from continuing operations................................................................ $ (388,809) $
Income (loss) from discontinued operations, net of tax ...........................................
Net income (loss)...................................................................................................... $ (838,414) $
(449,605)
496,495
(304,210)
192,285
$
$
360,365
474,124
834,489
The accompanying notes are an integral part of these consolidated financial statements.
71
2011
881,914
(32,636)
8,407
(24,229)
857,685
(33,687)
823,998
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
Net income (loss) ........................................................................................................ $ (799,549) $
Other comprehensive activity:
2013
Year Ended December 31,
2012
242,822
$
Net hedge (gains) losses included in continuing operations.....................................
Income tax (benefit) provision..................................................................................
Other comprehensive activity.................................................................................
Comprehensive income (loss) .....................................................................................
Comprehensive income attributable to the noncontrolling interests ........................
—
—
—
(799,549)
(38,865)
Comprehensive income (loss) attributable to common stockholders ......................... $ (838,414) $
4,855
(1,725)
3,130
245,952
(50,537)
195,415
$
The accompanying notes are an integral part of these consolidated financial statements.
72
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4
7
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
Year Ended December 31,
2012
2011
2013
Cash flows from operating activities:
Net income (loss)...................................................................................................... $ (799,549) $
Adjustments to reconcile net income (loss) to net cash provided by operating
activities:
242,822
$
881,914
Depletion, depreciation and amortization ..............................................................
Impairment of oil and gas properties......................................................................
Impairment of inventory and other property and equipment .................................
Exploration expenses, including dry holes.............................................................
Deferred income taxes............................................................................................
(Gain) loss on disposition of assets, net .................................................................
Accretion of discount on asset retirement obligations ...........................................
Discontinued operations .........................................................................................
Interest expense ......................................................................................................
Derivative related activity ......................................................................................
Amortization of stock-based compensation ...........................................................
Amortization of deferred revenue ..........................................................................
Other noncash items ...............................................................................................
Change in operating assets and liabilities
Accounts receivable, net ........................................................................................
Income taxes receivable .........................................................................................
Inventories ..............................................................................................................
Prepaid expenses ....................................................................................................
Other current assets ................................................................................................
Accounts payable ...................................................................................................
Interest payable ......................................................................................................
Income taxes payable .............................................................................................
Other current liabilities...........................................................................................
Net cash provided by operating activities............................................................
907,077
1,495,242
61,812
21,379
(222,374)
(209,021)
11,862
612,880
17,225
164,121
70,999
—
(6,073)
(122,914)
2,663
(39,062)
(531)
3,964
208,692
(5,709)
(62)
(27,342)
2,145,279
708,270
—
5,719
31,189
286,229
(45,898)
8,677
497,579
35,563
68,604
62,567
(42,069)
(45,293)
(28,206)
(5,953)
33,059
1,447
14,291
46,038
10,842
(9,580)
(38,320)
1,837,577
489,579
354,408
3,126
32,529
181,330
3,644
7,506
(265,327)
31,483
(221,899)
41,442
(44,951)
3,599
(47,331)
29,406
(137,401)
(3,415)
1,957
136,296
(1,768)
(7,623)
61,210
1,529,714
Cash flows from investing activities:
Proceeds from disposition of assets, net of cash sold...............................................
Payments for acquisition, net of cash acquired ........................................................
Distribution from (investment in) unconsolidated subsidiary ..................................
Additions to oil and gas properties ...........................................................................
Additions to other assets and other property and equipment, net.............................
Net cash used in investing activities ......................................................................
711,027
—
25,050
(2,638,799)
(237,082)
(2,139,804)
95,564
(297,092)
—
(2,758,073)
(296,809)
(3,256,410)
819,044
—
(89,620)
(1,926,965)
(363,246)
(1,560,787)
Cash flows from financing activities:
Borrowings under long-term debt.............................................................................
Principal payments on long-term debt......................................................................
Proceeds from issuance of common stock, net of issuance costs .............................
Proceeds from issuance of partnership common units, net of issuance costs...........
Distributions to noncontrolling interests ..................................................................
Payments of other liabilities .....................................................................................
Exercise of long-term incentive plan stock options and employee stock purchases
Purchase of treasury stock ........................................................................................
Excess tax benefits from share-based payment arrangements..................................
Payment of financing fees ........................................................................................
Dividends paid ..........................................................................................................
Net cash provided by financing activities ..............................................................
Net increase (decrease) in cash and cash equivalents .................................................
Cash and cash equivalents, beginning of period .........................................................
Cash and cash equivalents, end of period ................................................................... $
466,864
(1,546,771)
1,280,916
—
(36,054)
(3,625)
10,054
(20,102)
17,639
(8)
(11,138)
157,775
163,250
229,396
392,646
1,776,618
(612,001)
—
—
(35,903)
(1,153)
7,271
(63,325)
58,486
(9,227)
(10,021)
1,110,745
(308,088)
537,484
229,396
$
$
196,616
(294,883)
484,160
122,976
(26,702)
(901)
3,696
(40,355)
31,087
(8,741)
(9,556)
457,397
426,324
111,160
537,484
The accompanying notes are an integral part of these consolidated financial statements.
75
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012 and 2011
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 in the United States, with continuing field operations in the Permian Basin in West Texas, the Eagle Ford Shale play in
South Texas, the Raton field in southeastern Colorado, the Hugoton field in southwest Kansas and the West Panhandle field in the
Texas Panhandle. The Company's objective is to maximize shareholder investment returns by maintaining financial flexibility,
capital allocation discipline and enhancing net asset value through accretive drilling programs, joint ventures and acquisitions.
NOTE B. Summary of Significant Accounting Policies
Principles of consolidation. The consolidated financial statements include the accounts of the Company and its wholly-
owned and majority-owned subsidiaries since their acquisition or formation. In accordance with generally accepted accounting
principles in the United States ("GAAP"), the Company proportionately consolidates certain affiliate partnerships that are less
than wholly-owned and are involved in oil and gas producing activities. All material intercompany balances and transactions have
been eliminated.
Certain reclassifications have been made to the 2012 and 2011 financial statement and footnote amounts in order to conform
them to the 2013 presentations.
In addition, the presentation of purchases and sales of third-party oil and gas has been revised in 2012 and 2011 to present
separately the gross sales of purchased oil and gas and costs of purchased oil and gas. Previously, the sales and purchases were
netted in other expense. Revenues and costs from the purchase and sale transactions are presented on a gross basis as the Company
acts as a principal in the transactions by assuming the risks and rewards of ownership, including credit risk, of the oil and gas
purchased and assumes responsibility to deliver the oil and gas volumes sold. This revision did not impact the Company's balance
sheet, net income (loss) from continuing operations, equity or cash flows. While not material to the 2012 and 2011 financial
statements as a whole, the presentation has been revised to enhance consistency. The following individual line items were affected
in addition to total revenues and other income, and total costs and expenses:
Year Ended December 31,
2012
2011
Sales of purchased oil and gas, as previously reported ..................................................................... $
Revision of sales of purchased oil and gas........................................................................................
Sales of purchased oil and gas, reported herein ...........................................................................
$
Purchased oil and gas, as previously reported...................................................................................
Revision of purchased oil and gas .....................................................................................................
Purchased oil and gas, reported herein .........................................................................................
Other expense, as previously reported (excluding amounts included in discontinued operations)...
Revision of other expense .................................................................................................................
Other expense, reported herein.....................................................................................................
$
$
$
$
(in thousands)
— $
122,093
122,093
$
— $
120,408
120,408
112,490
1,685
114,175
$
$
$
—
14,542
14,542
—
13,949
13,949
62,478
593
63,071
Use of estimates in the preparation of financial statements. Preparation of the accompanying consolidated financial
statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts
of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported
amounts of revenues and expenses during the reporting periods. Depletion of oil and gas properties and impairment of goodwill
and proved and unproved oil and gas properties, in part, is determined using estimates of proved, probable and possible oil and
gas reserves. There are numerous uncertainties inherent in the estimation of quantities of proved, probable and possible reserves
and in the projection of future rates of production and the timing of development expenditures. Similarly, evaluations for impairment
of proved and unproved oil and gas properties are subject to numerous uncertainties including, among others, estimates of future
recoverable reserves and commodity price outlooks. Actual results could differ from the estimates and assumptions utilized.
76
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
Cash and cash equivalents. The Company's cash and cash equivalents include depository accounts held by banks and
marketable securities with original issuance maturities of 90 days or less.
Accounts receivable. As of December 31, 2013 and 2012, the Company had accounts receivable – trade, net of allowances
for bad debts, of $430.7 million and $316.9 million, respectively. The Company's accounts receivable – trade are primarily comprised
of oil and gas sales receivables, joint interest receivables and other receivables for which the Company does not require collateral
security.
As of December 31, 2013 and 2012, the Company's allowances for doubtful accounts totaled $1.4 million and $1.5 million,
respectively. The Company establishes allowances for bad debts equal to the estimable portions of accounts receivable for which
failure to collect is considered probable. The Company estimates the portions of joint interest receivables for which failure to
collect is probable based on percentages of joint interest receivables that are past due. The Company estimates the portions of
other receivables for which failure to collect is probable based on the relevant facts and circumstances surrounding the receivable.
Allowances for doubtful accounts are recorded as reductions to the carrying values of the receivables included in the Company's
consolidated balance sheets and as charges to other expense in the consolidated statements of operations in the accounting periods
during which failure to collect an estimable portion is determined to be probable.
Inventories. The Company's inventories consist of materials, supplies and commodities. The Company's materials and
supplies inventory is primarily comprised of oil and gas drilling or repair items such as tubing, casing, proppant used to fracture-
stimulate oil and gas wells, chemicals, operating supplies and ordinary maintenance materials and parts. The materials and supplies
inventory is primarily acquired for use in future drilling operations or repair operations and is carried at the lower of cost or market,
on a first-in, first-out cost basis. Valuation reserve allowances for materials and supplies inventories are recorded as reductions to
the carrying values of the materials and supply inventories in the Company's consolidated balance sheets and as charges to other
expense in the accompanying consolidated statements of operations.
Commodities inventories are carried at the lower of average cost or market, on a first-in, first-out basis. The Company's
commodities inventories consist of oil held in storage and natural gas liquids ("NGLs") and gas pipeline fill volumes. Any valuation
allowances of commodities inventories are recorded as reductions to the carrying values of the commodities inventories included
in the Company's consolidated balance sheets and as charges to other expense in the consolidated statements of operations.
The following table presents the Company's materials and supplies and commodities inventories as of December 31,
2013 and 2012:
Year Ended December 31,
Materials and supplies (a) ................................................................................................................. $
Commodities .....................................................................................................................................
Less: Noncurrent materials and supplies (b).....................................................................................
$
2013
2012
(in thousands)
210,792
$
258,962
13,429
(4,096)
220,125
$
5,446
(67,352)
197,056
____________________
(a) As of December 31, 2013 and 2012, the Company's materials and supplies inventories were net of valuation reserve
allowances of $31.8 million and $4.6 million, respectively. See Note D for additional information regarding inventory
impairments.
Included in other noncurrent assets in the Company's accompanying consolidated balance sheet.
(b)
Oil and gas properties. The Company utilizes the successful efforts method of accounting for its oil and gas properties.
Under this method, all costs associated with productive wells and nonproductive development wells are capitalized while
nonproductive exploration costs and geological and geophysical expenditures are expensed. The Company capitalizes interest on
expenditures for significant development projects, generally when the underlying project is sanctioned, until such projects are
ready for their intended use. For large development projects requiring significant upfront development costs to support the drilling
and production of a planned group of wells, the Company continues to capitalize interest on the portion of the development costs
attributable to the planned wells yet to be drilled.
The Company does not carry the costs of drilling an exploratory well as an asset in its consolidated balance sheets following
the completion of drilling unless both of the following conditions are met:
77
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
(i) The well has found a sufficient quantity of reserves to justify its completion as a producing well.
(ii) The Company is making sufficient progress assessing the reserves and the economic and operating viability of the
project.
Due to the capital intensive nature and the geographical location of certain projects, it may take an extended period of time
to evaluate the future potential of an exploration project and the economics associated with making a determination on its commercial
viability. In these instances, the project's feasibility is not contingent upon price improvements or advances in technology, but
rather the Company's ongoing efforts and expenditures related to accurately predicting the hydrocarbon recoverability based on
well information, gaining access to other companies' production data in the area, transportation or processing facilities and/or
getting partner approval to drill additional appraisal wells. These activities are ongoing and are being pursued constantly.
Consequently, the Company's assessment of suspended exploratory well costs is continuous until a decision can be made that the
project has found sufficient proved reserves to sanction the project or is noncommercial and is charged to exploration and
abandonments expense. See Note F for additional information regarding the Company's suspended exploratory well costs.
The Company owns interests in six gas processing plants and nine treating facilities. The Company is the operator of two
of the gas processing plants and all nine of the treating facilities. The Company's ownership interests in the gas processing plants
and treating facilities are primarily to accommodate handling the Company's gas production and thus are considered a component
of the capital and operating costs of the respective fields that they service. To the extent that there is excess capacity at a plant or
treating facility, the Company attempts to process third party gas volumes for a fee to keep the plant or treating facility at capacity.
All revenues and expenses derived from third party gas volumes processed through the plants and treating facilities are reported
as components of oil and gas production costs. Third party revenues generated from the processing plants and treating facilities
in continuing operations for the three years ended December 31, 2013, 2012 and 2011 were $57.2 million, $34.4 million and $42.6
million, respectively. Third party expenses attributable to the processing plants and treating facilities in continuing operations for
the same respective periods were $30.1 million, $26.5 million and $22.6 million. The capitalized costs of the plants and treating
facilities are included in proved oil and gas properties and are depleted using the unit-of-production method along with the other
capitalized costs of the field that they service.
The capitalized costs of proved properties are depleted using the unit-of-production method based on proved reserves. Costs
of significant nonproducing properties, wells in the process of being drilled and development projects are excluded from depletion
until the related project is completed and proved reserves are established or, if unsuccessful, impairment is determined.
Proceeds from the sales of individual properties and the capitalized costs of individual properties sold or abandoned are
credited and charged, respectively, to accumulated depletion, depreciation and amortization, if doing so does not materially impact
the depletion rate of an amortization base. Generally, no gain or loss is recognized until an entire amortization base is sold. However,
gain or loss is recognized from the sale of less than an entire amortization base if the disposition is significant enough to materially
impact the depletion rate of the remaining properties in the amortization base.
The Company performs assessments of its long-lived assets to be held and used, including proved oil and gas properties
accounted for under the successful efforts method of accounting, whenever events or circumstances indicate that the carrying value
of those assets may not be recoverable. An impairment loss is indicated if the sum of the expected future cash flows is less than
the carrying amount of the assets. In these circumstances, the Company recognizes an impairment loss for the amount by which
the carrying amount of the assets exceeds the estimated fair value of the assets. See Note D for additional information regarding
the Company's impairment of proved oil and gas properties.
Unproved oil and gas properties are periodically assessed for impairment on a project-by-project basis. These impairment
assessments are affected by the results of exploration activities, commodity price outlooks, planned future sales or expirations of
all or a portion of such projects. If the estimated future net cash flows attributable to such projects are not expected to be sufficient
to fully recover the costs invested in each project, the Company will recognize an impairment loss at that time.
Goodwill. During 2004, the Company recorded goodwill associated with a business combination, which represents the cost
of an acquired entity over the net amounts assigned to assets acquired and liabilities assumed. In accordance with GAAP, goodwill
is not amortized to earnings, but is assessed for impairment whenever events or circumstances indicate that impairment of the
carrying value of goodwill is likely, but no less often than annually. If the carrying value of goodwill is determined to be impaired,
it is reduced for the impaired value with a corresponding charge to earnings in the period in which it is determined to be impaired.
During the third quarter of 2013, the Company performed a qualitative assessment of goodwill to determine whether it was more
likely than not that the fair value of the Company's reporting unit was less than its carrying amount as a basis for determining
78
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
whether it was necessary to perform the two-step goodwill impairment test. Based upon the results of the assessment, the Company
determined that it was not likely that the Company's goodwill was impaired.
For the year ended December 31, 2013, the Company reduced the carrying value of goodwill by $23.8 million, reflecting
the portion of the Company's goodwill related to assets sold or included in assets held for sale at December 31, 2013, primarily
associated with the sale of 40 percent of Pioneer's interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp
Shale play in the southern portion of the Spraberry field in West Texas, and the planned sales of the Company's Alaska subsidiary
and Barnett Shale net assets. See Note C for additional information regarding the Company's divestitures. At December 31, 2013,
the Company performed a qualitative assessment of its remaining goodwill to determine whether it is more likely than not that the
fair value of the Company's reporting unit is less than its carrying amount, and the Company determined that it is not likely that
the Company's remaining goodwill is impaired.
Other property and equipment, net. Other property and equipment is recorded at cost. At December 31, 2013 and 2012,
respectively, the net carrying value of other property and equipment consisted of the following:
Year Ended December 31,
2013 (a)
2012 (a)
Proved and unproved sand properties (b) ......................................................................................... $
Equipment and rigs (c) ......................................................................................................................
Land and buildings............................................................................................................................
Transportation equipment .................................................................................................................
Furniture and fixtures........................................................................................................................
Leasehold improvements ..................................................................................................................
(in thousands)
451,384
$
457,033
313,165
344,554
41,397
47,905
25,748
385,887
259,629
44,928
43,614
26,603
$ 1,224,153
$ 1,217,694
____________________
(a) At December 31, 2013 and 2012, other property and equipment was net of accumulated depreciation of $458.4 million
(b)
(c)
and $395.9 million, respectively.
Includes sand mines, sales facilities and unproved leaseholds that primarily provide the Company and other unrelated
customers with proppant used in the fracture stimulation of oil and gas wells.
Includes drilling rigs, well servicing rigs and equipment and fracture stimulation equipment including assets owned by
subsidiaries that provide drilling, pumping and well services on Company-operated properties. As of December 31, 2013,
the Company owned 15 drilling rigs, eleven fracture stimulation fleets and other oilfield services equipment, including
pulling units, fracture stimulation tanks, water transport trucks, hot oilers, blowout preventers, construction equipment and
fishing tools. During December 2013, the Company committed to a plan to sell its majority interest in Sendero Drilling
Company, LLC ("Sendero"), which owns the Company's 15 vertical drilling rigs, to Sendero's minority interest owner.
Associated therewith, the Company has classified the assets and liabilities of Sendero, including $17.9 million of drilling
rigs, as assets held for sale in the accompanying consolidated balance sheet as of December 31, 2013. See Note C for
additional information.
The primary purposes of the Company's sand mines and drilling, pumping and well services operations are to accommodate
the Company's drilling and producing operations by increasing the availability of supplies, equipment and services, rather than
being dependent on third-party availability, and to contain associated costs. All intercompany gains or losses of the Company's
sand mines and drilling, pumping and well services operations are eliminated.
Earnings from sales of proppant and from providing drilling, pumping and well services to third-party customers and working
interest owners in Company-operated properties are included in interest and other income in the accompanying consolidated
statements of operations.
The capitalized costs of proved sand properties are depleted using the unit-of-production method based on proved sand
reserves. Equipment items are generally depreciated by individual component on a straight line basis over their economic useful
lives, which are generally from two to 12 years. Leasehold improvements are amortized over the lesser of their economic useful
lives or the underlying terms of the associated leases.
79
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The Company evaluates other property and equipment for potential impairment whenever indicators of impairment are
present. Circumstances that could indicate potential impairment include: significant adverse changes in industry trends and the
economic outlook; legal actions; regulatory changes; and significant declines in utilization rates or oil and gas prices. If it is
determined that other property and equipment is potentially impaired, the Company performs an impairment evaluation by
estimating the future undiscounted net cash flow from the use and eventual disposition of other property and equipment grouped
at the lowest level that cash flows can be identified. If the sum of the future undiscounted net cash flows is less than the net book
value of the property, an impairment loss is recognized for the excess, if any, of the assets' net book value over its estimated fair
value.
Investment in unconsolidated affiliate. During 2010, the Company formed EFS Midstream LLC ("EFS Midstream") to
own and operate gas and liquids gathering, treating and transportation assets in the Eagle Ford Shale play in South Texas. During
June 2010, the Company sold a 49.9 percent member interest in EFS Midstream to an unaffiliated third party for $46.4 million of
cash proceeds. Associated therewith, the Company recorded a $46.2 million deferred gain that is being amortized as a reduction
in production costs over a 20 year period, representing the term of a continuing commitment of Pioneer to deliver production
volumes through EFS Midstream handling and gathering facilities. The deferred gain is included in other current and noncurrent
liabilities in the Company's accompanying consolidated balance sheet.
The Company does not have control of EFS Midstream. Consequently, the Company accounts for this investment under
the equity method of accounting for investments in unconsolidated affiliates. Under the equity method, the Company's investment
in unconsolidated affiliates is increased for investments made and the investor's share of the investee's net income, and decreased
for distributions received, the carrying value of member interests sold and the investor's share of the investee's net losses.
The Company's equity interest in the net income or loss of EFS Midstream is recorded in interest and other income, net of
eliminations of the profit associated with gathering, treating and transportation fees charged to the Company by EFS Midstream,
in the accompanying consolidated statements of operations. See Note M for the Company's equity interest in the net income of
EFS Midstream for the years ended December 31, 2013, 2012 and 2011.
Asset retirement obligations. The Company records a liability for the fair value of an asset retirement obligation in the
period in which it is incurred if a reasonable estimate of fair value can be made. Asset retirement obligations are generally capitalized
as part of the carrying value of the long-lived asset to which it relates. Conditional asset retirement obligations meet the definition
of liabilities and are recognized when incurred if their fair values can be reasonably estimated.
The Company records the current and noncurrent portions of asset retirement obligations in other current liabilities and
other liabilities, respectively, in the accompanying consolidated balance sheets and expenditures are classified as cash used in
operating activities in the accompanying consolidated statements of cash flows. See Note I for additional information about the
Company's asset retirement obligations.
Treasury stock. Treasury stock purchases are recorded at cost. Upon reissuance, the cost of treasury shares held is reduced
by the average purchase price per share of the aggregate treasury shares held.
Issuance of common stock. In February 2013, the Company issued 10.35 million shares of its common stock and realized
$1.3 billion of cash proceeds, net of associated underwriting and offering expenses.
Noncontrolling interest in consolidated subsidiaries. The Company owns the majority interests in certain subsidiaries with
operations in the United States. Prior to December 17, 2013, the Company owned a 0.1 percent general partner interest and a 52.4
percent limited partner interest in Pioneer Southwest Energy Partners L.P. ("Pioneer Southwest") and consolidated the financial
position, results of operations and cash flows of Pioneer Southwest with those of Pioneer. Pioneer Southwest owned proved and
unproved oil and gas properties in the Spraberry field in the Permian Basin of West Texas. On December 17, 2013, the holders of
a majority of the outstanding common units of Pioneer Southwest approved an amended agreement and plan of merger, pursuant
to which (i) all of the then outstanding common units of Pioneer Southwest were canceled and converted into the right to receive
0.2325 of a share of common stock of the Company and (ii) Pioneer Southwest became a wholly-owned subsidiary of the Company.
The changes in the Company's ownership of Pioneer Southwest were accounted for by eliminating the noncontrolling interest
attributable to Pioneer Southwest. See Note C for additional information about Pioneer Southwest and the amended agreement
and plan of merger.
Noncontrolling interests in the net assets of consolidated subsidiaries totaled $13.2 million and $178.0 million as of December
31, 2013 and 2012, respectively. The Company recorded net income attributable to the noncontrolling interests of $38.9 million,
$50.5 million and $47.4 million for the years ended December 31, 2013, 2012 and 2011, respectively.
80
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
In accordance with GAAP, the Company records transfers of any gains or losses, net of taxes, from noncontrolling interests
in consolidated subsidiaries to additional paid in capital proportionate to the ownership after giving effect to the purchase or sale
of common units. The following table presents the Company's net income or loss attributable to common stockholders adjusted
for changes in equity as a result of transactions that changed the Company's ownership interest in Pioneer Southwest:
Net income (loss) attributable to common stockholders............................................. $ (838,414) $
Transfers from the noncontrolling interest in consolidated subsidiaries: ...................
(in thousands)
192,285
$
834,489
Year Ended December 31,
2013
2012
2011
Increase in additional paid in capital from the sale of 1.8 million Pioneer
Southwest common units during 2011, net of tax of $15.4 million......................
Increase in additional paid in capital from Pioneer Southwest's offering of
2.6 million common units during 2011, net of tax of $23.7 million.....................
Decrease in additional paid in capital for deferred taxes recognized attributable to
Pioneer Southwest's 2008 initial public offering of 9.5 million common units....
Increase in additional paid in capital from Pioneer Southwest merger ....................
Increase in additional paid in capital from deferred taxes recognized attributable
to Pioneer Southwest merger ................................................................................
Decrease in additional paid in capital from Pioneer Southwest merger transaction
costs.......................................................................................................................
Net increase (decrease) in equity from transactions with noncontrolling interests ..
Net income (loss) attributable to common stockholders and changes in equity from
—
—
—
168,685
200,091
—
—
26,915
8,104
(49,072)
—
—
—
—
—
—
35,019
(3,880)
364,896
—
(49,072)
transactions with noncontrolling interests ............................................................... $ (473,518) $
143,213
$
869,508
Revenue recognition. The Company recognizes revenue when it is realized or realizable and earned. Revenues are considered
realized or realizable and earned when: (i) persuasive evidence of an arrangement exists, (ii) delivery has occurred or services
have been rendered, (iii) the seller's price to the buyer is fixed or determinable and (iv) collectability is reasonably assured.
The Company uses the entitlements method of accounting for oil, NGLs and gas revenues. Sales proceeds in excess of the
Company's entitlement are included in other liabilities and the Company's share of sales taken by others is included in other assets
in the accompanying consolidated balance sheets.
The Company had no material oil or NGL entitlement assets or liabilities as of December 31, 2013 or 2012. The following
table presents the Company's gas entitlement assets and liabilities with their associated volumes as of December 31, 2013 and
2012. Gas volumes are presented in millions of cubic feet ("MMCF").
December 31,
2013
2012
Amount
Volume
Amount
Volume
Gas entitlement assets.......................................................................... $
Gas entitlement liabilities .................................................................... $
7.4
2.5
(dollars in millions)
2,990
715
$
$
6.8
1.9
2,870
582
The Company enters into oil and gas purchase transactions with third parties and separate sale transactions with third parties
to satisfy unused pipeline capacity commitments and to diversify a portion of the Company's WTI oil sales to a Gulf Coast oil
price. 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 oil and gas purchased and assuming
responsibility to deliver the oil and gas volumes sold. Deficiency payments on excess pipeline capacity are included in other
expense in the accompanying consolidated statements of operations. See Note N for further information on transportation
commitment charges.
81
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The Company recognized revenue of $42.1 million and $45.0 million during 2012 and 2011, respectively from volumetric
production payment ("VPP") agreements which represented limited-term overriding royalty interests in oil reserves that: (i) entitled
the purchaser to receive production volumes over a period of time from specific lease interests, (ii) were free and clear of all
associated production costs and capital expenditures associated with the reserves, (iii) were nonrecourse to the Company (i.e., the
purchaser's only recourse was to the reserves acquired), (iv) transferred title of the reserves to the purchaser and (v) allowed the
Company to retain the remaining reserves after the VPPs volumetric quantities had been delivered. The Company had no VPP
obligations in 2013 as all VPP production volumes were delivered as of December 31, 2012; as such, the Company recognized no
VPP revenue in 2013.
Derivatives. All derivatives are recorded in the accompanying consolidated balance sheets at estimated fair value. Effective
February 1, 2009, the Company discontinued hedge accounting on all of its then-existing hedge contracts. The effective portions
of the discontinued deferred hedges as of February 1, 2009 were included in accumulated other comprehensive income (loss)
("AOCI - Hedging") and were transferred to earnings during the same periods in which the forecasted hedged transactions were
recognized in the Company's earnings. During 2012, the remaining AOCI - Hedging losses were transferred to earnings. Since
discontinuing hedge accounting, the Company has recognized all changes in the fair values of its derivative contracts as gains or
losses in the earnings of the periods in which they occur.
The Company classifies the fair value amounts of derivative assets and liabilities executed under master netting arrangements
as net current or noncurrent derivative assets or net current or noncurrent derivative liabilities, whichever the case may be, by
commodity and counterparty. Net derivative asset values are determined, in part, by utilization of the derivative counterparties'
credit-adjusted risk-free rate curves and net derivative liabilities are determined, in part, by utilization of the Company's and,
through the date of the merger, Pioneer Southwest's credit-adjusted risk-free rate curves. The credit-adjusted risk-free rate curves
for the Company and the counterparties are based on their independent market-quoted credit default swap rate curves plus the
United States Treasury Bill yield curve as of the valuation date. Pioneer Southwest's credit-adjusted risk-free rate curve was based
on independent market-quoted forward London Interbank Offered Rate ("LIBOR") curves plus 162.5 basis points, representing
Pioneer Southwest's estimated borrowing rate. See Note E for additional information about the Company's derivative instruments.
Environmental. The Company's environmental expenditures are expensed or capitalized depending on their future economic
benefit. Expenditures that relate to an existing condition caused by past operations and that have no future economic benefits are
expensed. Expenditures that extend the life of the related property or mitigate or prevent future environmental contamination are
capitalized. Liabilities for expenditures that will not qualify for capitalization are recorded when environmental assessment and/
or remediation is probable and the costs can be reasonably estimated. Such liabilities are undiscounted unless the timing of cash
payments for the liability is fixed or reliably determinable. Environmental liabilities normally involve estimates that are subject
to revision until settlement occurs.
Stock-based compensation. For stock-based compensation awards granted or modified, stock-based compensation expense
is being recognized in the Company's financial statements on a straight line basis over the awards' vesting periods based on their
fair values on the dates of grant or modification, as applicable. The stock-based compensation awards generally vest over a period
not exceeding three years. The amount of stock-based compensation expense recognized at any date is approximately equal to the
ratable portion of the grant date value of the award that is vested at that date. The Company utilizes (i) the Black-Scholes option
pricing model to measure the fair value of stock options, (ii) the prior day's closing stock price on the date of grant for the fair
value of restricted stock, restricted stock units, partnership unit awards or phantom unit awards that are expected to be settled in
the Company's common stock ("Equity Awards"), (iii) the Monte Carlo simulation method for the fair value of performance unit
awards and (iv) a probabilistic forecasted fair value method for Series B unit awards issued by Sendero.
Stock-based compensation liability awards are awards that are expected to be settled in cash on their vesting dates, rather
than in equity shares or units ("Liability Awards"). Stock-based Liability Awards are recorded as accounts payable—affiliates
based on the vested portion of the fair value of the awards on the balance sheet date. The fair values of Liability Awards are updated
at each balance sheet date and changes in the fair values of the vested portions of the awards are recorded as increases or decreases
to stock-based compensation expense.
Segments. Operating segments are defined as components of an enterprise that (i) engage in activities from which it may
earn revenues and incur expenses (ii) for which separate operational financial information is available and is regularly evaluated
by the chief operating decision maker for the purpose of allocating resources and assessing performance.
Based upon how the Company is organized and managed, the Company has only one reportable operating segment, which
is oil and gas exploration and production. The Company considers its vertical integration services as ancillary to its oil and gas
82
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
exploration and producing activities and manages these services to support such activities. In addition, the Company has a single,
company-wide management team that allocates capital resources to maximize profitability and measures financial performance
as a single enterprise.
Assets held for sale and discontinued operations. On the date at which the Company meets all the held for sale criteria,
the Company discontinues the recording of depletion and depreciation of the assets or asset group to be sold and reclassifies the
assets and related liabilities to be sold as held for sale on the accompanying consolidated balance sheets. The assets and liabilities
are measured at the lower of their carrying amount or estimated fair value less cost to sell.
In addition, after determining that held for sale criteria has been met, the Company considers whether the held for sale assets
meet the criteria to be considered discontinued operations. If the assets held for sale are considered discontinued operations, the
Company classifies the results of operations from the assets held for sale as income or loss from discontinued operations, net of
tax in the accompanying consolidated statements of operations for the current period and all prior periods. See Note C for additional
information about the Company's divestitures.
New accounting pronouncements. In July 2013, the Financial Accounting Standards Boards issued Accounting Standards
Update ("ASU") 2013-11, "Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax
Loss, or a Tax Credit Carryforward Exists," which provides guidance on the presentation of unrecognized tax benefits. The adoption
of ASU 2013-11 during the third quarter of 2013 did not have a material impact on the Company's financial position and had no
impact on the Company's statements of operations or cash flows.
NOTE C. Acquisitions and Divestitures
Pioneer Southwest Merger Transaction
On December 17, 2013, the Company completed the acquisition of all of the outstanding common units of Pioneer Southwest
not already owned by the Company, through a merger of a wholly-owned subsidiary of the Company into Pioneer Southwest, the
result of which was that Pioneer Southwest became a wholly-owned subsidiary of the Company. The merger was effected pursuant
to an Agreement and Plan of Merger dated August 9, 2013, as amended on October 25, 2013 (as amended, the "Merger Agreement"),
and was approved by the holders of the common units of Pioneer Southwest at a special meeting held on December 17, 2013.
Pursuant to the Merger Agreement, all of the common units outstanding as of the closing of the merger except for the
common units owned by the Company, were canceled and converted into the right to receive 0.2325 of a share of common stock
of the Company per common unit (the "Conversion Ratio"). In lieu of receiving any fractional share of common stock to which
any holder of the Pioneer Southwest's common units would otherwise have been entitled, after aggregating all fractions of shares
to which such holder would be entitled, any fractional share was rounded up to a whole share of common stock of the Company.
Consequently, in December 2013, the Company issued an aggregate of 3.96 million shares of its common stock to Pioneer Southwest
unitholders. The merger is expected to facilitate the Company's plans to fully and optimally develop the Company's properties in
the Midland Basin in West Texas utilizing horizontal drilling and is expected to enhance the Company's organizational, operational
and administrative efficiencies.
On December 18, 2013, the Company caused Pioneer Southwest, its general partner and all of Pioneer Southwest's
subsidiaries to be merged with and into a wholly-owned subsidiary of the Company, the result of which was that all common units
of Pioneer Southwest were canceled and the Company no longer holds any common units.
Premier Silica Business Combination
On April 2, 2012, a wholly-owned subsidiary of the Company acquired an industrial sand mining business that is now named
Premier Silica LLC ("Premier Silica"). Premier Silica's primary mine operations are in Brady, Texas. The Brady mine facilities
primarily produce, process and provide sand to the Company for use as proppant in its fracture stimulation of oil and gas wells in
Texas. Premier Silica's sand production that is in excess of the Company's sand needs for fracture stimulation and sand production
that is not usable for fracture stimulation is primarily sold to third parties for industrial and recreational purposes. The aggregate
purchase price of Premier Silica was $297.1 million, including closing adjustments.
Divestitures Recorded in Continuing Operations
During December 2013, the Company committed to a plan to sell the Company's majority interest in Sendero to Sendero's
minority interest owner for $31.0 million, subject to negotiating a definitive sales agreement and the buyer completing its financing
83
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
arrangements. Associated with the planned sale of Sendero, the Company recorded a noncash loss of $25.5 million in other expense
during December 2013 to reduce the carrying value of Sendero's net assets to their estimated fair value. As part of the sales
negotiations, the Company plans to commit to lease 12 Sendero rigs through December 31, 2015, and to lease eight Sendero rigs
in 2016. The Company has classified Sendero assets and liabilities as held for sale in the accompanying consolidated balance
sheet as of December 31, 2013.
The Company recorded net gains on disposition of assets in continuing operations of $209.0 million and $45.9 million
during the years ended December 31, 2013 and 2012, respectively, and a net loss on disposition of assets in continuing operations
of $3.6 million during the year ended December 31, 2011. The following describes the significant divestitures included in continuing
operations:
•
Southern Wolfcamp. In January 2013, the Company signed an agreement with Sinochem Petroleum USA LLC
("Sinochem"), a U.S. subsidiary of the Sinochem Group, an unaffiliated third party, to sell 40 percent of Pioneer's
interest in 207,000 net acres leased by the Company in the horizontal Wolfcamp Shale play in the southern portion of
the Spraberry field in West Texas for total consideration of $1.8 billion, including normal closing adjustments. In May
2013, the Company completed the sale to Sinochem for net cash proceeds of $623.8 million, including normal closing
adjustments, resulting in a gain of $181.3 million related to the unproved property interests conveyed to Sinochem.
Sinochem is paying the remaining $1.2 billion of the transaction price by carrying 75 percent of Pioneer's portion of
ongoing drilling and facilities costs attributable to the Company's joint operations with Sinochem in the horizontal
Wolfcamp Shale play.
• West Panhandle. During the first quarter of 2013, the Company completed a sale of its interest in unproved oil and gas
properties adjacent to the Company's West Panhandle field operations for net cash proceeds of $38.1 million, which
resulted in a gain of $22.4 million,
• Eagle Ford Shale. In January 2012, the Company sold a portion of its interest in an unproved oil and gas property in
the Eagle Ford Shale play to unaffiliated third parties for cash proceeds of $54.7 million, which resulted in a gain of
$42.6 million.
• Other. During 2013, 2012 and 2011, the Company sold other proved and unproved properties, inventory and other
property and equipment and recorded net gains of $5.3 million and $3.3 million during 2013 and 2012, respectively,
and a net loss of $3.6 million during 2011.
Discontinued Operations
Alaska. During the fourth quarter of 2013, the Company committed to a plan to sell 100 percent of the capital stock in
Pioneer's Alaska subsidiary, representing all the Company's net assets in Alaska ("Pioneer Alaska"). The sale of Pioneer Alaska
continues to be subject to ongoing negotiations and certain other conditions, such as governmental approvals and buyer's
arrangement of financing.
The Company has classified (i) Pioneer Alaska assets and liabilities as held for sale in the accompanying consolidated
balance sheet as of December 31, 2013 and (ii) Pioneer Alaska results of operations as income (loss) from discontinued operations,
net of tax in the accompanying consolidated statements of operations (including a recasting of the Pioneer Alaska results of
operations for the years ended December 31, 2012 and 2011, which were originally classified as continuing operations).
Associated with the planned sale of Pioneer Alaska, the Company recorded a noncash impairment charge of $539.8 million
in discontinued operations during December 2013 to reduce the carrying value of Pioneer Alaska to its estimated fair value less
costs to sell of $350.6 million. See Note D for additional information about the Pioneer Alaska impairment charge. The recasting
of Pioneer Alaska results includes the sale of the Company's interest in the Cosmopolitan Unit in the Cook Inlet of Alaska in August
2012 to unaffiliated third parties for cash proceeds of $10.1 million, which, together with certain Company obligations assumed
by the purchasers, resulted in a gain of $12.6 million.
Barnett Shale. During the fourth quarter of 2013, the Company committed to a plan to divest of its net assets in the Barnett
Shale field in North Texas. The plan is expected to result in the sale of the Barnett Shale net assets during 2014. The Company
has classified its (i) Barnett Shale assets and liabilities as held for sale in the accompanying consolidated balance sheet as of
December 31, 2013 and (ii) Barnett Shale results of operations as income (loss) from discontinued operations, net of tax in the
accompanying consolidated statements of operations (including a recasting of the Barnett Shale results of operations for the years
ended December 31, 2012 and 2011, which were originally classified as continuing operations).
84
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
Associated with the Company's plan to sell its net assets in the Barnett Shale field, the Company recorded a noncash
impairment charge of $189.5 million in discontinued operations in December 2013 to reduce the carrying value of its net assets
in the Barnett Shale field to their estimated fair value less costs to sell. See Note D for more information about the impairment of
Barnett Shale net assets. Also included in discontinued operations in 2013 is the sale of the Company's interest in certain proved
and unproved oil and gas properties in the Barnett Shale field for net cash proceeds of $33.8 million, which resulted in a gain of
$8.7 million on the unproved properties sold.
The Company's plans to sell Pioneer Alaska and the Barnett Shale net assets are in differing stages of marketing and
negotiation. No assurance can be given that the sales will be completed in accordance with the Company's plans.
South Africa. In December 2011, the Company committed to a plan to exit South Africa and initiated a process to divest
its net assets in South Africa ("Pioneer South Africa"). During the first quarter of 2012, the Company agreed to sell its net assets
in Pioneer South Africa to an unaffiliated third party, effective January 1, 2012, for $60.0 million of cash proceeds before normal
closing and other adjustments, and the buyer's assumption of certain liabilities of the Company's South Africa subsidiaries. In
August 2012, the Company completed the sale of Pioneer South Africa for net cash proceeds of $15.9 million, including normal
closing adjustments for cash revenues and costs and expenses from the effective date through the date of the sale, resulting in a
gain of $28.6 million. The Company classified Pioneer South Africa's results of operations as income from discontinued operations,
net of tax in the accompanying consolidated statements of operations.
Tunisia. In February 2011, the Company sold 100 percent of the Company's share holdings in Pioneer Natural Resources
Tunisia Ltd. and Pioneer Natural Resources Anaguid Ltd. (referred to in the aggregate as "Pioneer Tunisia") to an unaffiliated third
party for cash proceeds of $802.5 million, including normal closing adjustments and excluding cash and cash equivalents sold,
resulting in a gain of $645.2 million. Accordingly, the Company has classified the results of operations of Pioneer Tunisia as
discontinued operations, net of tax in the accompanying consolidated statements of operations.
85
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The following table represents the components of the Company's discontinued operations for the years ended December
31, 2013, 2012 and 2011:
Revenues and other income:
Oil and gas ..............................................................................................................
Interest and other (a)...............................................................................................
Gain on disposition of assets, net (b)......................................................................
$
Year Ended December 31,
2013
2012
(in thousands)
2011
$
260,503
38,642
8,764
307,909
285,542
29,437
40,735
355,714
$
314,124
45,145
645,241
1,004,510
Costs and expenses:
Oil and gas production............................................................................................
Production and ad valorem taxes............................................................................
Depletion, depreciation and amortization (b) .........................................................
Impairment of oil and gas properties (b) (c)...........................................................
Exploration and abandonments...............................................................................
General and administrative .....................................................................................
Accretion of discount on asset retirement obligations (b) ......................................
Interest ....................................................................................................................
Other .......................................................................................................................
Income (loss) from discontinued operations before income taxes............................
Current tax provision ..............................................................................................
Deferred tax (provision) benefit (b)........................................................................
Income (loss) from discontinued operations .............................................................
90,333
10,151
103,787
729,305
52,707
12,261
831
—
9,021
1,008,396
(700,487)
(5,591)
256,473
79,853
9,034
101,921
532,589
108,076
6,061
2,731
—
2,096
842,361
(486,647)
(10,387)
192,824
$ (449,605) $ (304,210) $
55,698
8,239
130,606
—
44,898
13,517
3,436
829
5,849
263,072
741,438
(46,012)
(221,302)
474,124
____________________
(a)
Primarily comprised of Alaskan Petroleum Production Tax credits on qualifying capital expenditures of $38.6 million, $29.3
million and $38.9 million for the years ended December 31, 2013, 2012 and 2011, respectively.
(b) Represents significant noncash components of discontinued operations.
(c)
Represents a noncash impairment charge of $539.8 million on Pioneer Alaska net assets during the year ended December
31, 2013 and noncash impairment charges of $189.5 million and $532.6 million during the years ended December 31, 2013
and 2012, respectively, on the Company's net assets in the Barnett Shale field. See Note D for additional information
regarding the noncash impairment charges.
As of December 31, 2013, the carrying values of the Company's ownership in Pioneer Alaska, the Barnett Shale field and
Sendero were included in assets and liabilities held for sale in the accompanying consolidated balance sheet and were comprised
of the following (the Company had no assets held for sale as of December 31, 2012):
Composition of assets included in assets held for sale:
Current assets (excluding cash and cash equivalents)...............................................................................
Property, plant and equipment...................................................................................................................
Total assets ..............................................................................................................................................
Composition of liabilities included in liabilities held for sale:
Current liabilities .......................................................................................................................................
Other liabilities ..........................................................................................................................................
Total liabilities.........................................................................................................................................
86
December 31, 2013
(in thousands)
$
$
$
$
57,602
526,148
583,750
28,771
9,791
38,562
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
NOTE D. Fair Value Measurements
Fair value is defined as the price that would be received to sell an asset or the price paid to transfer a liability in an orderly
transaction between market participants at the measurement date. Fair value measurements are based upon inputs that market
participants use in pricing an asset or liability, which are characterized according to a hierarchy that prioritizes those inputs based
on the degree to which they are observable. Observable inputs represent market data obtained from independent sources, whereas
unobservable inputs reflect a company's own market assumptions, which are used if observable inputs are not reasonably available
without undue cost and effort. The three input levels of the fair value hierarchy are as follows:
• Level 1 – quoted prices for identical assets or liabilities in active markets.
• Level 2 – quoted prices for similar assets or liabilities in active markets; quoted prices for identical or similar assets or
liabilities in markets that are not active, inputs other than quoted prices that are observable for the asset or liability (e.g.
interest rates) and inputs derived principally from or corroborated by observable market data by correlation or other
means.
• Level 3 – unobservable inputs for the asset or liability.
Assets and liabilities measured at fair value on a recurring basis. The fair value input hierarchy level to which an asset
or liability measurement in its entirety falls is determined based on the lowest level input that is significant to the measurement in
its entirety.
The following tables present the Company's assets and liabilities that are measured at fair value on a recurring basis as of
December 31, 2013 and 2012 for each of the fair value hierarchy levels:
Fair Value Measurements at the End of the Reporting Period
Using
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
(in thousands)
Fair Value at
December 31,
2013
Assets:
Trading securities ..................................................... $
Commodity derivatives ............................................
Interest rate derivatives ............................................
Deferred compensation plan assets ..........................
Total assets.............................................................
Liabilities:
Commodity derivatives ............................................
Interest rate derivatives ............................................
Total liabilities .......................................................
Total recurring fair value measurements............... $
136
—
—
63,971
64,107
—
—
—
64,107
$
$
146
156,561
9,530
—
166,237
11,626
9,933
21,559
144,678
$
$
— $
—
—
—
—
—
—
—
— $
282
156,561
9,530
63,971
230,344
11,626
9,933
21,559
208,785
87
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
Fair Value Measurements at the End of the Reporting Period
Using
Quoted Prices in
Active Markets for
Identical Assets
(Level 1)
Significant Other
Observable
Inputs
(Level 2)
Significant
Unobservable
Inputs
(Level 3)
Fair Value at
December 31,
2012
(in thousands)
Assets:
Trading securities ..................................................... $
Commodity derivatives ............................................
Deferred compensation plan assets ..........................
Total assets.............................................................
Liabilities:
Commodity derivatives ............................................
Interest rate derivatives ............................................
Total liabilities .......................................................
Total recurring fair value measurements............... $
124
$
154
$
— $
—
49,685
49,809
—
—
—
334,376
—
334,530
15,999
9,724
25,723
—
—
—
—
—
—
278
334,376
49,685
384,339
15,999
9,724
25,723
49,809
$
308,807
$
— $
358,616
Trading securities and deferred compensation plan assets. The Company's trading securities are comprised of securities
that are both actively traded and not actively traded on major exchanges. The Company's deferred compensation plan assets
represent investments in equity and mutual fund securities that are actively traded on major exchanges. These investments are
measured based on observable prices on major exchanges. As of December 31, 2013 and 2012, substantially all of the significant
inputs to these asset exchange values represented Level 1 independent active exchange market price inputs. Inputs for certain
trading securities that are not actively traded on major exchanges were classified as Level 2 inputs.
Commodity derivatives. The Company's commodity derivatives represent oil, NGL and gas swap contracts, collar contracts
and collar contracts with short puts. The Company's asset and liability measurements for its oil, NGL and gas swap, collar and
collar contracts with short puts represent Level 2 inputs in the hierarchy priority. 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 which
include (i) the contracted notional volumes, (ii) independent active market price quotes, (iii) the applicable estimated credit-adjusted
risk-free rate yield curve and (iv) the implied rate of volatility inherent in the collar and collar contracts with short puts, which is
based on active and independent market-quoted volatility factors.
Interest rate derivatives. The Company's interest rate derivative assets and liabilities as of December 31, 2013 and 2012
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 as of December 31, 2013 and 2012 are
based on (i) the contracted notional amounts, (ii) LIBOR rate yield curves provided by counterparties and corroborated with
forward active market-quoted LIBOR yield curves and (iii) the applicable credit-adjusted risk-free rate yield curve. The Company's
interest rate derivative liability measurements represent Level 2 inputs in the hierarchy priority.
Assets and liabilities measured at fair value on a nonrecurring basis. Certain assets are measured at fair value on a
nonrecurring basis. These assets are not measured at fair value on any ongoing basis, but are subject to fair value adjustments in
certain circumstances. These assets can include long-lived assets that have been reduced to fair value when they are held for sale,
inventory and proved and unproved oil and gas properties that are written down to fair value when they are impaired.
Proved oil and gas properties. During 2013, 2012 and 2011, reductions in management's longer-term commodity price
outlooks ("Management's Price Outlooks") provided indications of possible impairment of the Company's predominately dry gas
properties in the Raton field in southeastern Colorado, the Barnett Shale field in North Texas and the Edwards Trend and Austin
Chalk fields in South Texas. As a result of management's assessments, during the years ended December 31, 2013, 2012 and 2011,
the Company recognized impairment charges to reduce the carrying values of the Raton field, the Barnett Shale field and the
Edwards Trend/Austin Chalk fields, respectively, to their estimated fair values. The impairment charge associated with the Barnett
Shale field is reported in income (loss) from discontinued operations, net of tax in the accompanying consolidated statements of
operations.
88
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The Company calculated the fair values of the Raton field, the Barnett Shale field and the Edwards Trend/Austin Chalk
fields proved properties using a discounted cash flow model. Significant Level 3 assumptions associated with the calculation of
discounted future cash flows included Management's Price Outlooks and management's outlooks for (i) production costs, (ii)
capital expenditures, (iii) production and (iv) estimated proved reserves and risk-adjusted probable reserves. Management's Price
Outlooks are developed based on third-party longer-term commodity futures price outlooks as of each measurement date. The
expected future net cash flows were discounted using an annual rate of 10 percent to determine fair value.
The following table presents the fair value and fair value adjustments (in millions) for the Company's 2013, 2012 and 2011
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:
Year ended
December 31,
Fair
Value
Fair Value Management's Price Outlooks
Oil
Adjustment
Gas
Edwards Trend/Austin Chalk........................
Barnett Shale .................................................
Raton .............................................................
2011
2012
2013
$
$
$
189.9
184.8
533.6
$
$
$
(354.4) $
(532.6) $
(1,495.2) $
92.69
87.09
80.40
$
$
$
5.14
4.78
4.43
It is reasonably possible that the estimate of undiscounted future net cash flows attributable to these or other properties may
change in the future resulting in the need to impair their carrying values. The primary factors that may affect estimates of future
cash flows are (i) future adjustments, both positive and negative, to proved and appropriate 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.
Assets classified as held for sale. The Company records assets classified as held for sale at the lower of the asset's carrying
amount or estimated fair value less costs to sell. The fair value of Pioneer Alaska is based on an estimated sale price based on
ongoing negotiations, less costs to sell, and is further supported by the Company's discounted cash flow model for the Alaska
proved properties using Level 3 inputs as discussed in the proved oil and gas properties section above. The fair value of the Barnett
Shale field assets is based upon a weighted average calculation that uses management inputs including an estimated sales price
and a discounted cash flow model for the proved properties using Level 3 assumptions as discussed in the proved oil and gas
properties section above. The fair value of the Sendero assets are based upon anticipated sales proceeds less costs to sell, which
represent a Level 3 input in the hierarchy priority. See Note C for additional information regarding the Company's planned
divestitures.
The following table presents the estimated fair value less costs to sell and fair value adjustments for the Company's assets
classified as held for sale as of December 31, 2013:
Discontinued operations held for sale - Alaska................................................................................ $
Discontinued operations held for sale - Barnett Shale field ............................................................ $
$
Other long-lived assets held for sale - Sendero ...............................................................................
Estimated
Fair Value
Less Costs
to Sell
Fair Value
Adjustment
(in millions)
350.6
180.4
31.4
$
$
$
(539.8)
(189.5)
(25.5)
Unproved oil and gas properties. During December 2012, the Company recorded an impairment charge to reduce the
carrying value of unproved properties in the Barnett Shale field of $71.8 million (reported in income (loss) from discontinued
operations, net of tax in the accompanying consolidated statements of operations). The Company calculated the estimated fair
value of the Barnett Shale unproved properties using significant Level 3 assumptions based on average lease bonuses per acre for
its Barnett liquid-rich acreage, allocating no value to dry gas acreage as the Company does not intend to develop that acreage.
Inventories. During December 2013, the Company recorded an impairment charge of $23.2 million to reduce the carrying
value of its excess vertical well pipe inventory. The Company calculated the estimated fair value of the inventory using significant
89
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
Level 2 assumptions based on third-party price quotes for the asset in an active market. The impairment charge is included in other
expense on the Company's accompanying consolidated statements of operations.
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 sheet as of December 31, 2013 and 2012 are as follows:
December 31, 2013
December 31, 2012
Carrying
Value
Fair
Value
Carrying
Value
Fair
Value
(in thousands)
Long-term debt..........................................................................
$ 2,653,059
$ 3,018,830
$ 3,721,193
$ 4,555,770
Long-term debt includes the Company's credit facility and the Company's senior notes. At December 31, 2012, long-term
debt also included Pioneer Southwest's credit facility and the Company's 2.875% Convertible Senior Notes due 2038 ("Convertible
Senior Notes"), which were both fully extinguished during 2013. The fair value of debt is determined utilizing inputs that are
Level 2 measurements in the fair value hierarchy.
Credit facilities. The fair values of the Company's and, through the date of the merger, Pioneer Southwest's credit facilities
are 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 rate (in the case of the Company's credit facility) or LIBOR (in the case of Pioneer
Southwest's credit facility) yield curves and (iii) the applicable credit-adjustments.
Senior notes. The Company's senior notes represent debt securities that are not actively traded on major exchanges. The
fair values of the Company's senior notes are based on their periodic values as quoted on the major exchanges.
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 relatively short
maturities. Non-financial assets and liabilities initially measured at fair value include certain assets acquired and liabilities assumed
in a business combination, goodwill and asset retirement obligations.
Concentrations of credit risk. As of December 31, 2013, the Company's primary concentration of credit risks are the risks
of collecting accounts receivable – trade and the risk of counterparties' failure to perform under derivative obligations. See Note
L for information regarding the Company's major customers.
The Company has entered into International Swap Dealers Association Master Agreements ("ISDA Agreements") with each
of its derivative counterparties. The terms of the ISDA Agreements provide the Company and the counterparties with rights of set
off upon the occurrence of defined acts of default by either the Company or a counterparty to a derivative, whereby the party not
in default may set off all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting
party. See Note E for additional information regarding the Company's derivative activities and information regarding derivative
net assets and liabilities by counterparty.
NOTE E. Derivative Financial Instruments
The Company utilizes commodity swap contracts, collar contracts and collar contracts with short puts to (i) reduce the effect
of price volatility on the commodities the Company produces and sells or consumes, (ii) support the Company's annual capital
budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also,
from time to time, utilizes interest rate contracts to reduce the effect of interest rate volatility on the Company's indebtedness.
90
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
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 actual index prices at which the oil is sold.
The following table sets forth the volumes per day in BBLs associated with the Company's outstanding oil derivative
contracts as of December 31, 2013 and the weighted average oil prices per BBL for those contracts:
2014
2015
2016
Swap contracts:
Volume (BBLs).........................................................................................................
Average price per BBL............................................................................................. $
10,000
93.87
Collar contracts with short puts:
Volume (BBLs).........................................................................................................
Average price per BBL:
Ceiling .................................................................................................................... $
Floor ....................................................................................................................... $
Short put ................................................................................................................. $
69,000
114.05
93.70
77.61
—
— $
—
—
85,000
25,000
98.98
88.06
73.06
$
$
$
93.30
85.00
70.00
$
$
$
$
Subsequent to December 31, 2013, the Company entered into rollfactor swap contracts for 5,000 BBLs per day of the
Company's March through December 2014 production with a NYMEX roll price of $0.82 per BBL and 5,000 BBLs per day of
the Company's 2015 production with a NYMEX roll price of $0.60 per BBL. Rollfactor swap contracts 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 posted prices. The
Company uses derivative contracts to manage the NGL component product price volatility.
As of December 31, 2013, the Company had natural gasoline collar contracts with short put derivatives for 1,000 BBLs per
day of 2014 production with a ceiling price of $109.50 per BBL, a floor price of $95.00 per BBL and short put price of $80.00
per BBL; and ethane collar contracts for 3,000 BBLs per day of 2014 production with a ceiling price of $13.72 per BBL and a
floor price of $10.78 per BBL.
Subsequent to December 31, 2013, the Company entered into propane swap contracts for 1,000 BBLs per day of March
through December 2014 production with a price of $47.57 per BBL and 2,000 BBLs per day of April through October 2014
production with a price of $48.51 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
derivative contracts to manage gas price volatility and basis swap contracts to reduce basis risk between HH prices and actual
index prices at which the gas is sold.
91
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The following table sets forth the volumes per day in MMBTUs associated with the Company's outstanding gas derivative
contracts as of December 31, 2013 and the weighted average gas prices per MMBTU for those contracts:
2014
2015
2016
Swap contracts:
Volume (MMBTUs)..................................................................................................
Price per MMBTU.................................................................................................... $
195,000
4.04
Collar contracts with short puts:
Volume (MMBTUs)..................................................................................................
Price per MMBTU:
115,000
Ceiling .................................................................................................................... $
Floor ....................................................................................................................... $
Short put ................................................................................................................. $
4.70
4.00
3.00
20,000
4.31
285,000
5.07
4.00
3.00
$
$
$
$
$
$
$
$
Basis swap contracts:
Volume (MMBTUs) (a)............................................................................................
Price per MMBTU.................................................................................................... $
85,082
30,000
(0.20) $
(0.18) $
—
—
20,000
5.36
4.00
3.00
—
—
_________________
(a)
Subsequent to December 31, 2013, the Company entered into additional basis swap contracts for 35,000 MMBTU per
day of April through December 2014 production with a negative price differential of $0.27 per MMBTU between the
relevant index price and the NYMEX price.
Marketing and basis transfer derivatives. Periodically, the Company enters into buy and sell marketing arrangements to
fulfill firm pipeline transportation commitments. Associated with these marketing arrangements, the Company may enter into
index swaps to mitigate price risk. As of December 31, 2013, the Company had no open marketing derivative positions. Subsequent
to December 31, 2013, the Company entered into marketing gas index swap contracts for 20,000 MMBTU per day of March 2014
volumes with a price differential of $0.34 per MMBTU, 10,000 MMBTU per day of April through October 2014 volumes with a
price differential of $0.36 per MMBTU and 30,000 MMBTU per day of April through December 2014 volumes with a price
differential of $0.30 per MMBTU.
Interest rates. During the second quarter of 2013, the Company terminated its interest rate derivative contracts that locked
in a fixed forward annual interest rate of 3.21 percent, for a 10-year period ending in December 2025, on a notional amount of
$250 million and received cash proceeds of $482 thousand.
As of December 31, 2013, the Company was a party to interest rate derivative contracts whereby the Company will receive
a fixed interest rate of 3.95 percent in exchange for paying a floating interest rate comprised of the three-month LIBOR plus an
average rate of 1.11 percent on a notional amount of $400 million through July 15, 2022.
Tabular disclosure of derivative financial instruments. All of the Company's derivatives are accounted for as non-hedge
derivatives as of December 31, 2013 and December 31, 2012 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.
92
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
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 December 31, 2013
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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives............. Derivatives - current
Interest rate derivatives ...................... Derivatives - current
Commodity price derivatives............. Derivatives - noncurrent
Interest rate derivatives ...................... Derivatives - noncurrent
Liability Derivatives:
Commodity price derivatives............. Derivatives - current
Commodity price derivatives............. Derivatives - noncurrent
Interest rate derivatives ...................... Derivatives - noncurrent
$
$
$
$
$
$
$
73,431
9,530
95,358
15,493
19,350
4,504
25,426
$
$
$
$
$
$
$
(7,724) $
— $
(4,504)
(15,493) $
$
(7,724) $
(4,504)
(15,493) $
$
65,707
9,530
90,854
—
166,091
11,626
—
9,933
21,559
Fair Value of Derivative Instruments as of December 31, 2012
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 thousands)
Derivatives not designated as hedging instruments
Asset Derivatives:
Commodity price derivatives............. Derivatives - current
Commodity price derivatives............. Derivatives - noncurrent
Liability Derivatives:
Commodity price derivatives............. Derivatives - current
Commodity price derivatives............. Derivatives - noncurrent
Interest rate derivatives ...................... Derivatives - noncurrent
$
$
$
$
$
286,805
61,618
21,102
8,944
9,724
$
$
$
$
$
(7,686) $
(6,361)
$
(7,686) $
(6,361)
—
$
279,119
55,257
334,376
13,416
2,583
9,724
25,723
The following table details the location of gains and losses reclassified from AOCI-Hedging into earnings on the
Company's discontinued cash flow hedging contracts in the accompanying consolidated statements of operations:
Derivatives in Cash Flow Hedging Relationships
Location of Gain/(Loss)
Reclassified from AOCI
into Earnings
Amount of Gain/(Loss) Reclassified
from AOCI into Earnings
Year Ended December 31,
2012
2013
2011
Interest rate derivatives .........................................
Commodity price derivatives ................................ Oil and gas revenue
Total.......................................................................
Interest expense
$
$
(in thousands)
— $
—
— $
(1,699) $
(3,156)
(4,855) $
(282)
32,918
32,636
93
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The following table details the location of gains and losses recognized on the Company's derivative contracts in the
accompanying consolidated statements of operations:
Derivatives Not Designated as Hedging Instruments
Location of Gain (Loss)
Recognized in Earnings on
Derivatives
Interest rate derivatives ......................................... Derivative gains, net
Commodity price derivatives ................................ Derivative gains, net
Total.......................................................................
$
$
Amount of Gain (Loss) Recognized in
Earnings on Derivatives
Year Ended December 31,
2012
(in thousands)
$
2013
2011
9,803
(5,793)
4,010
$
(22,428) $
352,679
330,251
$
3,098
389,654
392,752
Derivative counterparties. The Company uses credit and other financial criteria to evaluate the credit standing of, and to
select, counterparties to its derivative instruments. Although the Company does not obtain collateral or otherwise secure the fair
value of its derivative instruments, associated credit risk is mitigated by the Company's credit risk policies and procedures.
The following table provides the Company's net derivative assets or liabilities by counterparty as of December 31, 2013:
JP Morgan Chase..................................................................................................................................... $
Morgan Stanley........................................................................................................................................
Merrill Lynch...........................................................................................................................................
Barclays Capital.......................................................................................................................................
Den Norske Bank ....................................................................................................................................
Societe Generale......................................................................................................................................
Macquarie Bank.......................................................................................................................................
J. Aron & Company.................................................................................................................................
Wells Fargo Bank, N.A............................................................................................................................
Citibank, N.A...........................................................................................................................................
Deutsche Bank.........................................................................................................................................
BMO Financial Group.............................................................................................................................
Credit Suisse............................................................................................................................................
BP Corporation North America...............................................................................................................
Royal Bank of Canada.............................................................................................................................
BNP Paribas.............................................................................................................................................
Toronto Dominion ...................................................................................................................................
Mitsubishi UFJ Financial Group .............................................................................................................
Credit Agricole ........................................................................................................................................
Total......................................................................................................................................................... $
Net Assets (Liabilities)
(in thousands)
46,908
17,411
16,979
16,923
8,928
8,754
8,146
6,817
4,969
4,857
1,374
1,041
992
793
752
473
(476)
(504)
(605)
144,532
NOTE F. Exploratory Well Costs
The Company capitalizes exploratory well and project costs until a determination is made that the well or project has either
found proved reserves, is impaired or is sold. The Company's capitalized exploratory well and project costs are presented in proved
properties in the accompanying consolidated balance sheets. If the exploratory well or project is determined to be impaired, the
impaired costs are charged to exploration and abandonments expense.
94
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The following table reflects the Company's capitalized exploratory well and project activity during each of the years ended
December 31, 2013, 2012 and 2011:
Beginning capitalized exploratory well costs ............................................................. $
Additions to exploratory well costs pending the determination of proved reserves.
Reclassification due to determination of proved reserves ........................................
Disposition of assets sold..........................................................................................
Impairment of properties ..........................................................................................
Exploratory well costs charged to exploration and abandonment expense (a).........
Ending capitalized exploratory well costs (b)............................................................. $
2013
$
Year Ended December 31,
2012
(in thousands)
107,596
$
926,084
(790,373)
—
—
(30,637)
212,670
$
$
212,670
1,219,797
(1,044,815)
(92,855)
(86,761)
(49,134)
158,902
2011
96,193
524,313
(480,716)
(28,938)
—
(3,256)
107,596
_______________
(a)
Includes exploration and abandonment expense reclassified as discontinued operations of $43.3 million, $21.6 million, and
$180 thousand in 2013, 2012 and 2011, respectively.
Includes $60.3 million of capitalized exploratory well costs classified as held for sale in the accompanying consolidated
balance sheet as of December 31, 2013.
(b)
The following table provides an aging, as of December 31, 2013, 2012 and 2011 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:
Capitalized exploratory well costs that have been suspended:
One year or less ........................................................................................................ $
More than one year ...................................................................................................
$
Year Ended December 31,
2013
2012
2011
(in thousands, except well counts)
115,955
42,947
158,902
$
$
190,678
21,992
212,670
$
$
107,596
—
107,596
Number of projects with exploratory well costs that have been suspended for a
period greater than one year ....................................................................................
1
1
—
Alaska - Nuna. The Company's Nuna project, which has $42.9 million of suspended project costs as of December 31,
2013, includes the Nuna-1 exploration well that was drilled during 2012 to test the Torok formation and a second appraisal well
that was drilled and logged during the first quarter of 2013. The Company flow-tested the Nuna-1 well during the second quarter
of 2012 and again in the first quarter of 2013. The second appraisal well encountered a mechanical problem and could not be flow-
tested before the end of the winter drilling season. The results of the flow tests on the Nuna-1 well and the log data from the second
Nuna well are both very encouraging. The Company is currently conducting a front-end engineering design study to evaluate the
potential for onshore production facilities to support the project. The capitalized exploratory well costs associated with the Nuna
project are classified as held for sale in the accompanying consolidated balance sheet as of December 31, 2013.
Alaska - Oooguruk. As of December 31, 2012, the Company had $22.0 million of suspended well costs recorded for the
K-13 well in the Alaska Oooguruk field. Drilling on the K-13 well was completed during September 2011. During well completion
operations, subsurface damages were sustained. The Company performed repairs to correct a subsurface safety valve and a tubing
leak in the third quarter of 2013. These repairs enabled a production test in the fourth quarter of 2013, which had negative results.
Based on the negative production test results, the Company has discontinued any future plans to complete and produce the well.
Accordingly, an exploration and abandonment charge of $33.7 million was recorded in the fourth quarter of 2013 to write off the
K-13 well's carrying value, which is included in loss from discontinued operations, net of tax in the accompanying consolidated
statements of operations.
95
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
NOTE G. Long-term Debt and Interest Expense
Long-term debt, including the effects of issuance discounts and net deferred fair value hedge losses, consisted of the following
components at December 31, 2013 and 2012:
Outstanding debt principal balances:
December 31,
2013
2012
(in thousands)
Pioneer credit facility ....................................................................................................................... $
Pioneer Southwest credit facility......................................................................................................
5.875% senior notes due 2016..........................................................................................................
6.65% senior notes due 2017............................................................................................................
6.875 % senior notes due 2018.........................................................................................................
7.500 % senior notes due 2020.........................................................................................................
3.95% senior notes due 2022............................................................................................................
7.20% senior notes due 2028............................................................................................................
2.875% convertible senior notes due 2038.......................................................................................
— $
—
455,385
485,100
449,500
450,000
600,000
250,000
—
2,689,985
(35,885)
Issuance discounts ..............................................................................................................................
(1,041)
Net deferred fair value hedge losses...................................................................................................
Total long-term debt ........................................................................................................................... $ 2,653,059
474,000
126,000
455,385
485,100
449,500
450,000
600,000
250,000
479,907
3,769,892
(47,309)
(1,390)
$ 3,721,193
Credit Facility. During December 2012, the Company entered into the First Amendment to the Second Amended and
Restated 5-Year Revolving Credit Agreement (the "Credit Facility") with a syndicate of financial institutions that extended the
maturity to December 20, 2017 and increased the aggregate loan commitments to $1.5 billion. As of December 31, 2013, the
Company had no outstanding borrowings under the Credit Facility.
Borrowings under the Credit Facility may be in the form of revolving loans or swing line loans. Aggregate outstanding
swing line loans may not exceed $150 million. Revolving loans under the Credit Facility bear interest, at the option of the Company,
based on (a) a rate per annum equal to the higher of the prime rate announced from time to time by Wells Fargo Bank, National
Association or the weighted average of the rates on overnight Federal funds transactions with members of the Federal Reserve
System during the last preceding business day plus 0.5 percent plus a defined alternate base rate spread margin, which is currently
0.5 percent based on the Company's debt rating or (b) a base Eurodollar rate, substantially equal to LIBOR, plus a margin (the
"Applicable Margin"), which is currently 1.50 percent and is also determined by the Company's debt rating. Swing line loans under
the Credit Facility bear interest at a rate per annum equal to the "ASK" rate for Federal funds periodically published by the Dow
Jones Market Service plus the Applicable Margin. Letters of credit outstanding under the Credit Facility are subject to a per annum
fee, representing the Applicable Margin plus 0.125 percent. The Company also pays commitment fees on undrawn amounts under
the Credit Facility that are determined by the Company's debt rating (currently 0.25 percent). Borrowings under the Credit Facility
are general unsecured obligations.
The Credit Facility requires the maintenance of a ratio of total debt to book capitalization, subject to certain adjustments,
not to exceed .60 to 1.0. As of December 31, 2013, the Company was in compliance with all of its debt covenants.
Upon completion of the Pioneer Southwest merger, the Company repaid the outstanding indebtedness and terminated the
Pioneer Southwest $300 million Amended and Restated 5-Year Revolving Credit Agreement ("the "Pioneer Southwest Credit
Facility"). Associated therewith, the Company charged $861 thousand of unamortized deferred financing fees related to the Pioneer
Southwest Credit Facility to other expense in the accompanying consolidated statements of operations.
Senior notes. During June 2012, the Company issued $600 million of 3.95% Senior Notes due 2022 and received proceeds,
net of $8.5 million of offering discounts and costs, of $591.5 million. The Company used the net proceeds from the issuance to
reduce outstanding borrowings under the Credit Facility.
96
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The Company's senior notes are general unsecured obligations ranking equally in right of payment with all other senior
unsecured indebtedness of the Company and are senior in right of payment to all existing and future subordinated indebtedness
of the Company. The Company is a holding company that conducts all of its operations through subsidiaries; consequently, the
senior notes are structurally subordinated to all obligations of its subsidiaries. Interest on the Company's senior notes is payable
semiannually.
Convertible senior notes. As of December 31, 2012, the Company had $479.9 million of Convertible Senior Notes
outstanding. During December 2012 and March 2013, the Company's stock price met the price threshold that caused the Convertible
Senior Notes to be convertible during the six months ended June 30, 2013 at the option of the holders into a combination of cash
and the Company's common stock based on a formula set forth in the indenture supplement pursuant to which the Convertible
Senior Notes were issued. In addition, on April 15, 2013, the Company announced that it would exercise its option to redeem all
Convertible Senior Notes that had not been converted by the holders before May 16, 2013. Associated therewith, during the six
months ended June 30, 2013, holders of $479.1 million principal amount of the Convertible Senior Notes exercised their right to
convert their Convertible Senior Notes into cash and shares of the Company's common stock. The Company paid the tendering
holders $479.1 million of cash and issued to the tendering holders 4.4 million shares of the Company's common stock during the
six months ended June 30, 2013, in accordance with the terms of the Convertible Senior Notes indenture agreement. On May 16,
2013, the Company paid $845 thousand in principal and interest to redeem all Convertible Senior Notes that remained outstanding.
For the years ended December 31, 2013, 2012 and 2011, the Company recorded $9.4 million, $33.5 million and $32.3
million, respectively, of interest expense relating to the Convertible Senior Notes, which had an effective interest rate of 6.75
percent.
Principal maturities. Principal maturities of long-term debt at December 31, 2013, are as follows (in thousands):
—
2014........................................................................................................................................................................... $
—
2015........................................................................................................................................................................... $
455,385
2016........................................................................................................................................................................... $
485,100
2017........................................................................................................................................................................... $
2018........................................................................................................................................................................... $
449,500
Thereafter .................................................................................................................................................................. $ 1,300,000
Interest expense. The following amounts have been incurred and charged to interest expense for the years ended December
31, 2013, 2012 and 2011:
Year Ended December 31,
2013
2012
2011
Cash payments for interest .......................................................................................... $
Amortization of issuance discounts ............................................................................
Amortization of net deferred hedge losses (a) ............................................................
Accretion of discount on postretirement benefit obligations ......................................
Amortization of capitalized loan fees .........................................................................
Net changes in accruals...............................................................................................
Interest incurred ..........................................................................................................
Less capitalized interest ..............................................................................................
Total interest expense.................................................................................................. $
182,126
11,423
349
193
5,260
(5,709)
193,642
(9,892)
183,750
(in thousands)
168,665
$
27,351
2,018
257
5,937
10,842
215,070
(10,848)
204,222
$
$
$
165,251
25,210
573
315
5,385
(1,768)
194,966
(13,362)
181,604
_______________
(a)
Includes interest rate derivative hedges of $1.7 million and $282 thousand for the periods ended December 31, 2012 and
2011, respectively, that were reclassified from AOCI - Hedging into earnings upon expiration (see Note E).
97
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
NOTE H. Incentive Plans
Retirement Plans
Deferred compensation retirement plan. In August 1997, the Compensation Committee of the Company's board of directors
(the "Board") approved a deferred compensation retirement plan for the officers and certain key employees of the Company. Each
officer and key employee is allowed to contribute up to 25 percent of their base salary and 100 percent of their annual bonus. The
Company will provide a matching contribution of 100 percent of the officer's and key employee's contribution limited to the first
ten percent of the officer's base salary and eight percent of the key employee's base salary. The Company's matching contribution
vests immediately. A trust fund has been established by the Company to accumulate the contributions made under this retirement
plan. The Company's matching contributions were $2.7 million, $2.4 million and $2.2 million for the years ended December 31,
2013, 2012 and 2011, respectively.
401(k) plan. The Pioneer Natural Resources USA, Inc. ("Pioneer USA," a wholly-owned subsidiary of the Company)
401(k) and Matching Plan (the "401(k) Plan") is a defined contribution plan established under the Internal Revenue Code
Section 401. All regular full-time and part-time employees of Pioneer USA are eligible to participate in the 401(k) Plan on the
first day of the month following their date of hire. Participants may contribute an amount up to 80 percent of their annual salary
into the 401(k) Plan. Matching contributions are made to the 401(k) Plan in cash by Pioneer USA in amounts equal to 200 percent
of a participant's contributions to the 401(k) Plan that are not in excess of five percent of the participant's base compensation (the
"Matching Contribution"). Each participant's account is credited with the participant's contributions, Matching Contributions and
allocations of the 401(k) Plan's earnings. Participants are fully vested in their account balances except for Matching Contributions
and their proportionate share of 401(k) Plan earnings attributable to Matching Contributions, which proportionately vest over a
four-year period that begins with the participant's date of hire. During the years ended December 31, 2013, 2012 and 2011, the
Company recognized compensation expense of $29.7 million, $24.7 million and $18.3 million, respectively, as a result of Matching
Contributions.
Stock-based compensation costs. In accordance with GAAP, the Company records stock-based compensation expense,
equal to the fair value of share-based payments, ratably over the vesting periods of the Long-Term Incentive Plan ("LTIP") awards,
the Pioneer Southwest Long-Term Incentive Plan ("Pioneer Southwest LTIP") awards, the Series B unit awards issued by Sendero
and for payments associated with the Company's Employee Stock Purchase Plan ("ESPP").
The following table reflects stock-based compensation expense recorded for each type of incentive award and the associated
income tax benefit for the years ended December 31, 2013, 2012 and 2011:
Year Ended December 31,
2013
2012
2011
Restricted stock-equity awards ................................................................................. $
Restricted stock-Liability Awards.............................................................................
Stock options (a) .......................................................................................................
Performance unit awards ..........................................................................................
Pioneer Southwest LTIP ...........................................................................................
Sendero Series B units ..............................................................................................
ESPP .........................................................................................................................
Total............................................................................................................................. $
Income tax benefit....................................................................................................... $
56,165
40,404
2,952
9,131
1,029
1,020
1,731
112,432
36,298
(in thousands)
48,876
$
22,419
4,110
6,162
1,098
982
2,437
86,084
27,901
$
$
$
$
$
32,861
10,882
2,936
4,500
761
1,020
125
53,085
22,084
_____________________
(a)
Cash proceeds received from stock option exercises during 2013, 2012 and 2011 amounted to $5.0 million, $3.1 million
and $619 thousand, respectively.
As of December 31, 2013, there was $146.3 million of unrecognized stock-based compensation expense related to unvested
share-based compensation plans, including $44.8 million attributable to Liability Awards. The stock-based compensation expense
98
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
will be recognized on a straight-line basis over the remaining vesting periods of the awards, which is a period of less than three
years on a weighted average basis.
Pioneer Long-Term Incentive Plan
In May 2006, the Company's stockholders approved the LTIP, which provides for the granting of various forms of awards,
including stock options, stock appreciation rights, performance units, restricted stock and restricted stock units to directors, officers
and employees of the Company. The LTIP provides for the issuance of 9.1 million shares pursuant to awards under the plan. The
shares to be delivered under the LTIP shall be made available from (i) authorized but unissued shares, (ii) shares held as treasury
stock or (iii) previously issued shares reacquired by the Company, including shares purchased on the open market.
The following table shows the number of shares available for issuance pursuant to awards under the Company's LTIP at
December 31, 2013:
Approved and authorized awards ............................................................................................................................
Awards issued after May 3, 2006 ............................................................................................................................
Awards available for future grant............................................................................................................................
9,100,000
(6,506,571)
2,593,429
Restricted stock awards. During 2013, the Company awarded 683,952 restricted shares or units of the Company's common
stock as compensation to directors, officers and employees of the Company (including 250,641 shares or units representing Liability
Awards). The Company's issued shares, as reflected in the consolidated balance sheets as of December 31, 2013, do not include
197,340 of issued, but unvested shares awarded under stock-based compensation plans that have voting rights.
The following table reflects the restricted stock award activity for the year ended December 31, 2013:
Outstanding at beginning of year ..............................................................
Shares granted.........................................................................................
Shares forfeited.......................................................................................
Shares vested ..........................................................................................
Outstanding at end of year ........................................................................
Equity Awards
Liability Awards
Number of
Shares
$
1,512,762
433,311
$
(80,150) $
(517,908) $
$
1,348,015
Weighted
Average Grant-
Date Fair
Value
96.22
134.58
116.50
70.22
117.09
Number of Shares
405,916
250,641
(35,813)
(198,362)
422,382
The weighted average grant-date fair value of restricted stock equity awards awarded during 2013, 2012 and 2011 was
$134.58, $113.02 and $97.52, respectively. The fair value of shares for which restrictions lapsed during 2013, 2012 and 2011 was
$67.7 million, $137.2 million and $98.6 million, respectively, based on the market price on the vesting date.
As of December 31, 2013 and 2012, accounts payable – due to affiliates in the accompanying consolidated balance sheet
includes $33.0 million and $18.8 million of liabilities attributable to the Liability Awards, representing the earned portion of the
fair value of the outstanding awards as of that date. The fair value of shares for which restrictions lapsed during 2013, 2012 and
2011 was $26.1 million, $14.2 million and $6.7 million respectively, based on the market price on the vesting date.
Stock option awards. Certain employees may be granted options to purchase shares of the Company's common stock with
an exercise price equal to the fair market value of Pioneer common stock on the date of grant. The fair value of stock option awards
is determined using the Black-Scholes option-pricing model. Option awards have a ten-year contract life. The expected life of an
option is estimated based on historical and expected exercise behavior. The volatility assumption was estimated based upon
expectations of volatility over the life of the option as measured by historical volatility. The risk-free interest rate was based on
the United States Treasury rate for a term commensurate with the expected life of the option. The dividend yield was based upon
a seven-year average dividend yield.
99
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The Company did not grant any stock options during the year ended December 31, 2013. The Company used the following
weighted-average assumptions to estimate the fair value of stock options granted during the years ended December 31, 2012 and
2011:
Expected option life - years .......................................................................................................
Volatility.....................................................................................................................................
Risk-free interest rate.................................................................................................................
Dividend yield............................................................................................................................
7.0
49.4%
1.5%
0.4%
7.0
47.6%
2.9%
0.4%
2012
2011
A summary of the Company's nonstatutory stock option awards activity for the year ended December 31, 2013 is presented
below:
Number
of Shares
Weighted
Average
Exercise Price
Weighted
Average
Remaining
Contractual
Life
(in years)
Aggregate
Intrinsic Value
(in thousands)
Outstanding at beginning of year..................................
Options expired and forfeited.....................................
Options exercised .......................................................
Outstanding and expected to vest, at end of year .........
$
467,486
(11,085) $
(166,474) $
$
289,927
Exercisable at end of year.............................................
115,290
$
59.63
106.90
29.88
74.90
26.74
6.80
5.48
$
$
31,651
18,139
The weighted average grant-date fair value of options awarded during 2012 and 2011 was $56.29 and $49.61, respectively,
using the Black-Scholes option-pricing model. The intrinsic value of options exercised during 2013, 2012 and 2011 was $20.5
million, $17.2 million and $1.5 million, respectively, based on the difference between the market price at the exercise date and the
option exercise price.
Performance unit awards. During 2013, 2012 and 2011, the Company awarded performance units to certain of the
Company's officers under the LTIP. The number of shares of common stock to be issued is determined by comparing the Company's
total shareholder return to the total shareholder return of a predetermined group of peer companies over the performance period.
The performance unit awards vest over a 34-month service period. The grant-date fair values per unit of the 2013, 2012 and 2011
performance unit awards are $189.23, $172.57 and $134.68, respectively, which amounts were determined using the Monte Carlo
simulation method and are being recognized as stock-based compensation expense ratably over the performance period. The Monte
Carlo simulation model utilizes multiple input variables that determine the probability of satisfying the market condition stipulated
in the award grant and calculates the fair value of the award. Expected volatilities utilized in the model were estimated using a
historical period consistent with the remaining performance period of approximately three years. The risk-free interest rate was
based on the United States Treasury rate for a term commensurate with the expected life of the grant. The Company used the
following assumptions to estimate the fair value of performance unit awards granted during 2013, 2012 and 2011:
Risk-free interest rate ...................................................
Range of volatilities .....................................................
2013
0.40%
30.4% - 42.9%
2012
0.40%
33.6% - 49.0%
2011
1.32%
50.2% - 84.1%
100
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The following table summarizes the performance unit activity for the year ended December 31, 2013:
Beginning performance unit awards.......................................................................................
Units granted ........................................................................................................................
Units forfeited ......................................................................................................................
Units vested (b) ....................................................................................................................
Ending performance unit awards ............................................................................................
Number of
Units (a)
Weighted Average
Grant-Date
Fair Value
$
91,370
$
94,917
(10,842) $
(40,969) $
$
134,476
154.53
189.23
172.02
134.68
183.66
_____________________
(a)
These amounts reflect the number of performance units granted. The actual payout of shares may be between zero percent
and 250 percent of the performance units granted depending upon the total shareholder return ranking of the Company
compared to peer companies at the vesting date.
(b) On December 31, 2013, the service period lapsed on 40,969 of these performance unit awards. The lapsed units earned 2.5
shares for each vested award representing 102,424 aggregate shares of common stock issued on January 2, 2014.
The fair value of shares for which restrictions lapsed during 2013, 2012 and 2011 was $18.9 million, $18.8 million and
$44.7 million, respectively, based on the market price on the vesting date.
Pioneer 2008 PSE Employee Long-Term Incentive Plan
In May 2008, the board of directors of the general partner (the "General Partner") of Pioneer Southwest adopted the Pioneer
Southwest 2008 Long-Term Incentive Plan ("Pioneer Southwest LTIP"), which provides for the granting of various forms of unit-
based awards. In connection with the Pioneer Southwest merger the Company has, effective as of December 17, 2013, assumed,
adopted and amended the Pioneer Southwest LTIP, and has changed the name of such plan to the Pioneer 2008 PSE Employee
Long-Term Incentive Plan ("PSE LTIP"), and has assumed all Pioneer Southwest obligations associated with the Pioneer Southwest
LTIP existing prior to its assumption and adoption by the Company. The Pioneer Southwest LTIP limits the number of awards
granted under the plan to 3.0 million common units of Pioneer Southwest. As of the date of the Pioneer Southwest merger,
2.9 million common units under the Pioneer Southwest LTIP were available to be awarded or remained outstanding (678,034
common shares of Pioneer based upon the Conversion Ratio) and are carried forward to the PSE LTIP. The only outstanding
awards under the PSE LTIP at the time of the Pioneer Southwest merger and immediately prior to the assumption and adoption of
the PSE LTIP by the Company were phantom units of Pioneer Southwest. All such outstanding phantom units were converted at
the effective time of the Pioneer Southwest merger based on the Conversion Ratio into restricted stock units of the Company,
subject to the vesting schedule determined by the grant under the Pioneer Southwest LTIP which is a three-year vesting period
from the date of grant. The common shares of Pioneer to be delivered under the PSE LTIP shall be made available from (i)
authorized but unissued shares, (ii) shares held as treasury stock or (iii) previously issued shares reacquired by the Company,
including shares purchased on the open market.
The following table shows the number of Pioneer common shares available for issuance pursuant to awards under the PSE
LTIP at December 31, 2013:
Awards approved and outstanding.........................................................................................................................
Awards issued under the PSE LTIP (a)..................................................................................................................
Awards available for future grant (b).....................................................................................................................
678,034
(23,192)
654,842
_____________________
(a)
Shares that represent outstanding awards originally granted under the Pioneer Southwest LTIP that have been assumed and
adopted by the Company in connection with, and that continue to be outstanding after, the Pioneer Southwest merger.
Shares that have not been issued and are not subject to outstanding awards granted under the Pioneer Southwest LTIP.
(b)
101
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The board of directors of the General Partner awarded 7,496 restricted common Pioneer Southwest units (1,743 shares of
Pioneer common stock based on the Conversion Ratio) in 2012, which vested in May 2013, and 6,812 units (1,584 shares of
Pioneer common stock based on the Conversion Ratio) in 2011, which vested in May 2012, as compensation to non-employee
directors of the General Partner under the Pioneer Southwest LTIP. There were no restricted common units awarded under the
Pioneer Southwest LTIP during 2013 and no awards outstanding at December 31, 2013.
The following table summarizes the activity of phantom unit awards issued under the Pioneer Southwest LTIP during 2013,
which were converted to restricted stock units of the Company under the PSE LTIP based upon the Conversion Ratio:
Outstanding awards at beginning of year.............................................................................................
Units granted .....................................................................................................................................
Lapse of restrictions ..........................................................................................................................
Outstanding awards at end of year.......................................................................................................
Phantom Unit Awards
Number of
Awards (a)
Weighted
Average
Grant-Date
Fair Value
$
23,865
7,492
$
(8,165) $
$
23,192
117.94
110.32
97.81
122.55
_____________________
(a)
Reflects the number of awards in Pioneer common stock after the Pioneer Southwest merger based upon the Conversion
Ratio.
The weighted average grant-date fair value of Pioneer Southwest restricted common units awarded during 2012 and 2011
was $114.75 and $126.24, respectively, based upon the Conversion Ratio. The fair value of common units for which restrictions
lapsed on the restricted common units during 2013, 2012 and 2011 was $200 thousand, $200 thousand and $342 thousand,
respectively, based on the market price at the vesting date.
The weighted average grant-date fair value of Pioneer Southwest phantom units awarded during 2013, 2012 and 2011 was
$110.32, $120.43 and $138.32, respectively, based upon the Conversion Ratio. The fair value of phantom units for which restrictions
lapsed during 2013 was $799 thousand.
Subsidiary Issuances of Unit-Based Compensation
During 2010, Sendero entered into restricted unit agreements with two key employees, granting 1,000 Series B units in
Sendero. The Series B unit awards had a grant date fair value of $5.1 million, vest ratably over a five year service period and do
not earn equity rights unless certain defined performance conditions are achieved by Sendero.
Employee Stock Purchase Plan
The Company has an ESPP that allows eligible employees to annually purchase the Company's common stock at a discounted
price. Officers of the Company are not eligible to participate in the ESPP. Contributions to the ESPP are limited to 15 percent of
an employee's pay (subject to certain ESPP limits) during the eight-month offering period (January 1 to August 31). Participants
in the ESPP purchase the Company's common stock at a price that is 15 percent below the closing sales price of the Company's
common stock on either the first day or the last day of each offering period, whichever closing sales price is lower.
The following table shows the number of shares available for issuance under the ESPP at December 31, 2013:
Approved and authorized shares ..............................................................................................................................
Shares issued ............................................................................................................................................................
Shares available for future issuance .........................................................................................................................
1,250,000
(734,972)
515,028
102
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
Postretirement Benefit Obligations
At December 31, 2013 and 2012, the Company had $7.6 million and $9.7 million, respectively, of unfunded accumulated
postretirement benefit obligations. These obligations are comprised of five unfunded plans, of which four relate to predecessor
entities that the Company acquired in prior years, and two funded plans that the Company assumed sponsorship of in conjunction
with the acquisition of Premier Silica. Other than the Company's retirement plan and the two legacy-Premier Silica plans, the
participants of these plans are not current employees of the Company. The unfunded plans had no assets as of December 31, 2013
or 2012.
NOTE I. Asset Retirement Obligations
The Company's asset retirement obligations primarily relate to the future plugging and abandonment of wells and related
facilities. Market risk premiums associated with asset retirement obligations are estimated to represent a component of the
Company's credit-adjusted risk-free rate that is utilized in the calculations of asset retirement obligations. The following table
summarizes the Company's asset retirement obligation activity during the years ended December 31, 2013, 2012 and 2011:
Beginning asset retirement obligations ....................................................................... $
Obligations assumed in acquisitions.........................................................................
New wells placed on production...............................................................................
Changes in estimates (a) ...........................................................................................
Obligations reclassified to liabilities held for sale....................................................
Disposition of wells ..................................................................................................
Obligations settled ....................................................................................................
Accretion of discount on continuing operations.......................................................
Accretion of discount from integrated services (b) ..................................................
Accretion of discount on discontinued operations....................................................
Ending asset retirement obligations ............................................................................ $
Year Ended December 31,
2013
2012
2011
197,754
—
5,775
7,939
(10,091)
(6,083)
(13,953)
11,862
14
831
194,048
(in thousands)
136,742
$
10,498
9,593
51,536
—
(2,536)
(18,066)
8,677
100
1,210
197,754
$
$
$
152,291
6
9,233
7,490
(29,892)
(448)
(12,880)
7,506
—
3,436
136,742
_____________________
(a)
The changes in the 2013, 2012 and 2011 estimates are primarily due to increases in abandonment cost estimates based on
recent actual costs incurred to abandon wells and declines in credit-adjusted risk-free discount rates used to value increases
in asset retirement obligations. The increases in 2013 and 2011 estimates were partially offset by higher commodity prices,
which had the effect of lengthening the economic life of certain wells and decreasing the present value of future retirement
obligations. The increase in the 2012 estimate was further impacted by declines in oil, NGL and gas prices used to calculate
proved reserves, which had the effect of shortening the economic life of certain wells and increasing the present value of
future retirement obligations.
(b) Accretion of discount from integrated services includes Premier Silica accretion expense, which is recorded as a reduction
in income from vertical integration services in interest and other income in the Company's accompanying consolidated
statements of operations. See Note M for more information about interest and other income.
As of December 31, 2013 and 2012, the current portions of the Company's asset retirement obligations were $19.3 million
and $13.3 million, respectively.
NOTE J. Commitments and Contingencies
Severance agreements. The Company has entered into severance and change in control agreements with its officers and
certain key employees. The current annual salaries for the officers and key employees covered under such agreements total $43.2
million.
Indemnifications. The Company has agreed to indemnify its directors and certain of its officers, employees and agents with
respect to claims and damages arising from acts or omissions taken in such capacity, as well as with respect to certain litigation.
103
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
Legal actions. The Company is party to various proceedings and claims incidental to its business. While many of these
matters involve inherent uncertainty, the Company believes that the amount of the liability, if any, ultimately incurred with respect
to such other 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.
Lawsuits filed in state and federal courts in Texas relating to the Pioneer Southwest merger. On May 15, 2013, David
Flecker, a purported unitholder of Pioneer Southwest, filed a class action petition on behalf of Pioneer Southwest's unitholders
and a derivative suit on behalf of Pioneer Southwest against the Company, Pioneer USA, the General Partner and the directors of
the General Partner, in the 134th Judicial District of Dallas County, Texas (the "Flecker Lawsuit"). A similar class action petition
and derivative suit was filed against the same defendants on May 20, 2013, in the 160th Judicial District of Dallas County, Texas,
by purported unitholder Vipul Patel (the "Patel Lawsuit"). On September 3, 2013, the court consolidated the Patel Lawsuit into
the Flecker Lawsuit (as consolidated, the "Texas State Court Lawsuit"), and the plaintiffs filed a consolidated derivative and class
action petition on September 5, 2013.
The Texas State Court Lawsuit alleges, among other things, that the consideration offered by the Company in the Pioneer
Southwest merger was unfair and inadequate and that, by pursuing a transaction that was the result of an allegedly conflicted and
unfair process, the defendants breached their duties under Pioneer Southwest's partnership agreement as well as the implied covenant
of good faith and fair dealing, and engaged in self-dealing. Specifically, the lawsuit alleges that the director defendants: (i) engaged
in self-dealing, failed to act in good faith toward Pioneer Southwest, and breached their duties owed to Pioneer Southwest; (ii)
failed to properly value Pioneer Southwest and its various assets and operations and ignored or failed to protect against the numerous
conflicts of interest arising out of the proposed transaction; and (iii) breached the implied covenant of good faith and fair dealing
by engaging in a flawed merger process. The Texas State Court Lawsuit also alleges that the Company, Pioneer USA and the
General Partner aided and abetted the director defendants in their purported breach of fiduciary duties. Based on these allegations,
the plaintiffs in the Texas State Court Lawsuit seek to have the Pioneer Southwest merger rescinded. The plaintiffs also seek money
damages and attorneys' fees. The defendants have filed a motion to dismiss the Texas State Court Lawsuit based on improper
forum.
In September 2013, representatives of the plaintiffs in the Texas State Court Lawsuit and the defendants entered into a
memorandum of understanding (the "Memorandum of Understanding") to settle the claims and allegations made in the lawsuit.
The Memorandum of Understanding provided the plaintiffs with a period of confirmatory discovery during which the plaintiffs
could confirm the fairness and reasonableness of the settlement contemplated by the Memorandum of Understanding. As part of
the consideration for the settlement, the Merger Agreement was amended to provide for contractual appraisal rights for the
unitholders. The parties to the Memorandum of Understanding agreed to use their reasonable best efforts to obtain the agreement
of any plaintiffs filing similar lawsuits to become party to the Memorandum of Understanding and the related settlement, and it
is a condition to the consummation of the final settlement that any such plaintiffs join the settlement or such similar lawsuits
otherwise be dismissed with prejudice prior to the final approval of the settlement.
On January 7, 2014, the defendants and representatives of the plaintiffs in the Texas State Court Lawsuit entered into a
stipulation of settlement (the "Stipulation of Settlement"). The Stipulation of Settlement provides for a full and complete discharge,
dismissal with prejudice, settlement and release of all claims, suits and causes of action by the plaintiffs (other than appraisal rights
under the Merger Agreement) against the defendants and their representatives arising out of or relating to the allegations made in
the Texas State Court Lawsuit and the Federal Lawsuits (as defined below), the Pioneer Southwest merger or any deliberations,
negotiations, disclosures, omissions, press releases, statements or misstatements in connection therewith, any fiduciary or other
obligations in respect of the merger or any alternative transaction or under Pioneer Southwest's partnership agreement, or any costs
and expenses associated with settlement other than as provided in the Stipulation of Settlement.
On January 11, 2014, the 134th Judicial District, Dallas County, Texas (the "Court") entered a Preliminary Approval Order
providing for, among other things, the scheduling of a settlement hearing to be held before the Court, George L. Allen, Sr. Courts
Building, 600 Commerce Street, 6th Floor West (Old), Dallas, TX 75202, on March 17, 2014, at 9:30 a.m; the certification, for
settlement purposes only, of a Class consisting of all persons who held Pioneer Southwest common units, either of record or
beneficially, at any time during the period from and including May 6, 2013 to and including December 17, 2013, the date of
consummation of the Pioneer Southwest merger, including any and all of their respective successors-in-interest, predecessors,
representatives, trustees, executors, administrators, heirs, assigns, or transferees, and any person or entity acting for or on behalf
of, or claiming under, any of them, and specifically including plaintiffs, but excluding defendants, their subsidiary companies,
affiliates, assigns, members of their immediate families, and the legal representatives, heirs, successors, or assigns of any such
excluded person. All proceedings relating to the allegations made in the Texas State Court Lawsuit other than with respect to the
104
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
settlement have been stayed, and the Court entered an injunction against the commencement or prosecution of any action by any
member of the Class asserting any of the claims subject to the settlement. There can be no assurance that a final settlement will
be approved.
Former lawsuits relating to the Pioneer Southwest merger that have been dismissed
United States District Court for the Northern District of Texas. On August 21, 2013, Allan H. Beverly, a purported unitholder,
filed a class action complaint against Pioneer Southwest, the Company, Pioneer USA, MergerCo and the directors of the General
Partner in the United States District Court for the Northern District of Texas (the "Beverly Lawsuit"). On September 13, 2013,
Douglas Shelton, another purported unitholder, filed a class action complaint against the same defendants in the Beverly Lawsuit
(as well as the General Partner) in the same court as the Beverly Lawsuit (the "Shelton Lawsuit" and with the Beverly Lawsuit,
the “Federal Lawsuits”). The Beverly Lawsuit alleged that the defendants breached their fiduciary duties by agreeing to the merger
by means of an unfair process and for an unfair price. Specifically, the lawsuit alleged that the director defendants: (i) failed to
maximize the value of Pioneer Southwest to its public unitholders and took steps to avoid competitive bidding; (ii) failed to properly
value Pioneer Southwest; and (iii) ignored or failed to protect against the numerous conflicts of interest arising out of the proposed
transaction. The Beverly Lawsuit also alleged that the Company, Pioneer USA and MergerCo aided and abetted the director
defendants in their purported breach of fiduciary duties. The Shelton Lawsuit made similar allegations to the Beverly Lawsuit,
specifically: (i) that the Company, as controlling unitholder, failed to fulfill its fiduciary duties in connection with the merger
because it purportedly could not establish that the proposed merger was the result of a fair process that would return a fair price
to the unaffiliated unitholders of Pioneer Southwest; (ii) that the director defendants breached their fiduciary duties by failing to
exercise due care and diligence in connection with the proposed merger because the proposed merger was purportedly not the
result of a fair process that will return a fair price to the unaffiliated unitholders; and (iii) that the non-director defendants aided
and abetted the director defendants in their purported breach of fiduciary duties. The plaintiffs in the Federal Lawsuits sought the
same remedies as the plaintiffs in the Texas State Court Lawsuit. The representatives of the plaintiffs in the Federal Lawsuits are
also parties to the Memorandum of Understanding. In accordance with the Memorandum of Understanding, the plaintiffs in the
Beverly Lawsuit voluntarily dismissed all claims in the lawsuit on October 15, 2013, and the plaintiffs in the Shelton Lawsuit
voluntarily dismissed all claims in the lawsuit on October 16, 2013.
Delaware Court of Chancery. On September 23, 2013, Patrick Wilson, another purported unitholder, filed a class action
petition on behalf of the unitholders against Pioneer USA, MergerCo, Pioneer Southwest, the General Partner and the directors of
the General Partner in the Court of Chancery of the State of Delaware (the "Wilson Lawsuit"). The Wilson Lawsuit alleged that
the director defendants breached their purported fiduciary obligations to the unitholders by engaging in a process that undervalued
Pioneer Southwest and which allegedly constituted gross negligence, recklessness, willful misconduct, bad faith or knowing
violations of law. Additionally, the Wilson Lawsuit alleged that the non-director defendants aided and abetted the purported breaches
of fiduciary duties of the director defendants. The Wilson Lawsuit sought the same remedies as the plaintiffs in the Texas State
Court Lawsuit and the Federal Lawsuits. The plaintiff in the Wilson Lawsuit voluntarily dismissed that action on January 2, 2014.
After participating in and receiving confirmatory discovery, the plaintiff in the Wilson Action has informed representatives of the
plaintiffs in the Texas State Court Lawsuit that he intends to participate as a class member in the settlement.
The Company cannot predict the outcome of these or any other lawsuits that might be filed subsequent to the date of the
filing of this Report, nor can the Company predict the amount of time and expense that will be required to resolve these lawsuits.
See Note C for a description of the Merger Agreement.
Obligations following divestitures. In April 2006, the Company provided the purchaser of its Argentine assets certain
indemnifications. The Company remains responsible for certain contingent liabilities related to such indemnifications, subject to
defined limitations, including matters of litigation, environmental contingencies, royalty obligations and income taxes. The
Company has also retained certain liabilities and indemnified buyers for certain matters in connection with other divestitures,
including the sale of its Canadian assets in 2007, the sale of Pioneer Tunisia in February 2011, the sale of Pioneer South Africa in
August 2012, the planned sale of Alaska in 2014 and in connection with sales of joint interests. The Company does not believe
that these obligations are probable of having a material impact on its liquidity, financial position or future results of operations.
Drilling commitments. The Company periodically enters into contractual arrangements under which the Company is
committed to expend funds to drill wells in the future. The Company also enters into agreements to secure drilling rig services,
which require the Company to make future minimum payments to the rig operators. The Company records drilling commitments
in the periods in which the well is drilled or rig services are performed.
105
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
Lease agreements. The Company leases equipment and office facilities under operating leases. Rent expense for the years
ended December 31, 2013, 2012 and 2011 were $57.9 million, $48.0 million and $35.2 million, respectively. These payments
include $9.8 million, $7.9 million and $5.7 million associated with discontinued operations for the years ended December 31,
2013, 2012 and 2011, respectively, which are included in earnings from discontinued operations, net of tax, in the accompanying
consolidated statements of operations.
Future minimum lease commitments under noncancelable operating leases at December 31, 2013 are as follows (in
thousands):
2014 ............................................................................................................................................................................... $ 25,305
2015 ............................................................................................................................................................................... $ 18,495
2016 ............................................................................................................................................................................... $ 16,135
2017 ............................................................................................................................................................................... $ 15,637
2018 ............................................................................................................................................................................... $ 15,418
Thereafter ...................................................................................................................................................................... $ 26,569
Gathering, processing, transportation and fractionation agreements. The Company from time to time enters into, and as
of December 31, 2013 is a party to, contractual commitments with midstream service companies and pipeline carriers for future
gathering, processing, transportation and fractionation. These commitments are normal and customary for the Company's business
activities. Future minimum gathering, processing, transportation and fractionation commitments at December 31, 2013 are as
follows (in thousands):
2014............................................................................................................................................................................ $
2015............................................................................................................................................................................ $
2016............................................................................................................................................................................ $
2017............................................................................................................................................................................ $
2018............................................................................................................................................................................ $
Thereafter................................................................................................................................................................... $
353,167
404,493
418,665
282,077
245,250
773,868
Certain future minimum gathering, processing, transportation and fractionation fees are based upon rates and tariffs subject
to change over the lives of the commitments. The above commitments include demand fees associated with volume delivery
commitments of up to 50,000 BOEPD through August 2017 that are related to the Company's Permian Basin operations. The
Company does not expect to be able to fulfill all of its short-term and long-term delivery obligations from projected production
of available reserves; consequently, the Company plans to purchase third party volumes to satisfy its commitment if it is economical
to do so; otherwise, it will pay demand fees for commitment shortfalls.
NOTE K. Related Party Transactions
The Company, through a wholly-owned subsidiary, (i) serves as operator of properties in which it and its affiliated
partnerships have an interest and (ii) owns a noncontrolling interest in its unconsolidated affiliate, EFS Midstream, which it
manages. Through these relationships, the Company is a party to transactions with the affiliated partnerships and EFS Midstream
that represent related party transactions.
Transactions with affiliated partnerships. The Company receives producing well overhead and other fees related to the
operation of the properties in which it and its affiliated partnerships have an interest. The affiliated partnerships also reimburse
the Company for their allocated share of general and administrative charges. Reimbursements of fees are recorded as reductions
to general and administrative expenses in the Company's consolidated statements of operations.
106
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The related party transactions with affiliated partnerships are summarized below for the years ended December 31, 2013,
2012 and 2011:
2013
Year Ended December 31,
2012
(in thousands)
2011
Receipt of lease operating and supervision charges in accordance with standard
industry operating agreements................................................................................. $
Reimbursement of general and administrative expenses ............................................ $
2,502
276
$
$
2,437
342
$
$
2,104
313
Transactions with EFS Midstream. The Company, through a wholly-owned subsidiary, (i) provides certain services as
the manager of EFS Midstream in accordance with a Master Services Agreement and (ii) is the operator of Eagle Ford Shale
properties for which EFS Midstream provides certain services under a Hydrocarbon Gathering and Handling Agreement (the
"HGH Agreement"). During 2013, the Company received $25.1 million in distributions from EFS Midstream.
Master Services Agreement. The terms of the Master Services Agreement provide that the Company will perform certain
manager services for EFS Midstream and be compensated by monthly fixed payments and variable payments attributable to
expenses incurred by employees whose time is substantially dedicated to EFS Midstream's business. During 2013, 2012 and 2011,
the Company received $3.0 million, $2.3 million and $2.2 million of fixed payments and $16.4 million, $11.8 million and $8.4
million of variable payments, respectively, from EFS Midstream. During 2013, the Company purchased other plant and equipment
from EFS Midstream totaling $2.8 million. The Company also paid $1.9 million to purchase rights of way from EFS Midstream
during 2011.
Hydrocarbon Gathering and Handling Agreement. During June 2010, the Company entered into the HGH Agreement with
EFS Midstream. In accordance with the terms of the HGH Agreement, EFS Midstream is obligated to construct certain equipment
and facilities capable of gathering, treating and transporting oil and gas production from the Eagle Ford Shale properties operated
by the Company. The HGH Agreement also obligates the Company and its Eagle Ford Shale working interest partners to use the
EFS Midstream gathering, treating and transportation equipment and facilities. In accordance with the terms of the HGH Agreement,
the Company paid EFS Midstream $81.3 million, $58.5 million and $21.3 million of gathering and treating fees during 2013, 2012
and 2011, respectively. Such amounts were expensed as oil and gas production costs in the accompanying consolidated statements
of operations.
NOTE L. Major Customers
The Company's share of oil and gas production is sold to various purchasers who must be prequalified under the Company's
credit risk policies and procedures. The Company records allowances for doubtful accounts based on the age of accounts receivables
and the financial condition of its purchasers and, depending on facts and circumstances, may require purchasers to provide collateral
or otherwise secure their accounts.
The following purchasers individually accounted for ten percent or more of the Company's consolidated oil, NGL and gas
revenues, including the revenues from discontinued operations, in at least one of the three years ended December 31, 2013:
Plains Marketing LP....................................................................................................
Enterprise Products Partners L.P.................................................................................
Occidental Energy Marketing Inc ...............................................................................
26%
12%
12%
25%
14%
13%
16%
12%
14%
The loss of any of these significant purchasers could have a material adverse effect on the ability of the Company to sell
its oil and gas production.
Year Ended December 31,
2012
2011
2013
107
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
NOTE M. Interest and Other Income
The following table provides the components of the Company's interest and other income during the years ended
December 31, 2013, 2012 and 2011:
Other income............................................................................................................... $
Equity interest in income of EFS Midstream..............................................................
Deferred compensation plan income...........................................................................
Interest income ............................................................................................................
Income (loss) from vertical integration services (a) ...................................................
Total interest and other income................................................................................... $
2013
$
Year Ended December 31,
2012
(in thousands)
5,382
$
2,183
1,872
1,465
(11,934)
(1,032) $
8,282
7,266
5,954
321
(4,862)
16,961
$
2011
9,125
1,925
1,657
697
15,978
29,382
______________________
(a)
Income (loss) from vertical integration services represent net margins that result from Company-provided fracture
stimulation, drilling and related service operations, which are ancillary to and supportive of the Company's oil and gas
joint operating activities, and do not represent intercompany transactions. For the three years ended December 31, 2013,
2012 and 2011, these net margins include $284.9 million, $247.8 million and $50.9 million of gross vertical integration
revenues, respectively and $289.8 million, $259.7 million and $34.9 million of total vertical integration costs and
expenses, respectively.
NOTE N. Other Expense
The following table provides the components of the Company's other expense during the years ended December 31, 2013,
2012 and 2011:
Year Ended December 31,
2013
2012
2011
Impairment of inventory and other property and equipment (a)................................. $
Transportation commitment charge (b).......................................................................
Other............................................................................................................................
Above market and idle drilling and well service equipment charges (c)....................
Contingency and environmental accrual adjustments.................................................
Terminated drilling rig contract charges (d)................................................................
Premier Silica acquisition costs ..................................................................................
Total other expense ..................................................................................................... $
61,812
39,121
16,386
9,771
9,277
1,019
—
137,386
(in thousands)
5,719
$
38,830
17,940
33,124
478
15,747
2,337
114,175
$
$
$
3,126
23,841
11,884
20,163
4,057
—
—
63,071
____________________
(a)
Represents charges of $36.3 million to reduce excess materials and supplies inventories to their market value and a charge
of $25.5 million to reduce the carrying value of Sendero to its estimated fair value. See Notes C and D for additional
information on the fair value of Sendero and material and supplies inventory, respectively.
Primarily represents firm transportation payments on excess pipeline capacity commitments.
Primarily represents expenses attributable to the portion of Pioneer's contracted drilling rig rates that were above market
rates and idle drilling rig and fracture stimulation fleet fees, neither of which were chargeable to joint operations.
Primarily represents charges to terminate rig contracts that were not required to meet planned drilling activities.
(b)
(c)
(d)
NOTE O. Income Taxes
The Company and its eligible subsidiaries file a consolidated United States federal income tax return. Certain subsidiaries
are not eligible to be included in the consolidated United States federal income tax return and separate provisions for income taxes
108
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
have been determined for these entities or groups of entities. The tax returns and the amount of taxable income or loss are subject
to examination by United States federal, state, local and foreign taxing authorities. The Company made current and estimated tax
payments of $12.4 million, $32.3 million and $22.3 million (net of tax refunds) during 2013, 2012 and 2011, respectively. These
payments and net refunds include tax payments related to Pioneer Tunisia's and Pioneer South Africa's operations of $9.8 million
and $12.2 million during 2012 and 2011, respectively.
The Company continually assesses both positive and negative evidence to determine whether it is more likely than not that
deferred tax assets can be realized prior to their expiration. Pioneer monitors Company-specific, oil and gas industry and worldwide
economic factors and assesses the likelihood that the Company's net operating loss carryforwards ("NOLs") and other deferred
tax attributes in the United States, state, local and foreign tax jurisdictions will be utilized prior to their expiration.
The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position
will be sustained upon examination by the taxing authorities, based upon the technical merits of the position. As of December 31,
2013, the Company had unrecognized tax benefits of $21.2 million resulting from net operating loss carryovers and alternative
minimum tax credits obtained from the acquisition of Premier Silica. The unrecognized tax benefit is recorded as a reduction of
the associated deferred tax asset and, if recognized, would affect the annual effective tax rate. The Company expects to resolve
uncertainties regarding the unrecognized tax benefit within twelve months of December 31, 2013. There were no unrecognized
tax benefits as of December 31, 2012.
With respect to income taxes, the Company's policy is to account for interest charges as interest expense and any penalties
as other expense in the consolidated statements of operations. The Company files income tax returns in the United States federal
jurisdiction, and various state and foreign jurisdictions. As of December 31, 2013, there are no proposed adjustments or uncertain
positions in any jurisdiction that would have a significant effect on the Company's future results of operations or financial position.
The Company's earliest open years in its key jurisdictions are as follows:
United States ....................................................................................................................................................................
Various U.S. states............................................................................................................................................................
South Africa......................................................................................................................................................................
2012
2009
2008
The Company's income tax (provision) benefit and amounts separately allocated were attributable to the following items
for the years ended December 31, 2013, 2012 and 2011:
Year Ended December 31,
2013
2012
2011
Income tax (provision) benefit from continuing operations ....................................... $
Income tax (provision) benefit from discontinued operations ....................................
Changes in goodwill - tax benefits related to stock-based compensation...................
Changes in stockholders' equity:
Net deferred hedge (loss) gain..................................................................................
Excess tax benefit related to stock-based compensation ..........................................
Tax benefit attributable to conversion of 2.875% senior convertible notes..............
Tax benefit attributable to 2013 merger with Pioneer Southwest.............................
Tax attributable to 2008 Pioneer Southwest initial public offering..........................
Tax attributable to 2009 and 2011 issuance of Pioneer Southwest common units...
Tax on Pioneer Southwest common units sold by the Company during 2011.........
211,775
250,882
—
—
17,639
38,415
200,091
—
—
—
(in thousands)
$ (290,488) $ (188,278)
(267,314)
40
182,437
—
(1,725)
58,486
—
—
(49,072)
—
—
8,407
31,087
—
—
—
(23,711)
(15,381)
109
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The Company's income tax (provision) benefit attributable to income from continuing operations consisted of the following
for the years ended December 31, 2013, 2012 and 2011:
Current:
U.S. federal ............................................................................................................... $
U.S. state...................................................................................................................
Foreign......................................................................................................................
Deferred:
U.S. federal ...............................................................................................................
U.S. state...................................................................................................................
Income tax (provision) benefit from continuing operations ....................................... $
2013
Year Ended December 31,
2012
(in thousands)
2011
(10,406) $
44
(237)
(10,599)
(5,575) $
1,316
—
(4,259)
—
(6,948)
—
(6,948)
201,060
21,314
222,374
211,775
(272,289)
(13,940)
(286,229)
(179,699)
(1,631)
(181,330)
$ (290,488) $ (188,278)
Reconciliations of the United States federal statutory tax rate to the Company's effective tax rate for income (loss) from
continuing operations are as follows for the years ended December 31, 2013, 2012 and 2011:
Year Ended December 31,
2013
2012
2011
Income (loss) from continuing operations before income taxes ................................. $ (561,719)
(38,865)
Less: Net income attributable to noncontrolling interests .........................................
Income (loss) from continuing operations attributable to common stockholders
(in thousands, except percentages)
$ 837,520
(50,537)
$ 596,068
(47,425)
before income taxes .............................................................................................
Federal statutory income tax rate ................................................................................
(Provision) benefit for federal income taxes...............................................................
State income tax (provision) benefit (net of federal tax) ............................................
Other............................................................................................................................
210,204
13,883
(12,312)
Income tax (provision) benefit from continuing operations ..................................... $ 211,775
(600,584)
35%
786,983
548,643
35%
(275,444)
(8,206)
(6,838)
$ (290,488)
35%
(192,025)
(5,576)
9,323
$ (188,278)
Effective income tax rate, excluding income attributable to the noncontrolling
interest..................................................................................................................
35%
37%
34%
110
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The tax effects of temporary differences that give rise to significant portions of the deferred tax assets and deferred tax
liabilities related to continuing operations are as follows as of December 31, 2013 and 2012:
Deferred tax assets:
Net operating loss carryforward (a) (b) ...................................................................................... $
Asset retirement obligations .......................................................................................................
Incentive plans ............................................................................................................................
Other ...........................................................................................................................................
Total deferred tax assets ...........................................................................................................
$
328,874
73,623
67,990
74,184
544,671
509,485
72,391
51,056
107,836
740,768
Deferred tax liabilities:
December 31,
2013
2012
(in thousands)
Oil and gas properties, principally due to differences in basis, depletion and the deduction of
intangible drilling costs for tax purposes.............................................................................
Other property and equipment, principally due to the deduction of bonus depreciation for tax
purposes...............................................................................................................................
Net deferred hedge gains ............................................................................................................
Other ...........................................................................................................................................
Total deferred tax liabilities......................................................................................................
(263,939)
(173,097)
(208,058)
(2,967,665)
Net deferred tax liability ............................................................................................................... $ (1,491,886) $ (2,226,897)
Reflected in accompanying consolidated balance sheets as:
(254,632)
(108,784)
(103,255)
(2,036,557)
(1,569,886)
(2,322,571)
Current deferred income tax liability.......................................................................................... $
Noncurrent deferred income tax liability....................................................................................
(86,481)
(2,140,416)
Total.......................................................................................................................................... $ (1,491,886) $ (2,226,897)
(1,472,717)
(19,169) $
____________________
(a) Net operating loss carryforwards as of December 31, 2013 consist of $917.4 million of U.S. federal NOLs which expire
primarily in 2032, $122.0 million of Colorado NOLs which expire between 2027 and 2033 and $50.6 million of Kansas
NOLs which expire between 2018 and 2023.
(b) Net operating loss carryforwards as of December 31, 2013 are net of a $1.5 million valuation allowance relating to $32
million of Kansas NOLs that the Company believes will more likely than not expire unutilized.
NOTE P. Net Income Per Share Attributable To Common Stockholders
In the calculation of basic net income (loss) per share attributable to common stockholders, participating securities are
allocated earnings based on actual dividend distributions received plus a proportionate share of undistributed net income attributable
to common stockholders, if any, after recognizing distributed earnings. The Company's participating securities do not participate
in undistributed net losses because they are not contractually obligated to do so. The computation of diluted net income (loss) per
share attributable to common stockholders reflects the potential dilution that could occur if securities or other contracts to issue
common stock that are dilutive were exercised or converted into common stock or resulted in the issuance of common stock that
would then share in the earnings of the Company. During periods in which the Company realizes a loss from continuing operations
attributable to common stockholders, securities or other contracts to issue common stock would not be dilutive to net loss per
share and conversion into common stock is assumed not to occur. Diluted net income (loss) per share is calculated under both the
two-class method and the treasury stock method and the more dilutive of the two calculations is presented.
The Company's basic net income (loss) per share attributable to common stockholders is computed as (i) net income (loss)
attributable to common stockholders, (ii) less participating share- and unit-based basic earnings (iii) divided by weighted average
basic shares outstanding. The Company's diluted net income (loss) per share attributable to common stockholders is computed as
(i) basic net income (loss) attributable to common stockholders, (ii) plus diluted adjustments to participating undistributed earnings
(iii) divided by weighted average diluted shares outstanding (excluding shares held in treasury).
111
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The following table is a reconciliation of the Company's net income (loss) attributable to common stockholders to basic net
income (loss) attributable to common stockholders and to diluted net income (loss) attributable to common stockholders for the
years ended December 31, 2013, 2012 and 2011:
Continuing
Operations
Year Ended December 31, 2013
Discontinued
Operations
(in thousands)
Total
Net loss attributable to common stockholders ............................................................ $ (388,809) $ (449,605) $ (838,414)
(130)
(838,544)
—
Diluted loss attributable to common stockholders ................................................. $ (388,869) $ (449,675) $ (838,544)
Participating basic earnings (a).................................................................................
Basic loss attributable to common stockholders ....................................................
Reallocation of participating earnings (a).................................................................
(70)
(449,675)
—
(60)
(388,869)
—
Year Ended December 31, 2012
Discontinued
Operations
Continuing
Operations
Total
Net income (loss) attributable to common stockholders............................................. $
Participating basic earnings (a).................................................................................
Basic income (loss) attributable to common stockholders.....................................
Reallocation of participating earnings (a).................................................................
Diluted income (loss) attributable to common stockholders.................................. $
Net income attributable to common stockholders....................................................... $
Participating basic earnings (a).................................................................................
Basic net income attributable to common stockholders.........................................
Reallocation of participating earnings (a).................................................................
Diluted income attributable to common stockholders............................................ $
496,495
(2,160)
494,335
115
494,450
(in thousands)
$ (304,210) $
(869)
(305,079)
46
$ (305,033) $
192,285
(3,029)
189,256
161
189,417
Year Ended December 31, 2011
Continuing
Operations
Discontinued
Operations
Total
360,365
(6,554)
353,811
166
353,977
(in thousands)
474,124
$
(8,624)
465,500
219
465,719
$
$
$
834,489
(15,178)
819,311
385
819,696
______________________
(a) Unvested restricted stock awards and Pioneer Southwest phantom unit awards (prior to the December 2013 Pioneer Southwest
merger) represent participating securities because they participate in nonforfeitable dividends or distributions with the
common equity owners of the Company or Pioneer Southwest, as applicable. Participating share- or unit-based earnings
represent the distributed and undistributed earnings of the Company attributable to the participating securities. Unvested
restricted stock awards and phantom unit awards do not participate in undistributed net losses as they are not contractually
obligated to do so.
112
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
December 31, 2013, 2012, and 2011
The following table is a reconciliation of basic weighted average common shares outstanding to diluted weighted average
common shares outstanding for the years ended December 31, 2013, 2012 and 2011:
2013 (a)
Year Ended December 31,
2012
(in thousands)
2011
Weighted average common shares outstanding:
Basic .........................................................................................................................
Dilutive common stock options (b) ..........................................................................
Contingently issuable—performance shares ............................................................
Convertible Senior Notes dilution (c).......................................................................
Diluted ......................................................................................................................
136,130
—
—
—
136,130
122,966
183
180
2,991
126,320
116,904
190
424
1,697
119,215
______________________
(a)
The following common share equivalents were excluded from the weighted average diluted shares for the year ended
December 31, 2013 because they would have been anti-dilutive to the loss recorded for the period: (i) 135,190 outstanding
options to purchase the Company's common stock, (ii) 200,360 common shares attributable to unvested performance awards
and (iii) 1,087,401 common shares related to the 2013 redemption of the Convertible Senior Notes, representing the weighted
average portion of the year that is not included in the basic weighted average common shares outstanding.
(b) Options to purchase 129,918 shares of the Company's common stock were excluded from the diluted income per share
calculations for the year ended December 31, 2012 because they would have been anti-dilutive to the calculation.
(c) Weighted average common shares outstanding have been increased to reflect the dilutive effect that would have resulted if
the Convertible Senior Notes had qualified for and been converted during the years ended December 31, 2012 and 2011,
respectively.
113
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
Oil & Gas Exploration and Production Activities
The Company has operations in one business and geographic segment, that being oil and gas exploration and
production. See the Company's accompanying statements of operations for information about results of operations for oil and
gas producing activities.
Capitalized Costs
December 31,
2013 (a)
2012
(in thousands)
Oil and gas properties:
Proved ............................................................................................................................................. $ 14,291,483
123,382
Unproved ........................................................................................................................................
14,414,865
Capitalized costs for oil and gas properties..................................................................................
(5,293,775)
Less accumulated depletion, depreciation and amortization ..........................................................
Net capitalized costs for oil and gas properties............................................................................ $ 9,121,090
$ 14,259,708
231,555
14,491,263
(4,412,913)
$ 10,078,350
_______________
(a)
Includes $885.3 million of proved property and $390.7 million of accumulated depletion, depreciation and amortization
related to Pioneer Alaska and the Barnett Shale field, which were classified as assets held for sale at December 31, 2013.
Costs Incurred for Oil and Gas Producing Activities (a)
Year Ended December 31,
2013
2012
2011
(in thousands)
Property acquisition costs:
Proved................................................................................................................ $
Unproved ...........................................................................................................
Exploration costs..................................................................................................
Development costs ...............................................................................................
Total costs incurred..............................................................................................
12,861
63,162
1,290,472
1,481,318
$ 2,847,813
$
16,962
140,515
966,828
1,881,459
$ 3,005,764
$
7,571
124,326
567,196
1,474,393
$ 2,173,486
_______________
(a)
The costs incurred for oil and gas producing activities includes the following amounts of asset retirement obligations:
Proved property acquisition costs ........................................................................ $
Exploration costs..................................................................................................
Development costs ...............................................................................................
Total ..................................................................................................................... $
Reserve Quantity Information
2013
— $
Year Ended December 31,
2012
(in thousands)
24
2,200
56,648
58,872
$
$
$
2,560
9,954
12,514
2011
6
1,222
18,274
19,502
The estimates of the Company's proved reserves as of December 31, 2013, 2012 and 2011 were based on evaluations
prepared by the Company's engineers and audited by independent petroleum engineers with respect to the Company's major
properties and prepared by the Company's engineers with respect to all other properties. Proved reserves were estimated in
accordance with guidelines established by the United States Securities and Exchange Commission (the "SEC") and the FASB,
which require that reserve estimates be prepared under existing economic and operating conditions based upon an average of the
first-day-of-the-month commodity price during the 12-month period ending on the balance sheet date with no provision for price
and cost escalations except by contractual arrangements.
114
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
Proved reserve quantity estimates are subject to numerous uncertainties inherent in the estimation of quantities of proved
reserves and in the projection of future rates of production and the timing of development expenditures. The accuracy of such
estimates is a function of the quality of available data and of engineering and geological interpretation and judgment. Results of
subsequent drilling, testing and production may cause either upward or downward revision of previous estimates. Further, the
volumes considered to be commercially recoverable fluctuate with changes in prices and operating costs. The Company emphasizes
that proved reserve estimates are inherently imprecise and that estimates of new discoveries are more imprecise than those of
currently producing oil and gas properties. Accordingly, these estimates are expected to change as additional information becomes
available in the future.
115
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1
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
Revisions of previous estimates. At December 31, 2013, revisions of previous estimates are comprised of 319 MMBOE of
proved undeveloped reserves that are no longer expected to be drilled and 11 MMBOE of negative revisions attributable to updated
performance profiles and cost estimates, partially offset by 30 MMBOE of positive price revisions. The Company continues to
shift its drilling activity in the Spraberry/Wolfcamp play in the Midland Basin of West Texas from vertical drilling to horizontal
drilling. The Company believes that replacing vertical drilling with horizontal drilling will enhance ultimate resource recoveries
and improve rates of return per dollar invested. As a result, Pioneer no longer expects to drill a significant number of its previously
recorded vertical proved undeveloped locations. Consequently, proved undeveloped reserves were reduced by 231 MMBOE
associated with vertical drilling locations in the Spraberry/Wolfcamp. This reduction in proved reserves is reflected in revisions
of previous estimates. Based on the limited horizontal drilling conducted by Pioneer to date in six Wolfcamp and Spraberry shale
intervals across Pioneer's acreage position in the Spraberry/Wolfcamp field, sufficient production and well control data is not yet
available to support the replacement of the vertical proved undeveloped reserves with horizontal proved undeveloped reserve
additions. Pioneer also removed an additional 88 MMBOE of proved undeveloped reserves that are primarily attributable to the
announced divestitures of Pioneer's Alaska and Barnett Shale Combo assets (45 MMBOE) and previously recorded gas wells that
are no longer expected to be drilled due to the reallocation of drilling capital to higher-rate-of-return oil wells. The December 31,
2013 NYMEX price used for oil and gas reserve preparation based upon SEC guidelines was $96.82 per barrel of oil and $3.67
per Mcf of gas, compared to $94.84 per barrel of oil and $2.76 per Mcf of gas at December 31, 2012.
At December 31, 2012, revisions of previous estimates are comprised of 82 MMBOE of negative price revisions and 27
MMBOE of negative revisions due to updated performance profiles and cost estimates. The December 31, 2012 NYMEX price
used for oil and gas reserve preparation based upon SEC guidelines was $94.84 per barrel of oil and $2.76 per Mcf of gas, compared
to $96.13 per barrel of oil and $4.12 per Mcf of gas at December 31, 2011.
At December 31, 2011, revisions of previous estimates were comprised of 28 MMBOE of negative price revisions and 10
MMBOE of negative revisions due to updated performance profiles and cost estimates. The December 31, 2011 NYMEX price
used for oil and gas reserve preparation based upon SEC guidelines increased $16.85 per barrel of oil and decreased $0.25 per
Mcf of gas from $79.28 per barrel of oil and $4.37 per Mcf of gas at December 31, 2010.
Extensions and discoveries. Extensions and discoveries at December 31, 2013, 2012 and 2011 are primarily comprised of
discoveries and extensions in the Wolfcamp, Strawn, Atoka and Mississippian horizons in the Spraberry field and discoveries in
the Eagle Ford Shale and Barnett Shale Combo plays.
Sales of minerals-in-place. Sales of minerals-in-place in 2013, 2012 and 2011 are primarily related to the divestment of 40
percent of the Company's interest in 207,000 net acres in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry
field in West Texas, Pioneer South Africa and Pioneer Tunisia, respectively. See Note C for additional information regarding the
Company's divestitures and discontinued operations.
Purchases of minerals-in-place. Purchases of minerals-in-place during all years are primarily attributable to acquisitions
in the Company's Spraberry field.
Improved recovery. Additions from improved recovery during 2012 and 2011 relate to recognizing secondary recovery
reserves attributable to waterflooding the Nuiqsut horizon of the Alaskan Oooguruk development project.
117
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
The following table provides the Company's proved developed and proved undeveloped reserves for the years ended
December 31, 2013, 2012 and 2011.
Proved Developed Reserves:
December 31, 2011...........................................................................
December 31, 2012...........................................................................
December 31, 2013...........................................................................
190,206
230,700
256,638
120,405
134,637
148,161
1,853,363
1,605,209
1,703,667
619,506
632,872
688,743
Oil
(MBBLs)
NGLs
(MBBLs)
Gas
(MMCF)
Total
(MBOE)
Proved Undeveloped Reserves:
December 31, 2011...........................................................................
December 31, 2012...........................................................................
December 31, 2013...........................................................................
239,799
256,138
85,467
90,630
97,939
37,261
677,675
592,271
202,674
443,375
452,789
156,507
Oil
(MBBLs)
NGLs
(MBBLs)
Gas
(MMCF)
Total
(MBOE)
The following table summarizes the Company's proved undeveloped reserves activity during the year ended December 31,
2013 (in MBOE).
Beginning proved undeveloped reserves..............................................................................................................
Revisions of previous estimates.........................................................................................................................
Extensions and discoveries ................................................................................................................................
Sales of minerals-in-place..................................................................................................................................
Transfers to proved developed...........................................................................................................................
Ending proved undeveloped reserves...................................................................................................................
452,789
(309,435)
79,711
(16,026)
(50,532)
156,507
As of December 31, 2013, the Company had 783 proved undeveloped well locations as compared to 3,810 and 4,599 at
December 31, 2012 and 2011, respectively. The Company has 26 proved undeveloped well locations (representing 2 MMBOE
of proved reserves) that are scheduled to be drilled more than five years from their original date of booking. All of these wells
are scheduled to be drilled within five years of the December 31, 2009 effective date of the Commission's Final Rule on the
Modernization of Oil and Gas Reporting.
The changes in proved undeveloped reserves during 2013 are comprised of the following items:
Revisions of previous estimates. Revisions of previous estimates are comprised of 319 MMBOE of proved undeveloped
reserves that are no longer expected to be drilled, partially offset by 8 MMBOE of positive revisions attributable to updated
performance profiles and cost estimates and 1 MMBOE of positive price revisions. As described in revisions of previous estimates
of total proved reserves, Pioneer no longer expects to drill a significant number of its previously recorded vertical proved
undeveloped locations. Consequently, proved undeveloped reserves were reduced by 231 MMBOE associated with vertical drilling
locations in the Spraberry/Wolfcamp. This reduction in proved reserves is reflected in revisions of previous estimates. Based on
the limited horizontal drilling conducted by Pioneer to date in six Wolfcamp and Spraberry shale intervals across Pioneer's acreage
position in the Spraberry/Wolfcamp field, sufficient production and well control data is not yet available to support the replacement
of the vertical proved undeveloped reserves with horizontal proved undeveloped reserve additions. Pioneer also removed an
additional 88 MMBOE of proved undeveloped reserves that are primarily attributable to the announced divestitures of Pioneer's
Alaska and Barnett Shale Combo assets (45 MMBOE) and previously recorded gas wells that are no longer expected to be drilled
due to the reallocation of drilling capital to higher-rate-of-return oil wells.
Extensions and discoveries. Extensions and discoveries are primarily comprised of extensions and discoveries in the
Wolfcamp, Strawn, Atoka and Mississippian horizons in the Spraberry field and discoveries in the Eagle Ford Shale.
Sales of minerals-in-place. Sales of minerals-in-place are primarily related to the divestment of a 40 percent interest in
207,000 net acres in the horizontal Wolfcamp Shale play in the southern portion of the Spraberry field in West Texas and sales in
the Barnett Shale Combo play.
118
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
Transfers to proved developed. Transfers to proved developed reserves represents those undeveloped proved reserves that
moved to proved developed as a result of development drilling during 2013. During 2013, the Company incurred $1.5 billion of
development costs and developed 11 percent of its proved undeveloped reserves. See the following table for the Company's firm
plans for future development expenditures.
Within the Spraberry field, the Company uses both public and proprietary geologic data to establish continuity of the
formation and its producing properties. This included seismic data and interpretations (2-D, 3-D and micro seismic); open hole
log information (both vertical and horizontally collected) and petrophysical analysis of the log data; mud logs; gas sample analysis;
drill cutting samples; measurements of total organic content; thermal maturity; sidewall cores and data measured from the
Company's internal core analysis facility. After the geologic area was shown to be continuous, statistical analysis of existing
producing wells was conducted to generate areas of reasonable certainty at distances from established production. As a result of
this analysis, proved undeveloped reserves for drilling locations within these areas of reasonable certainty were recorded during
2013.
While the Company expects, based on Management's Price Outlooks, that future operating cash flows will provide adequate
funding for future development of its proved undeveloped reserves over the next five years, it may also use any combination of
internally-generated cash flows, cash and cash equivalents on hand, availability under its credit facility, proceeds from the sale of
joint interests and nonstrategic assets or external financing sources to fund these and other capital expenditures, including
exploratory drilling and acquisitions. The following table represents the estimated timing and cash flows of developing the
Company's proved undeveloped reserves as of December 31, 2013 (dollars in thousands):
Year Ended December 31, (a)
2014......................................................................
2015......................................................................
2016......................................................................
2017......................................................................
2018......................................................................
Thereafter (b) .......................................................
Estimated
Future
Production
(MBOE)
4,076
12,974
13,569
13,831
10,956
101,101
156,507
Future Cash
Inflows
$
254,760
864,940
866,283
840,869
663,828
6,174,957
$ 9,665,637
Future
Production
Costs
$
40,458
129,438
143,693
149,559
121,608
1,785,314
$ 2,370,070
$
Future
Development
Costs
750,851
924,482
519,534
319,391
116,153
75,427
$ 2,705,838
Future Net
Cash Flows
$
(536,549)
(188,980)
203,056
371,919
426,067
4,314,216
$ 4,589,729
______________________
(a)
Production and cash flows represent the drilling results from the respective year plus the incremental effects of proved
undeveloped drilling.
The $75.4 million of future development costs includes (i) $26.5 million of completion costs forecasted after 2018 and
(ii) $48.9 million of net abandonment costs in future years.
(b)
119
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows is computed by applying commodity prices used in determining
proved reserves (with consideration of price changes only to the extent provided by contractual arrangements) to the estimated
future production of proved reserves less estimated future expenditures (based on year-end estimated costs) to be incurred in
developing and producing the proved reserves, discounted using a rate of ten percent per year to reflect the estimated timing of
the future cash flows. Future income taxes are calculated by comparing undiscounted future cash flows to the tax basis of oil and
gas properties plus available carryforwards and credits and applying the current tax rates to the difference. The discounted future
cash flow estimates do not include the effects of the Company's commodity derivative contracts. Utilizing the first-day-of-the-
month commodity prices during the 12-month period ending on December 31, 2013, held constant over each derivative contract's
term, the net present value of the Company's derivative contracts discounted at ten percent was a liability of $47.7 million at
December 31, 2013.
Discounted future cash flow estimates like those shown below are not intended to represent estimates of the fair value of
oil and gas properties. Estimates of fair value should also consider probable and possible reserves, anticipated future commodity
prices, interest rates, changes in development and production costs and risks associated with future production. Because of these
and other considerations, any estimate of fair value is necessarily subjective and imprecise.
The following tables provide the standardized measure of discounted future cash flows as of December 31, 2013, 2012 and
2011, as well as a rollforward in total for each respective year:
December 31,
2013
2012
2011
(in thousands)
Oil and gas producing activities:
Future cash inflows .......................................................................................... $ 43,542,036
(20,044,053)
Future production costs....................................................................................
(4,101,795)
Future development costs (a) ...........................................................................
(4,954,730)
Future income tax expense...............................................................................
14,441,458
(7,140,847)
Standardized measure of discounted future cash flows (b)................................ $ 7,300,611
10% annual discount factor..............................................................................
$ 56,692,889
(23,977,062)
(9,803,698)
(6,600,395)
16,311,734
(9,958,336)
$ 6,353,398
$ 59,220,357
(21,154,016)
(8,466,407)
(9,581,515)
20,018,419
(12,205,396)
$ 7,813,023
__________________
(a)
Includes $815.4 million, $840.0 million and $785.0 million of undiscounted future asset retirement expenditures estimated
as of December 31, 2013, 2012 and 2011, respectively, using current estimates of future abandonment costs. See Note I for
additional information regarding the Company's discounted asset retirement obligations.
Includes $282.6 million and $378.6 million attributable to a 48 percent noncontrolling interest in Pioneer Southwest for
2012 and 2011, respectively.
(b)
120
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
Changes in Standardized Measure of Discounted Future Net Cash Flows
2013
Year Ended December 31,
2012
(in thousands)
2011
Oil and gas sales, net of production costs ............................................................. $ (2,499,851) $ (2,038,353) $ (1,755,153)
Revisions of previous estimates:
Net changes in prices and production costs........................................................
Changes in future development costs .................................................................
Revisions in quantities........................................................................................
Accretion of discount..........................................................................................
Changes in production rates, timing and other (a)..............................................
Extensions, discoveries and improved recovery ...................................................
Development costs incurred during the period .....................................................
Sales of minerals-in-place .....................................................................................
Purchases of minerals-in-place .............................................................................
Change in present value of future net revenues ....................................................
Net change in present value of future income taxes .............................................
(1,772,269)
1,339,923
(2,675,762)
832,351
2,453,933
2,248,416
1,254,832
(338,261)
3,834
847,146
100,067
947,213
Balance, beginning of year....................................................................................
6,353,398
Balance, end of year.............................................................................................. $ 7,300,611
(3,069,880)
(1,649,417)
(1,126,865)
1,109,022
743,212
1,731,465
1,399,731
(38,106)
172,474
(2,766,717)
1,307,092
(1,459,625)
7,813,023
$ 6,353,398
2,615,481
(1,280,213)
(442,120)
800,468
1,660,419
1,676,866
750,268
(1,021,513)
81,036
3,085,539
(684,525)
2,401,014
5,412,009
$ 7,813,023
__________________
(a)
The Company's changes in Standardized Measure attributable to production rates, timing and other primarily represent
changes in the Company's estimates of when proved reserve quantities will be realized. During the twelve months ended
December 31, 2013, the Company's undiscounted future net cash flows from proved reserves declined; however, the timing
of the recovery of the future net cash flows accelerated, partially due to the aforementioned removal of lower-return-on-
investment vertical well locations, resulting in an increase in Standardized Measure. During the twelve months ended
December 31, 2012 and 2011, the Company increased its development drilling capital plans, which had the effect of
accelerating the estimated timing of development and realization of undeveloped proved reserves.
121
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
Selected Quarterly Financial Results
The following table provides selected quarterly financial results for the years ended December 31, 2013 and 2012, with
adjustments to conform to the annual results:
Quarter
First
Second
Third
Fourth
(in thousands, except per share data)
Year Ended December 31, 2013:
Oil and gas revenues:
As reported ..................................................................................................
Adjustment for discontinued operations...................................................
As Adjusted............................................................................................
Total revenues and other income: (a)
As reported ..................................................................................................
Adjustment for derivative losses, net .......................................................
Adjustment for sales of purchased oil and gas (b)....................................
Adjustment for discontinued operations...................................................
As Adjusted............................................................................................
Total costs and expenses: (c)
As reported ..................................................................................................
Adjustment for derivative losses, net (a) ..................................................
Adjustment for purchased oil and gas (b).................................................
Adjustment for other expense (b) .............................................................
Adjustment for discontinued operations...................................................
As Adjusted............................................................................................
Net income (loss) ...........................................................................................
Net income (loss) attributable to common stockholders................................
Net income (loss) attributable to common stockholders per share:
Basic ............................................................................................................
Diluted.........................................................................................................
Year Ended December 31, 2012:
Oil and gas revenues:
As reported .................................................................................................
Adjustment for discontinued operations ..................................................
As Adjusted ...........................................................................................
Total revenues and other income: (a)
As reported .................................................................................................
Adjustment for derivative gains, net........................................................
Adjustment for sales of purchased oil and gas (b)...................................
Adjustment for discontinued operations ..................................................
As Adjusted ...........................................................................................
Total costs and expenses:
As reported .................................................................................................
Adjustment for derivative gains, net........................................................
Adjustment for purchased oil and gas (b) ................................................
Adjustment for other expense (b) ............................................................
Adjustment for discontinued operations ..................................................
As Adjusted ...........................................................................................
Net income (loss) ..........................................................................................
Net income (loss) attributable to common stockholders...............................
Net income (loss) attributable to common stockholders per share: ..............
Basic ...........................................................................................................
Diluted ........................................................................................................
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
787,855
(59,354)
728,501
$
$
845,136
(63,938)
781,198
831,587
(42,243)
55,905
(78,936)
766,313
$ 1,181,727
—
56,076
(78,589)
$ 1,159,214
663,058
(42,243)
55,727
178
(53,222)
623,498
108,735
100,663
0.77
0.75
718,956
(54,908)
664,048
784,460
91,750
20,052
(66,753)
829,509
456,494
91,750
19,168
884
(71,473)
496,823
220,958
214,619
$
$
$
$
$
$
$
$
$
$
638,224
—
54,984
1,092
(58,621)
635,679
351,474
337,263
2.42
2.40
641,737
(61,719)
580,018
917,975
—
20,095
(61,719)
876,351
$
$ 1,014,615
—
20,294
(199)
(507,161)
527,549
$
(39,537) $
(70,392) $
$
$
$
908,757
(72,699)
836,058
826,822
—
82,238
(85,860)
823,200
670,042
—
85,424
(3,186)
(58,583)
693,697
98,547
91,125
0.65
0.65
716,327
(59,461)
656,866
615,437
—
29,891
(75,630)
569,698
615,419
—
29,687
204
(44,693)
600,617
21,699
19,224
1.73
1.68
$
$
(0.57) $
(0.57) $
0.15
0.15
$
$
$
$
809,939
—
809,939
970,783
—
—
—
970,783
$ 2,328,355
—
—
—
—
2,328,355
$ (1,358,305)
$ (1,367,465)
$
$
$
$
$
$
$
$
$
$
$
$
(9.82)
(9.82)
734,640
(60,261)
674,379
818,686
—
52,055
(73,778)
796,963
769,973
—
51,259
796
(212,016)
610,012
39,702
28,834
0.23
0.22
_____________________
(a)
The Company's total revenues and other income include net derivative gains of $144.4 million and $4.3 million during the second and
fourth quarters of 2013, respectively, and net derivative losses of $42.2 million and $102.5 million during the first and third quarters of
2013, respectively. During 2012, the Company's total revenues and other income included net derivative gains of $91.8 million, $275.8
million and $86.7 million during the first, second and fourth quarters, respectively, and net derivative losses of $124.0 million during
the third quarter.
122
PIONEER NATURAL RESOURCES COMPANY
UNAUDITED SUPPLEMENTARY INFORMATION
December 31, 2013, 2012 and 2011
(b)
(c)
Includes the revision to the presentation of purchases and sales of third-party oil and gas from other expense to gross sales of purchased
oil and gas and costs of purchased oil and gas. Revenues and costs from the purchase and sale transactions are presented on a gross basis
as the Company acts as a principal in the transactions by assuming the risks and rewards of ownership, including credit risk, of the oil
and gas purchased and assumes responsibility for the delivery of the oil and gas volumes sold. See Note B for additional information
on purchases and sales of third-party oil and gas.
During the fourth quarter of 2013, the Company's total costs and expenses include (i) charges of $1.5 billion to impair the carrying value
of proved gas properties in the Raton field and (ii) charges of $48.7 million to impair the carrying value of excess materials inventory
and other property and equipment held for sale.
123
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of disclosure controls and procedures. The Company's management, with the participation of its principal
executive officer and principal financial officer, have evaluated, as required by Rule 13a-15(b) under the Securities Exchange Act
of 1934 ("the Exchange Act"), the effectiveness of the Company's disclosure controls and procedures (as defined in Exchange Act
Rule 13a-15(e)) as of the end of the period covered by this Report. Based on that evaluation, the principal executive officer and
principal financial officer concluded that the Company's disclosure controls and procedures were effective, as of the end of the
period covered by this Report, in ensuring that information required to be disclosed by the Company in the reports that it files or
submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC's
rules and forms, including that such information is accumulated and communicated to the Company's management, including the
principal executive officer and principal financial officer, to allow timely decisions regarding required disclosure.
Changes in internal control over financial reporting. There have been no changes in the Company's internal control over
financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the three months ended December
31, 2013 that have materially affected, or are reasonably likely to materially affect, the Company's internal control over financial
reporting.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
The management of the Company is responsible for establishing and maintaining adequate internal control over financial
reporting. The Company's internal control over financial reporting is a process designed by or under the supervision of the
Company's principal executive officer and principal financial officer and effected by the Board, management and other personnel
to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the Company's financial
statements for external purposes in accordance with generally accepted accounting principles.
The Company's management, with the participation of its principal executive officer and principal financial officer assessed
the effectiveness, as of December 31, 2013, of the Company's internal control over financial reporting based on the criteria for
effective internal control over financial reporting established in "Internal Control — Integrated Framework (1992)," issued by the
Committee of Sponsoring Organizations of the Treadway Commission. Based on the assessment, management determined that
the Company maintained effective internal control over financial reporting at a reasonable assurance level as of December 31,
2013, based on those criteria.
Ernst & Young LLP, the independent registered public accounting firm that audited the consolidated financial statements
of the Company included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company's
internal control over financial reporting as of December 31, 2013. The report, which expresses an unqualified opinion on the
effectiveness of the Company's internal control over financial reporting as of December 31, 2013, is included in this Item under
the heading "Report of Independent Registered Public Accounting Firm."
124
REPORT OF INDEPENDENT REGISTERED PUBLIC
ACCOUNTING FIRM
The Board of Directors and Stockholders of
Pioneer Natural Resources Company
We have audited Pioneer Natural Resources Company's (the "Company") internal control over financial reporting as of
December 31, 2013, based on criteria established in Internal Control—Integrated Framework issued by the Committee of
Sponsoring Organizations of the Treadway Commission (1992 framework) (the COSO criteria). Pioneer Natural Resources
Company's management is responsible for maintaining effective internal control over financial reporting, and for its assessment
of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal
Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's internal control over financial
reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United
States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal
control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal
control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in
the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that
(1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions
of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the
company are being made only in accordance with authorizations of management and directors of the company; and (3) provide
reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's
assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because
of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, Pioneer Natural Resources Company maintained, in all material respects, effective internal control over
financial reporting as of December 31, 2013, based on the COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States),
the consolidated balance sheets of Pioneer Natural Resources Company as of December 31, 2013 and 2012 and the related
consolidated statements of operations, comprehensive income (loss), equity and cash flows for each of the three years in the period
ended December 31, 2013, and our report dated February 26, 2014 expressed an unqualified opinion thereon.
/s/ Ernst & Young LLP
Dallas, Texas
February 26, 2014
125
ITEM 9B. OTHER INFORMATION
None.
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required in response to this Item will be set forth in the Company's definitive proxy statement for the
annual meeting of stockholders to be held during May 2014 and is incorporated herein by reference.
ITEM 11.
EXECUTIVE COMPENSATION
The information required in response to this Item will be set forth in the Company's definitive proxy statement for the
annual meeting of stockholders to be held during May 2014 and is incorporated herein by reference.
ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS
Securities Authorized for Issuance under Equity Compensation Plans
The following table summarizes information about the Company's equity compensation plans as of December 31, 2013:
Number of securities
to be issued upon
exercise of
outstanding options,
warrants and rights (a)
Weighted-average
exercise price of
outstanding
options, warrants
and rights
Number of securities
remaining
available for future
issuance under equity
compensation
plans (excluding
securities reflected in
first column)
Equity compensation plans approved by security holders:
Pioneer Natural Resources Company:
2006 Long-Term Incentive Plan (b)(c) .........................
Long-Term Incentive Plan.............................................
Employee Stock Purchase Plan (d) ...............................
Equity compensation plans not approved by security
holders (e)........................................................................
Total: ..................................................................................
115,290
—
—
—
115,290
$
$
26.74
—
—
—
26.74
2,593,429
—
515,028
654,842
3,763,299
_______________________
(a)
(b)
(c)
(d)
There are no outstanding warrants or equity rights awarded under the Company's equity compensation plans. The securities
listed do not include restricted stock awarded under the Company's previous Long-Term Incentive Plan and the Company's
2006 Long-Term Incentive Plan.
In May 2006, the stockholders of the Company approved the 2006 Long-Term Incentive Plan, which provided for the
issuance of up to 9.1 million awards, as was supplementally approved by the stockholders of the Company during May
2009. Awards under the 2006 Long-Term Incentive Plan can be in the form of stock options, stock appreciation rights,
performance units, restricted stock and restricted stock units. No additional awards may be made under the prior Long-
Term Incentive Plan.
The number of securities remaining for future issuance has been reduced by the maximum number of shares that could be
issued pursuant to outstanding grants of performance units at December 31, 2013.
The number of remaining securities available for future issuance under the Company's Employee Stock Purchase Plan is
based on the original authorized issuance of 750,000 shares plus an additional 500,000 shares supplementally approved
less 734,972 cumulative shares issued through December 31, 2013. See Note H of Notes to Consolidated Financial Statements
included in "Item 8. Financial Statements and Supplementary Data" for a description of each of the Company's equity
compensation plans.
126
(e)
These represent awards available for issuance under the Pioneer Southwest 2008 Long-Term Incentive Plan, which was
assumed by the Company as part of the Pioneer Southwest merger.
The remaining information required in response to this Item will be set forth in the Company's definitive proxy statement
for the annual meeting of stockholders to be held during May 2014 and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required in response to this Item will be set forth in the Company's definitive proxy statement for the
annual meeting of stockholders to be held during May 2014 and is incorporated herein by reference.
ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required in response to this Item will be set forth in the Company's definitive proxy statement for the
annual meeting of stockholders to be held during May 2014 and is incorporated herein by reference.
PART IV
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a) Listing of Financial Statements
Financial Statements
The following consolidated financial statements of the Company are included in "Item 8. Financial Statements and
Supplementary Data":
• Report of Independent Registered Pubic Accounting Firm
• Consolidated Balance Sheets as of December 31, 2013 and 2012
• Consolidated Statements of Operations for the Years Ended December 31, 2013, 2012 and 2011
• Consolidated Statements of Comprehensive Income (Loss) for the Years Ended December 31, 2013, 2012 and 2011
• Consolidated Statements of Stockholders' Equity for the Years Ended December 31, 2013, 2012 and 2011
• Consolidated Statements of Cash Flows for the Years Ended December 31, 2013, 2012 and 2011
• Notes to Consolidated Financial Statements
• Unaudited Supplementary Information
(b) Exhibits
The exhibits to this Report that are required to be filed pursuant to Item 15(b) are included in the Company's Form 10-K
filed with the SEC on February 26, 2014.
(c)
Financial Statement Schedules
No financial statement schedules are required to be filed as part of this Report or they are inapplicable.
127
Shareholder Information
Stock Exchange Listing – Common Stock
Information Requests
New York Stock Exchange: PXD
To receive additional copies of the Annual
Corporate Information
Pioneer Natural Resources Company
5205 N. O’Connor Blvd., Suite 200
Irving, TX 75039
(972) 444-9001
www.pxd.com
Stock Transfer Agent and Registrar
Communication concerning the transfer
or exchange of shares, dividends, lost
Report on Form 10-K as filed with the SEC
or to obtain other Pioneer publications,
please contact:
Pioneer Natural Resources Company
Investor Relations
5205 N. O’Connor Blvd., Suite 200
Irving, TX 75039
(972) 969-3583
Email: ir@pxd.com
certificates or change of address should
Investor Relations/Media Contact
be directed to:
Continental Stock Transfer & Trust Company
17 Battery Place, 8th Floor
New York, NY 10004
(888) 509-5586
www.continentalstock.com
Email: pioneer@continentalstock.com
Annual Meeting
The Annual Meeting of stockholders will be
held at 5205 N. O’Connor Blvd., Suite 250,
Irving, Texas 75039, on Wednesday, May 28,
2014, at 9:00 a.m. Central Time.
Shareholders, portfolio managers, brokers
and securities analysts seeking information
concerning Pioneer’s operations or financial
results are encouraged to contact Frank
Hopkins, Senior Vice President, Investor
Relations at (972) 444-9001. Media inquiries
should be directed to Susan Spratlen, Vice
President, Communication at (972) 444-9001.
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Pioneer Natural Resources Company
5205 N. O’Connor Blvd.
Suite 200
Irving, Texas 75039
(972) 444-9001
NYSE: PXD
www.pxd.com
BEYOND EXPECTATIONS