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, 2004
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 6, 2004... 120,104,666
PIONEER NATURAL RESOURCES COMPANY
TABLE OF CONTENTS
Page
Definitions of Oil and Gas Terms and Conversions Used Herein........ 3
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of March 31, 2004 and
December 31, 2003 ..................................... 4
Consolidated Statements of Operations for the three
months ended March 31, 2004 and 2003................... 5
Consolidated Statement of Stockholders' Equity for the
three months ended March 31, 2004...................... 6
Consolidated Statements of Cash Flows for the three
months ended March 31, 2004 and 2003................... 7
Consolidated Statements of Comprehensive Income for the
three months ended March 31, 2004 and 2003............. 8
Notes to Consolidated Financial Statements................ 9
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations....................... 26
Item 3. Quantitative and Qualitative Disclosures About
Market Risk............................................... 36
Item 4. Controls and Procedures................................... 39
PART II. OTHER INFORMATION
Item 1. Legal Proceedings......................................... 39
Item 6. Exhibits and Reports on Form 8-K.......................... 39
Signatures ......................................................... 41
Exhibit Index....................................................... 42
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: "Bbl" means a standard barrel containing 42 United
States gallons; "BOE" means a barrel of oil equivalent and is a standard
convention used to express oil and gas volumes on a comparable oil equivalent
basis; "Btu" means British thermal unit and is a measure of the amount of energy
required to raise the temperature of one pound of water one degree Fahrenheit;
"LIBOR" means London Interbank Offered Rate, which is a market rate of
interest;"MBbl" means one thousand Bbls; "MBOE" means one thousand BOEs; "Mcf"
means one thousand cubic feet and is a measure of natural gas volume; "MMBtu"
means one million Btus; "MMcf" means one million cubic feet; "NGL" means natural
gas liquid; "NYMEX" means the New York Mercantile Exchange; "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.
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 NGL.
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 Pioneer
Natural Resources Company's ("Pioneer" or the "Company") 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; and, 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, except share data)
March 31, December 31,
2004 2003
----------- -----------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents............................................ $ 9,022 $ 19,299
Accounts receivable:
Trade, net of allowance for doubtful accounts of $2,466
and $4,727 as of March 31, 2004 and December 31, 2003,
respectively.................................................... 145,733 111,033
Due from affiliates............................................... 406 447
Inventories.......................................................... 17,210 17,509
Prepaid expenses..................................................... 10,166 11,083
Deferred income taxes................................................ 35,780 40,514
Other current assets:
Derivatives....................................................... 179 423
Other, net of allowance for doubtful accounts of $4,486 as of
March 31, 2004 and December 31, 2003............................ 4,217 4,807
---------- ----------
Total current assets............................................ 222,713 205,115
---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts method
of accounting:
Proved properties................................................. 5,069,733 4,983,558
Unproved properties............................................... 176,580 179,825
Accumulated depletion, depreciation and amortization................. (1,808,468) (1,676,136)
---------- ----------
Total property, plant and equipment............................. 3,437,845 3,487,247
---------- ----------
Deferred income taxes.................................................. 198,587 192,344
Other property and equipment, net...................................... 28,470 28,080
Other assets:
Derivatives.......................................................... 157 209
Other, net of allowance for doubtful accounts of $92 as of
March 31, 2004 and December 31, 2003.............................. 40,512 38,577
---------- ----------
$ 3,928,284 $ 3,951,572
========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Accounts payable:
Trade............................................................. $ 173,378 $ 177,614
Due to affiliates................................................. 2,523 8,804
Interest payable..................................................... 37,728 37,034
Income taxes payable................................................. 8,986 5,928
Other current liabilities:
Derivatives....................................................... 195,295 161,574
Other............................................................. 45,668 38,798
---------- ----------
Total current liabilities....................................... 463,578 429,752
---------- ----------
Long-term debt......................................................... 1,456,695 1,555,461
Derivatives............................................................ 89,524 48,825
Deferred income taxes.................................................. 12,832 12,121
Other liabilities...................................................... 147,828 145,641
Stockholders' equity:
Common stock, $.01 par value; 500,000,000 shares authorized;
120,118,811 and 119,665,784 shares issued as of
March 31, 2004 and December 31, 2003, respectively................ 1,202 1,197
Additional paid-in capital........................................... 2,751,454 2,734,403
Treasury stock, at cost; 67,408 and 378,012 shares as of
March 31, 2004 and December 31, 2003, respectively................ (1,367) (5,385)
Deferred compensation................................................ (24,164) (9,933)
Accumulated deficit.................................................. (839,646) (887,848)
Accumulated other comprehensive income (loss):
Net deferred hedge losses, net of tax............................. (158,879) (104,130)
Cumulative translation adjustment................................. 29,227 31,468
---------- ----------
Total stockholders' equity...................................... 1,757,827 1,759,772
Commitments and contingencies
---------- ----------
$ 3,928,284 $ 3,951,572
========== ==========
The financial information included as of March 31, 2004 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 STATEMENTS OF OPERATIONS
(in thousands, except per share data)
(Unaudited)
Three months ended
March 31,
------------------------
2004 2003
---------- ----------
Revenues and other income:
Oil and gas............................................................ $ 446,526 $ 284,999
Interest and other..................................................... 1,735 2,713
Gain (loss) on disposition of assets, net.............................. (13) 1,426
--------- ---------
448,248 289,138
--------- ---------
Costs and expenses:
Oil and gas production................................................. 89,211 67,867
Depletion, depreciation and amortization............................... 136,499 70,049
Exploration and abandonments........................................... 80,506 35,867
General and administrative............................................. 18,329 15,481
Accretion of discount on asset retirement obligations.................. 1,966 1,094
Interest............................................................... 21,576 22,491
Other.................................................................. 196 5,178
--------- ---------
348,283 218,027
--------- ---------
Income before income taxes and cumulative effect of change in
accounting principle.................................................... 99,965 71,111
Income tax provision....................................................... (39,777) (2,304)
--------- ---------
Income before cumulative effect of change in accounting principle.......... 60,188 68,807
Cumulative effect of change in accounting principle, net of tax............ - 15,413
--------- ---------
Net income................................................................. $ 60,188 $ 84,220
========= =========
Net income per share:
Basic:
Income before cumulative effect of change in accounting principle.... $ .51 $ .59
Cumulative effect of change in accounting principle, net of tax...... - .13
--------- ---------
Net income........................................................ $ .51 $ .72
========= =========
Diluted:
Income before cumulative effect of change in accounting principle.... $ .50 $ .58
Cumulative effect of change in accounting principle, net of tax...... - .13
--------- ---------
Net income........................................................ $ .50 $ .71
========= =========
Weighted average shares outstanding:
Basic.................................................................. 118,719 116,743
========= =========
Diluted................................................................ 120,264 118,675
========= =========
Dividends declared per share............................................... $ .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.
5
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(in thousands)
(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, 2004...... $1,197 $2,734,403 $(5,385) $ (9,933) $(887,848) $(104,130) $ 31,468 $1,759,772
Dividends declared............... - - - - (11,986) - - (11,986)
Exercise of long-term
incentive plan stock options.... - (1,089) 9,584 - - - - 8,495
Purchase of treasury stock....... - - (5,566) - - - - (5,566)
Tax benefits related to
stock-based compensation........ - 1,935 - - - - - 1,935
Deferred compensation:
Compensation deferred.......... 5 16,205 - (16,210) - - - -
Deferred compensation
included in net income........ - - - 1,979 - - - 1,979
Net income....................... - - - - 60,188 - - 60,188
Other comprehensive income
(loss):
Net deferred hedge losses,
net of tax:
Net deferred hedge losses.... - - - - - (117,392) - (117,392)
Tax benefits related to net
deferred hedge losses..... - - - - - 31,871 - 31,871
Net hedge losses included
in net income............. - - - - - 30,772 - 30,772
Translation adjustment......... - - - - - - (2,241) (2,241)
----- --------- ------ ------- -------- -------- ------- ---------
Balance as of March 31, 2004....... $1,202 $2,751,454 $(1,367) $(24,164) $(839,646) $(158,879) $ 29,227 $1,757,827
===== ========= ====== ======= ======== ======== ======= =========
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 STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
Three months ended
March 31,
---------------------
2004 2003
--------- ---------
Cash flows from operating activities:
Net income.......................................................... $ 60,188 $ 84,220
Adjustments to reconcile net income to net cash
provided by operating activities:
Depletion, depreciation and amortization......................... 136,499 70,049
Exploration expenses, including dry holes........................ 78,820 30,263
Deferred income taxes............................................ 32,720 254
(Gain) loss on disposition of assets, net........................ 13 (1,426)
Accretion of discount on asset retirement obligations............ 1,966 1,094
Interest related amortization.................................... (6,370) (4,565)
Commodity hedge related amortization............................. (11,291) (17,782)
Cumulative effect of change in accounting principle, net of tax.. - (15,413)
Other noncash items.............................................. 1,220 4,733
Changes in operating assets and liabilities:
Accounts receivable, net......................................... (33,737) (25,967)
Inventories...................................................... (19) (360)
Prepaid expenses................................................. 917 (8,222)
Other current assets, net........................................ 757 398
Accounts payable................................................. (6,002) 8,381
Interest payable................................................. 693 522
Income taxes payable............................................. 3,058 1,452
Other current liabilities........................................ (5,802) 9,158
-------- --------
Net cash provided by operating activities...................... 253,630 136,789
-------- --------
Cash flows from investing activities:
Proceeds from disposition of assets................................. 285 15,553
Additions to oil and gas properties................................. (167,226) (252,753)
Other property additions, net....................................... (5,360) (2,281)
-------- --------
Net cash used in investing activities.......................... (172,301) (239,481)
-------- --------
Cash flows from financing activities:
Borrowings under long-term debt..................................... 56,083 116,628
Principal payments on long-term debt................................ (146,083) (15,000)
Payment of other liabilities........................................ (4,355) (6,380)
Purchase of treasury stock.......................................... (5,566) -
Exercise of long-term incentive plan stock options.................. 8,495 5,346
-------- --------
Net cash provided by (used in) financing activities............ (91,426) 100,594
-------- --------
Net decrease in cash and cash equivalents............................... (10,097) (2,098)
Effect of exchange rate changes on cash and cash equivalents............ (180) 466
Cash and cash equivalents, beginning of period.......................... 19,299 8,490
-------- --------
Cash and cash equivalents, end of period................................ $ 9,022 $ 6,858
======== ========
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 COMPREHENSIVE INCOME
(in thousands)
(Unaudited)
Three months ended
March 31,
----------------------
2004 2003
--------- ---------
Net income................................................... $ 60,188 $ 84,220
-------- --------
Other comprehensive income (loss):
Net deferred hedge losses, net of tax:
Net deferred hedge losses.............................. (117,392) (116,164)
Tax benefits related to net deferred hedge losses...... 31,871 (268)
Net hedge losses included in net income................ 30,772 50,363
Translation adjustment................................... (2,241) 12,192
-------- --------
Other comprehensive loss............................ (56,990) (53,877)
-------- --------
Comprehensive income......................................... $ 3,198 $ 30,343
======== ========
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
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(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 an independent oil and gas
exploration and production company with ownership interests in oil and gas
properties located in the United States, Argentina, Canada, Gabon, 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, 2004 and for the three-month
periods ended March 31, 2004 and 2003 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.
Certain information and footnote disclosures normally included in financial
statements prepared in accordance with generally accepted accounting principles
have been condensed or omitted in this Form 10-Q pursuant to the rules and
regulations of the Securities and Exchange Commission ("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 of and for the year ended December 31, 2003.
Adoption of SFAS 143. On January 1, 2003, the Company adopted the
provisions of Statement of Financial Accounting Standards No. 143, "Accounting
for Asset Retirement Obligations" ("SFAS 143"). SFAS 143 amended Statement of
Financial Accounting Standards No. 19, "Financial Accounting and Reporting by
Oil and Gas Producing Companies" ("SFAS 19") to require that the fair value of a
liability for an asset retirement obligation be recognized in the period in
which it is incurred if a reasonable estimate of fair value can be made. Under
the provisions of SFAS 143, asset retirement obligations are capitalized as part
of the carrying value of the long-lived asset.
The adoption of SFAS 143 resulted in a January 1, 2003 cumulative effect
adjustment to record a gain of $15.4 million, net of $1.3 million of deferred
tax, as a cumulative effect adjustment of a change in accounting principle in
the Company's Consolidated Statements of Operations for the three months ended
March 31, 2003. See Notes C and E for additional information regarding the
Company's income taxes and asset retirement obligations, respectively.
Inventories. Inventories are comprised of $15.6 million and $15.3 million
of lease and well equipment and $1.6 million and $2.2 million of commodities as
of March 31, 2004 and December 31, 2003, respectively. Lease and well equipment
is net of lower of cost or market allowances of $.6 million as of March 31, 2004
and December 31, 2003.
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" and related interpretations. Stock-based compensation expense
associated with option grants was not recognized in the Company's net income
during the three-month periods ended March 31, 2004 and 2003, 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. 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
Statement of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" to stock-based compensation during the three-month periods ended
March 31, 2004 and 2003:
9
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
Three months ended
March 31,
------------------------
2004 2003
--------- ---------
(in thousands, except
per share amounts)
Net income, as reported................................. $ 60,188 $ 84,220
Plus: Stock-based compensation expense included
in net income for all awards, net of tax (a)......... 1,257 1,369
Deduct: Stock-based compensation expense determined
under fair value based method for all awards,
net of tax (a)....................................... (3,115) (4,401)
-------- --------
Pro forma net income.................................... $ 58,330 $ 81,188
======== ========
Net income per share:
Basic - as reported.................................. $ .51 $ .72
======== ========
Basic - pro forma.................................... $ .49 $ .70
======== ========
Diluted - as reported................................ $ .50 $ .71
======== ========
Diluted - pro forma.................................. $ .49 $ .68
======== ========
<FN>
- -----------
(a) For the three months ended March 31, 2004, stock-based compensation expense
included in net income is net of a tax benefit of $722 thousand. Similarly,
stock-based compensation expense determined under the fair value based
method for the three months ended March 31, 2004 is net of a $1.8 million
tax benefit. No tax benefits were recognized for the stock-based
compensation expense amounts during the three months ended March 31, 2003.
See Note C for additional information regarding the Company's income taxes.
</FN>
NOTE C. Income Tax Assets
The Company accounts for income taxes in accordance with the provisions of
Statement of Financial Accounting Standards No. 109, "Accounting for Income
Taxes" ("SFAS 109"). SFAS 109 requires that the Company continually assess both
positive and negative evidence to determine whether it is more likely than not
that deferred tax assets can be realized prior to their expiration. From 1998
until 2003, the Company maintained a valuation allowance against a portion of
its deferred tax asset position in the United States. During the third quarter
of 2003, the Company concluded that it was more likely than not that it would be
able to realize its gross deferred tax asset position in the United States.
Accordingly, the Company reversed its valuation allowances in the United States.
As a result of the reversal of the valuation allowances against the Company's
United States deferred tax assets, the Company's effective tax rate on future
earnings in the United States will approximate statutory rates.
Pioneer will continue to monitor Company-specific, oil and gas industry and
worldwide economic factors and will assess the likelihood that the Company's net
operating loss carryforwards and other deferred tax attributes in the United
States and foreign tax jurisdictions will be utilized prior to their expiration.
As of March 31, 2004, the Company's valuation allowances related to foreign tax
jurisdictions are $102.1 million.
10
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
Income tax provision (benefit) attributable to income before cumulative
effect of change in accounting principle consists of the following for the
three-month periods ended March 31, 2004 and 2003:
Three months ended
March 31,
----------------------
2004 2003
--------- ---------
(in thousands)
Current:
U.S. state and local......................... $ 1,003 $ (22)
Foreign...................................... 6,054 2,072
-------- --------
7,057 2,050
-------- --------
Deferred:
U.S. state and local......................... 35,509 -
Foreign...................................... (2,789) 254
-------- --------
32,720 254
-------- --------
$ 39,777 $ 2,304
======== ========
NOTE D. 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 March 2004, the Company entered into interest rate swap contracts on an
aggregate $150 million notional amount to hedge the fair value of its 7-1/2
percent senior notes. The terms of the interest rate swap contracts match the
scheduled maturity of the hedged senior notes, require the counterparties to pay
the Company a 7-1/2 percent fixed annual interest rate and require the Company
to pay the counterparties variable annual interest rates equal to the periodic
six-month LIBOR plus a weighted average annual margin of 3.71 percent. During
February 2003, the Company entered into similar interest rate swap contracts
which were terminated during May 2003 for $11.4 million of cash proceeds. As of
March 31, 2004, the carrying value of the Company's fair value hedges was a
liability of $1.5 million.
As of March 31, 2004, the carrying value of the Company's long-term debt in
the accompanying Consolidated Balance Sheets included $20.1 million of
incremental carrying value attributable to net deferred hedge gains on
terminated interest rate swaps that are being amortized as net reductions 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 $7.3 million and $5.9 million
during the three-month periods ended March 31, 2004 and 2003, respectively.
Settlements of open fair value hedges reduced the Company's interest expense by
$167 thousand and $867 thousand during the three-month periods ended March 31,
2004 and 2003, respectively.
11
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
The following table sets forth, as of March 31, 2004, the scheduled
amortization of net deferred hedge gains and losses on terminated agreements
that will be recognized as increases in the case of losses, or decreases in the
case of gains, to the Company's future interest expense:
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------- -------- ------- ------- ---------
(in thousands)
2004 net hedge gain amortization...... $ 6,116 $ 5,489 $ 4,555 $ 16,160
2005 net hedge gain amortization...... $ 4,264 $ 2,816 $ 2,313 $ 1,575 10,968
2006 net hedge gain amortization...... $ 1,441 $ 824 $ 676 $ 253 3,194
2007 net hedge gain (loss) amortization $ 123 $ (417) $ (684) $(1,003) (1,981)
2008 net hedge loss amortization...... $ (599) $ (747) $ (755) $ (899) (3,000)
2009 net hedge loss amortization...... $ (879) $(1,070) $(1,082) $(1,135) (4,166)
2010 net hedge loss amortization...... $(1,109) $ - $ - $ - (1,109)
--------
$ 20,066
========
The terms of the fair value hedge agreements described above perfectly
matched the terms of the hedged senior notes. The Company did not exclude any
component of the derivatives' gains or losses from the measurement of hedge
effectiveness.
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 utilizes interest rate swap contracts to
reduce the effect of interest rate volatility on the Company's variable rate
line of credit indebtedness and, from time to time, forward currency exchange
agreements to reduce the effect of U.S. dollar to Canadian dollar exchange rate
volatility.
Oil prices. All material sales contracts governing the Company's oil
production have been tied directly or indirectly to NYMEX prices. The following
table sets forth the Company's outstanding oil hedge contracts and the weighted
average NYMEX prices for those contracts as of March 31, 2004:
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
-------- -------- -------- -------- -----------
Daily oil production hedged:
2004 - Swap Contracts
Volume (Bbl)................. 24,000 14,000 14,000 17,309
Price per Bbl................ $ 26.51 $ 24.65 $ 24.65 $ 25.50
2005 - Swap Contracts
Volume (Bbl)................. 17,000 17,000 17,000 17,000 17,000
Price per Bbl................ $ 24.93 $ 24.93 $ 24.93 $ 24.93 $ 24.93
2006 - Swap Contracts
Volume (Bbl)................. 5,000 5,000 5,000 5,000 5,000
Price per Bbl................ $ 26.19 $ 26.19 $ 26.19 $ 26.19 $ 26.19
2007 - Swap Contracts
Volume (Bbl)................. 1,000 1,000 1,000 1,000 1,000
Price per Bbl................ $ 26.00 $ 26.00 $ 26.00 $ 26.00 $ 26.00
2008 - Swap Contracts
Volume (Bbl)................. 5,000 5,000 5,000 5,000 5,000
Price per Bbl................ $ 26.09 $ 26.09 $ 26.09 $ 26.09 $ 26.09
12
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(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, 2004 and
2003:
Three months ended
March 31,
-------------------
2004 2003
------- -------
Average price reported per Bbl..................... $ 28.31 $ 25.82
Average price realized per Bbl..................... $ 32.12 $ 30.92
Reduction to oil revenue (in millions)............. $ (16.5) $ (14.7)
Natural gas liquids prices. During the three-month periods ended March 31,
2004 and 2003, the Company did not enter into any NGL hedge contracts. There
were no outstanding NGL hedge contracts at March 31, 2004.
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 Company's outstanding gas hedge
contracts and the weighted average index prices for those contracts as of March
31, 2004:
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
--------- --------- --------- --------- -----------
Daily gas production hedged:
2004 - Swap Contracts
Volume (Mcf)................... 280,000 280,000 280,000 280,000
Index price per MMBtu.......... $ 4.11 $ 4.11 $ 4.11 $ 4.11
2005 - Swap Contracts
Volume (Mcf)................... 60,000 60,000 60,000 60,000 60,000
Index price per MMBtu.......... $ 4.24 $ 4.24 $ 4.24 $ 4.24 $ 4.24
2006 - Swap Contracts
Volume (Mcf)................... 70,000 70,000 70,000 70,000 70,000
Index price per MMBtu.......... $ 4.16 $ 4.16 $ 4.16 $ 4.16 $ 4.16
2007 - Swap Contracts
Volume (Mcf)................... 20,000 20,000 20,000 20,000 20,000
Index price per MMBtu.......... $ 3.51 $ 3.51 $ 3.51 $ 3.51 $ 3.51
13
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(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, 2004 and 2003:
Three months ended
March 31,
--------------------
2004 2003
------- -------
Average price reported per Mcf........................ $ 4.41 $ 4.16
Average price realized per Mcf........................ $ 4.64 $ 5.05
Reduction to gas revenue (in millions)................ $ (14.2) $ (35.7)
Hedge ineffectiveness. During the thee-month periods ended March 31, 2004
and 2003, the Company recognized other expense of $44 thousand and $1.8 million,
respectively, related to the ineffective portions of its cash flow hedging
instruments.
Accumulated other comprehensive income (loss) ("AOCI") - net deferred hedge
losses, net of tax. As of March 31, 2004 and December 31, 2003, AOCI - net
deferred hedge losses, net of tax represented net deferred losses of $158.9
million and $104.1 million, respectively. The AOCI - net deferred hedge losses,
net of tax balance as of March 31, 2004 was comprised of $276.3 million of net
deferred hedge losses on the effective portions of open commodity cash flow
hedges, $34.1 million of net deferred gains on terminated cash flow hedges and
$83.2 million of associated net deferred tax benefits. The increase in AOCI -
net deferred hedge losses, net of tax during the three months ended March 31,
2004 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 hedge 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 hedge gains on terminated cash flow hedges are
fixed.
During the twelve months ending March 31, 2005, based on current estimates
of future commodity prices, the Company expects to reclassify $188.5 million of
net deferred losses associated with open cash flow hedges and $33.2 million of
net deferred gains on terminated cash flow hedges from AOCI - net deferred hedge
losses, net of tax to oil and gas revenues. The Company also expects to
reclassify approximately $56.7 million of net deferred income tax benefits
during the twelve months ending March 31, 2005 from AOCI - net deferred hedge
losses, net of tax to income tax provision.
The following table sets forth, as of March 31, 2004, the scheduled
reclassifications of net deferred hedge gains on terminated cash flow hedges
that will be recognized in the Company's future oil and gas revenues:
First Second Third Fourth
Quarter Quarter Quarter Quarter Total
------- ------- ------- ------- -------
(in thousands)
2004 net deferred hedge gains..... $10,932 $11,001 $10,954 $32,887
2005 net deferred hedge gains..... $ 307 $ 310 $ 315 $ 317 1,249
------
$34,136
======
NOTE E. Asset Retirement Obligations
As referred to in Note B, the Company adopted the provision of SFAS 143 on
January 1, 2003. The Company's asset retirement obligations primarily relate to
the future plugging and abandonment of proved properties and related facilities.
14
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
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 143 during the three-month periods ended March 31, 2004 and 2003:
Three months ended
March 31,
----------------------
2004 2003
--------- --------
(in thousands)
Beginning asset retirement obligations....................... $ 105,036 $ 34,692
Cumulative effect adjustment................................. - 23,393
New wells placed on production and changes in estimates...... 2,732 6,965
Liabilities settled.......................................... (2,597) (2,442)
Accretion expense............................................ 1,966 1,094
Currency translation......................................... (103) 472
-------- -------
Ending asset retirement obligations ......................... $ 107,034 $ 64,174
======== =======
NOTE F. Postretirement Benefit Obligations
As of March 31, 2004 and December 31, 2003, the Company had recorded $15.5
million and $15.6 million, respectively, of unfunded accumulated postretirement
benefit obligations 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, 2004 and 2003:
Three months ended
March 31,
----------------------
2004 2003
-------- --------
(in thousands)
Beginning accumulated postretirement benefit obligations........ $ 15,556 $ 19,743
Benefit payments................................................ (339) (240)
Service costs................................................... 58 51
Accretion of discounts.......................................... 226 372
------- -------
Ending accumulated postretirement benefit obligations........... $ 15,501 $ 19,926
======= =======
NOTE G. 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 it 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 plaintiffs, as royalty owners, are not responsible. Second, the
15
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
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 $65 million, 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 the 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 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. Although the amount of any resulting
liability 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 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.
Kansas ad valorem tax. The Natural Gas Policy Act of 1978 ("NGPA") allows a
"severance, production or similar" tax to be included as an add-on, over and
above the maximum lawful price for gas. Based on a Federal Energy Regulatory
Commission ("FERC") ruling that Kansas ad valorem tax was such a tax, one of the
Company's predecessor entities collected the Kansas ad valorem tax in addition
to the otherwise maximum lawful price. The FERC's ruling was appealed to the
United States Court of Appeals for the District of Columbia ("D.C. Circuit"),
which held in June 1988 that the FERC failed to provide a reasonable basis for
its findings and remanded the case to the FERC for further consideration.
On December 1, 1993, the FERC issued an order reversing its prior ruling,
but limited the effect of its decision to Kansas ad valorem taxes for sales made
on or after June 28, 1988. The FERC clarified the effective date of its decision
by an order dated May 18, 1994. The order clarified that the effective date
applies to tax bills rendered after June 28, 1988, not sales made on or after
that date. Numerous parties filed appeals on the FERC's action in the D.C.
Circuit. Various gas producers challenged the FERC's orders on two grounds: (1)
that the Kansas ad valorem tax, properly understood, does qualify for
reimbursement under the NGPA; and (2) the FERC's ruling should, in any event,
have been applied prospectively. Other parties challenged the FERC's orders on
the grounds that the FERC's ruling should have been applied retroactively to
December 1, 1978, the date of the enactment of the NGPA and producers should
have been required to pay refunds accordingly.
The D.C. Circuit issued its decision on August 2, 1996, which holds that
producers must make refunds of all Kansas ad valorem tax collected with respect
to production since October 4, 1983, as opposed to June 28, 1988. Petitions for
rehearing were denied on November 6, 1996. Various gas producers subsequently
filed a petition for writ of certiori with the United States Supreme Court
seeking to limit the scope of the potential refunds to tax bills rendered on or
after June 28, 1988 (the effective date originally selected by the FERC).
16
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
Williams Natural Gas Company filed a cross-petition for certiori seeking to
impose refund liability back to December 1, 1978. Both petitions were denied on
May 12, 1997.
The Company and other producers filed petitions for adjustment with the
FERC on June 24, 1997. The Company was seeking a waiver or set-off from the FERC
with respect to that portion of the refund associated with (i) nonrecoupable
royalties, (ii) nonrecoupable Kansas property taxes based, in part, upon the
higher prices collected and (iii) interest for all periods. On September 10,
1997, the FERC denied this request, and on October 10, 1997, the Company and
other producers filed a request for rehearing. Pipelines were given until
November 10, 1997 to file claims on refunds sought from producers and refund
claims totaling approximately $30.2 million were made against the Company.
Through March 31, 2004, the Company has settled $21.6 million of the original
claim amounts. As of March 31, 2004 and December 31, 2003, the Company had on
deposit $10.7 million, including accrued interest, in an escrow account and had
a corresponding obligation for the remaining claim recorded in other current
liabilities in the accompanying Consolidated Balance Sheets as of March 31,
2004.
On December 1, 2003, an administrative law judge issued a Partial Initial
Decision denying the Company's request to allow any waiver or set-off from the
refunds and stating that the Company must pay the FERC interest rate on the
refund claims instead of the escrow interest rate. As of December 31, 2003, the
Company had accrued an additional $1.5 million obligation for the difference
between the escrow interest rate and the FERC interest rate. During the first
quarter of 2004, the FERC overruled this administrative law judge's decision as
it relates to the payment of interest and stated that the escrow interest rate
is sufficient. As of March 31, 2004, the Company reversed the additional $1.5
million obligation that had been recorded for the difference between the escrow
interest rate and the FERC interest rate. The Company intends to vigorously
appeal the administrative law judge's decision denying waiver or set-off from
the refunds and believes that the accrued obligations will be sufficient to
resolve the remaining claims.
NOTE H. Income Per Share Before Cumulative Effect of Change in Accounting
Principle
Basic income per share before cumulative effect of change in accounting
principle is computed by dividing income before cumulative effect of change in
accounting principle by the weighted average number of common shares outstanding
for the period. The computation of diluted income per share before cumulative
effect of change in accounting principle reflects the potential dilution that
could occur if securities or other contracts to issue common stock that are
dilutive to income before cumulative effect of change in accounting principle
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 the basic and diluted weighted
average shares outstanding for the three-month periods ended March 31, 2004 and
2003:
Three months ended
March 31,
---------------------
2004 2003
-------- --------
(in thousands)
Weighted average common shares outstanding:
Basic............................................. 118,719 116,743
Dilutive common stock options (a)................. 1,177 1,793
Restricted stock awards........................... 368 139
-------- --------
Diluted........................................... 120,264 118,675
======= ========
<FN>
- ---------------
(a) Common stock options to purchase 30,712 shares and 1,377,519 shares of
common stock were outstanding but not included in the computations of
diluted income per share before cumulative effect of change in accounting
principle for the three-month periods ended March 31, 2004 and 2003,
respectively, 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.
</FN>
17
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
NOTE I. 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. Africa is primarily comprised of operations in Gabon, South Africa and
Tunisia.
The following tables provide the Company's interim geographic operating
segment data for the three-month periods ended March 31, 2004 and 2003.
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 and
Other" 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.
18
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
United Headquarters Consolidated
States Argentina Canada Africa and other Total
-------- --------- -------- -------- ------------ ------------
(in thousands)
Three months ended March 31, 2004:
Revenues and other income:
Oil and gas revenues.............. $357,308 $ 30,883 $ 18,219 $ 40,116 $ - $ 446,526
Interest and other................ - - - - 1,735 1,735
Gain (loss) on disposition
of assets, net.................. 51 - - - (64) (13)
------- ------- ------- ------- ------- --------
357,359 30,883 18,219 40,116 1,671 448,248
------- ------- ------- ------- ------- --------
Costs and expenses:
Oil and gas production............ 66,019 6,759 7,949 8,484 - 89,211
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
------- ------- ------- ------- ------- --------
216,946 22,851 28,400 35,304 44,782 348,283
------- ------- ------- ------- ------- --------
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
======= ======= ======= ======= ======= ========
United Headquarters Consolidated
States Argentina Canada Africa and other Total
-------- --------- -------- -------- ------------ ------------
(in thousands)
Three months ended March 31, 2003:
Revenues and other income:
Oil and gas revenues.............. $239,251 $ 23,381 $ 22,367 $ - $ - $ 284,999
Interest and other................ - - - - 2,713 2,713
Gain on disposition of assets,
net............................. 1,246 - 1 - 179 1,426
------- ------- ------- ------- ------- --------
240,497 23,381 22,368 - 2,892 289,138
------- ------- ------- ------- ------- --------
Costs and expenses:
Oil and gas production............ 55,537 5,409 6,921 - - 67,867
Depletion, depreciation and
amortization.................... 52,858 8,326 6,551 - 2,314 70,049
Exploration and abandonments...... 17,787 3,044 11,327 3,709 - 35,867
General and administrative........ - - - - 15,481 15,481
Accretion of discount on asset
retirement obligations.......... - - - - 1,094 1,094
Interest.......................... - - - - 22,491 22,491
Other............................. - - - - 5,178 5,178
------- ------- ------- ------- ------- --------
126,182 16,779 24,799 3,709 46,558 218,027
------- ------- ------- ------- ------- --------
Income (loss) before income taxes
and cumulative effect of change
in accounting principle........... 114,315 6,602 (2,431) (3,709) (43,666) 71,111
Income tax benefit (provision)..... (40,010) (2,311) 960 1,298 37,759 (2,304)
------- ------- ------- ------- ------- --------
Income (loss) before cumulative
effect of change in accounting
principle......................... $ 74,305 $ 4,291 $ (1,471) $ (2,411) $ (5,907) $ 68,807
======= ======= ======= ======= ======= ========
19
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
NOTE J. Pioneer USA
Pioneer Natural Resources USA, Inc. ("Pioneer USA") is a wholly-owned
subsidiary of the Company that has fully and unconditionally guaranteed certain
debt securities of the Company. In accordance with practices accepted by the
SEC, the Company has prepared Consolidating Condensed Financial Statements in
order to quantify the assets and results of operations of Pioneer USA as a
subsidiary guarantor. The following Consolidating Condensed Balance Sheets as of
March 31, 2004 and December 31, 2003, and Consolidating Condensed Statements of
Operations and Comprehensive Income and Consolidating Condensed Statements of
Cash Flows for the three-month periods ended March 31, 2004 and 2003 present
financial information for Pioneer Natural Resources Company as the Parent on a
stand- alone basis (carrying any investments in subsidiaries under the equity
method), financial information for Pioneer USA on a stand-alone basis (carrying
any investment in non-guarantor subsidiaries under the equity method), financial
information for the non-guarantor subsidiaries of the Company on a consolidated
basis, the consolidation and elimination entries necessary to arrive at the
information for the Company on a consolidated basis, and the financial
information for the Company on a consolidated basis. Pioneer USA is not
restricted from making distributions to the Company.
20
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
CONSOLIDATING CONDENSED BALANCE SHEET
As of March 31, 2004
(in thousands)
(Unaudited)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Eliminations Total
---------- ----------- ------------ ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents................. $ 19 $ 1,063 $ 7,940 $ - $ 9,022
Other current assets, net................. 1,550,774 (1,248,898) (88,185) - 213,691
--------- ---------- ---------- ---------- ----------
Total current assets................. 1,550,793 (1,247,835) (80,245) - 222,713
--------- ---------- ---------- ---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties...................... - 3,549,681 1,520,052 - 5,069,733
Unproved properties.................... - 24,492 152,088 - 176,580
Accumulated depletion, depreciation and
amortization............................ - (1,302,712) (505,756) - (1,808,468)
--------- ---------- ---------- ---------- ----------
Total property, plant and equipment.. - 2,271,461 1,166,384 - 3,437,845
--------- ---------- ---------- ---------- ----------
Deferred income taxes....................... 193,555 - 5,032 - 198,587
Other property and equipment, net........... - 24,349 4,121 - 28,470
Other assets, net........................... 14,325 18,147 8,197 - 40,669
Investment in subsidiaries.................. 1,708,426 227,547 - (1,935,973) -
--------- ---------- --------- ---------- ----------
$3,467,099 $ 1,293,669 $1,103,489 $(1,935,973) $ 3,928,284
========= ========== ========= ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities......................... $ 42,740 $ 349,439 $ 71,399 $ - $ 463,578
Long-term debt.............................. 1,456,695 - - - 1,456,695
Other liabilities........................... 1,546 269,822 (34,016) - 237,352
Deferred income taxes....................... - - 12,832 - 12,832
Stockholders' equity........................ 1,966,118 674,408 1,053,274 (1,935,973) 1,757,827
Commitments and contingencies
--------- ---------- --------- ---------- ----------
$3,467,099 $ 1,293,669 $1,103,489 $(1,935,973) $ 3,928,284
========= ========== ========= ========== ==========
CONSOLIDATING CONDENSED BALANCE SHEET
As of December 31, 2003
(in thousands)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Eliminations Total
---------- ----------- ------------ ------------ ------------
ASSETS
Current assets:
Cash and cash equivalents................. $ 369 $ 4,225 $ 14,705 $ - $ 19,299
Other current assets, net................. 1,654,575 (1,354,256) (114,503) - 185,816
--------- ---------- --------- ---------- ----------
Total current assets................. 1,654,944 (1,350,031) (99,798) - 205,115
--------- ---------- --------- ---------- ----------
Property, plant and equipment, at cost:
Oil and gas properties, using the
successful efforts method of accounting:
Proved properties...................... - 3,508,365 1,475,193 - 4,983,558
Unproved properties.................... - 25,460 154,365 - 179,825
Accumulated depletion, depreciation and
amortization............................ - (1,208,700) (467,436) - (1,676,136)
--------- ---------- --------- ---------- ----------
Total property, plant and equipment.. - 2,325,125 1,162,122 - 3,487,247
--------- ---------- --------- ---------- ----------
Deferred income taxes....................... 190,492 - 1,852 - 192,344
Other property and equipment, net........... - 23,890 4,190 - 28,080
Other assets, net........................... 14,836 17,076 6,874 - 38,786
Investment in subsidiaries.................. 1,604,534 167,515 - (1,772,049) -
--------- ---------- --------- ---------- ----------
$3,464,806 $ 1,183,575 $1,075,240 $(1,772,049) $ 3,951,572
========= ========== ========= ========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities......................... $ 29,978 $ 347,720 $ 52,054 $ - $ 429,752
Long-term debt.............................. 1,555,461 - - - 1,555,461
Other liabilities........................... - 226,055 (31,589) - 194,466
Deferred income taxes....................... - - 12,121 - 12,121
Stockholders' equity........................ 1,879,367 609,800 1,042,654 (1,772,049) 1,759,772
Commitments and contingencies
--------- ---------- --------- ---------- ----------
$3,464,806 $ 1,183,575 $1,075,240 $(1,772,049) $ 3,951,572
========= ========== ========= ========== ==========
21
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2004
(in thousands)
(Unaudited)
Non- Consolidated
Pioneer Guarantor Income Tax Consolidated
Parent USA Subsidiaries Provision Eliminations Total
-------- -------- ------------ ------------ ------------ -------------
Revenues and other income:
Oil and gas................................ $ - $330,303 $ 116,223 $ - $ - $ 446,526
Interest and other......................... 69 811 855 - - 1,735
Gain (loss) on disposition of assets, net.. - 89 (102) - - (13)
------- ------- -------- ------- -------- --------
69 331,203 116,976 - - 448,248
------- ------- -------- ------- -------- --------
Costs and expenses:
Oil and gas production..................... - 60,360 28,851 - - 89,211
Depletion, depreciation and amortization... - 96,309 40,190 - - 136,499
Exploration and abandonments............... - 47,789 32,717 - - 80,506
General and administrative................. 411 14,807 3,111 - - 18,329
Accretion of discount on asset
retirement obligations................... - 1,512 454 - - 1,966
Interest................................... 6,823 14,426 327 - - 21,576
Equity income from subsidiaries............ (103,862) (4,160) - - 108,022 -
Other...................................... - (1,181) 1,377 - - 196
------- ------- -------- ------- -------- --------
(96,628) 229,862 107,027 - 108,022 348,283
------- ------- -------- ------- -------- --------
Income before income taxes.................... 96,697 101,341 9,949 - (108,022) 99,965
Income tax provision.......................... - - (3,268) (36,509) - (39,777)
------- ------- -------- ------- -------- --------
Net income.................................... 96,697 101,341 6,681 (36,509) (108,022) 60,188
Other comprehensive income (loss):
Net deferred hedge losses, net of tax:
Net deferred hedge losses................ - (111,230) (6,162) - - (117,392)
Tax benefits related to net deferred
hedge losses........................... - - 167 31,704 - 31,871
Net hedge losses included in net income.. - 24,367 6,405 - - 30,772
Translation adjustment..................... - - (2,241) - - (2,241)
------- ------- -------- ------ -------- --------
Comprehensive income.......................... $ 96,697 $ 14,478 $ 4,850 $ (4,805) $(108,022) $ 3,198
======= ======= ======== ======= ======== ========
22
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
CONSOLIDATED CONDENSED STATEMENT OF OPERATIONS
AND COMPREHENSIVE INCOME
For the Three Months Ended March 31, 2003
(in thousands)
(Unaudited)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Eliminations Total
-------- --------- ------------ ------------ ------------
Revenues and other income:
Oil and gas............................... $ - $ 214,715 $ 70,284 $ - $ 284,999
Interest and other........................ - 786 1,927 - 2,713
Gain on disposition of assets, net........ - 1,230 196 - 1,426
------- -------- -------- ------- ---------
- 216,731 72,407 - 289,138
------- -------- -------- ------- ---------
Costs and expenses:
Oil and gas production.................... - 50,529 17,338 - 67,867
Depletion, depreciation and amortization.. - 51,830 18,219 - 70,049
Exploration and abandonments.............. - 19,792 16,075 - 35,867
General and administrative................ 295 12,310 2,876 - 15,481
Accretion of discount on asset
retirement obligations.................. - 857 237 - 1,094
Interest.................................. 5,081 17,192 218 - 22,491
Equity (income) loss from subsidiaries.... (89,626) 5,454 - 84,172 -
Other..................................... 30 813 4,335 - 5,178
------- -------- -------- ------- ---------
(84,220) 158,777 59,298 84,172 218,027
------- -------- -------- ------- ---------
Income before income taxes and cumulative
effect of change in accounting
principle................................. 84,220 57,954 13,109 (84,172) 71,111
Income tax provision......................... - - (2,304) - (2,304)
------- -------- -------- ------- ---------
Income before cumulative effect of change
in accounting principle................... 84,220 57,954 10,805 (84,172) 68,807
Cumulative effect of change in accounting
principle, net of tax..................... - 11,859 3,554 - 15,413
------- -------- -------- ------- ---------
Net income................................... 84,220 69,813 14,359 (84,172) 84,220
Other comprehensive income (loss):
Net deferred hedge losses, net of tax:
Net deferred hedge losses............... - (103,549) (12,615) - (116,164)
Tax benefits related to net deferred
hedge losses.......................... - - (268) - (268)
Net hedge losses included in net income. - 44,444 5,919 - 50,363
Translation adjustment.................... - - 12,192 - 12,192
-------- -------- -------- ------- ---------
Comprehensive income......................... $ 84,220 $ 10,708 $ 19,587 $(84,172) $ 30,343
======= ======== ======== ======= =========
23
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Three Months Ended March 31, 2004
(in thousands)
(Unaudited)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Total
--------- --------- ------------ ------------
Cash flows from operating activities:
Net cash provided by operating activities......... $ 86,721 $ 109,212 $ 57,697 $ 253,630
-------- -------- -------- --------
Cash flows from investing activities:
Proceeds from disposition of assets............... - 285 - 285
Additions to oil and gas properties............... - (106,430) (60,796) (167,226)
Other property additions, net..................... - (3,612) (1,748) (5,360)
-------- -------- -------- --------
Net cash used in investing activities.......... - (109,757) (62,544) (172,301)
-------- -------- -------- --------
Cash flows from financing activities:
Borrowings under long-term debt................... 56,083 - - 56,083
Principal payments on long-term debt.............. (146,083) - - (146,083)
Payment of other liabilities...................... - (2,617) (1,738) (4,355)
Purchase of treasury stock........................ (5,566) - - (5,566)
Exercise of long-term incentive plan stock
options......................................... 8,495 - - 8,495
-------- -------- -------- --------
Net cash used in financing activities.......... (87,071) (2,617) (1,738) (91,426)
-------- -------- -------- --------
Net decrease in cash and cash equivalents.......... (350) (3,162) (6,585) (10,097)
Effect of exchange rate changes on cash and
cash equivalents................................. - - (180) (180)
Cash and cash equivalents, beginning of period..... 369 4,225 14,705 19,299
-------- -------- -------- --------
Cash and cash equivalents, end of period........... $ 19 $ 1,063 $ 7,940 $ 9,022
======== ======== ======== ========
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS
For the Three Months Ended March 31, 2003
(in thousands)
(Unaudited)
Non-
Pioneer Guarantor Consolidated
Parent USA Subsidiaries Total
--------- --------- ------------ ------------
Cash flows from operating activities:
Net cash provided by (used in) operating
activities...................................... $(106,957) $ 198,841 $ 44,905 $ 136,789
-------- -------- -------- ---------
Cash flows from investing activities:
Proceeds from disposition of assets............... - 15,472 81 15,553
Additions to oil and gas properties............... - (204,983) (47,770) (252,753)
Other property (additions) dispositions, net...... - (2,358) 77 (2,281)
-------- -------- -------- ---------
Net cash used in investing activities.......... - (191,869) (47,612) (239,481)
-------- -------- -------- ---------
Cash flows from financing activities:
Borrowings under long-term debt................... 116,628 - - 116,628
Principal payments on long-term debt.............. (15,000) - - (15,000)
Payment of other liabilities...................... - (6,292) (88) (6,380)
Exercise of long-term incentive plan stock
options......................................... 5,346 - - 5,346
-------- -------- -------- ---------
Net cash provided by (used in) financing
activities................................... 106,974 (6,292) (88) 100,594
-------- -------- -------- ---------
Net increase (decrease) in cash and cash
equivalents...................................... 17 680 (2,795) (2,098)
Effect of exchange rate changes on cash and
cash equivalents................................. - - 466 466
Cash and cash equivalents, beginning of period..... 6 1,783 6,701 8,490
-------- -------- -------- ---------
Cash and cash equivalents, end of period........... $ 23 $ 2,463 $ 4,372 $ 6,858
========= ======== ======== =========
24
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
March 31, 2004
(Unaudited)
NOTE K. Subsequent Events
Permian Basin acquisition. On April 1, 2004, the Company completed the
acquisition of various working interests in approximately 600 Spraberry field
oil wells, 400 of which were already operated by the Company. The total purchase
price of this acquisition was $19.7 million, including normal purchase
adjustments.
Proposed merger with Evergreen Resources, Inc. On May 3, 2004, the Company
entered into an Agreement and Plan of Merger (the "Merger Agreement") with
Evergreen Resources, Inc. ("Evergreen"), a publicly traded independent oil and
gas company primarily engaged in the operation, development, production,
exploration and acquisition of North American unconventional natural gas.
Evergreen is based in Denver, Colorado and is one of the leading developers of
coal bed methane reserves in the United States. Evergreen's operations are
principally focused on developing and expanding its coal bed methane project
located in the Raton Basin in southern Colorado and its recently acquired
producing properties in the Piceance Basin in western Colorado, the Uintah Basin
in eastern Utah and the Western Canada Sedimentary. The Merger Agreement
provides for a merger by which Evergreen will become a subsidiary of Pioneer
(the "Proposed Merger").
In accordance with the Merger Agreement, holders of 44 million shares of
Evergreen common stock will have the right to receive an aggregate of
approximately 25 million shares of Pioneer common stock (with related
stockholders rights) and a total of approximately $850 million in cash. This
represents a price per Evergreen share of $39.00 (based on Pioneer's last
reported sale price on May 3, 2004 of $33.52 per share). Holders of Evergreen
common stock will have the option to elect among three types of consideration
for a share of Evergreen common stock: (1) 1.1635 shares of Pioneer common
stock; (2) $39.00 cash; or (3) .58175 shares of Pioneer common stock and $19.50
in cash. Evergreen stockholders who do not make an election will receive .58175
shares of Pioneer common stock and $19.50 in cash per Evergreen share. All
holders of unvested restricted stock under Evergreen's stock-based employee
plans will be deemed to have elected to receive Pioneer common stock. Holders
who elect all stock consideration or all cash consideration (other than holders
of unvested restricted stock) will be subject to allocation of the stock and
cash so that the aggregate amounts of stock and cash will be as set forth in the
first sentence of this paragraph.
In addition, Evergreen will seek to sell its Kansas assets before the
closing date of the Proposed Merger. Evergreen stockholders will receive an
additional cash payment of the greater of (i) $.35 per share (approximately $15
million) as consideration from Pioneer for the Kansas properties in the Proposed
Merger, or (ii) the gross proceeds less transaction costs from the sale of the
Kansas properties to a third party that closes before the closing date of the
Proposed Merger.
The Company intends to file with the SEC a Registration Statement on Form
S-4 relating to the shares of Pioneer common stock to be issued in the Proposed
Merger. A portion of such registration statement will constitute a proxy
statement/prospectus to be submitted to the stockholders of Evergreen's common
stock and the Company's common stock for special meetings to be held by each
company's stockholders in connection with the Proposed Merger. It is expected
that such proxy statement/prospectus will be mailed to all stockholders during
the third quarter of 2004, and that such meeting will be held, and the Proposed
Merger will be consummated, during the second half of 2004. Since meetings of
both Evergreen's and Pioneer's stockholders are required in connection with the
Proposed Merger, in addition to a number of other conditions, there can be no
assurance that the Proposed Merger will occur.
25
PIONEER NATURAL RESOURCES COMPANY
Item 2. Management's Discussion and Analysis of Financial Condition and
Results of Operations
The information included in Item 2 and Item 3 of 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 the Company, are subject to a number
of risks and uncertainties which 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, international operations and
associated international political and economic instability, government
regulation or action, litigation, the costs and results of drilling and
operations, the Company's ability to replace reserves or implement its business
plans, access to and cost of capital, uncertainties about estimates of reserves,
quality of technical data and environmental risks, acts of war and terrorism.
These and other risks are described in the Company's 2003 Annual Report on Form
10-K that is available from the SEC.
Financial and Operating Performance
The Company's financial and operating performance for the first quarter of
2004 included the following highlights:
o A 57% increase in oil and gas revenue over that of the first quarter
of 2003, resulting from increases in commodity prices and volumes
sold, as further described below.
o Growth in the Company's deepwater Gulf of Mexico sales volumes,
including initial production from the Harrier field during January
2004.
o Higher than anticipated Argentine oil and gas sales volumes,
primarily due to strong gas demand throughout their summer season.
o Higher than anticipated South African oil sales due to one
additional cargo shipment during the quarter.
o An 85 percent increase in net cash provided by operating activities,
as compared to the first quarter of 2003, primarily resulting from
increased oil and gas sales.
o A $.10 per common share semiannual dividend declared by the board of
directors, payable on April 13, 2004 to shareholders of record on
March 29, 2004.
o Rating agencies upgrade of the Company to investment grade status in
response to improved financial position and earnings trends, along
with other factors specific to the Company.
The Company recorded net income of $60.2 million ($.50 per diluted share)
for the three months ended March 31, 2004, as compared to net income of $84.2
million ($.71 per diluted share) for the same period in 2003, including a $15.4
million benefit from the cumulative effect of change in accounting principle,
net of tax, associated with the Company's adoption of SFAS 143 on January 1,
2003. See Notes B and E of Notes to Consolidated Financial Statements included
in "Item 1. Financial Statements" for additional information regarding the
Company's adoption of SFAS 143. Income before income taxes and cumulative effect
of change in accounting principle increased by $28.9 million, or 41 percent,
during the first quarter of 2004 as compared to that of the first quarter of
2003. However, as a result of the increase in earnings and the reversal of the
Company's United States deferred tax asset valuation allowances during the third
quarter of 2003, the Company's income tax provision increased by $37.5 million
in the first-quarter-2004 to first-quarter-2003 comparison.
The Company's net cash provided by operating activities was $253.6 million
for the three months ended March 31, 2004, representing an increase of $116.8
million, as compared to net cash provided by operating activities of $136.8
million for the same period in 2003. During the three months ended March 31,
2004, the Company used its net cash provided by operating activities to fund
$167.2 million of additions to oil and gas properties and, together with a
decease in cash on hand, to repay $90.0 million of long-term borrowings under
the Company's $700 million revolving credit agreement (the "Revolving Credit
Agreement").
Proposed Merger with Evergreen Resources, Inc.
As described in Note K of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements", on May 3, 2004, the Company entered
into the Merger Agreement with Evergreen, a publicly traded independent oil and
gas company primarily engaged in the operation, development, production,
exploration and acquisition of North American unconventional natural gas.
26
Evergreen's operations are principally focused on developing and expanding its
coal bed methane project located in the Raton Basin in southern Colorado and its
recently acquired producing properties in the Piceance Basin in western
Colorado, the Uintah Basin in eastern Utah and the Western Canada Sedimentary.
The Merger Agreement provides for a merger by which Evergreen will become a
subsidiary of Pioneer.
Proposed purchase terms. In accordance with the Merger Agreement, holders
of 44 million shares of Evergreen common stock will have the right to receive an
aggregate of approximately 25 million shares of Pioneer common stock (with
related stockholders rights) and a total of approximately $850 million in cash.
This represents a price per Evergreen share of $39.00 (based on Pioneer's last
reported sale price on May 3, 2004 of $33.52 per share). Holders of Evergreen
common stock will have the option to elect among three types of consideration
for a share of Evergreen common stock: (1) 1.1635 shares of Pioneer common
stock; (2) $39.00 cash; or (3) .58175 shares of Pioneer common stock and $19.50
in cash. Evergreen stockholders who do not make an election will receive .58175
shares of Pioneer common stock and $19.50 in cash per Evergreen share. All
holders of unvested restricted stock under Evergreen's stock- based employee
plans will be deemed to have elected to receive Pioneer common stock. Holders
who elect all stock consideration or all cash consideration (other than holders
of unvested restricted stock) will be subject to allocation of the stock and
cash so that the aggregate amounts of stock and cash will be as set forth in the
first sentence of this paragraph.
In addition, Evergreen will seek to sell its Kansas assets before the
closing date of the Proposed Merger. Evergreen stockholders will receive an
additional cash payment of the greater of (i) $.35 per share (approximately $15
million) as consideration from Pioneer for the Kansas properties in the Proposed
Merger, or (ii) the gross proceeds less transaction costs from the sale of the
Kansas properties to a third party that closes before the closing date of the
Proposed Merger.
Strategic rationale. Pioneer's business strategy for sustaining above
average growth in per share value is predicated on the leveraging of its
long-lived foundation assets. Those foundation assets generate dependable
operating cash flows while requiring relatively low amounts of maintenance
capital. As a result, the Company's foundation assets provide free cash flows
(i.e., operating cash flows after maintenance capital expenditures) that finance
investments in high-impact, high-return exploration and acquisition
opportunities, such as the Company's investments in the deepwater Gulf of
Mexico, Alaska, South Africa, Tunisia and Gabon. The Proposed Merger offers an
opportunity for the Company to rebalance its portfolio of long-lived foundation
assets with the addition of Evergreen's onshore producing asset base and
low-risk development drilling program. Additionally, the Company's decision to
pursue the Proposed Merger was positively impacted by the compatible technical
and corporate cultures of Pioneer and Evergreen, Evergreen's substantial acreage
position in key growth basins of the United States Rockies area and the
opportunity to leverage Evergreen's technical expertise in the area of coal bed
methane operations.
Liquidity and capital structure. The completion of the Proposed Merger is
expected to result in a short-term increase of approximately $1.2 billion in the
Company's long-term debt, comprised of the funding of $850 million in cash
consideration paid, approximately $30 million of transaction costs associated
with the Proposed Merger, approximately $15 million to fund the purchase of
Evergreen's Kansas assets if Evergreen is unable to sell those assets prior to
closing the Proposed Merger and the assumption of (i) $100 million of Evergreen
4.75 percent convertible senior subordinated bonds that are callable in December
2006 and (ii) $200 million of Evergreen 5.875 percent senior subordinated bonds
due in 2012. The Company intends to finance the cash costs of the Proposed
Merger with a new $900 million, 364-day senior unsecured revolving credit
facility (the "364-day Facility"), the terms of which will essentially mirror
those of the Company's Revolving Credit Agreement, including the bearing of a
variable annual rate of interest equal to the 6-month LIBOR rate plus a 100
basis point LIBOR margin. The Company also intends to exercise its option under
the Revolving Credit Agreement allowing an increase in the facility's borrowing
commitment to $1 billion. During the one-year period subsequent to the closing
of the Proposed Merger, the Company may repay the 364-day Facility with
available operating cash flows, available commitments under the Revolving Credit
Agreement or any combination of those or other available capital sources.
The completion of the Proposed Merger is expected to increase the Company's
stockholders' equity by approximately $900 million as a result of the associated
issuance of approximately 25 million shares of Pioneer common stock. The
Company's ratio of debt to book capitalization is expected to approximate 47
percent immediately after the Proposed Merger closes in the latter part of 2004.
27
The Company has targeted a ratio of debt to book capitalization of 40
percent or less by the end of 2005. To achieve this target, the Company intends
to implement an aggressive commodity hedging program of Pioneer's and
Evergreen's 2004 and 2005 forecasted oil and gas production. The Company began
implementing this program prior to the announcement of the Proposed Merger,
utilizing commodity swap contracts entered into with highly-rated financial
institution counterparties. Consistent with this program, Evergreen has hedged
approximately 75 percent of its 2004 and 2005 forecasted gas production. The
Company has hedged approximately 35 percent and 45 percent of its remaining
forecasted 2004 worldwide liquids and North American gas production,
respectively, and 30 percent of its forecasted 2005 worldwide liquids and North
American gas production. See Note D of Notes to Consolidated Financial
Statements included in "Item 1. Financial Statements" and "Item 3. Quantitative
and Qualitative Disclosures About Market Risk" for more information regarding
the Company's commodity hedge positions.
Regulatory and shareholders approvals. The Company intends to file with the
SEC a Registration Statement on Form S-4 relating to the shares of Pioneer
common stock to be issued in the Proposed Merger. A portion of such registration
statement will constitute a proxy statement/prospectus to be submitted to the
stockholders of Evergreen's common stock and the Company's common stock for
special meetings to be held by each company's stockholders in connection with
the Proposed Merger. It is expected that such proxy statement/prospectus will be
mailed to all stockholders during the third quarter of 2004, and that such
meeting will be held, and the Proposed Merger will be consummated, during the
second half of 2004. Since meetings of both Evergreen's and Pioneer's
stockholders are required in connection with the Proposed Merger, in addition to
a number of other conditions, there can be no assurance that the Proposed Merger
will occur.
Drilling Highlights
During the first quarter of 2004, the Company incurred $164.1 million of
finding and development costs including $102.0 million for exploration
activities, $55.7 million for development activities and $6.4 million for
acquisitions. The majority of the Company's exploration and development
expenditures was spent on drilling wells, acquiring seismic data and
constructing infrastructure for the Company's significant development projects.
The following tables summarize the Company's development drilling and
exploration and extension drilling activities for the three months ended March
31, 2004:
Development Drilling
------------------------------------------------------------------------
Beginning Wells Wells Successful Unsuccessful Ending Wells
in Progress Spud Wells Wells In Progress
--------------- ------ ---------- ------------- ------------
Gulf of Mexico/Gulf Coast..... 3 4 1 - 6
Permian Basin................. - 29 25 - 4
Mid-Continent................. 25 21 30 - 16
----- ---- ----- ---- -----
Total Domestic......... 28 54 56 - 26
Argentina..................... 3 8 7 - 4
Canada........................ 6 3 7 - 2
Africa ....................... - 1 - - 1
----- ---- ----- ---- -----
Total Worldwide........ 37 66 70 - 33
===== ==== ===== ==== =====
Exploration/Extension Drilling
------------------------------------------------------------------------
Beginning Wells Wells Successful Unsuccessful Ending Wells
in Progress Spud Wells Wells In Progress
--------------- ------ ---------- ------------- ------------
Gulf of Mexico/Gulf Coast.... 6 1 2 3 2
Mid-Continent................ 2 - - - 2
Alaska....................... 3 - - - 3
----- ---- ----- ---- -----
Total Domestic.......... 11 1 2 3 7
Argentina.................... 10 6 4 1 11
Canada....................... 11 35 19 18 9
Africa....................... 2 5 1 4 2
----- ---- ----- ---- -----
Total Worldwide......... 34 47 26 26 29
===== ==== ===== ==== =====
28
Domestic. The Company spent $99.3 million during the first quarter of 2004
on acquisition, drilling and seismic activities in the Gulf of Mexico/Gulf
Coast, Alaska, Permian Basin and Mid-Continent areas of the United States.
Gulf of Mexico/Gulf Coast Area. In the Gulf of Mexico/Gulf Coast area, the
Company spent $69.7 million of acquisition, drilling and seismic capital. In the
deepwater Gulf of Mexico, the Company completed one development project, had
development activities on two significant projects underway and had three
significant exploration wells being drilled during the first quarter of 2004.
o Falcon Area - During the first quarter of 2003, the Company drilled its
Harrier discovery, which was completed as a one-well subsea tie-back to the
Falcon field facilities and placed on production in January 2004. In
addition, during the third quarter of 2003, the Company successfully
drilled the Tomahawk and Raptor prospects, which are being developed as
single-well subsea tie-backs to the Falcon field facilities. To accommodate
the incremental production from Harrier, Tomahawk and Raptor as well as
potential throughput associated with additional planned exploration, an
additional parallel pipeline connecting the Falcon field to the Falcon
platform on the Gulf of Mexico shelf has been added, doubling its capacity
to 400 MMcf of gas per day. The Tomahawk and Raptor discoveries are
expected to start production during the latter half of the second quarter
of 2004. In addition, the Company may drill an additional Falcon area
exploration prospect during the fourth quarter of 2004.
o Devils Tower Area - The Dominion-operated Devils Tower development project
was sanctioned in 2001 as a spar development project with the owners
leasing a spar from a third party for the life of the field. The spar has
slots for eight dry tree wells and up to two subsea tie-back risers and is
capable of handling 60 MBbls of oil per day and 60 MMcf of gas per day.
Eight Devils Tower wells and three subsea tie-back wells in the Triton and
Goldfinger fields have been drilled and are awaiting completion. Subsequent
to quarter-end, completion operations on the first Devils Tower well were
commenced and production began in early May. Production will increase as
the wells are individually completed from the spar. The Company holds a 25
percent working interest in each of the above projects.
In addition to the development projects above in the deepwater Gulf of
Mexico, the Company participated in three sub-salt deepwater prospects during
the first quarter of 2004 exposing the Company to significant reserve potential,
two of which were noncommercial. The operator of the third prospect is
conducting open-hole evaluations to assess the rock and fluid properties and
structural position of the well. Project sanctioning of the Company's Ozona Deep
discovery is expected to be completed during the latter part of 2004.
The Company's joint exploration agreement with Woodside Energy (USA), Inc.
("Woodside"), a subsidiary of Woodside Energy Ltd. of Australia, has been
extended for an additional year through 2005 over the shallow-water Texas shelf
region of the Gulf of Mexico. The Midway prospect, the fourth well drilling
under this partnership, encountered 30 feet of net gas pay and is expected to be
tied back to an existing production platform with first production anticipated
during the second half of 2004. Three other intervals with an additional 60 feet
of gas bearing sands were also encountered and will require additional analysis
to determine future commercial potential. The Company has a 37.5 percent working
interest in this well. The four additional wells to be drilled under the
agreement, were mutually agreed to be deferred until more technical work can be
performed on the prospects by both companies. Additionally, the Company and
Woodside are evaluating shallower gas prospects on the Gulf of Mexico shelf for
possible inclusion in the 2004 drilling program.
Alaska area. The Company spent $8.3 million of acquisition and seismic
capital to add to its leasehold position and to acquire seismic data over the
newly acquired acreage. During the fourth quarter of 2002, the Company acquired
a 70 percent working interest and operatorship in ten state leases on Alaska's
North Slope. Associated therewith, the Company drilled three exploratory wells
during 2003 to test a possible extension of the productive sands in the Kuparuk
River field into the shallow waters offshore. Although all three of the wells
found the sands filled with oil, they were too thin to be considered commercial
on a stand-alone basis. However, the wells also encountered thick sections of
oil- bearing Jurassic-aged sands, and the first well flowed at a rate of
approximately 1,300 barrels per day. In January 2004, the Company farmed-into a
large acreage block to the southwest of the Company's discovery. During the
remainder of 2004, the Company plans to analyze seismic data and technical
information from other wells drilled southwest of its discovery and evaluate the
feasibility of potential development options.
29
Permian Basin area. The Company spent $11.0 million of capital during the
first quarter of 2004 primarily on development drilling in the Spraberry oil
trend where the Company plans to drill approximately 100 wells during 2004.
Included in the capital spent during the first quarter of 2004 was a $1.0
million deposit related to the acquisition of various working interests in
approximately 600 Spraberry oil wells, 400 of which were already operated by the
Company. On April 1, 2004, the Company consummated this transaction for an
additional $18.7 million paid at closing.
Mid-Continent area. The Company spent $10.3 million of capital during the
first quarter of 2004 primarily in the West Panhandle field in Texas where the
Company plans to drill approximately 110 wells during 2004. The Company also
plans to drill approximately 20 wells this year in the Hugoton field in Kansas.
Argentina. The Company spent $22.8 million of acquisition, drilling and
seismic capital during the first quarter of 2004. With the economic environment
in Argentina stabilizing and the potential for improvements in future gas
prices, the Company has doubled its capital budget in Argentina for 2004.
The Company's drilling activities in Argentina continue to confirm the
presence of significant deep gas reserves. First quarter 2004 Argentine gas
production was the highest summer production in the segment's history and
Pioneer expects to complete the expansion of its Loma Negra gas plant in
Argentina over the next few months, increasing plant capacity by 25 percent as
demand peaks during the winter months in Argentina. The Company is also
acquiring additional 3-D seismic in support of future Argentine drilling plans.
Canada. The Company spent $27.4 million of acquisition, drilling and
seismic capital during the first quarter of 2004, primarily in the Chinchaga,
Martin Creek and Lookout Butte areas that are mainly accessible for drilling
during the winter months.
Africa. The Company spent $14.6 million of acquisition, drilling and
seismic capital during the first quarter of 2004 in South Africa, Tunisia and
Gabon.
South Africa. Near the end of the first quarter of 2004, the Company began
drilling a water injection well at the Sable field in an attempt to enhance
production. The production impact of the water injection well is not expected to
be known until later in 2004. The Company also continues to evaluate the
potential to develop its large quantity of gas reserves by attempting to
establish a contract to supply gas to an existing synthetic fuels plant.
Tunisia. The Company spent $1.5 million of capital during the first quarter
of 2004, primarily to place its most recent discovery, Hawa, on production.
During 2004, the Company plans to drill one to two exploration wells on the
Company-operated El Hamra permit, a development well at Hawa and another
exploration well on the ENI-operated Adam concession.
Gabon. The Company spent $12.7 million of capital during the first quarter
of 2004 to drill five exploration wells, one of which was successful in
extending the planned development area to the south. The remaining four wells,
although unsuccessful and expensed as dry holes, were helpful in defining the
future development of the oil rim. The Company is currently in the process of
completing the plan of development to be filed with the government late in the
second quarter of 2004. If approved, development operations will commence with
first production expected in 2006.
Results of Operations
Oil and gas revenues. Revenues from oil and gas operations totaled $446.5
million for the three months ended March 31, 2004, compared to $285.0 million
for the same period in 2003. The increase in oil and gas revenues during the
first quarter of 2004 as compared to the first quarter of 2003 is principally
attributable to (i) increased gas production from the Company's deepwater Gulf
of Mexico projects, including a full quarter of production from the Company's
Falcon field that first produced during March 2003, incremental Falcon
production attributable to the March 28, 2003 purchase of the remaining 25
percent interest in the field and initial production in January 2004 from the
Harrier field in the deepwater Gulf of Mexico; (ii) oil production from the
Company's Tunisian and South African projects which first began producing
operations during the second and third quarters of 2003, respectively; (iii)
increased oil, NGL and gas production from the Company's Argentine assets,
primarily due to strengthening demand fundamentals in the country; and (iv)
increases in the Company's reported oil, NGL and gas prices including the
results of hedging activities.
30
The following table provides the Company's average daily production volumes
and average reported prices, including the results of hedging activities, by
geographic area and in total, for the three-month periods ended March 31, 2004
and 2003:
Three months ended
March 31,
----------------------
2004 2003
-------- ---------
Average daily production:
Oil (Bbls):
United States................................. 24,971 24,086
Argentina..................................... 8,628 7,673
Canada........................................ 100 135
Africa........................................ 14,034 -
Worldwide..................................... 47,733 31,894
NGLs (Bbls):
United States................................. 20,936 20,024
Argentina..................................... 1,424 1,130
Canada........................................ 1,046 879
Worldwide..................................... 23,406 22,033
Gas (Mcf):
United States................................. 550,480 339,598
Argentina..................................... 97,818 66,633
Canada........................................ 40,019 40,876
Worldwide..................................... 688,317 447,107
Total (BOE):
United States................................. 137,653 100,708
Argentina..................................... 26,355 19,909
Canada........................................ 7,816 7,827
Africa........................................ 14,034 -
Worldwide..................................... 185,858 128,444
Average reported prices:
Oil (per Bbl):
United States................................. $ 26.67 $ 25.85
Argentina..................................... $ 27.93 $ 25.61
Canada........................................ $ 35.00 $ 31.81
Africa........................................ $ 31.41 $ -
Worldwide..................................... $ 28.31 $ 25.82
NGLs (per Bbl):
United States................................. $ 21.52 $ 21.63
Argentina..................................... $ 29.16 $ 24.27
Canada........................................ $ 26.51 $ 27.51
Worldwide..................................... $ 22.21 $ 22.00
Gas (per Mcf):
United States................................. $ 5.11 $ 4.72
Argentina..................................... $ .58 $ .54
Canada........................................ $ 4.22 $ 5.38
Worldwide..................................... $ 4.41 $ 4.16
On a BOE basis, worldwide average daily production increased by 45 percent
during the three months ended March 31, 2004, as compared to the same period in
2003. During the first quarter of 2004, as compared to the first quarter of
2003, worldwide oil production increased 50 percent; NGL production increased by
six percent; and gas production increased by 54 percent. Per BOE average daily
production, on a first-quarter to first-quarter comparison, increased by 37
percent and 32 percent in the United States and Argentina, respectively, while
production in Canada decreased by a negligible amount. Production from the
Company's Tunisian and South African oil projects began during the second and
third quarters of 2003, respectively.
As discussed above, oil and gas revenues for the three months ended March
31, 2004 were positively impacted by commodity price increases. Comparing the
first quarter of 2004 to the same period in 2003, the Company's average
worldwide oil price increased ten percent, average worldwide NGL price increased
one percent and average worldwide gas price increased six percent.
31
Second quarter 2004 production is expected to average 180,000 to 195,000
BOEs per day, reflecting the incremental production expected from Devils Tower,
Tomahawk and Raptor, the variability of oil cargo shipments in Tunisia and South
Africa, and the seasonal increase in gas demand during Argentina's winter
season.
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 2004,
the Company's commodity price hedges decreased oil and gas revenues by $30.7
million as compared to $50.4 million of commodity hedge losses during the same
period in 2003. See Note D 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,
2004 and 2003.
Subsequent to March 31, 2004, the Company entered into new swap contracts
to hedge (i) 6,189 Bbls per day of the nine months ended December 31, 2004 oil
sales at a weighted average fixed price per Bbl of $36.74, (ii) 10,000 Bbls per
day of 2005 oil sales at a weighted average fixed price per Bbl of $33.14, (iii)
30,000 Mcf per day of July through December 2004 gas sales at a weighted average
fixed price per MMBtu of $6.42 and (iv) 114,904 Mcf per day of 2005 gas sales at
a weighted average fixed price per MMBtu of $5.54. See "Proposed Merger with
Evergreen Resources, Inc. - Liquidity and capital structure", for information
regarding the Company's hedge program.
Oil and gas production costs. During the three months ended March 31, 2004,
total production costs per BOE averaged $5.27, representing a decrease of $.60
per BOE, or ten percent, as compared to total production costs per BOE of $5.87
during the first quarter of 2003. Lease operating expenses and workover expenses
represent the components of production costs for which the Company has
management control, while production and ad valorem taxes and field fuel
expenses are directly related to commodity price changes.
The decrease in total production costs per BOE during the first quarter of
2004, as compared to the first quarter of 2003, is primarily comprised of
decreases in production taxes and field fuel costs resulting from a $.42 per Mcf
decrease in realized gas prices excluding hedge results.
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, 2004 and 2003:
Three months ended
March 31,
-------------------
2004 2003
------- -------
Lease operating expense..................... $ 3.36 $ 3.35
Taxes:
Production............................... .58 .84
Ad valorem............................... .46 .48
Field fuel expenses......................... .65 1.00
Workover costs.............................. .22 .20
------ -----
Total production costs................... $ 5.27 $ 5.87
====== ======
Three months ended
March 31,
-------------------
2004 2003
------- -------
Total production costs:
United States............................ $ 5.27 $ 6.13
Argentina................................ $ 2.82 $ 3.02
Canada................................... $ 11.18 $ 9.82
Africa .................................. $ 6.64 $ -
Worldwide................................ $ 5.27 $ 5.87
Based on market-quoted commodity prices during April 2004, the Company
expects second quarter 2004 production costs to average $5.20 to $5.70 per BOE.
32
Depletion, depreciation and amortization expense. The Company's total
depletion, depreciation and amortization expense per BOE was $8.07 and $6.06 for
the three-month periods ended March 31, 2004 and 2003, respectively. Depletion
expense per BOE, the largest component of depletion, depreciation and
amortization, increased to $7.91 per BOE during the three months ended March 31,
2004, as compared to $5.86 per BOE during the same period in 2003, primarily due
to increases in higher cost-basis deepwater Gulf of Mexico, Tunisian and South
African production volumes.
The following table provides the Company's depletion expense per BOE by
geographic area for the three-month periods ended March 31, 2004 and 2003:
Three months ended
March 31,
-------------------
2004 2003
------- -------
Depletion expense:
United States........................... $ 7.77 $ 5.83
Argentina............................... $ 5.23 $ 4.65
Canada.................................. $ 10.51 $ 9.30
Africa ................................. $ 12.84 $ -
Worldwide............................... $ 7.91 $ 5.86
The Company expects second quarter 2004 depletion, depreciation and
amortization expense to average $8.00 to $8.50 per BOE.
Exploration, abandonments, geological and geophysical costs. Exploration,
abandonments, geological and geophysical costs were $80.5 million during the
three months ended March 31, 2004, as compared to $35.9 million during the same
period in 2003. The increase in exploration, abandonments, geological and
geophysical expense during the first quarter of 2004 as compared to the same
period of 2003 is comprised of a $31.0 million increase in dry hole expense, an
$11.4 million increase in geological and geophysical expenses and a $2.2 million
increase in leasehold abandonments and other exploration expenses. Significant
components of the Company's dry hole expense during the first quarter of 2004
included $26.4 million and $10.7 million on the Company's deepwater Gulf of
Mexico Juno and Myrtle Beach prospects, respectively, and $6.4 million and $2.8
million on the Company's Olowi and Dentale prospects, respectively, in Gabon.
During the first quarter of 2004, the Company completed and evaluated 52
exploration/extension wells, 26 of which were successfully completed as
discoveries.
The following table provides the Company's geological and geophysical
costs, exploratory dry hole expense, lease abandonments expense and other
exploration expense for the three-month periods ended March 31, 2004 and 2003:
Africa
United and
States Argentina Canada Other Total
------- --------- -------- ------- --------
(in thousands)
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
====== ====== ======= ====== =======
Three months ended March 31, 2003:
Geological and geophysical............ $ 5,839 $ 1,732 $ 1,337 $ 1,474 $ 10,382
Exploratory dry holes................. 11,358 880 8,714 2,227 23,179
Leasehold abandonments and other...... 590 432 1,276 8 2,306
------ ------ ------- ------ -------
$17,787 $ 3,044 $ 11,327 $ 3,709 $ 35,867
====== ====== ======= ====== =======
The Company expects second quarter 2004 exploration, abandonments,
geological and geophysical costs to be $25 million to $50 million, dependent
largely on exploratory drilling results and expected seismic expenditures.
33
General and administrative expense. General and administrative expense for
the three-month periods ended March 31, 2004 and 2003 was $18.3 million and
$15.5 million, respectively. The increase in general and administrative expense
is primarily due to increases in administrative staff and performance-related
compensation costs.
The Company expects second quarter 2004 general and administrative expense
to be $16 million to $18 million.
Accretion of discount on asset retirement obligations. During the
three-month periods ended March 31, 2004 and 2003, accretion of discount on
asset retirement obligations was $2.0 million and $1.1 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 the deepwater Gulf of Mexico, Tunisian and South African wells which
began production during the twelve months ended March 31, 2004. See "Cumulative
effect of change in accounting principle" and Notes B and E of Notes to
Consolidated Financial Statements included in "Item 1. Financial Statements" for
additional information regarding the Company's adoption of SFAS 143.
The Company expects second quarter 2004 accretion of discount on asset
retirement obligations to be approximately $2 million.
Interest expense. Interest expense was $21.6 million for the three months
ended March 31, 2004, as compared to $22.5 million for the same period in 2003.
The decrease in interest expense is primarily due to a $1.0 million decrease in
interest incurred on the Revolving Credit Agreement, primarily associated with
reduced borrowings and a $.7 million increase in interest rate hedge gains,
partially offset by a $.9 million decrease in interest capitalized. The weighted
average interest rate on the Company's indebtedness for the three months ended
March 31, 2004 was 5.31 percent as compared to 5.56 percent for the same period
in 2003, including the effects of the Company's interest rate swaps.
The Company expects second quarter 2004 interest expense to be $20 million
to $23 million.
Other expenses. Other expenses for the three-month periods ended March 31,
2004 and 2003 were $.2 million and $5.2 million, respectively. The decrease in
other expenses is primarily attributable to a $1.8 million decrease in hedge
ineffectiveness charges and a $.3 million decrease in foreign exchange losses.
Income tax provision. During the three months ended March 31, 2004, the
Company recognized an income tax provision of $39.8 million, as compared to a
$2.3 million tax provision recognized during the same period in 2003. The
increase in the Company's effective tax rate is primarily attributable to the
reversal of the Company's United States deferred tax asset valuation allowances
during the third quarter of 2003. See Note C of Notes to Consolidated Financial
Statements included in "Item 1. Financial Statements" for additional information
regarding the Company's income taxes.
During the second quarter of 2004, the Company estimates that its cash
income taxes will be $3 million to $6 million.
Cumulative effect of change in accounting principle. As previously
discussed, the Company adopted the provisions of SFAS 143 on January 1, 2003 and
recognized a $15.4 million benefit from the cumulative effect of change in
accounting principle, net of $1.3 million of deferred tax. See Notes B and E of
Notes to Consolidated Financial Statements included in "Item 1. Financial
Statements" for additional information regarding the Company's adoption of SFAS
143.
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.
Oil and gas properties. The Company's cash expenditures for additions to
oil and gas properties during the three-month periods ended March 31, 2004 and
2003 totaled $167.2 million and $252.8 million, respectively. The Company's
first quarter 2004 additions to oil and gas properties were funded by net cash
provided by operating activities of $253.6 million. The Company's first quarter
2003 additions to oil and gas properties were funded by $136.8 million of net
cash provided by operating activities, $15.6 million of proceeds from
disposition of assets and borrowings under long-term debt.
34
Contractual obligations, including off-balance sheet obligations. The
Company's contractual obligations include long-term debt, operating leases,
drilling commitments, derivative obligations and other liabilities. 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, 2004, the material off-balance sheet arrangements and transactions
that the Company has entered into include (i) undrawn letters of credit, (ii)
operating lease agreements, (iii) drilling commitments and (iv) 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. Other than the Company's
derivative obligations, there have been no material changes in its contractual
obligations since December 31, 2003. 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 assets and liabilities during the three
months ended March 31, 2004.
Working capital. Funding for the Company's working capital obligations is
provided by internally-generated cash flow. Funding for the repayment of
principal and interest on outstanding debt and the Company's capital expenditure
program 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.
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 2004.
Operating activities. Net cash provided by operating activities during the
three-month periods ended March 31, 2004 and 2003 were $253.6 million and $136.8
million, respectively. The increase in net cash provided by operating activities
was primarily due to higher production volumes and higher commodity prices.
Investing activities. Net cash used in investing activities during the
three-month periods ended March 31, 2004 and 2003 were $172.3 million and $239.5
million, respectively. The decrease in net cash used in investing activities was
primarily due to an $85.5 million decrease in additions to oil and gas
properties. The decrease is primarily attributable to a $119.4 million
acquisition of an additional 25 percent interest in the Falcon field offset by
$15.3 million of proceeds from disposition of assets during the first quarter of
2003.
Financing activities. Net cash used in financing activities during the
three months ended March 31, 2004 was $91.4 million as compared to net cash
provided by financing activities of $100.6 million during the same period of
2003. The reduction in long-term debt was made possible by the combined effects
of increased net cash provided by operating activities and decreased additions
to oil and gas properties. During the three months ended March 31, 2004, the
Company also used $5.6 million to purchase 183,300 shares of treasury stock.
During March 2004, the Company's board of directors declared a $.10 per
common share semiannual dividend, payable on April 13, 2004 to shareholders of
record on March 29, 2004. Associated therewith, the Company distributed $12
million of aggregate dividends during April 2004. If declared by the board of
directors, the Company's second semiannual dividend will be distributed during
October 2004.
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 the
Revolving Credit Agreement. Outstanding borrowings under the Revolving Credit
Agreement totaled $70.0 million as of March 31, 2004. Including $28.2 million of
undrawn and outstanding letters of credit under the Revolving Credit Agreement,
the Company has $601.8 million of unused borrowing capacity as of March 31,
2004.
35
Book capitalization and current ratio. The Company's book capitalization at
March 31, 2004 was $3.2 billion, consisting of debt of $1.4 billion and
stockholders' equity of $1.8 billion. Consequently, the Company's debt to book
capitalization decreased to 45.3 percent at March 31, 2004 from 46.9 percent at
December 31, 2003. The Company's ratio of current assets to current liabilities
was .48 at March 31, 2004 and December 31, 2003.
Status of Accounting Development
In its review of registrants' filings, the staff of the SEC has taken the
position that Statement of Financial Accounting Standards No. 141, "Business
Combinations" ("SFAS 141") and Statement of Financial Accounting Standards No.
142, "Goodwill and Other Intangible Assets" ("SFAS 142"), require oil and gas
companies to separately report on their balance sheets the costs of leasehold
mineral rights, including related accumulated depletion, as intangible assets
and provide related disclosures.
The Company has historically included producing leasehold mineral rights
costs in the proved properties caption on its Consolidated Balance Sheets. This
classification is consistent with the provisions of SFAS 19 and standard
industry practice. Almost all costs included in the Company's unproved
properties caption on the Consolidated Balance Sheets are leasehold mineral
rights that are regularly evaluated for impairment based on lease term and
drilling activity.
The SEC staff referred the issue of whether leasehold mineral rights
constitute tangible or intangible assets to the Emerging Issues Task Force (the
"EITF") of the Financial Accounting Standard Board (the "FASB"). An EITF working
group was created to research this issue and at the March 17 - 18, 2004 EITF
meeting, the working group reached a consensus that leasehold mineral rights
constituted tangible assets. Ratification of the consensus was subject to
resolution of inconsistencies between the characterization of mineral rights as
tangible assets in the working group consensus and the characterization of
mineral rights as intangible assets in SFAS 141 and SFAS 142. On April 2, 2004,
the FASB issued for comment proposed FASB Staff Positions (the "FSP") No. 141-a
and 142-a to eliminate the inconsistencies between the working group consensus
and the provisions of SFAS 141 and SFAS 142. The FSP was finalized on April 30,
2004 and is effective for all reporting periods beginning after April 29, 2004.
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, 2003.
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 for the year
ended December 31, 2003.
The following table reconciles the changes that occurred in the fair values
of the Company's open derivative contracts during the first quarter of 2004:
Derivative Contract Net Liabilities
----------------------------------------
Interest
Commodities Rate Total
----------- -------- -----------
(in thousands)
Fair value of contracts outstanding
as of December 31, 2003............... $(201,422) $ - $ (201,422)
Changes in contract fair value (a)....... (122,223) (1,546) (123,769)
Contract maturities...................... 46,655 - 46,655
-------- ------- ---------
Fair value of contracts outstanding
as of March 31, 2004.................. $(276,990) $ (1,546) $ (278,536)
======== ======= =========
<FN>
- ---------------
(a) At inception, new derivative contracts entered into by the Company have no
intrinsic value.
</FN>
36
The following disclosures provide specific information about material
changes that have occurred since December 31, 2003 in the Company's portfolio of
financial instruments. The Company may recognize future earnings gains or losses
on these instruments from changes in commodity prices or interest rates.
Interest rate sensitivity. The following table provides information about
the debt obligations and derivative financial instruments of the Company that
are sensitive to changes in interest rates as of March 31, 2004. 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, 2004. 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 the six-month LIBOR.
During March 2004, the Company entered into interest rate swap contracts on
an aggregate $150 million notional amount to hedge the fair value of its 7-1/2
percent senior notes. The terms of the interest rate swap contracts match the
scheduled maturity of the hedged senior notes, require the counterparties to pay
the Company a 7-1/2 percent fixed annual interest rate and require the Company
to pay the counterparties variable annual interest rates equal to the periodic
six-month LIBOR plus a weighted average annual margin of 3.71 percent. For
interest rate swap contracts, the table presents the notional amounts together
with the fixed rate to be received by the Company and the variable rate to be
paid estimated based on the current variable rate being paid by the Company
projected forward proportionate to the forward yield curve for the six-month
LIBOR.
Interest Rate Sensitivity
Debt Obligations and Derivative Financial Instruments as of March 31, 2004
Nine months Liability
ended Year ended December 31, Fair Value at
December 31, ---------------------------------------------------------- March 31,
2004 2005 2006 2007 2008 Thereafter Total 2004
----------- -------- -------- -------- -------- ---------- ---------- -----------
(in thousands, except interest rates)
Total Debt:
Fixed rate maturities...... $ - $134,182 $ - $154,218 $353,174 $745,121 $1,386,695 $(1,599,861)
Weighted average
interest rate (%)........ 7.93 7.86 7.83 7.81 8.34 8.37
Variable rate maturities... $ - $ - $ - $ - $ 70,000 $ - $ 70,000 $ (70,000)
Average interest rate (%).. 2.80 4.19 5.32 6.07 6.60 -
Interest Rate Hedge
Derivatives (a):
Notional debt amount....... $150,000 $150,000 $150,000 $150,000 $150,000 $150,000 $ 150,000 $ (1,546)
Fixed rate receivable (%).. 7.50 7.50 7.50 7.50 7.50 7.50
Variable rate payable (%).. 5.51 6.90 8.03 8.78 9.31 10.64
<FN>
- ---------------
(a) During April 2004, the Company entered into interest rate swap contracts to
hedge $150 million notional amount of its 9-5/8 percent senior notes at an
average annual variable rate of the six-month LIBOR plus a weighted average
margin of 5.66 percent.
</FN>
Commodity price sensitivity. During the first quarter of 2004, the Company
entered into certain oil and gas hedge derivatives and terminated other oil and
gas hedge derivatives. The following tables provide information about the
Company's oil and gas derivative financial instruments that were sensitive to
oil or gas price changes as of March 31, 2004. As of March 31, 2004, all of the
Company's oil and gas derivative financial instruments qualified as hedges.
37
See Note D 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, 2004
Nine months Liability
ended Year ended December 31, Fair Value at
December 31, ---------------------------------------- March 31,
2004 2005 2006 2007 2008 2004
----------- -------- -------- -------- ------- -------------
(in thousands)
Oil Hedge Derivatives (a):
Average daily notional Bbl volumes:
Swap contracts (b)...................... 17,309 17,000 5,000 1,000 5,000 $(87,260)
Weighted average fixed price per Bbl... $ 25.50 $ 24.93 $ 26.19 $ 26.00 $ 26.09
Average forward NYMEX oil prices (c)..... $ 38.15 $ 33.94 $ 31.21 $ 29.24 $ 28.49
<FN>
- ---------------
(a) See Note D 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, 2004, the Company entered into new oil swap
contracts to hedge 6,189 Bbls per day of the nine months ended December 31,
2004 oil sales at a weighted average fixed price per Bbl of $36.74 and
10,000 Bbls per day of 2005 oil sales at a weighted average fixed price per
Bbl of $33.14.
(c) The average forward NYMEX oil prices are based on May 5, 2004 market
quotes.
</FN>
Gas Price Sensitivity (a)
Derivative Financial Instruments as of March 31, 2004
Nine months Liability
ended Year ended December 31, Fair Value at
December 31, ------------------------------ March 31,
2004 2005 2006 2007 2004
----------- -------- -------- -------- -------------
(in thousands)
Gas Hedge Derivatives (b):
Average daily notional MMBtu volumes:
Swap contracts (c)....................... 280,000 60,000 70,000 20,000 $(189,730)
Weighted average fixed price per MMBtu.. $ 4.11 $ 4.24 $ 4.16 $ 3.51
Average forward NYMEX gas prices (d)...... $ 6.46 $ 5.82 $ 5.26 $ 5.02
<FN>
- ---------------
(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
contract and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(b) See Note D 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, 2004, the Company entered into new gas swap
contracts to hedge 30,000 Mcf per day of July through December 2004 gas
sales at a weighted average fixed price per MMBtu of $6.42 and 114,904 Mcf
per day of 2005 gas sales at a weighted average fixed price per MMBtu of
$5.54.
(d) The average forward NYMEX gas prices are based on May 5, 2004 market
quotes.
</FN>
38
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.
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
As discussed in Note G of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements", the Company is a party to various
legal actions incidental to its business. Except for the specific legal actions
described in Note G, 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 6. Exhibits and Reports on Form 8-K
Exhibits
2.1 Agreement and Plan of Merger dated May 3, 2004, among the Company,
Evergreen Resources, Inc. and BC Merger Sub, Inc. (incorporated by
reference to Exhibit 2.1 to the Company's current report on Form 8-K,
File No. 1-13245, filed with the SEC on May 5, 2004).
10.1 Consulting and Non-Competition Agreement, dated May 3, 2004, between
the Company and Dennis R. Carlton (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 May 5, 2004).
10.2 Consulting and Non-Competition Agreement, dated May 3, 2004, between
the Company and Kevin R. Collins (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 May 5, 2004).
10.3 Non-Competition Agreement, dated May 3, 2004, between the Company and
Mark S. Sexton (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 May 5, 2004).
31.1 Chief Executive Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 Chief Financial Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 Chief Executive Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 Chief Financial Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
Reports on Form 8-K
During the three months ended March 31, 2004, the Company filed with the
SEC current reports on Form 8-K on February 2, February 18 and March 30, 2004,
to provide certain information that is deemed furnished, not filed, under the
Exchange Act.
The Company's February 2, 2004 Form 8-K provided, as an exhibit thereto, a
news release issued by the Company on February 2, 2004 announcing, together with
related information, financial and operating results for the quarter and year
ended December 31, 2003, providing an operations update and providing the
Company's first quarter 2004 financial outlook based on current expectations.
39
The Company's February 18, 2004 Form 8-K provided, as an exhibit thereto, a
news release issued by the Company on February 18, 2004 announcing, the
declaration of a semiannual cash dividend of $0.10 per share on its outstanding
common stock payable on April 13, 2004 to stockholders of record on March 29,
2004 by the Company's board of directors.
The Company's March 30, 2004 Form 8-K provided, as an exhibit thereto, a
news release issued by the Company on March 30, 2004 providing a guidance update
on first quarter production and exploration and abandonment expense based on
current expectations and partial quarter actual results; announcing recent
drilling results, including information regarding the Company's Juno and Myrtle
Beach prospects; and providing certain forward looking information, including
the acquisition of additional interests in the Spraberry field and timing of
first production from the Company's deepwater Gulf of Mexico Devils Tower,
Tomahawk and Raptor fields.
40
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 7, 2004 By: /s/ Timothy L. Dove
-----------------------------------
Timothy L. Dove
Executive Vice President and Chief
Financial Officer
Date: May 7, 2004 By: /s/ Richard P. Dealy
-----------------------------------
Richard P. Dealy
Vice President and Chief
Accounting Officer
41
Exhibit Index
Page
2.1 Agreement and Plan of Merger dated May 3, 2004, among the Company,
Evergreen Resources, Inc. and BC Merger Sub, Inc. (incorporated by
reference to Exhibit 2.1 to the Company's current report on Form
8-K, File No. 1-13245, filed with the SEC on May 5, 2004).
10.1 Consulting and Non-Competition Agreement, dated May 3, 2004,
between the Company and Dennis R. Carlton (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 May 5, 2004).
10.2 Consulting and Non-Competition Agreement, dated May 3, 2004,
between the Company and Kevin R. Collins (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 May 5, 2004).
10.3 Non-Competition Agreement, dated May 3, 2004, between the Company
and Mark S. Sexton (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 May 5, 2004).
31.1 (a) Chief Executive Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
31.2 (a) Chief Financial Officer certification under Section 302 of the
Sarbanes-Oxley Act of 2002.
32.1 (a) Chief Executive Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
32.2 (a) Chief Financial Officer certification under Section 906 of the
Sarbanes-Oxley Act of 2002.
- -------------
(a) filed herewith
42