UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
/ x / QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended March 31, 2005
or
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from _______ to ________
Commission File Number: 1-13245
PIONEER NATURAL RESOURCES COMPANY
------------------------------------------------------
(Exact name of Registrant as specified in its charter)
Delaware 75-2702753
----------------------------------------- -------------------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)
5205 N. O'Connor Blvd., Suite 900, Irving, Texas 75039
- ------------------------------------------------ ----------
(Address of principal executive offices) (Zip Code)
(972) 444-9001
----------------------------------------------------
(Registrant's telephone number, including area code)
Not applicable
----------------------------------------------------
(Former name, former address and former fiscal year,
if changed since last report)
Indicate by check mark whether the Registrant (1) has filed all reports required
to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during
the preceding 12 months (or for such shorter period that the Registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days.
Yes / x / No / /
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act).
Yes / x / No / /
Number of shares of Common Stock outstanding as of May 2, 2005...... 143,985,774
PIONEER NATURAL RESOURCES COMPANY
TABLE OF CONTENTS
Page
Definitions of Oil and Gas Terms and Conventions Used Herein............. 3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2005 and
December 31, 2004...................................... 4
Consolidated Statements of Operations for the
three months ended March 31, 2005 and 2004............. 6
Consolidated Statement of Stockholders' Equity for
the three months ended March 31, 2005.................. 7
Consolidated Statements of Cash Flows for the
three months ended March 31, 2005 and 2004............. 8
Consolidated Statements of Comprehensive Income (Loss)
for the three months ended March 31, 2005 and 2004..... 9
Notes to Consolidated Financial Statements................ 10
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations.................... 27
Item 3. Quantitative and Qualitative Disclosures About
Market Risk............................................ 38
Item 4. Controls and Procedures................................... 40
PART II. OTHER INFORMATION
Item 1. Legal Proceedings......................................... 41
Item 2. Unregistered Sales of Equity Securities and
Use of Proceeds........................................ 41
Item 6. Exhibits.................................................. 42
Signatures .......................................................... 43
Exhibit Index .......................................................... 44
Cautionary Statement Concerning Forward-Looking Statements
The information included in this document includes 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 ("Pioneer" or the
"Company") are subject to a number of risks and uncertainties that may cause the
Company's actual results in future periods to differ materially from the
forward-looking statements. These risks and uncertainties include, among other
things, volatility of oil and gas prices, product supply and demand,
competition, government regulation or action, international operations and
associated international political and economic instability, litigation, the
costs and results of drilling and operations, the Company's ability to replace
reserves, implement its business plans, or complete its development projects as
scheduled, access to and cost of capital, uncertainties about estimates of
reserves, quality of technical data, environmental and weather risks, acts of
war or terrorism. These and other risks are described in the Company's 2004
Annual Report on Form 10-K, as amended, and other filings with the SEC.
2
Definitions of Oil and Gas Terms and Conventions Used Herein
Within this Report, the following oil and gas terms and conventions have
specific meanings:
o "Bbl" means a standard barrel containing 42 United States gallons.
o "Bcf" means billion cubic feet.
o "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 6.0 Mcf of gas to 1.0 Bbl of oil or
natural gas liquid.
o "BOEPD" means BOE per day.
o "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.
o "LIBOR" means London Interbank Offered Rate, which is a market rate of
interest.
o "Mcf" means one thousand cubic feet and is a measure of natural gas
volume.
o "MMBbl" means one million Bbls.
o "MMBOE" means one million BOEs.
o "MMBtu" means one million Btus.
o "NGL" means natural gas liquid.
o "NYMEX" means the New York Mercantile Exchange.
o "proved reserves" mean the estimated quantities of crude oil, natural
gas, and natural gas liquids which geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years
from known reservoirs under existing economic and operating conditions,
i.e., prices and costs as of the date the estimate is made. Prices
include consideration of changes in existing prices provided only by
contractual arrangements, but not on escalations based upon future
conditions.
(i) Reservoirs are considered proved if economic producibility is
supported by either actual production or conclusive formation test. The
area of a reservoir considered proved includes (A) that portion
delineated by drilling and defined by gas-oil and/or oil-water
contacts, if any; and (B) the immediately adjoining portions not yet
drilled, but which can be reasonably judged as economically productive
on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural
occurrence of hydrocarbons controls the lower proved limit of the
reservoir.
(ii) Reserves which can be produced economically through
application of improved recovery techniques (such as fluid injection)
are included in the "proved" classification when successful testing by
a pilot project, or the operation of an installed program in the
reservoir, provides support for the engineering analysis on which the
project or program was based.
(iii) Estimates of proved reserves do not include the following:
(A) oil that may become available from known reservoirs but is
classified separately as "indicated additional reserves"; (B) crude
oil, natural gas, and natural gas liquids, the recovery of which is
subject to reasonable doubt because of uncertainty as to geology,
reservoir characteristics, or economic factors; (C) crude oil, natural
gas, and natural gas liquids, that may occur in undrilled prospects;
and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
o "SEC" means the United States Securities and Exchange Commission.
o 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.
o Unless otherwise indicated, all currency amounts are expressed in U.S.
dollars.
3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands)
March 31, December 31,
2005 2004
----------- -----------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents........................................ $ 16,039 $ 7,257
Accounts receivable:
Trade, net of allowance for doubtful accounts of $7,348
as of March 31, 2005 and December 31, 2004.................. 222,742 207,696
Due from affiliates........................................... 2,132 2,583
Inventories...................................................... 41,256 40,332
Prepaid expenses................................................. 8,355 10,822
Deferred income taxes............................................ 188,124 115,206
Other current assets:
Derivatives................................................... 157 209
Other, net of allowance for doubtful accounts of $4,486
as of March 31, 2005 and December 31, 2004.................. 9,056 9,320
---------- ----------
Total current assets..................................... 487,861 393,425
---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method
of accounting:
Proved properties............................................. 7,861,900 7,654,181
Unproved properties........................................... 476,705 470,435
Accumulated depletion, depreciation and amortization............. (2,395,972) (2,243,549)
---------- ----------
Total property, plant and equipment...................... 5,942,633 5,881,067
---------- ----------
Deferred income taxes.............................................. 2,038 2,963
Goodwill........................................................... 307,951 315,880
Other property and equipment, net.................................. 82,244 78,696
Other assets:
Derivatives...................................................... 1,595 -
Other, net of allowance for doubtful accounts of $92 as of
March 31, 2005 and December 31, 2004.......................... 58,015 56,436
---------- ----------
$ 6,882,337 $ 6,728,467
========== ==========
The financial information included as of March 31, 2005 has been prepared by
management without audit by independent public accountants.
The accompanying notes are an integral part of these
consolidated financial statements.
4
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS (Continued)
(in thousands, except share data)
March 31, December 31,
2005 2004
----------- ------------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade........................................................... $ 279,580 $ 205,153
Due to affiliates............................................... 3,274 10,898
Interest payable................................................... 29,976 45,735
Income taxes payable............................................... 16,295 13,520
Other current liabilities:
Derivatives..................................................... 438,969 224,612
Deferred revenue................................................ 84,469 -
Other........................................................... 70,436 44,541
---------- ----------
Total current liabilities.................................. 922,999 544,459
---------- ----------
Long-term debt....................................................... 1,831,938 2,385,950
Derivatives.......................................................... 382,700 182,803
Deferred income taxes................................................ 518,291 607,415
Deferred revenue..................................................... 545,811 -
Other liabilities and minority interests............................. 173,658 176,060
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized;
146,798,361 and 145,644,828 shares issued at March 31, 2005
and December 31, 2004, respectively............................. 1,468 1,456
Additional paid-in capital......................................... 3,761,660 3,705,286
Treasury stock, at cost; 2,896,434 and 813,166 shares at
March 31, 2005 and December 31, 2004, respectively.............. (118,215) (27,793)
Deferred compensation.............................................. (64,750) (22,558)
Accumulated deficit................................................ (600,361) (634,146)
Accumulated other comprehensive income (loss):
Net deferred hedge losses, net of tax........................... (522,124) (241,350)
Cumulative translation adjustment............................... 49,262 50,885
---------- ----------
Total stockholders' equity................................. 2,506,940 2,831,780
Commitments and contingencies
---------- ----------
$ 6,882,337 $ 6,728,467
========== ==========
The financial information included as of March 31, 2005 has been prepared by
management without audit by independent public accountants.
The accompanying notes are an integral part of these
consolidated financial statements.
5
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)
Three months ended
March 31,
-----------------------
2005 2004
--------- ---------
Revenues and other income:
Oil and gas.............................................. $ 520,312 $ 435,527
Interest and other....................................... 28,333 1,735
Gain (loss) on disposition of assets, net................ 2,221 (13)
-------- --------
550,866 437,249
-------- --------
Costs and expenses:
Oil and gas production................................... 113,962 78,212
Depletion, depreciation and amortization................. 156,151 136,499
Impairment of long-lived assets.......................... 152 -
Exploration and abandonments............................. 67,385 80,506
General and administrative............................... 29,585 18,329
Accretion of discount on asset retirement obligations.... 2,140 1,966
Interest................................................. 33,251 21,576
Other.................................................... 11,720 196
-------- --------
414,346 337,284
-------- --------
Income before income taxes................................... 136,520 99,965
Income tax provision......................................... (51,863) (39,777)
-------- --------
Net income................................................... $ 84,657 $ 60,188
======== ========
Net income per share:
Basic.................................................... $ .59 $ .51
======== ========
Diluted.................................................. $ .58 $ .50
======== ========
Weighted average shares outstanding:
Basic.................................................... 142,898 118,719
======== ========
Diluted.................................................. 147,345 120,264
======== ========
Dividends declared per share................................. $ .10 $ .10
======== ========
The financial information included herein has been prepared by
management without audit by independent public accountants.
The accompanying notes are an integral part of these
consolidated financial statements.
6
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(in thousands, except per share data)
(Unaudited)
Accumulated Other
Comprehensive Income (Loss)
---------------------------
Net
Deferred
Additional Hedge Cumulative Total
Common Paid-in Treasury Deferred Accumulated Losses, Translation Stockholders'
Stock Capital Stock Compensation Deficit Net of Tax Adjustment Equity
------ ---------- -------- ------------ ----------- ----------- ----------- ------------
Balance as of January 1, 2005.... $1,456 $3,705,286 $(27,793) $ (22,558) $(634,146) $ (241,350) $ 50,885 $2,831,780
Dividends declared ($.10 per
common share)................ - - - - (14,394) - - (14,394)
Exercise of long-term incentive
plan stock options........... - - 61,464 - (36,478) - - 24,986
Purchase of treasury stock..... - - (151,886) - - - - (151,886)
Tax benefits related to
stock-based compensation..... - 8,711 - - - - - 8,711
Deferred compensation:
Compensation deferred........ 12 48,597 - (48,609) - - - -
Deferred compensation
included in net income..... - - - 5,152 - - - 5,152
Forfeitures of deferred
compensation............... - (934) - 1,265 - - - 331
Net income..................... - - - - 84,657 - - 84,657
Other comprehensive income (loss):
Net deferred hedge losses,
net of tax:
Net deferred hedge losses.. - - - - - (524,596) - (524,596)
Net hedge losses included
in net income............ - - - - - 52,322 - 52,322
Tax benefits related to
net hedge losses......... - - - - - 191,500 - 191,500
Translation adjustment....... - - - - - - (1,623) (1,623)
----- --------- -------- ---------- -------- --------- ------- ---------
Balance as of March 31, 2005..... $1,468 $3,761,660 $(118,215) $ (64,750) $(600,361) $(522,124) $ 49,262 $2,506,940
====== ========== ========= =========== ======== ======== ======= =========
The financial information included herein has been prepared by
management without audit by independent public accountants.
The accompanying notes are an integral part of these
consolidated financial statements.
7
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
Three months ended
March 31,
--------------------------
2005 2004
--------- ---------
Cash flows from operating activities:
Net income...................................................... $ 84,657 $ 60,188
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization...................... 156,151 136,499
Impairment of long-lived assets............................... 152 -
Exploration expenses, including dry holes..................... 58,445 78,820
Deferred income taxes......................................... 42,972 32,720
Loss (gain) on disposition of assets, net..................... (2,221) 13
Accretion of discount on asset retirement obligations......... 2,140 1,966
Noncash interest expense...................................... 696 (6,370)
Commodity hedge related activity.............................. (3,061) (11,392)
Amortization of stock-based compensation...................... 5,152 1,979
Amortization of deferred revenue.............................. (11,625) -
Other noncash items........................................... 4,678 (658)
Changes in operating assets and liabilities, net of effects
from acquisition:
Accounts receivable, net...................................... (12,033) (33,737)
Inventories................................................... (1,315) (19)
Prepaid expenses.............................................. 2,449 917
Other current assets, net..................................... (198) 757
Accounts payable.............................................. 17,593 (6,002)
Interest payable.............................................. (16,259) 693
Income taxes payable.......................................... 2,775 3,058
Other current liabilities..................................... 3,736 (5,802)
-------- --------
Net cash provided by operating activities.................. 334,884 253,630
-------- --------
Cash flows from investing activities:
Payments for acquisition, net of cash acquired.................. (965) -
Proceeds from disposition of assets............................. 600,096 285
Additions to oil and gas properties............................. (226,170) (167,226)
Other property additions, net................................... (11,062) (5,360)
-------- --------
Net cash provided by (used in) investing activities........ 361,899 (172,301)
-------- --------
Cash flows from financing activities:
Borrowings under long-term debt................................. 155,713 56,083
Principal payments on long-term debt............................ (708,713) (146,083)
Payment of other liabilities.................................... (8,302) (4,355)
Exercise of long-term incentive plan stock options.............. 24,986 8,495
Purchase of treasury stock...................................... (151,886) (5,566)
-------- ---------
Net cash used in financing activities...................... (688,202) (91,426)
-------- --------
Net increase (decrease) in cash and cash equivalents................ 8,581 (10,097)
Effect of exchange rate changes on cash and cash equivalents........ 201 (180)
Cash and cash equivalents, beginning of period...................... 7,257 19,299
-------- --------
Cash and cash equivalents, end of period............................ $ 16,039 $ 9,022
======== ========
The financial information included herein has been prepared by
management without audit by independent public accountants.
The accompanying notes are an integral part of these
consolidated financial statements.
8
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
(in thousands)
(Unaudited)
Three months ended
March 31,
--------------------------
2005 2004
--------- ---------
Net income................................................. $ 84,657 $ 60,188
-------- --------
Other comprehensive loss:
Net deferred hedge losses, net of tax:
Net deferred hedge losses............................ (524,596) (117,392)
Net hedge losses included in net income.............. 52,322 30,772
Tax benefits related to net hedge losses............. 191,500 31,871
Translation adjustment................................. (1,623) (2,241)
-------- --------
Other comprehensive loss.......................... (282,397) (56,990)
-------- --------
Comprehensive income (loss)................................ $(197,740) $ 3,198
======== ========
The financial information included herein has been prepared by
management without audit by independent public accountants.
The accompanying notes are an integral part of these
consolidated financial statements.
9
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
NOTE A. Organization and Nature of Operations
Pioneer 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 with operations in the United States,
Argentina, Canada, Equatorial Guinea, Nigeria, South Africa and Tunisia.
NOTE B. Basis of Presentation
Presentation. In the opinion of management, the unaudited consolidated
financial statements of the Company as of March 31, 2005 and for the three-month
periods ended March 31, 2005 and 2004 include all adjustments and accruals,
consisting only of normal, recurring accrual adjustments, which are necessary
for a fair presentation of the results for the interim periods. These interim
results are not necessarily indicative of results for a full year. Certain
amounts in the prior period financial statements have been reclassified to
conform to the current period presentation.
On September 28, 2004, the Company completed a merger with Evergreen
Resources, Inc. ("Evergreen"), as set forth in the Agreement and Plan of Merger
dated May 3, 2004, that added to the Company's United States and Canadian asset
base and expanded its portfolio of development and exploration opportunities in
North America. Evergreen's operations were primarily focused on developing and
expanding its coal bed methane production from the Raton Basin in southern
Colorado.
In accordance with the provisions of Statement of Financial Accounting
Standards ("SFAS") No. 141, "Business Combinations" ("SFAS 141"), the merger has
been accounted for as a purchase of Evergreen by Pioneer. As a result, the
historical financial statements for the Company are those of Pioneer prior to
September 28, 2004. The accompanying Consolidated Statements of Operations and
Cash Flows for the three months ended March 31, 2005 include the financial
results of the net assets acquired in the Evergreen merger. See Note C for
additional information regarding the Evergreen merger.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
in the United States have been condensed or omitted in this Form 10-Q pursuant
to the rules and regulations of the SEC. These consolidated financial statements
should be read in connection with the consolidated financial statements and
notes thereto included in the Company's Annual Report on Form 10-K, as amended,
as of and for the year ended December 31, 2004.
Inventories. Inventories were comprised of $38.7 million and $37.9 million
of materials and supplies and $2.6 million and $2.4 million of commodities as of
March 31, 2005 and December 31, 2004, respectively. The Company's materials and
supplies inventory is primarily comprised of oil and gas drilling or repair
items such as tubing, casing, chemicals, operating supplies and ordinary
maintenance materials and parts. The materials and supplies inventory are
primarily acquired for use in future drilling operations or repair operations
and are carried at the lower of cost or market, on a first-in, first-out basis.
Commodities inventory is carried at the lower of average cost or market, on a
first-in, first- out basis. As of March 31, 2005 and December 31, 2004, the
Company's materials and supplies inventory were net of $.4 million of valuation
reserve allowances.
Goodwill. As is described in Note C, the Company recorded $323.0 million of
goodwill associated with the Evergreen merger. The goodwill was recorded to the
Company's United States reporting unit and is subject to change during the
six-month period ending September 30, 2005 if the settlement values of monetary
assets acquired and liabilities assumed in the merger differ from their
estimated values as of the merger date. In accordance with Emerging Issues Task
10
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
Force Abstract Issue No. 00-23, "Issues Related to the Accounting for Stock
Compensation under APB Opinion No. 25 and Financial Accounting Standards Board
("FASB") Interpretation No. 44", the Company has reduced goodwill by $15.0
million since September 28, 2004, including $6.0 million during the three months
ended March 31, 2005, for certain tax benefits associated with the exercise of
fully-vested stock options assumed in conjunction with the Evergreen merger. In
accordance with SFAS No. 142, "Goodwill and Other Intangible Assets", 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 pretax earnings in the period in which it is determined
to be impaired.
Stock-based compensation. The Company has a long-term incentive plan (the
"Long-Term Incentive Plan") under which the Company grants stock-based
compensation. The Company accounts for stock-based compensation granted under
the Long-Term Incentive Plan using the intrinsic value method prescribed by
Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued to
Employees" ("APB 25") and related interpretations. The Company did not grant any
stock options under the Long-Term Incentive Plan during the three months ended
March 31, 2005. Stock-based compensation expense associated with option grants
was not recognized in the determination of the Company's net income during the
three-month periods ended March 31, 2005 and 2004, as all options granted under
the Long-Term Incentive Plan had exercise prices equal to the market value of
the underlying common stock on the dates of grant. Stock-based compensation
expense associated with restricted stock awards is deferred and amortized to
earnings ratably over the vesting periods of the awards. See "New accounting
pronouncement" below for information regarding the Company's adoption of SFAS
No. 123 (revised 2004), "Share-Based Payment" ("SFAS 123(R)").
The following table illustrates the pro forma effect on net income and
earnings per share as if the Company had applied the fair value recognition
provisions of SFAS No. 123, "Accounting for Stock-Based Compensation" ("SFAS
123") to stock-based compensation during the three-month periods ended March 31,
2005 and 2004:
Three months ended
March 31,
---------------------
2005 2004
-------- --------
(in thousands, except
per share amounts)
Net income, as reported................................ $ 84,657 $ 60,188
Plus: Stock-based compensation expense included
in net income for all awards, net of tax (a)........ 3,271 1,257
Deduct: Stock-based compensation expense determined
under fair value based method for all awards,
net of tax (a)...................................... (4,242) (3,115)
------- -------
Pro forma net income................................... $ 83,686 $ 58,330
======= =======
Net income per share:
Basic - as reported................................. $ .59 $ .51
======= =======
Basic - pro forma................................... $ .58 $ .49
======= =======
Diluted - as reported............................... $ .58 $ .50
======= =======
Diluted - pro forma................................. $ .57 $ .49
======= =======
- -----------
(a) For the three-month periods ended March 31, 2005 and 2004, stock-based
compensation expense included in net income is net of tax benefits of $1.9
million and $.7 million, respectively. Similarly, stock-based compensation
expense determined under the fair value based method for the three-month
periods ended March 31, 2005 and 2004 is net of tax benefits of $2.4
million and $1.8 million, respectively. See Note D for additional
information regarding the Company's income taxes.
11
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
New accounting pronouncements. The following discussions provide
information about new accounting pronouncements that have been issued by the
FASB:
SFAS 123(R). On December 16, 2004, the FASB issued SFAS 123(R), which is a
revision of SFAS 123. SFAS 123(R) supersedes APB 25 and amends SFAS No. 95,
"Statement of Cash Flows". Generally, the approach in SFAS 123(R) is similar to
the approach described in SFAS 123. However, SFAS 123(R) will require all
share-based payments to employees, including grants of employee stock options,
to be recognized in the Company's Consolidated Statements of Operations based on
their fair values. Pro forma disclosure is no longer an alternative.
SFAS 123(R) must be adopted no later than January 1, 2006 and permits
public companies to adopt its requirements using one of two methods:
o A "modified prospective" method in which compensation cost is recognized
beginning with the effective date based on the requirements of SFAS 123(R)
for all share-based payments granted after the adoption date and based on
the requirements of SFAS 123 for all awards granted to employees prior to
the effective date of SFAS 123(R) that remain unvested on the adoption
date.
o A "modified retrospective" method which includes the requirements of the
modified prospective method described above, but also permits entities to
restate either all prior periods presented or prior interim periods of the
year of adoption based on the amounts previously recognized under SFAS 123
for purposes of pro forma disclosures.
The Company has elected to adopt the provisions of SFAS 123(R) on January 1,
2006 using the modified prospective method.
As permitted by SFAS 123, the Company currently accounts for share-based
payments to employees using the intrinsic value method prescribed by APB 25 and
related interpretations. As such, the Company generally did not recognize
compensation expenses associated with employee stock option grants. The Company
has not issued stock options to employees since the year ended December 31,
2003. Consequently, the adoption of SFAS 123(R)'s fair value method will not
have a significant impact on the Company's future results of operations or
financial position. Had the Company adopted SFAS 123(R) in prior periods, the
impact would have approximated the impact of SFAS 123 as described in the pro
forma net income and earnings per share disclosures above. The adoption of SFAS
123(R) will have no effect on the Company's unvested outstanding restricted
stock awards. The Company estimates that the adoption of SFAS 123(R), based on
estimated outstanding unvested stock options, will result in future compensation
charges to general and administrative expenses of approximately $1.1 million
during 2006.
The Company has an Employee Stock Purchase Plan (the "ESPP") that allows
eligible employees to annually purchase the Company's common stock at a
discount. The provisions of SFAS 123(R) will cause the ESPP to be a compensatory
plan. However, the change in accounting for the ESPP is not expected to have a
material impact on the Company's financial position, future results of
operations or liquidity. Historically, the ESPP compensatory amounts have been
nominal.
SFAS 123(R) also requires the current tax benefits in excess of recognized
compensation expenses to be reported as a financing cash flow, rather than as an
operating cash flow as required under current literature. This requirement may
serve to reduce the Company's future cash flows provided by operating activities
and increase future cash flows provided by financing activities, to the extent
of associated tax benefits that may be realized in the future.
12
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
FSP FAS 19-1. In April 2005, the FASB issued Staff Position No. FAS 19-1,
"Accounting for Suspended Well Costs ("FSP FAS 19-1"). FSP FAS 19-1 amends SFAS
No. 19, "Financial Accounting and Reporting by Oil and Gas Producing Companies"
("SFAS 19"), to allow continued capitalization of exploratory well costs beyond
one year from the date drilling was completed under circumstances where the well
has found a sufficient quantity of reserves to justify its completion as a
producing well and the enterprise is making sufficient progress assessing the
reserves and the economic and operating viability of the project. FSP FAS 19-1
also amends SFAS 19 to require enhanced disclosures of suspended exploratory
well costs in the notes to the financial statements for annual and interim
periods when there has been a significant change from the previous disclosure.
The guidance in FSP FAS 19-1 is effective for the first reporting period
beginning after April 4, 2005. The Company will adopt the new requirements and
include any required disclosures in its Form 10-Q for the period ended June 30,
2005. The adoption of FSP FAS 19-1 is not expected to have a material impact on
the Company's consolidated financial position or results of operations.
NOTE C. Evergreen Merger
On September 28, 2004, Pioneer completed its merger with Evergreen with
Pioneer being the surviving corporation for accounting purposes. The transaction
was accounted for as a purchase of Evergreen by Pioneer in accordance with SFAS
141. The merger with Evergreen was accomplished through the issuance of 25.4
million shares of Pioneer common stock and $851.1 million of cash paid, net of
$12.1 million of acquired cash, to the Evergreen shareholders at closing. The
cash consideration paid in the merger was financed through borrowings on the
Company's $900 million 364-day senior unsecured revolving credit facility (the
"364-Day Credit Agreement"). See Note E for additional information on the
364-Day Credit Agreement.
Evergreen was a publicly-traded independent oil and gas company primarily
engaged in the production, development, exploration and acquisition of North
American unconventional gas and was one of the leading developers of coal bed
methane reserves in the United States. Evergreen's operations were principally
focused on developing and expanding its coal bed methane field located in the
Raton Basin in southern Colorado. Evergreen also had operations in the Piceance
Basin in western Colorado, the Uinta Basin in eastern Utah and the Western
Canada Sedimentary Basin.
The Company recorded $323.0 million of goodwill associated with the
Evergreen merger, which amount represents the excess of the purchase
consideration over the net fair value of the identifiable net assets acquired.
The following unaudited pro forma combined condensed financial data for the
three-month period ended March 31, 2004 was derived from the historical
financial statements of Pioneer and Evergreen giving effect to the Evergreen
merger as if it had occurred on January 1, 2004. The unaudited pro forma
combined condensed financial data have been included for comparative purposes
only and are not necessarily indicative of the results that might have occurred
had the merger taken place on January 1, 2004 and are not intended to be a
projection of future results.
Revenues (in thousands)................ $ 499,426
=========
Net income (in thousands).............. $ 67,009
=========
Net income per share:
Basic............................... $ .47
=========
Diluted............................. $ .45
=========
NOTE D. Income Taxes
The Company accounts for income taxes in accordance with the provisions of
SFAS No. 109, "Accounting for Income Taxes" ("SFAS 109"). SFAS 109 requires that
the Company continually assess both positive and negative evidence to determine
13
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
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 and other deferred tax attributes in
the United States, state, local and foreign tax jurisdictions will be utilized
prior to their expiration. As of March 31, 2005, the Company's valuation
allowances related to foreign and domestic tax jurisdictions were $109.5 million
and $.2 million, respectively.
On October 22, 2004, the American Jobs Creation Act (the "AJCA") was signed
into law. The AJCA includes a deduction of 85 percent of certain foreign
earnings that are repatriated, as defined in the AJCA. The Company may elect to
apply this provision to qualifying earnings repatriations in 2005. The Company
is evaluating the effects of the repatriation provision; however, the Company
does not expect to be able to complete this evaluation until after Congress or
the Treasury Department provide additional clarifying language on key elements
of the provision. The Company expects to complete its evaluation of the effects
of the repatriation provision within a reasonable period of time following the
publication of the additional clarifying language. The range of possible amounts
that the Company is considering for repatriation under section 965 of the
Internal Revenue Code is between zero and $80 million with a related potential
range of income tax between zero and $5 million, excluding the effects of
potential repatriation of funds that may occur as a result of the Canadian asset
divestiture referred to in Note N. Until the Company decides to repatriate any
foreign earnings, it will continue to treat them as permanently invested.
Income tax provision (benefit) attributable to net income consisted of the
following for the three-month periods ended March 31, 2005 and 2004:
Three months ended
March 31,
----------------------
2005 2004
-------- --------
(in thousands)
Current:
U.S. federal....................... $ - $ 1,000
Foreign............................ 8,891 6,057
------- -------
8,891 7,057
------- -------
Deferred:
U.S. federal....................... 41,532 34,080
U.S. state and local............... 1,147 1,429
Foreign............................ 293 (2,789)
------- -------
42,972 32,720
------- -------
$ 51,863 $ 39,777
======= =======
NOTE E. Long-term Debt
Lines of credit. During January 2005, the Company entered into a second
amendment (the "Second Amendment") to the Company's $700 million 5-Year
Revolving Credit Agreement (the "Revolving Credit Agreement") and a first
amendment (the "First Amendment") to the 364-Day Credit Agreement. The Second
Amendment and the First Amendment amended certain sections of the Revolving
Credit Agreement and the 364-Day Credit Agreement, respectively, to (i) provide
for the Company's ability to enter into volumetric production payment ("VPP")
agreements and (ii) clarify certain definitional matters. See Notes L and N for
additional discussion regarding the Company's entrance into VPP agreements.
During February 2005, the Company reduced the loan commitments under the
364-Day Credit Agreement by $250 million. During April 2005, the Company reduced
its loan commitments by an additional $200 million under the 364-Day Credit
Agreement to $450 million.
14
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
As of March 31, 2005, the Company was in compliance with all of its debt
covenants.
Senior notes. During April 2005, $131 million of the Company's 8-7/8%
senior notes due 2005 (the "8-7/8% Notes") matured. The Company utilized unused
borrowing capacity under its 364-Day Credit Agreement to repay the 8-7/8% Notes.
See Note N for information regarding the Company's redemption of a portion
of its outstanding 9-5/8% senior notes due 2010 (the "9-5/8% Notes") during
April 2005.
NOTE F. Derivative Financial Instruments
Fair value hedges. The Company monitors the debt capital markets and
interest rate trends to identify opportunities to enter into and terminate
interest rate swap contracts with the objective of minimizing costs of capital.
During the three months ended March 31, 2004, the Company, from time to time,
entered into interest rate swap contracts to hedge a portion of the fair value
of its senior notes. The terms of the interest rate swap contracts were for
notional amounts that matched the scheduled maturity of the hedged senior notes,
required the counterparties to pay the Company a fixed annual interest rate
equal to the stated bond coupon rates on the notional amounts and required the
Company to pay the counterparties variable annual interest rates on the notional
amounts equal to the periodic LIBOR plus a weighted average annual margin.
During the three months ended March 31, 2004, settlements of open fair value
hedges reduced the Company's interest expense by $.2 million. As of March 31,
2005 and December 31, 2004, the Company was not a party to any open fair value
hedges.
As of March 31, 2005, the carrying value of the Company's long-term debt in
the accompanying Consolidated Balance Sheets included a $5.7 million reduction
in the carrying value attributable to net deferred hedge losses on terminated
fair value hedges that are being amortized as net increases to interest expense
over the original terms of the terminated agreements. The amortization of net
deferred hedge gains on terminated interest rate swaps reduced the Company's
reported interest expense by $2.2 million and $7.3 million during the
three-month periods ended March 31, 2005 and 2004, respectively.
The following table sets forth, as of March 31, 2005, the scheduled
amortization of net deferred hedge gains (losses) on terminated interest rate
hedges (including terminated fair value and cash flow hedges) that will be
recognized as increases in the case of losses, and decreases in the case of
gains, to the Company's future interest expense:
2005 2006 2007 2008 2009 Thereafter
------ ------ ------- ------- ------- ----------
(in thousands)
Net deferred hedge gains (losses) $1,205 $ 625 $(2,222) $(1,937) $(2,351) $(5,913)
====== ===== ====== ====== ====== ======
Cash flow hedges. The Company utilizes commodity swap and collar contracts
to (i) reduce the effect of price volatility on the commodities the Company
produces and sells, (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 and forward currency exchange agreements to reduce the effect of
U.S. dollar to Canadian dollar exchange rate volatility.
15
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
Oil prices. All material physical sales contracts governing the Company's
United States oil production have been tied directly or indirectly to NYMEX
prices. As of March 31, 2005, all of the Company's commodity hedges are
designated as hedges of United States forecasted sales. The following table sets
forth the volumes hedged in Bbls underlying the Company's outstanding oil hedge
contracts and the weighted average NYMEX prices per Bbl for those contracts as
of March 31, 2005:
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
------------- ------------- ------------- ------------- -------------
Average daily oil production hedged (a):
2005 - Swap Contracts
Volume (Bbl).................... 27,000 27,000 27,000 27,000
Price per Bbl................... $ 27.97 $ 27.97 $ 27.97 $ 27.97
2006 - Swap Contracts
Volume (Bbl).................... 11,973 11,973 11,973 11,973 11,973
Price per Bbl................... $ 35.43 $ 35.43 $ 35.43 $ 35.43 $ 35.43
2006 - Collar Contracts
Volume (Bbl).................... 3,500 3,500 3,500 3,500 3,500
Price per Bbl................... $35.00-$41.95 $35.00-$41.95 $35.00-$41.95 $35.00-$41.95 $35.00-$41.95
2007 - Swap Contracts
Volume (Bbl).................... 13,000 13,000 13,000 13,000 13,000
Price per Bbl................... $ 30.89 $ 30.89 $ 30.89 $ 30.89 $ 30.89
2008 - Swap Contracts
Volume (Bbl).................... 20,278 20,278 20,278 20,278 20,278
Price per Bbl................... $ 32.46 $ 32.46 $ 32.46 $ 32.46 $ 32.46
2009 - Swap Contracts
Volume (Bbl).................... 1,643 1,643 1,643 1,643 1,643
Price per Bbl................... $ 47.25 $ 47.25 $ 47.25 $ 47.25 $ 47.25
2010 - Swap Contracts
Volume (Bbl).................... 1,643 1,643 1,643 1,643 1,643
Price per Bbl................... $ 46.40 $ 46.40 $ 46.40 $ 46.40 $ 46.40
- ---------------
(a) Subsequent to March 31, 2005, the Company conveyed to the purchaser of its
April VPP the following oil swap contracts which were included in the
schedule above: (i) 1,973 Bbls per day of 2006 oil sales at a weighted
average fixed price per Bbl of $54.40, (ii) 3,278 Bbls per day of 2008 oil
sales at a weighted average fixed price per Bbl of $49.28, (iii) 1,643 Bbls
per day of 2009 oil sales at a weighted average fixed price per Bbl of
$47.25 and (iv) 1,643 Bbls per day of 2010 oil sales at a weighted average
fixed price per Bbl of $46.40. See Note N for additional information
regarding the Company's April VPP.
16
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
The Company reports average oil prices per Bbl including the effects of oil
quality adjustments and the net effect of oil hedges. The following table sets
forth the Company's oil prices, both reported (including hedge results) and
realized (excluding hedge results), and the net effect of settlements of oil
price hedges on oil revenue for the three-month periods ended March 31, 2005 and
2004:
Three months ended
March 31,
------------------
2005 2004
------- -------
Average price reported per Bbl................... $ 33.27 $ 28.31
Average price realized per Bbl................... $ 43.29 $ 32.12
Reduction to oil revenue (in millions)........... $ (44.3) $ (16.5)
Natural gas liquids prices. During the three-month periods ended March 31,
2005 and 2004, the Company did not enter into any NGL hedge contracts. There
were no outstanding NGL hedge contracts at March 31, 2005.
Gas prices. The Company employs a policy of hedging a portion of its gas
production based on the index price upon which the gas is actually sold in order
to mitigate the basis risk between NYMEX prices and actual index prices, or
based on NYMEX prices if NYMEX prices are highly correlated with the index
price. The following table sets forth the volumes hedged in MMBtus underlying
the Company's outstanding gas hedge contracts and the weighted average index
prices per MMBtu for those contracts as of March 31, 2005:
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
----------- ----------- ----------- ----------- -----------
Average daily gas production hedged (a):
2005 - Swap Contracts
Volume (MMBtu)........................ 286,703 290,000 260,000 278,873
Index price per MMBtu................. $ 5.20 $ 5.23 $ 5.22 $ 5.22
2006 - Swap Contracts
Volume (MMBtu)........................ 80,000 80,000 80,000 80,000 80,000
Index price per MMBtu................. $ 4.50 $ 4.50 $ 4.50 $ 4.50 $ 4.50
2006 - Collar Contracts
Volume (MMBtu)........................ 55,000 5,000 5,000 5,000 17,329
Index price per MMBtu................. $7.07-$9.70 $5.25-$7.15 $5.25-$7.15 $5.25-$7.15 $6.67-$9.14
2007 - Swap Contracts
Volume (MMBtu)........................ 35,000 35,000 35,000 35,000 35,000
Index price per MMBtu................. $ 4.63 $ 4.63 $ 4.63 $ 4.63 $ 4.63
2008 - Swap Contracts
Volume (MMBtu)........................ 5,000 5,000 5,000 5,000 5,000
Index price per MMBtu................. $ 5.38 $ 5.38 $ 5.38 $ 5.38 $ 5.38
- --------------
(a) Subsequent to March 31, 2005, the Company conveyed to the purchaser of its
April VPP the following gas swap contracts which were included in the
schedule above: (i) 5,841 MMBtu per day of 2005 gas sales at a weighted
average fixed price per MMBtu of $7.14, (ii) 6,158 MMBtu per day of 2006
gas sales at a weighted average fixed price per MMBtu of $6.90 and (iii)
5,805 MMBtu per day of 2007 gas sales at a weighted average fixed price per
MMBtu of $6.35. See Note N for additional information regarding the
Company's April VPP.
17
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
The Company reports average gas prices per Mcf including the effects of Btu
content, gas processing, shrinkage adjustments and the net effect of gas hedges.
The following table sets forth the Company's gas prices, both reported
(including hedge results) and realized (excluding hedge results), and the net
effect of settlements of gas price hedges on gas revenue for the three-month
periods ended March 31, 2005 and 2004:
Three months ended
March 31,
---------------------
2005 2004
------- --------
Average price reported per Mcf................... $ 5.04 $ 4.38
Average price realized per Mcf................... $ 5.16 $ 4.62
Reduction to gas revenue (in millions)........... $ (8.0) $ (14.2)
Hedge ineffectiveness. During the three-month periods ended March 31, 2005
and 2004, the Company recognized other expense of $6.8 million and $44,000,
respectively, related to the ineffective portions of its cash flow hedging
instruments.
Accumulated other comprehensive income (loss) - net deferred hedge losses,
net of tax ("AOCI - Hedging"). As of March 31, 2005 and December 31, 2004, AOCI
- - Hedging represented net deferred losses of $522.1 million and $241.4 million,
respectively. The AOCI - Hedging balance as of March 31, 2005 was comprised of
$788.5 million of net deferred losses on the effective portions of open cash
flow hedges, $49.8 million of net deferred losses on terminated cash flow hedges
(including $4.9 million of net deferred losses on terminated cash flow interest
rate hedges) and $316.2 million of associated net deferred tax benefits. The
increase in AOCI - Hedging during the three months ended March 31, 2005 was
primarily attributable to increases in future commodity prices relative to the
commodity prices stipulated in the hedge contracts, partially offset by the
reclassification of net deferred hedge losses to net income as derivatives
matured by their terms. The net deferred losses associated with open cash flow
hedges remain subject to market price fluctuations until the positions are
either settled under the terms of the hedge contracts or terminated prior to
settlement. The net deferred losses on terminated cash flow hedges are fixed.
During the twelve months ending March 31, 2006, based on current estimates
of future commodity prices, the Company expects to reclassify $434.5 million of
net deferred losses associated with open commodity hedges and $9.2 million of
net deferred losses on terminated commodity hedges from AOCI - Hedging to oil
and gas revenues. The Company also expects to reclassify approximately $162.1
million of net deferred income tax benefits associated with commodity hedges
during the twelve months ending March 31, 2006 from AOCI - Hedging to income tax
benefit.
The following table sets forth, as of March 31, 2005, the scheduled
amortization of net deferred losses on terminated commodity hedges that will be
recognized as decreases to the Company's future oil and gas revenues:
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- ---------
(in thousands)
2005 net deferred hedge losses.... $ (677) $ (934) $(1,936) $ (3,547)
2006 net deferred hedge losses.... $(5,625) $(1,676) $(1,521) $(2,205) (11,027)
2007 net deferred hedge losses.... $(4,051) $ (936) $ (734) $(1,450) (7,171)
2008 net deferred hedge losses.... $(3,570) $ (872) $ (855) $(1,487) (6,784)
2009 net deferred hedge losses.... $(2,817) $ (748) $ (785) $(1,409) (5,759)
2010 net deferred hedge losses.... $(1,012) $ (995) $ (980) $ (961) (3,948)
2011 net deferred hedge losses.... $ (873) $ (889) $ (902) $ (907) (3,571)
2012 net deferred hedge losses.... $ (810) $ (791) $ (783) $ (772) (3,156)
-------
$(44,963)
=======
18
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
NOTE G. Asset Retirement Obligations
The Company's asset retirement obligations primarily relate to the future
plugging and abandonment of proved properties and related facilities. The
Company does not provide for a market risk premium associated with asset
retirement obligations because a reliable estimate cannot be determined. The
Company has no assets that are legally restricted for purposes of settling asset
retirement obligations. The following table summarizes the Company's asset
retirement obligation transactions recorded in accordance with the provisions of
SFAS No. 143, "Accounting for Asset Retirement Obligations" during the
three-month periods ended March 31, 2005 and 2004:
Three months ended
March 31,
---------------------
2005 2004
-------- --------
(in thousands)
Beginning asset retirement obligations............ $120,879 $105,036
New wells placed on production and
changes in estimates......................... 1,445 2,732
Liabilities settled............................ (2,400) (2,597)
Accretion of discount.......................... 2,140 1,966
Currency translation........................... (127) (103)
------- -------
Ending asset retirement obligations .............. $121,937 $107,034
======= =======
The Company records the current and noncurrent portions of asset retirement
obligations in other current liabilities and other liabilities and minority
interests, respectively, in the accompanying Consolidated Balance Sheets.
NOTE H. Postretirement Benefit Obligations
As of March 31, 2005 and December 31, 2004, the Company had recorded $15.7
million and $15.5 million, respectively, of unfunded accumulated postretirement
benefit obligations, the current and noncurrent portions of which are included
in other current liabilities and other liabilities and minority interests,
respectively, in the accompanying Consolidated Balance Sheets.
The following table reconciles changes in the Company's unfunded
accumulated postretirement benefit obligations during the three-month periods
ended March 31, 2005 and 2004:
Three months ended
March 31,
-------------------
2005 2004
------- -------
(in thousands)
Beginning accumulated postretirement benefit obligations...... $15,534 $15,556
Benefit payments........................................... (186) (339)
Service costs.............................................. 81 58
Accretion of discounts..................................... 225 226
------ ------
Ending accumulated postretirement benefit obligations......... $15,654 $15,501
====== ======
19
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
NOTE I. Commitments and Contingencies
Legal actions. The Company is party to various legal actions incidental to
its business, including, but not limited to, the proceedings described below.
The majority of these lawsuits primarily involve claims for damages arising from
oil and gas leases and ownership interest disputes. The Company believes that
the ultimate disposition of these legal actions will not have a material adverse
effect on the Company's consolidated financial position, liquidity, capital
resources or future results of operations. The Company will continue to evaluate
its litigation matters on a quarter-by- quarter basis and will adjust its
litigation reserves as appropriate to reflect the then current status of
litigation.
Alford. The Company is party to a 1993 class action lawsuit filed in the
26th Judicial District Court of Stevens County, Kansas by two classes of royalty
owners, one for each of the Company's gathering systems connected to the
Company's Satanta gas plant. The case was relatively inactive for several years.
In early 2000, the plaintiffs amended their pleadings and the case now contains
two material claims. First, the plaintiffs assert that they were improperly
charged expenses (primarily field compression), which are a "cost of
production", and for which the plaintiffs, as royalty owners, are not
responsible. Second, the plaintiffs claim they are entitled to 100 percent of
the value of the helium extracted at the Company's Satanta gas plant. If the
plaintiffs were to prevail on the above two claims in their entirety, it is
possible that the Company's liability (both for periods covered by the lawsuit
and from the last date covered by the lawsuit to the present - because the
deductions continue to be taken and the plaintiffs continue to be paid for a
royalty share of the helium) could reach approximately $30 million related to
the cost of production claim and approximately $40 million related to the helium
claim, plus prejudgment interest. However, the Company believes it has valid
defenses to the plaintiffs' claims, has paid the plaintiffs properly under their
respective oil and gas leases and other agreements, and intends to vigorously
defend itself.
The Company does not believe the costs it has deducted are a "cost of
production". The costs being deducted are post production costs incurred to
transport the gas to the Company's Satanta gas plant for processing, where the
valuable hydrocarbon liquids and helium are extracted from the gas. The
plaintiffs benefit from such extractions and the Company believes that charging
the plaintiffs with their proportionate share of such transportation and
processing expenses is consistent with Kansas law and with the parties'
agreements.
The Company has also vigorously defended against plaintiffs' claims to 100
percent of the value of the helium extracted, and believes that in accordance
with applicable law, it has properly accounted to the plaintiffs for their
fractional royalty share of the helium under the specified royalty clauses of
the respective oil and gas leases. The Company has not established a provision
for the helium claim.
The factual evidence in the case was presented to the 26th Judicial
District Court without a jury in December 2001. Oral arguments were heard by the
court in April 2002, and although the court has not yet entered a judgment or
findings, it could do so at any time. The Company strongly denies the existence
of any material underpayment to the plaintiffs and believes it presented strong
evidence at trial to support its positions. However, either through a negotiated
settlement or court ruling, the Company could have to pay some part of the cost
of production claim and, accordingly, the Company has established a partial
reserve for this claim. Although the amount of any resulting liability, to the
extent that it exceeds the Company's provision, could have a material adverse
effect on the Company's results of operations for the quarterly reporting period
in which such liability is recorded, the Company does not expect that any such
additional liability will have a material adverse effect on its consolidated
financial position as a whole or on its liquidity, capital resources or future
annual results of operations.
MOSH Holding. The Company and its principal U.S. subsidiary, Pioneer
Natural Resources USA, Inc., were named as defendants in a case styled MOSH
Holding, L.P. v Pioneer Natural Resources Company; Pioneer Natural Resources
USA, Inc.; Woodside Energy (USA) Inc.; and JPMorgan Chase Bank, NA, as Trustee
of the Mesa Offshore Trust, which was filed on April 11, 2005, in the District
Court of Travis County, Texas (250th Judicial District). The plaintiff is a
20
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
unitholder in the Mesa Offshore Trust, which was created in 1982 as the sole
limited partner in a partnership that holds an overriding royalty interest in
certain oil and gas leases offshore Louisiana and Texas. The plaintiff alleges
that the Company, together with Woodside Energy (USA) Inc., concealed the value
of the royalty interest, worked to terminate the Mesa Offshore Trust
prematurely, and to capture for itself and Woodside Energy (USA) Inc. profits
that belong to the Mesa Offshore Trust. The plaintiff also alleges breaches of
fiduciary duty, misapplication of trust property, common law fraud, gross
negligence, and breach of the conveyance agreement for the overriding royalty
interest. The claims appear to relate principally to farmout arrangements
established in 2003 for two offshore properties, the Brazos Area Block A-7 and
Brazos Area Block A-39. The relief sought by the plaintiff includes monetary and
punitive damages and certain equitable relief, including an accounting of
expenses, a setting aside of certain farmouts, and a temporary and permanent
injunction. The Company believes the claims are without merit and intends to
defend the lawsuit vigorously.
Argentine Environmental. The Company's subsidiary in Argentina is involved
in various administrative proceedings with the Neuquen Province environmental
authorities relating to the permitting and discharges from operations in that
province. In general, the Company's subsidiary is cooperating with the
proceedings, although it from time to time challenges whether certain assessed
fines are appropriate. The Company estimates that fines assessed in these
proceedings will be immaterial, but in the aggregate could exceed $100,000.
NOTE J. Net Income Per Share
Basic net income per share is computed by dividing net income by the
weighted average number of common shares outstanding for the period. The
computation of diluted net income per share reflects the potential dilution that
could occur if securities or other contracts to issue common stock that are
dilutive to net income 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.
The following table is a reconciliation of basic net income to diluted net
income for the three-month periods ended March 31, 2005 and 2004:
Three months ended
March 31,
--------------------
2005 2004
-------- --------
(in thousands)
Basic net income....................................... $ 84,657 $ 60,188
Interest expense on convertible notes, net of tax...... 802 -
------- -------
Diluted net income..................................... $ 85,459 $ 60,188
======= =======
21
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
The following table is a reconciliation of basic weighted average common
shares outstanding to diluted weighted average common shares outstanding for the
three-month periods ended March 31, 2005 and 2004:
Three months ended
March 31,
-------- --------
2005 2004
-------- --------
(in thousands)
Weighted average common shares outstanding:
Basic................................................ 142,898 118,719
Dilutive common stock options (a).................... 1,293 1,177
Restricted stock awards.............................. 827 368
Convertible notes dilution (b)....................... 2,327 -
-------- --------
Diluted.............................................. 147,345 120,264
======== ========
- ---------------
(a) Common stock options to purchase 30,712 shares of common stock were
outstanding but not included in the computations of diluted net income per
share for the three-month periods ended March 31, 2005 and 2004 because the
exercise prices of the options were greater than the average market price
of the common shares and would be anti-dilutive to the computations.
(b) Associated with the Evergreen merger, the Company assumed convertible notes
eligible for 2.3 million shares of the Company's common stock upon
conversion.
NOTE K. Geographic Operating Segment Information
The Company has operations in only one industry segment, that being the oil
and gas exploration and production industry; however, the Company is
organizationally structured along geographic operating segments, or regions. The
Company has reportable operations in the United States, Argentina, Canada and
Africa and Other. Africa and Other is primarily comprised of operations in
Equatorial Guinea, Gabon, Nigeria, South Africa and Tunisia.
The following tables provide the Company's interim geographic operating
segment data for the three-month periods ended March 31, 2005 and 2004.
Geographic operating segment income tax benefits (provisions) have been
determined based on statutory rates existing in the various tax jurisdictions
where the Company has oil and gas producing activities. The "Headquarters" table
column includes revenues and expenses that are not routinely included in the
earnings measures internally reported to management on a geographic operating
segment basis.
22
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
United Africa Consolidated
States Argentina Canada and Other Headquarters Total
-------- --------- -------- --------- ------------ ------------
(in thousands)
Three months ended March 31, 2005:
Revenues and other income:
Oil and gas revenues............ $403,833 $ 38,030 $ 30,758 $ 47,691 $ - $ 520,312
Interest and other.............. - - - - 28,333 28,333
Gain on disposition of
assets, net................... 2,032 - - - 189 2,221
------- ------- ------- ------- ------- --------
405,865 38,030 30,758 47,691 28,522 550,866
------- ------- ------- ------- ------- --------
Costs and expenses:
Oil and gas production.......... 86,144 8,507 11,544 7,767 - 113,962
Depletion, depreciation and
amortization.................. 114,446 17,932 9,593 9,377 4,803 156,151
Impairment of long-lived assets. - - - 152 - 152
Exploration and abandonments.... 39,479 2,584 4,037 21,285 - 67,385
General and administrative...... - - - - 29,585 29,585
Accretion of discount on asset
retirement obligations........ - - - - 2,140 2,140
Interest........................ - - - - 33,251 33,251
Other........................... - - - - 11,720 11,720
------- ------- ------- ------- ------- --------
240,069 29,023 25,174 38,581 81,499 414,346
------- ------- ------- ------- ------- --------
Income (loss) before income taxes.. 165,796 9,007 5,584 9,110 (52,977) 136,520
Income tax benefit (provision)..... (60,516) (3,152) (2,108) (2,060) 15,973 (51,863)
------- ------- ------- ------- ------- --------
Net income (loss).................. $105,280 $ 5,855 $ 3,476 $ 7,050 $(37,004) $ 84,657
======= ======= ======= ======= ======= ========
Three months ended March 31, 2004:
Revenues and other income:
Oil and gas revenues............ $346,309 $ 30,883 $ 18,219 $ 40,116 $ - $ 435,527
Interest and other.............. - - - - 1,735 1,735
Gain (loss) on disposition of
assets, net................... 51 - - - (64) (13)
------- ------- ------- ------- ------- --------
346,360 30,883 18,219 40,116 1,671 437,249
------- ------- ------- ------- ------- --------
Costs and expenses:
Oil and gas production.......... 55,020 6,759 7,949 8,484 - 78,212
Depletion, depreciation and
amortization.................. 97,371 12,542 7,475 16,396 2,715 136,499
Exploration and abandonments.... 53,556 3,550 12,976 10,424 - 80,506
General and administrative...... - - - - 18,329 18,329
Accretion of discount on asset
retirement obligations........ - - - - 1,966 1,966
Interest........................ - - - - 21,576 21,576
Other........................... - - - - 196 196
------- ------- ------- ------- ------- --------
205,947 22,851 28,400 35,304 44,782 337,284
------- ------- ------- ------- ------- --------
Income (loss) before income taxes.. 140,413 8,032 (10,181) 4,812 (43,111) 99,965
Income tax benefit (provision)..... (51,251) (2,811) 3,843 (1,162) 11,604 (39,777)
------- ------- ------- ------- ------- --------
Net income (loss).................. $ 89,162 $ 5,221 $ (6,338) $ 3,650 $(31,507) $ 60,188
======= ======= ======= ======= ======= ========
23
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
NOTE L. Volumetric Production Payments
During January 2005, the Company sold two percent of its total proved
reserves, or 20.5 MMBOE of proved reserves, by means of two VPPs for net
proceeds of $592.3 million, including the assignment of the Company's
obligations under certain derivative hedge agreements. Proceeds from the VPPs
were initially used to pay down indebtedness. The first VPP sold 58 Bcf of
Hugoton field gas volumes over an expected five-year term that began in February
2005 for $275.2 million. The second VPP sold 10.8 MMBbls of oil volumes over an
expected seven-year term beginning in January 2006 for $317.1 million.
The Company's VPPs represent limited-term overriding royalty interests in
oil and gas reserves which: (i) entitle the purchaser to receive production
volumes over a period of time from specific lease interests; (ii) are free and
clear of all associated future production costs and capital expenditures; (iii)
are nonrecourse to the Company (i.e., the purchaser's only recourse is to the
assets acquired); (iv) transfers title to the purchaser and (v) allows the
Company to retain the assets after the VPPs volumetric quantities have been
delivered.
Under SFAS 19, a VPP is considered a sale of proved reserves and the
related future production of those proved reserves. As a result, the Company (i)
removes the proved reserves associated with the VPPs; (ii) recognizes the VPP
proceeds as deferred revenue which will be amortized on a unit-of-production
basis to future oil and gas revenues over the terms of the VPPs; (iii) retains
responsibility for 100 percent of the production costs and capital costs related
to VPP interests and (iv) no longer recognizes production associated with the
VPP volumes.
The following table represents the breakdown of the components of the VPPs:
Hugoton Spraberry
Field (Gas) Field (Oil) Total
---------- ---------- ----------
(in thousands)
VPP proceeds, net of transaction costs.... $ 275,163 $ 317,123 $ 592,286
Fair value of derivatives conveyed (a).... 12,860 36,759 49,619
--------- --------- ---------
Deferred revenue.......................... 288,023 353,882 641,905
Less first quarter 2005 amortization...... (11,625) - (11,625)
--------- --------- ---------
Deferred revenue March 31, 2005...... $ 276,398 $ 353,882 $ 630,280
========= ========= =========
- -----------
(a) Represents the fair value of the derivative obligations conveyed as part of
the VPP transaction. The fair value was deferred in AOCI-Hedging until the
delivery of the VPP volumes occurs at which time the fair value of the
derivative obligations attributable to the delivered volumes will be
recognized as a decrease to oil and gas revenues. See Note F for additional
discussion regarding the Company's hedge positions.
The above deferred revenue amounts will be recognized in oil and gas
revenues in the Consolidated Statements of Operations as noted below, assuming
the related VPP production volumes are delivered as scheduled (in thousands):
Remaining 2005......................... $ 54,176
2006................................... 120,219
2007................................... 115,363
2008................................... 108,168
2009................................... 100,381
2010................................... 44,952
2011................................... 44,952
2012................................... 42,069
---------
$ 630,280
=========
24
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
NOTE M. Business Interruption Insurance Claims
During September 2004, the Company sustained damages as a result of
Hurricane Ivan at its Devils Tower and Canyon Express platform facilities in the
deepwater Gulf of Mexico. The damages delayed scheduled well completions and
interrupted production during the second half of 2004 and during the first
quarter 2005. The Company maintains business interruption insurance coverage for
such circumstances and events and has filed claims with its insurance providers.
Based on the terms of the insurance coverage, the Company estimates its
losses since the occurrence and through March 31, 2005 to be approximately $32.4
million. The Company recorded $7.6 million and $24.8 million of the estimated
claims in the fourth quarter of 2004 and in the first quarter of 2005,
respectively, in interest and other income in the Company's Consolidated
Statements of Operations. In March 2005, the Company received a $14.3 million
partial payment from its insurance providers related to its Devils Tower claim.
NOTE N. Subsequent Events
VPP transaction. During April 2005, the Company sold less than one percent
of its total proved reserves, or 7.3 MMBOE of proved reserves, by means of a new
VPP for net proceeds of $300.4 million, including the value attributable to
certain derivative hedge agreements assigned to the buyer of the April VPP.
Proceeds from the April VPP were initially used to pay down indebtedness. The
April VPP sold 6.0 Bcf of Spraberry field gas volumes over an expected 32-month
term beginning in May 2005 and 6.2 MMBbls of Spraberry field oil volumes over an
expected five-year term beginning in January 2006. The following table
represents the breakdown of the components of the April VPP:
Spraberry Spraberry
Field (Gas) Field (Oil) Total
---------- ---------- ----------
(in thousands)
VPP proceeds, net of transaction costs.... $ 37,613 $ 262,790 $ 300,403
Fair value of derivatives conveyed (a).... (526) (11,076) (11,602)
--------- --------- ---------
Deferred revenue.......................... $ 37,087 $ 251,714 $ 288,801
========= ========= =========
- -----------
(a) Represents the fair value of the derivative agreements conveyed as part of
the VPP transaction. The fair value will be deferred in AOCI-Hedging until
the delivery of the VPP volumes occurs at which time the fair value of the
derivative agreements attributable to the delivered volumes will be
recognized as an increase to oil and gas revenues.
The above deferred revenue amounts will be recognized in oil and gas
revenues in the Consolidated Statements of Operations as noted below, assuming
the related April VPP production volumes are delivered as scheduled (in
thousands):
Remaining 2005......................... $ 9,973
2006................................... 70,132
2007................................... 65,891
2008................................... 49,986
2009................................... 47,540
2010................................... 45,279
--------
$ 288,801
========
Asset divestitures. During April 2005, the Company announced the signing of
a definitive agreement for the sale of three non-strategic Canadian properties
and completed the sale of certain East Texas properties for expected aggregate
sales proceeds of approximately $232 million.
25
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2005
(Unaudited)
Canadian divestiture. The Company's Canadian divestiture includes all of
the Company's interests in Martin Creek, Conroy Black and Lookout Butte oil and
gas properties for expected proceeds of approximately $207 million, subject to
normal closing adjustments. The Canadian divestiture is expected to be completed
during the second quarter of 2005, although no assurances can be given that the
transaction will be completed as planned.
East Texas divestiture. During April 2005, the Company completed the
aforementioned divestiture of East Texas properties for approximately $25
million of net cash proceeds.
Debt redemption. During April 2005, the Company redeemed $32.4 million
principal amount of its 9-5/8% Notes. The Company will recognize a pretax loss
on the redemption of the 9-5/8% Notes of $7.3 million during the second quarter
of 2005.
26
PIONEER NATURAL RESOURCES COMPANY
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
Financial and Operating Performance
During 2005, the Company announced the following significant events and
initiatives:
o Production resumed in mid-February from Canyon Express after hurricane
related repairs were completed.
o The Company sold two VPPs during the first quarter of 2005 for net
proceeds of $592.3 million, including the assignment of $49.6 million
of the Company's derivative hedge obligations.
o The Company sold a third VPP during April 2005 for net proceeds of
$300.4 million.
o During April 2005, the Company announced the signing of a definitive
agreement for the sale of three non-strategic Canadian properties and
completed the sale of certain East Texas properties for expected
aggregate sales proceeds of approximately $232 million.
o In Alaska, the Company acquired a 20 percent interest in approximately
452,000 additional acres and gained the rights to extensive seismic and
geologic data in the National Petroleum Reserve - Alaska (the "NPR-A")
Northeast Planning Area. The Company also participated in the NPR-A
Northwest Planning Area lease sale and acquired working interests
ranging from 20 percent to 30 percent in approximately 808,000 acres.
o The Company acquired 13 blocks, all in the deepwater Gulf of Mexico,
for $7.5 million.
o The Company executed a multi-year service contract with Doyon Drilling,
Inc. and Akita Drilling, Ltd. who will build and operate a new drilling
rig designed for exploration drilling on the Company's Alaskan North
Slope properties.
o The Company joined Oranto Petroleum and Orandi Petroleum in an existing
production sharing contract on Block 320 in deepwater Nigeria gaining
exploration rights from the Nigerian National Petroleum Corporation.
o The Company's board of directors approved a 2005 capital program
providing for total capital expenditures of $900 million to $950
million.
o The board of directors approved a new share repurchase program
authorizing the purchase of up to $300 million of the Company's common
stock.
o The board of directors declared a semiannual cash dividend of $.10 per
share to common stockholders of record at the close of business on
March 31, 2005. The dividend was paid on April 15, 2005.
The Company's financial and operating performance for the first quarter of
2005 included the following highlights:
o Average daily sales volumes, on a BOE basis, increased four percent
during the first quarter of 2005 as compared to the first quarter of
2004.
o Oil and gas revenues increased 19 percent during the first quarter of
2005 as compared to the same period in 2004 as a result of the
increased production volumes and increases in worldwide oil and gas
prices.
o Interest and other income increased by $26.6 million during the first
quarter of 2005 as compared to the first quarter of 2004, primarily due
to business interruption insurance claims related to Hurricane Ivan.
o Income before income taxes increased by 37 percent to $136.5 million
during the first quarter of 2005 from $100.0 million during the first
quarter of 2004.
o Net income increased to $84.7 million ($.58 per diluted share) for the
first quarter of 2005, as compared to $60.2 million ($.50 per diluted
share) for the same period in 2004.
o Net cash provided by operating activities increased by 32 percent to
$334.9 million during the first quarter of 2005 from $253.6 million
during the first quarter of 2004.
o Outstanding debt decreased by $554.0 million, or 23 percent, as of
March 31, 2005 as compared to debt outstanding as of December 31, 2004.
27
PIONEER NATURAL RESOURCES COMPANY
Volumetric Production Payments
During January 2005, the Company sold two percent of its total proved
reserves, or 20.5 MMBOE of proved reserves, by means of two VPPs for net
proceeds of $592.3 million, including the assignment of the Company's
obligations under certain derivative hedge agreements. Proceeds from the VPPs
were initially used to pay down indebtedness. The first VPP sold 58 Bcf of
Hugoton field gas volumes over an expected five-year term beginning in February
2005 for $275.2 million. The second VPP sold 10.8 MMBbls of Spraberry field oil
volumes over an expected seven-year term beginning in January 2006 for $317.1
million.
During April 2005, the Company sold less than one percent of its total
proved reserves, or 7.3 MMBOE of proved reserves, by means of another VPP for
net proceeds of $300.4 million, including the value of certain derivative hedge
agreements assigned to the buyer of the VPP. Proceeds from the VPP were
initially used to pay down indebtedness. The VPP sold 6.0 Bcf of Spraberry field
gas volumes over an expected 32-month term beginning in May 2005 and 6.2 MMBbls
of Spraberry field oil volumes over an expected five-year term beginning in
January 2006. See Notes L and N of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements" for additional information regarding
the Company's VPPs.
Asset Divestitures
During April 2005, the Company announced the signing of a definitive
agreement for the sale of three non- strategic Canadian properties and completed
the sale of certain East Texas properties for expected aggregate sales proceeds
of approximately $232 million.
Canadian divestiture. The Company's Canadian divestiture includes all of
the Company's interests in Martin Creek, Conroy Black and Lookout Butte oil and
gas properties for expected proceeds of approximately $207 million, subject to
normal closing adjustments. As of March 1, 2005, the Company's net proved
reserves in these properties were estimated to be approximately 9 MMBOE. The
Company's current net production from the properties averages approximately
3,000 BOEPD. The Canadian divestiture is expected to be completed during the
second quarter of 2005, although no assurances can be given that the transaction
will be completed as planned.
East Texas divestiture. During April 2005, the Company completed the
aforementioned divestiture of East Texas properties for approximately $25
million of net cash proceeds. As of March 31, 2005, the Company's net proved
reserves in these properties were estimated to be approximately 2.5 MMBOE. The
Company's net production from the properties averaged approximately 400 BOEPD.
The net cash proceeds from this divestiture were used to reduce outstanding
indebtedness.
Second Quarter 2005 Outlook
Based on current estimates, the Company expects that second quarter 2005
production will average 185,000 to 205,000 BOEPD, including a full quarter of
production from Canyon Express, continued ramp up of production from Devils
Tower, typical variability in the timing of oil cargo shipments in South Africa
and Tunisia and the impact of a full quarter of VPP volumes sold.
Second quarter production costs (including production and ad valorem taxes)
are expected to average $6.25 to $6.75 per BOE based on current NYMEX strip
prices for oil and gas. DD&A expense is expected to average $9.10 to $9.60 per
BOE during the second quarter of 2005.
Total exploration and abandonment expense is expected to be $50 million to
$70 million and includes carryover costs associated with unsuccessful wells that
were in progress at the end of the first quarter of 2005, plans to drill two
deepwater Gulf of Mexico exploration wells and the acquisition of additional
seismic data. General and administrative expense is expected to be $27 million
to $29 million. Interest expense is expected to be $29 million to $32 million,
and accretion of discount on asset retirement obligations is expected to be
approximately $2 million to $3 million.
28
PIONEER NATURAL RESOURCES COMPANY
The Company's second quarter 2005 effective income tax rate is expected to
range from 36 percent to 39 percent based on current capital spending plans,
including cash income taxes of $5 million to $10 million that are principally
related to Argentine and Tunisian income taxes and nominal alternative minimum
tax in the U.S. Other than in Argentina and Tunisia, the Company continues to
benefit from the carryforward of net operating losses and other positive tax
attributes.
Acquisition and Drilling Highlights
During the first quarter of 2005, the Company incurred $285.5 million in
finding and development costs including $149.5 million for development
activities, $101.7 million for exploration activities and $34.3 million on
acquisitions. The majority of the Company's development and exploration
expenditures were spent on drilling wells, acquiring seismic data and
constructing infrastructure for the Company's development projects. The
following tables summarize the Company's development and exploration/extension
drilling activities for the three months ended March 31, 2005:
Development Drilling
---------------------------------------------------------------------------
Beginning Wells Wells Successful Unsuccessful Ending Wells
in Progress Spud Wells Wells In Progress
--------------- --------- ---------- ------------ ------------
United States................. 32 101 109 1 23
Argentina..................... 6 22 20 2 6
Canada........................ 2 28 25 - 5
------ ------ ------ ------ ------
Total Worldwide......... 40 151 154 3 34
====== ====== ====== ====== ======
Exploration/Extension Drilling
---------------------------------------------------------------------------
Beginning Wells Wells Successful Unsuccessful Ending Wells
in Progress Spud Wells Wells In Progress
--------------- --------- ---------- ------------ ------------
United States................ 9 6 4 1 10
Argentina.................... 8 - 6 1 1
Canada....................... 21 16 22 5 10
Africa....................... 4 3 - 2 5
------ ------ ------ ------ ------
Total Worldwide......... 42 25 32 9 26
====== ====== ====== ====== ======
Domestic. The Company spent $153.3 million during the first quarter of 2005
on acquisition, drilling and seismic activities in the Gulf of Mexico, onshore
Gulf Coast, Permian Basin, Mid-Continent, Rocky Mountain and Alaska areas of the
United States.
Gulf of Mexico area. In the Gulf of Mexico area, the Company spent $47.8
million of drilling, construction, acquisition and seismic capital during the
first quarter of 2005. In the first quarter the Company was awarded leases on
three Gulf of Mexico deepwater blocks covering approximately 17,000 acres. The
Company was also the high bidder and is currently awaiting Mineral Management
Services approval on ten additional deepwater blocks covering approximately
46,000 acres. The following are updates of four projects in the deepwater Gulf
of Mexico:
o Canyon Express - Production from the Canyon Express gas system was shut in
in early December 2004 as a result of damage caused by Hurricane Ivan to
the methanol delivery system. In mid-February 2005, repair activities were
completed and production operations were resumed. Pioneer maintains
business interruption insurance on the Canyon Express project and as a
result of the damage caused by Hurricane Ivan, the Company has accrued $9.7
million in the first quarter for its estimated claim for production loss.
The Company has the potential to recover an additional amount under its
business interruption policy depending on the outcome of the determination
of the timing of the waiting period under the policy.
o Falcon Corridor - During the first quarter of 2005, production activities
in the Falcon Corridor occurred as expected. The Raptor well was shut in in
early March 2005 as the production volumes had declined to a level that
29
PIONEER NATURAL RESOURCES COMPANY
made it difficult to produce without substantially limiting production from
the Company's Falcon wells. Sidetrack operations are planned for the Raptor
field during the second quarter of 2005 to further increase reserve
recovery. The Company drilled an exploration well on the Hellcat prospect,
a Falcon Corridor satellite prospect, during the first quarter of 2005, but
the well was determined to be noncommercial.
o Devils Tower Area - The Devils Tower facilities sustained significant
damage in mid-September 2004 due to Hurricane Ivan, and production from the
three wells producing at that time did not resume until late October 2004.
A fourth well began producing at the end of November. The damage to the
platform rig sustained during Hurricane Ivan delayed completion activities
related to the four additional wells previously drilled to develop the
field. Rig repairs took over 120 days, and completion activities for
continued field development began late in January 2005. Pioneer maintains
business interruption insurance and has filed a claim related to (a)
production lost from its productive wells and (b) four wells that were
expected to be completed but were delayed due to the effects of Hurricane
Ivan. In the first quarter of 2005, the Company received a partial payment
of $14.3 million of estimated business interruption recovery related to its
claim. In the fourth quarter of 2004 and the first quarter of 2005, the
Company recorded $7.6 million and $15.1 million of estimated business
interruption recovery, respectively, related to its claim. The Company
expects to have additional business interruption insurance recoveries
related to future periods as a result of losses associated with delays in
completing certain wells. In addition, three subsea tie-back wells in the
Goldfinger and Triton satellite discoveries in the Devils Tower area are
expected to be jointly tied back to the Devils Tower spar with first
production expected in late 2005. Production is expected to continue to
increase as the remaining wells are completed and certain other wells are
recompleted to new zones. The Company holds a 25 percent working interest
in each of the above projects.
o Thunder Hawk - During 2004, the Company participated in a successful
exploration well on the Dominion- operated Thunder Hawk prospect located in
Mississippi Canyon Block 734. The well encountered in excess of 300 feet of
net oil pay in two high-quality reservoir zones. Murphy Exploration and
Production Company is now the operator and has commenced drilling an
additional well to further delineate the field. The Company owns a 12.5
percent working interest in the discovery.
Onshore Gulf Coast area. In the Onshore Gulf Coast area, the Company spent
$11.2 million of drilling, construction, acquisition and seismic capital during
the first quarter of 2005. The Company has focused its drilling efforts in this
area on the Pawnee field in the Edwards Reef trend in South Texas. The Company
plans to drill approximately 12 wells in this area during 2005.
Permian Basin area. The Company spent $25.5 million of capital during the
first quarter of 2005 primarily on development drilling in the Spraberry oil
trend where the Company plans to drill approximately 175 wells during 2005.
Mid-Continent area. The Company spent $7.0 million of capital during the
first quarter of 2005 primarily in the West Panhandle field in Texas where the
Company plans to drill approximately 90 wells during 2005. The Company also
plans to drill approximately 20 wells during 2005 in the Hugoton field in
Kansas.
Rocky Mountain area. The Company spent $25.2 million of capital during the
first quarter of 2005 primarily on development drilling in the Raton Basin in
Colorado. The Company plans on drilling approximately 300 wells during 2005 in
the Rocky Mountain area.
Alaska area. The Company spent $36.6 million of acquisition, drilling and
seismic capital during the first quarter of 2005 to drill wells, add to its
leasehold position and expand its North Slope seismic data coverage.
During the first quarter of 2005, the Company participated in three
exploration wells. Two wells were drilled in the NPR-A and the results are
currently being evaluated. The third well was drilled on the Tuvaaq prospect
operated by Kerr-McGee. The Tuvaaq well encountered wet sands in the primary
Ivishak objective and hydrocarbon-bearing sands in the Schrader Bluff interval.
The Company elected to assign its interest in the well to Kerr-McGee in lieu of
payment of its capital costs rather than participate in the Schrader Bluff
interval due to the Company's small working interest in any potential
development.
30
PIONEER NATURAL RESOURCES COMPANY
Pioneer also holds a 50 percent working interest in a 130,000-acre position
adjacent to and south of the giant Prudhoe Bay and Kuparuk Units, and during the
first quarter of 2005, shot a new 3-D seismic survey over the area.
International. The Company's international operations are located in the
Neuquen and Austral Basins areas of Argentina, the Chinchaga, Martin Creek,
Lookout Butte and Carbon areas of Canada, the Sable oil field offshore South
Africa and in southern Tunisia. Additionally, the Company has other development
and exploration activities in Equatorial Guinea, Nigeria, South Africa and
Tunisia.
Argentina. The Company spent $26.1 million of acquisition, drilling and
seismic capital during the first quarter of 2005.
Canada. The Company spent $54.7 million of acquisition, drilling and
seismic capital during the first quarter of 2005, primarily in the Chinchaga and
Carbon areas that are only accessible for drilling during the winter months.
During April 2005, the Company announced the signing of a definitive
agreement for the sale of three non- strategic Canadian properties in Martin
Creek, Conroy Black and Lookout Butte for expected proceeds of approximately
$207 million, subject to normal closing adjustments. The Canadian divestiture is
expected to be completed during the second quarter of 2005. See Note N of Notes
to Consolidated Financial Statements included in "Item 1. Financial Statements".
Africa. The Company spent $51.4 million of acquisition, drilling and
seismic capital during the first quarter of 2005, primarily in Equatorial
Guinea, Gabon, Nigeria, South Africa and Tunisia.
Equatorial Guinea. The Company spent $.5 million of seismic and drilling
capital during the first quarter of 2005 in Block H offshore Equatorial Guinea.
The Company has several other prospects on the block that are being evaluated
for future drilling, one of which is expected to be drilled during 2005.
Gabon. The Company spent $.5 million of capital during the first quarter of
2005. In 2004 the Company drilled five exploration wells, one of which was
initially evaluated as successful in extending the planned development area to
the south. The remaining four wells were unsuccessful. Despite the successful
extension well, in October 2004 the Company canceled the development of the
Olowi field due to a substantial increase in projected development costs which
resulted in the project not offering competitive returns. The Company's current
Gabonese permit was extended to January 2006 to allow more time for the Company
to determine if it has any viable options to monetize its investment prior to
abandoning the project and exiting Gabon. During the first quarter of 2005, the
Company recognized an additional impairment charge of $.2 million.
Nigeria. The Company spent $43.1 million of acquisition, drilling and
seismic capital during the first quarter of 2005. The Company joined Oranto
Petroleum and Orandi Petroleum in an existing production sharing contract on
Block 320 in deepwater Nigeria gaining exploration rights from the Nigerian
National Petroleum Corporation. The 442,000 acre block is located about 90 miles
southeast of Lagos in water depths ranging between 6,900 to 8,900 feet. The
Company owns a 51 percent working interest and is the technical operator. Under
terms of an existing production sharing contract, Pioneer and the other
participants will carry out a work program that includes acquiring a minimum of
1,790 square kilometers of 3-D seismic data and drilling at least one
exploration well by February of 2007. The Company farmed-in to the
Devon-operated Block 256 during the first quarter and participated in an
unsuccessful exploration well.
South Africa. The Company spent $.3 million of drilling and seismic capital
during the first quarter of 2005. During 2005, the Company currently plans to
spend approximately $1 million in South Africa for production enhancement
opportunities at Sable.
Tunisia. The Company spent $5.0 million of drilling and seismic capital
during the first quarter of 2005 primarily to drill one exploration well in its
partner-operated Adam oil field and one unsuccessful exploration well in its
Company- operated El Hamra permit. The remaining capital budget for Tunisia in
2005 includes two appraisal wells on the Anaguid permit.
31
PIONEER NATURAL RESOURCES COMPANY
Results of Operations
Oil and gas revenues. Revenues from oil and gas operations totaled $520.3
million for the three months ended March 31, 2005 as compared to $435.5 million
for the same period in 2004, representing a 19 percent increase. The revenue
increase from 2004 to 2005 was due to a four percent increase in average daily
BOE sales volumes, an 18 percent increase in oil prices, a 21 percent increase
in NGL prices and a 15 percent increase in gas prices, including the effects of
commodity price hedges.
The following table provides average daily sales volumes, by geographic
area and in total, for the three-month periods ended March 31, 2005 and 2004:
Three months ended
March 31,
----------------------
2005 2004
-------- --------
Average daily sales volumes:
Oil (Bbls)
United States.......................... 28,723 24,971
Argentina.............................. 8,191 8,628
Canada................................. 230 100
Africa................................. 11,967 14,034
-------- --------
Worldwide.............................. 49,111 47,733
======== ========
NGLs (Bbls)
United States.......................... 17,543 20,936
Argentina.............................. 1,572 1,424
Canada................................. 601 1,046
-------- --------
Worldwide.............................. 19,716 23,406
======== ========
Gas (Mcf)
United States.......................... 538,285 527,630
Argentina.............................. 130,351 97,818
Canada................................. 49,546 40,019
-------- --------
Worldwide.............................. 718,182 665,467
======== ========
Total (BOE)
United States.......................... 135,980 133,845
Argentina.............................. 31,488 26,355
Canada................................. 9,089 7,816
Africa................................. 11,967 14,034
-------- --------
Worldwide.............................. 188,524 182,050
======== ========
Worldwide average daily sales volumes on a BOE basis increased four percent
during the first quarter of 2005 as compared to the first quarter of 2004. On a
quarter-to-quarter comparison, average daily BOE sales volumes increased by two
percent in the United States, by 19 percent in Argentina and by 16 percent in
Canada and decreased by 15 percent in Africa.
The increase in daily sales volumes in the United States was principally
due to production from the properties acquired in the Evergreen merger on
September 28, 2004 and production from the Devils Tower oil field which first
began producing during May 2004, partially offset by approximately 4,000 BOEPD
of Hugoton VPP volumes sold during the first quarter of 2005 which are not
included in the Company's reported sales volumes, production lost at Canyon
Express associated with the aforementioned hurricane damage and normal
production declines.
Canadian sales volumes increased due to new production from Canadian
properties acquired in the Evergreen merger and the influx of production from
new wells drilled during the winter drilling seasons.
On a quarter-to-quarter comparison, Argentine average daily BOE sales
volumes increased as a result of increases in wells drilled. The Company has
continued to increase capital expenditures in Argentina as the stability of the
Argentine peso and the general economic outlook for Argentina has improved.
32
PIONEER NATURAL RESOURCES COMPANY
The following table provides average reported prices, including the results
of hedging activities, and average realized prices, excluding the results of
hedging activities, by geographic area and in total, for the three-month periods
ended March 31, 2005 and 2004:
Three months ended
March 31,
----------------------
2005 2004
-------- --------
Average reported prices:
Oil (per Bbl):
United States...................... $ 28.96 $ 26.67
Argentina.......................... $ 31.75 $ 27.93
Canada............................. $ 53.81 $ 35.00
Africa............................. $ 44.28 $ 31.41
Worldwide.......................... $ 33.27 $ 28.31
NGLs (per Bbl):
United States...................... $ 26.15 $ 21.52
Argentina.......................... $ 30.35 $ 29.16
Canada............................. $ 39.07 $ 26.51
Worldwide.......................... $ 26.88 $ 22.21
Gas (per Mcf):
United States...................... $ 5.94 $ 5.10
Argentina.......................... $ .88 $ .58
Canada............................. $ 6.17 $ 4.22
Worldwide.......................... $ 5.04 $ 4.38
Average realized prices:
Oil (per Bbl):
United States...................... $ 46.08 $ 32.72
Argentina.......................... $ 31.75 $ 30.67
Canada............................. $ 53.81 $ 35.00
Africa............................. $ 44.28 $ 31.91
Worldwide.......................... $ 43.29 $ 32.12
NGLs (per Bbl):
United States...................... $ 26.15 $ 21.52
Argentina.......................... $ 30.35 $ 29.16
Canada............................. $ 39.07 $ 26.51
Worldwide.......................... $ 26.88 $ 22.21
Gas (per Mcf):
United States...................... $ 6.10 $ 5.32
Argentina.......................... $ .88 $ .58
Canada............................. $ 6.19 $ 5.21
Worldwide.......................... $ 5.16 $ 4.62
Hedging activities. The oil and gas prices that the Company reports are
based on the market price received for the commodities adjusted by the results
of the Company's cash flow hedging activities. The Company utilizes commodity
swap and collar contracts in order to (i) reduce the effect of price volatility
on the commodities the Company produces and sells, (ii) support the Company's
annual capital budgeting and expenditure plans and (iii) reduce commodity price
risk associated with certain capital projects. During the first quarter of 2005,
the Company's commodity price hedges decreased oil and gas revenues by $52.3
million, as compared to $30.7 million during the same period in 2004. See Note F
of Notes to Consolidated Financial Statements included in "Item 1. Financial
Statements" for specific information regarding the Company's hedging activities
during the three-month periods ended March 31, 2005 and 2004.
Argentina commodity prices. Argentine commodity prices have been
significantly below those in the world markets for a period of time. In May
2004, pursuant to a decree, the Argentine government approved measures to permit
producers to renegotiate gas sales contracts, excluding those that could affect
small residential customers. Pursuant to that decree, wellhead prices are
scheduled to rise from a 2004 year end range of $.61 to $.78 per Mcf to a range
of $.87 to $1.04 per Mcf after July 2005, depending on the region where the gas
is produced. No further gas price increases beyond July 2005 were allowed for in
the decree. Also, due to the Argentine export tax (expires in February 2007) and
price caps required by the Argentine government on oil prices paid by Argentine
refiners, the price of Argentine oil has been below that realized in world
markets. For additional information regarding the suppressed Argentine commodity
prices see the Company's 2004 Form 10-K, as amended. At the present time, no
33
PIONEER NATURAL RESOURCES COMPANY
specific predictions can be made about future commodity prices in Argentina.
However, in the short term, the Company expects Argentine commodity price
realizations to be less than those in the United States.
Interest and other income. Interest and other income for the three-month
periods ended March 31, 2005 and 2004 was $28.3 million and $1.7 million,
respectively. The increase in interest and other income is attributable to the
recognition of $24.8 million in business interruption insurance claims
associated with lost production as a result of the damage caused by Hurricane
Ivan to the Devils Tower facilities and the Canyon Express methanol delivery
system. See Note M of Notes to Consolidated Financial Statements included in
"Item 1. Financial Statements" for additional information regarding the
Company's business interruption insurance claims.
Oil and gas production costs. The Company recorded production costs of
$114.0 million and $78.2 million during the three-month periods ended March 31,
2005 and 2004, 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 production taxes and ad valorem taxes are
directly related to commodity price changes. Total production costs per BOE
increased by 42 percent during the three months ended March 31, 2005 as compared
to the same respective period in 2004 primarily due to (i) an increase in ad
valorem taxes, (ii) additional workover activities performed during Canada's
winter access season, (iii) the retention of operating costs related to VPP
volumes sold, and (iv) new production added from the Evergreen merger which
represent higher operating cost properties than the Company's other United
States properties.
The following tables provide the components of the Company's total
production costs per BOE and total production costs per BOE by geographic area
for the three-month periods ended March 31, 2005 and 2004:
Three months ended
March 31,
------- -------
2005 2004
------- -------
Lease operating expense................ $ 5.01 $ 3.43
Taxes:
Ad valorem.......................... .58 .47
Production.......................... .78 .59
Workover costs......................... .35 .23
------ ------
Total production costs.............. $ 6.72 $ 4.72
====== ======
Three months ended
March 31,
-------------------
2005 2004
------- -------
Total production costs:
United States....................... $ 7.04 $ 4.52
Argentina........................... $ 3.00 $ 2.82
Canada.............................. $ 14.11 $ 11.18
Africa ............................. $ 7.21 $ 6.64
Worldwide........................... $ 6.72 $ 4.72
Depletion, depreciation and amortization expense. The Company's total DD&A
expense was $9.20 and $8.24 per BOE for the three-month periods ended March 31,
2005 and 2004, respectively. Depletion expense, the largest component of DD&A
expense, increased to $8.92 per BOE for the three months ended March 31, 2005,
as compared to $8.08 during the same respective period in 2004. The increase in
per BOE depletion expense during the three months ended March 31, 2005, as
compared to the same period in 2004, is primarily due to new Rocky Mountain area
production acquired in the Evergreen merger and a higher depletion rate for the
Hugoton field as a result of the VPP volumes sold. Additionally, the Company's
depletion expense per BOE increased in Argentina and declined in Africa on
quarter-to- quarter comparisons due to net downward reserve revisions in
Argentina and upward reserve revisions in South Africa and Tunisia during 2004.
34
PIONEER NATURAL RESOURCES COMPANY
The following table provides depletion expense per BOE by geographic area
for the three-month periods ended March 31, 2005 and 2004:
Three months ended
March 31,
-------------------
2005 2004
------- -------
Depletion expense:
United States......................... $ 9.35 $ 7.99
Argentina............................. $ 6.33 $ 5.23
Canada................................ $ 11.73 $ 10.51
Africa ............................... $ 8.71 $ 12.84
Worldwide............................. $ 8.92 $ 8.08
Exploration, abandonments, geological and geophysical costs. Exploration,
abandonments, geological and geophysical costs were $67.4 million during the
three months ended March 31, 2005, as compared to $80.5 million during the same
period of 2004. The following table provides the Company's geological and
geophysical costs, exploratory dry hole expense, lease abandonments and other
exploration expense by geographic area for the three-month periods ended March
31, 2005 and 2004:
Africa
United and
States Argentina Canada Other Total
------- --------- ------- ------- ---------
(in thousands)
Three months ended March 31, 2005:
Geological and geophysical............ $25,722 $ 1,675 $ 986 $ 9,410 $ 37,793
Exploratory dry holes................. 11,516 889 2,865 11,556 26,826
Leasehold abandonments and other...... 2,241 20 186 319 2,766
------ ------ ------ ------ -------
$39,479 $ 2,584 $ 4,037 $21,285 $ 67,385
====== ====== ====== ====== =======
Three months ended March 31, 2004:
Geological and geophysical............ $15,769 $ 3,130 $ 1,147 $ 1,733 $ 21,779
Exploratory dry holes................. 36,968 405 8,170 8,684 54,227
Leasehold abandonments and other...... 819 15 3,659 7 4,500
------ ------ ------ ------ -------
$53,556 $ 3,550 $12,976 $10,424 $ 80,506
====== ====== ====== ====== =======
The decrease in exploration, abandonments, geological and geophysical costs
during the first quarter of 2005, as compared to the first quarter of 2004, is
primarily comprised of a $27.4 million decrease in dry hole expense, offset by a
$16.0 million increase in geological and geophysical expense. Significant
components of the Company's dry hole expense during the first quarter of 2005
included $9.1 million associated with an unsuccessful Nigerian well, $9.0
million associated with an unsuccessful well testing a satellite prospect in the
Falcon Corridor and $2.4 million on an unsuccessful well on the Company's El
Hamra permit in Tunisia. During the first three months of 2005, the Company
drilled and evaluated 41 exploration/extension wells, 32 of which were
successfully completed as discoveries. During the same period in 2004, the
Company drilled and evaluated 52 exploration/extension wells, 26 of which were
successfully completed as discoveries.
General and administrative expense. General and administrative expense for
the three-month periods ended March 31, 2005 and 2004 was $29.6 million and
$18.3 million, respectively. The increase in general and administrative expense
was primarily due to increases in administrative staff, including staff
increases associated with the Evergreen merger, and performance-related
compensation costs including the amortization of restricted stock awarded to
officers, directors and employees during the quarter ended March 31, 2005, as
compared to the same period of 2004.
Accretion of discount on asset retirement obligations. During the
three-month periods ended March 31, 2005 and 2004, accretion of discount on
asset retirement obligations was $2.1 million and $2.0 million, respectively.
The increase in accretion of discount on asset retirement obligations is
primarily due to the increase in future plugging and abandonment obligations
related to new wells in the deepwater Gulf of Mexico, Tunisia and South Africa
and accretion of discount on asset retirement obligations assumed with the
Evergreen merger. See Note G of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements" for additional information regarding
the Company's asset retirement obligations.
35
PIONEER NATURAL RESOURCES COMPANY
Interest expense. Interest expense was $33.3 for the three months ended
March 31, 2005, as compared to $21.6 million for the same periods in 2004. The
weighted average interest rates on the Company's indebtedness for the three
months ended March 31, 2005 was 6.0 percent, as compared to 5.3 percent for the
same period in 2004, taking into account the effect of interest rate
derivatives. The increase in interest expense was primarily due to a $5.2
million decrease in interest rate hedge gains, a $.9 million decrease in
capitalized interest as the Company completed its major development projects in
the Gulf of Mexico and South Africa, increased borrowings under the Company's
lines of credit, primarily as a result of the Evergreen merger, and the
assumption of $300 million of notes in connection with the Evergreen merger.
Other expenses. Other expenses for the three-month periods ended March 31,
2005 and 2004 were $11.7 million and $.2 million, respectively. The increase in
other expenses is primarily attributable to a $6.8 million increase in hedge
ineffectiveness, a $2.8 million increase in legal and environmental accruals and
$.8 million of non-compete agreement amortization associated with the Evergreen
merger.
Income tax provision. During the three months ended March 31, 2005, the
Company recognized income tax provisions of $51.9 million, as compared to $39.8
million for the same period in 2004. The Company's first quarter of 2005
effective tax rate of 38.0 percent is higher than the combined United States
federal and state statutory rate of approximately 36.5 percent primarily due to
foreign tax rates, statutes that differ from those in the United States and
expenses for unsuccessful well costs in foreign locations where the Company
receives no expected income tax benefits.
Capital Commitments, Capital Resources and Liquidity
Capital commitments. The Company's primary needs for cash are for
exploration, development and acquisitions of oil and gas properties, repayment
of contractual obligations and working capital obligations. Funding for
exploration, development and acquisitions of oil and gas properties and
repayment of contractual obligations may be provided by any combination of
internally-generated cash flow, proceeds from the disposition of non-strategic
assets or alternative financing sources as discussed in "Capital resources"
below. Generally, funding for the Company's working capital obligations is
provided by internally-generated cash flow.
Oil and gas properties. The Company's cash expenditures for additions to
oil and gas properties during the three- month periods ended March 31, 2005 and
2004 totaled $226.2 million and $167.2 million, respectively. The expenditures
for additions to oil and gas properties were internally funded by $334.9 million
and $253.6 million, respectively, of net cash provided by operating activities.
Contractual obligations, including off-balance sheet obligations. The
Company's contractual obligations include long-term debt, operating leases,
drilling commitments, derivative obligations, other liabilities and VPP
obligations. 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 March 31, 2005, the material off-balance sheet
arrangements and transactions that the Company has entered into include (i)
$54.7 million of undrawn letters of credit, (ii) operating lease agreements,
(iii) drilling commitments, (iv) VPP obligations (to physically deliver volumes
and pay related costs in the future) 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
and gas transportation commitments. Since December 31, 2004, the material
changes in the Company's contractual obligations were changes in the Company's
derivative obligations and the aforementioned sale of VPPs. There have been no
other material changes in the Company's contractual obligations since December
31, 2004. See "Item 3. Quantitative and Qualitative Disclosures About Market
Risk" for a table of changes in the fair value of the Company's open derivative
contract liabilities during the three months ended March 31, 2005.
Capital resources. The Company's primary capital resources are net cash
provided by operating activities, proceeds from financing activities and
proceeds from sales of non-strategic assets. The Company expects that these
resources will be sufficient to fund its capital commitments during the
remainder of 2005.
36
PIONEER NATURAL RESOURCES COMPANY
Operating activities. Net cash provided by operating activities during the
three-month periods ended March 31, 2005 and 2004 were $334.9 million and $253.6
million, respectively. The increase in net cash provided by operating activities
was primarily due to increased production volumes and higher commodity prices.
Investing activities. Net cash provided by investing activities during the
three months ended March 31, 2005 was $361.9 million as compared to net cash
used in investing activities of $172.3 million during the same respective period
in 2004. The increase in net cash provided by investing activities was primarily
due to the $592.3 million of net proceeds from VPPs.
As previously discussed, the Company received $300.4 million of net
proceeds from a third VPP transaction completed during April 2005. See Notes L
and N of Notes to Consolidated Financial Statements included in "Item 1.
Financial Statements" for more information regarding the Company's VPP
transactions completed during 2005.
Financing activities. Net cash used in financing activities during the
three months ended March 31, 2005 was $688.2 million, as compared to $91.4
million during the same period in 2004. The Company had net repayments on long-
term debt of $553.0 million, as compared to $90.0 million during the same period
in 2004.
During February 2005, the Company's board of directors declared a
semiannual dividend of $.10 per common share, payable on April 15, 2005 to
shareholders of record on March 31, 2005. Associated therewith, the Company
distributed $14.7 million of aggregate dividends during April 2005. The
Company's board of directors may change the current dividend amount in the
future if warranted by future liquidity and capital resource attributes.
During April 2005, $131.0 million of the Company's 8-7/8% Notes matured and
were repaid. The Company also redeemed $32.4 million principal amount of its
9-5/8% Notes. The Company will recognize a pretax loss on the redemption of the
9-5/8% Notes of $7.3 million during the second quarter of 2005. The Company
utilized unused borrowing capacity under its 364-Day Credit Agreement to fund
these financing activities.
During the three months ended March 31, 2005, the Company expended $151.9
million to acquire 3.7 million shares of treasury stock. During January 2005,
the Company's board of directors approved a share repurchase program authorizing
the purchase of $300 million of the Company's common stock. Based on current
expectations, the Company intends to expend the remaining $148.1 million
authorized under the share repurchase program during the remainder of 2005.
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 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 Company's board of directors.
Liquidity. The Company's principal source of short-term liquidity is its
revolving lines of credit. Outstanding borrowings under the lines of credit
totaled $275 million as of March 31, 2005. Including $49.3 million of undrawn
and outstanding letters of credit under the lines of credit, the Company had
$1.0 billion of unused borrowing capacity as of March 31, 2005.
During April 2005, the Company reduced the loan commitments under the
364-Day Credit Agreement by $200 million to $450 million, which reduces the
Company's total borrowing capacity under its lines of credit to $1.15 billion.
Book capitalization and current ratio. The Company's book capitalization at
March 31, 2005 was $4.3 billion, consisting of debt of $1.8 billion and
stockholders' equity of $2.5 billion. Consequently, the Company's debt to book
capitalization decreased to 42 percent at March 31, 2005 from 46 percent at
December 31, 2004. The Company's ratio of current assets to current liabilities
was .53 to 1.00 at March 31, 2005 as compared to .72 to 1.00 at December 31,
2004. The decline in the Company's ratio of current assets to current
liabilities was primarily due to increases in its current derivative liabilities
as a result of higher commodity prices and in current deferred revenues as a
result of the VPPs.
37
PIONEER NATURAL RESOURCES COMPANY
Item 3. Quantitative and Qualitative Disclosures About Market Risk
The following quantitative and qualitative disclosures about market risk
are supplementary to the quantitative and qualitative disclosures provided in
the Company's Annual Report on Form 10-K for the year ended December 31, 2004.
As such, the information contained herein should be read in conjunction with the
related disclosures in the Company's Annual Report on Form 10-K, as amended, for
the year ended December 31, 2004.
Although certain derivative contracts that the Company has been a party to
did not qualify as hedges, the Company does not enter into derivative or other
financial instruments for trading purposes.
The following table reconciles the changes that occurred in the fair values
of the Company's open derivative contracts during the first quarter of 2005:
Derivative Contract Net Liabilities
---------------------------------------
Interest
Commodities Rate Total
----------- -------- ----------
(in thousands)
Fair value of contracts outstanding
as of December 31, 2004............... $ (406,546) $ - $ (406,546)
Changes in contract fair values (a)...... (516,615) (1,563) (518,178)
Contract maturities...................... 55,899 - 55,899
Contract terminations.................... 48,057 1,563 49,620
--------- ------- ---------
Fair value of contracts outstanding
as of March 31, 2005.................. $ (819,205) $ - $ (819,205)
========= ======= =========
- ---------------
(a) At inception, new derivative contracts entered into by the Company have no
intrinsic value.
Interest rate sensitivity. The following table provides information about
other financial instruments the Company was a party to as of March 31, 2005 and
that are sensitive to changes in interest rates. For debt obligations, the table
presents 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 debt's estimated fair value. For fixed rate debt, the
weighted average interest rate represents the contractual fixed rates that the
Company was obligated to periodically pay on the debt as of March 31, 2005. For
variable rate debt, the average interest rate represents the average rates being
paid on the debt projected forward proportionate to the forward yield curve for
LIBOR on May 3, 2005.
Interest Rate Sensitivity
Debt Obligations and Derivative Financial Instruments as of March 31, 2005
Nine months Liability
ending Year ending December 31, Fair Value at
December 31, ----------------------------------------------------- March 31,
2005 2006 2007 2008 2009 Thereafter Total 2005
----------- ------- -------- -------- -------- ---------- --------- -----------
(in thousands, except interest rates)
Total Debt:
Fixed rate principal
maturities (a).............. $130,950 $ - $ 32,075 $350,000 $ - $1,151,579 $1,664,604 $(1,823,784)
Weighted average
interest rate (%).......... 6.28 6.40 6.39 7.04 7.04 7.04
Variable rate maturities..... $ - $ - $ - $275,000 $ - $ - $ 275,000 $ (275,000)
Average interest rate (%).. 3.73 4.25 4.44 4.57 - -
- -------------
(a) Represents maturities of principal amounts excluding (i) debt issuance
discounts and premiums and (ii) deferred fair value hedge gains and losses.
38
PIONEER NATURAL RESOURCES COMPANY
Commodity price sensitivity. The following tables provide information about
the Company's oil and gas derivative financial instruments that were sensitive
to changes in oil or gas prices as of March 31, 2005. As of March 31, 2005, all
of the Company's oil and gas derivative financial instruments qualified as
hedges.
See Note F of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for information regarding the terms of the Company's
derivative financial instruments that are sensitive to changes in oil and gas
prices.
Oil Price Sensitivity
Derivative Financial Instruments as of March 31, 2005
Nine months Liability
ending Year ending December 31, Fair Value at
December 31, ---------------------------------------------------- March 31,
2005 2006 2007 2008 2009 2010 2005
----------- -------- -------- -------- -------- -------- -----------
(in thousands)
Oil Hedge Derivatives (a):
Average daily notional Bbl volumes:
Swap contracts (b)................ 27,000 11,973 13,000 20,278 1,643 1,643 $(506,128)
Weighted average fixed price
per Bbl......................... $ 27.97 $ 35.43 $ 30.89 $ 32.46 $ 47.25 $ 46.40
Collar contracts.................. - 3,500 - - - - $ (17,229)
Weighted average ceiling price
per Bbl......................... $ - $ 41.95 $ - $ - $ - $ -
Weighted average floor price
per Bbl......................... $ - $ 35.00 $ - $ - $ - $ -
Average forward NYMEX oil
prices (c)...................... $ 52.82 $ 53.40 $ 51.80 $ 49.59 $ 48.74 $ 48.14
- ---------------
(a) See Note F of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for hedge volumes and weighted average prices by
calendar quarter.
(b) Subsequent to March 31, 2005, the Company conveyed to the purchaser of its
April VPP the following oil swap contracts which were included in the
schedule above: (i) 1,973 Bbls per day of 2006 oil sales at a weighted
average fixed price per Bbl of $54.40, (ii) 3,278 Bbls per day of 2008 oil
sales at a weighted average fixed price per Bbl of $49.28, (iii) 1,643 Bbls
per day of 2009 oil sales at a weighted average fixed price per Bbl of
$47.25 and (iv) 1,643 Bbls per day of 2010 oil sales at a weighted average
fixed price per Bbl of $46.40.
(c) The average forward NYMEX oil prices are based on May 3, 2005 market
quotes.
39
PIONEER NATURAL RESOURCES COMPANY
Gas Price Sensitivity
Derivative Financial Instruments as of March 31, 2005
Nine months Liability
ending Year ending December 31, Fair Value at
December 31, -------------------------------- March 31,
2005 2006 2007 2008 2005
----------- -------- -------- -------- -------------
(in thousands)
Gas Hedge Derivatives (a):
Average daily notional MMBtu volumes (b):
Swap contracts (c)........................ 278,873 80,000 35,000 5,000 $(292,303)
Weighted average fixed price per MMBtu... $ 5.22 $ 4.50 $ 4.63 $ 5.38
Collar contracts.......................... - 17,329 - - $ (3,545)
Weighted average ceiling price
per MMBtu.............................. $ - $ 9.14 $ - $ -
Weighted average floor price
per MMBtu.............................. $ - $ 6.67 $ - $ -
Average forward NYMEX gas prices (d)....... $ 7.05 $ 7.22 $ 6.82 $ 6.41
- ---------------
(a) To minimize basis risk, the Company enters into basis swaps for a portion
of its gas hedges to connect the index price of the hedging instrument from
a NYMEX index to an index which reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
collar contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(b) See Note F of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for hedge volumes and weighted average prices by
calendar quarter.
(c) Subsequent to March 31, 2005, the Company conveyed to the purchaser of its
April VPP the following gas swap contracts which were included in the
schedule above: (i) 5,841 MMBtu per day of 2005 gas sales at a weighted
average fixed price per MMBtu of $7.14, (ii) 6,158 MMBtu per day of 2006
gas sales at a weighted average fixed price per MMBtu of $6.90 and (iii)
5,805 MMBtu per day of 2007 gas sales at a weighted average fixed price per
MMBtu of $6.35.
(d) The average forward NYMEX gas prices are based on May 3, 2005 market
quotes.
Item 4. Controls and Procedures
Evaluation of disclosure controls and procedures. The Company's 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 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 quarterly report on
Form 10-Q. Based on that evaluation, the principal executive officer and
principal financial officer concluded that the design and operation of the
Company's disclosure controls and procedures are effective 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.
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 Company's
last fiscal quarter that have materially affected or are reasonably likely to
materially affect the Company's internal control over financial reporting.
40
PIONEER NATURAL RESOURCES COMPANY
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
The Company is party to various legal proceedings, which are described
under "Legal actions" in Note I of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements". The Company is also party to other
litigation incidental to its business. Except for the specific legal actions
described in Note I of Notes to Consolidated Financial Statements included in
"Item 1. Financial Statements", the Company believes that the probable damages
from such other legal actions will not be in excess of ten percent of the
Company's current assets.
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Purchases of Equity Securities by the Issuer and Affiliated Purchasers
The following table summarizes the Company's purchases of treasury stock
during the three months ended March 31, 2005:
Total Number of Shares
(or Units) Purchased
Total Number of Average Price as Part of Publicly
Shares (or Units) Paid per Share Announced Plans
Period Purchased (or Unit) or Programs
------ ----------------- -------------- ----------------------
January 2005................ 75,000 $ 38.177 75,000
February 2005............... 2,214,700 $ 39.141 2,214,700
March 2005.................. 1,450,400 $ 42.979 1,450,400
------------ ------------
Total............... 3,740,100 $ 40.610 3,740,100
============ ============
During January 2005, the Company's board of directors approved a share
repurchase program authorizing the purchase of up to $300 million of the
Company's common stock.
41
PIONEER NATURAL RESOURCES COMPANY
Item 6. Exhibits
Exhibits
10.1 Production Payment Purchase and Sale Agreement dated as of January 26,
2005 among the Company, as the Seller, and Royalty Acquisition
Company, LLC, as the Buyer (related to Hugoton gas) (incorporated by
reference to exhibit 99.2 to the Company's current report on Form 8-K,
File No. 1-13245, filed with the SEC on February 1, 2005).
10.2 Production Payment Purchase and Sale Agreement dated as of January 26,
2005 among the Company, as the Seller, and Royalty Acquisition
Company, LLC, as the Buyer (related to Spraberry oil) (incorporated by
reference to exhibit 99.3 to the Company's current report on Form
8-K, File No. 1-13245, filed with the SEC on February 1, 2005).
10.3 Second Amendment to 5-Year Revolving Credit Agreement dated as of
January 21, 2005 among the Company, as the Borrower; JPMorgan Chase
Bank as the Administrative Agent; JPMorgan Chase Bank and Bank of
America, N.A., as the Issuing Banks; Wachovia Bank, National
Association as the Syndication Agent; Bank of America, N.A., Bank
One, N.A., Fleet National Bank and Wells Fargo Bank, National
Association, as the Co-Documentation Agents; J.P. Morgan Securities
Inc. and Wachovia Capital Markets, LLC, as the Co-Arrangers and Joint
Bookrunners; and certain other lenders (incorporated by reference to
exhibit 99.1 to the Company's current report on Form 8-K, File No.
1-13245, filed with the SEC on January 27, 2005).
10.4 First Amendment to 364-Day Credit Agreement dated as of January 21,
2005 among the Company, as the Borrower; JPMorgan Chase Bank as the
Administrative Agent; Bank of America, N.A., Barclays Bank PLC, Wells
Fargo Bank, National Association and Wachovia Bank, National
Association as the Co-Documentation Agents; J.P. Morgan Securities
Inc. as the Lead Arranger and Sole Bookrunner; and certain other
lenders (incorporated by reference to exhibit 99.2 to the Company's
current report on Form 8-K, File No. 1-13245, filed with the SEC on
January 27, 2005).
10.5G Fourth Amendment to the Company's Long-Term Incentive Plan, effective
as of November 20, 2003.
10.6G Fifth Amendment to the Company's Long-Term Incentive Plan, effective
as of May 12, 2004.
10.7G Sixth Amendment to the Company's Long-Term Incentive Plan, effective
as of December 17, 2004.
10.8G Third Amendment to the Company's Employee Stock Purchase Plan, dated
August 21, 2000.
10.9G Fourth Amendment to the Company's Employee Stock Purchase Plan, dated
February 19, 2003.
10.10G First Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective January 10, 2003.
10.11G Second Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective April 16, 2003.
10.12G Third Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective June 16, 2003.
10.13G Fourth Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective December 24, 2003.
10.14G Fifth Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective September 28, 2004.
10.15G The Company's Executive Deferred Compensation Retirement Plan, Amended
and Restated Effective as of August 1, 2002.
10.16 Production Payment Purchase and Sale Agreement dated as of April 19,
2005 among the Company, as the Seller, and Wolfcamp Oil and Gas Trust,
as the Buyer (incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K, File No. 1-13245, filed with the
SEC on April 21, 2005).
10.17G Form of Omnibus Nonstatutory Stock Option Agreement for Non-employee
Directors.
10.18(a) Purchase and Sale Agreement dated as of April 28, 2005 among Pioneer
Natural Resources Canada Inc., as the Vendor, and Ketch Resources
Ltd., as the Purchaser.
10.19G Form of Restricted Stock Award Agreement.
10.20G Form of Omnibus Nonstatutory Stock Option Agreement for Option Award
Participants (Group 1).
10.21G Offer of Employment Letter dated as of April 8, 2005 among the Company
and Mark S. Berg.
31.1(a) Chief Executive Officer certification under Section 302 of Sarbanes-
Oxley Act of 2002.
31.2(a) Chief Financial Officer certification under Section 302 of Sarbanes-
Oxley Act of 2002.
32.1(b) Chief Executive Officer certification under Section 906 of Sarbanes-
Oxley Act of 2002.
32.2(b) Chief Financial Officer certification under Section 906 of Sarbanes-
Oxley Act of 2002.
- ---------------
(a) Filed herewith.
(b) Furnished herewith.
G Executive Compensation Plan or Arrangement filed herewith pursuant to Item
14(c).
42
PIONEER NATURAL RESOURCES COMPANY
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
Registrant has duly caused this report to be signed on its behalf by the
undersigned hereto duly authorized.
PIONEER NATURAL RESOURCES COMPANY
Date: May 6, 2005 By: /s/ Richard P. Dealy
----------------------------------
Richard P. Dealy
Executive Vice President and Chief
Financial Officer
Date: May 6, 2005 By: /s/ Darin G. Holderness
----------------------------------
Darin G. Holderness
Vice President and Chief
Accounting Officer
43
PIONEER NATURAL RESOURCES COMPANY
Exhibit Index
10.1 Production Payment Purchase and Sale Agreement dated as of January 26,
2005 among the Company, as the Seller, and Royalty Acquisition
Company, LLC, as the Buyer (related to Hugoton gas) (incorporated by
reference to exhibit 99.2 to the Company's current report on Form 8-K,
File No. 1- 13245, filed with the SEC on February 1, 2005).
10.2 Production Payment Purchase and Sale Agreement dated as of January 26,
2005 among the Company, as the Seller, and Royalty Acquisition
Company, LLC, as the Buyer (related to Spraberry oil) (incorporated by
reference to exhibit 99.3 to the Company's current report on Form 8-K,
File No. 1- 13245, filed with the SEC on February 1, 2005).
10.3 Second Amendment to 5-Year Revolving Credit Agreement dated as of
January 21, 2005 among the Company, as the Borrower; JPMorgan Chase
Bank as the Administrative Agent; JPMorgan Chase Bank and Bank of
America, N.A., as the Issuing Banks; Wachovia Bank, National
Association as the Syndication Agent; Bank of America, N.A., Bank One,
N.A., Fleet National Bank and Wells Fargo Bank, National Association,
as the Co-Documentation Agents; J.P. Morgan Securities Inc. and
Wachovia Capital Markets, LLC, as the Co-Arrangers and Joint
Bookrunners; and certain other lenders (incorporated by reference to
exhibit 99.1 to the Company's current report on Form 8-K, File No. 1-
13245, filed with the SEC on January 27, 2005).
10.4 First Amendment to 364-Day Credit Agreement dated as of January 21,
2005 among the Company, as the Borrower; JPMorgan Chase Bank as the
Administrative Agent; Bank of America, N.A., Barclays Bank PLC, Wells
Fargo Bank, National Association and Wachovia Bank, National
Association as the Co-Documentation Agents; J.P. Morgan Securities
Inc. as the Lead Arranger and Sole Bookrunner; and certain other
lenders (incorporated by reference to exhibit 99.2 to the Company's
current report on Form 8-K, File No. 1-13245, filed with the SEC on
January 27, 2005).
10.5G Fourth Amendment to the Company's Long-Term Incentive Plan, effective
as of November 20, 2003.
10.6G Fifth Amendment to the Company's Long-Term Incentive Plan, effective
as of May 12, 2004.
10.7G Sixth Amendment to the Company's Long-Term Incentive Plan, effective
as of December 17, 2004.
10.8G Third Amendment to the Company's Employee Stock Purchase Plan, dated
August 21, 2000.
10.9G Fourth Amendment to the Company's Employee Stock Purchase Plan, dated
February 19, 2003.
10.10G First Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective January 10, 2003.
10.11G Second Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective April 16, 2003.
10.12G Third Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective June 16, 2003.
10.13G Fourth Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective December 24, 2003.
10.14G Fifth Amendment to the Company's Pioneer Natural Resources USA, Inc.
40l(k) and Matching Plan (Amended and Restated Effective as of January
1, 2002), effective September 28, 2004.
10.15G The Company's Executive Deferred Compensation Retirement Plan, Amended
and Restated Effective as of August 1, 2002.
10.16 Production Payment Purchase and Sale Agreement dated as of April 19,
2005 among the Company, as the Seller, and Wolfcamp Oil and Gas Trust,
as the Buyer (incorporated by reference to Exhibit 99.2 to the
Company's Current Report on Form 8-K, File No. 1-13245, filed with the
SEC on April 21, 2005).
10.17G Form of Omnibus Nonstatutory Stock Option Agreement for Non-employee
Directors.
10.18(a) Purchase and Sale Agreement dated as of April 28, 2005 among Pioneer
Natural Resources Canada Inc., as the Vendor, and Ketch Resources
Ltd., as the Purchaser.
10.19G Form of Restricted Stock Award Agreement.
10.20G Form of Omnibus Nonstatutory Stock Option Agreement for Option Award
Participants (Group 1).
10.21G Offer of Employment Letter dated as of April 8, 2005 among the Company
and Mark S. Berg.
31.1(a) Chief Executive Officer certification under Section 302 of Sarbanes-
Oxley Act of 2002.
31.2(a) Chief Financial Officer certification under Section 302 of Sarbanes-
Oxley Act of 2002.
32.1(b) Chief Executive Officer certification under Section 906 of Sarbanes-
Oxley Act of 2002.
32.2(b) Chief Financial Officer certification under Section 906 of Sarbanes-
Oxley Act of 2002.
- ---------------
(a) filed herewith.
(b) furnished herewith.
G Executive Compensation Plan or Arrangement filed herewith pursuant to Item
14(c).
44