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 June 30, 1999
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 No. 1-13245
PIONEER NATURAL RESOURCES COMPANY
---------------------------------
(Exact name of Registrant as specified in its ch
Delaware 75-2702753
-------- ----------
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)
1400 Williams Square West, 5205 N. O'Connor Blvd., Irving, Texas 75039
- ---------------------------------------------------------------- -----
(Address of principal executive offices) (Zip code)
Registrant?s Telephone Number, including area code: (972) 444-9001
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 / /
Number of shares of Common Stock outstanding as of July 30, 1999 . . 100,300,023
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
TABLE OF CONTENTS
Page
----
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
Consolidated Balance Sheets as of June 30, 1999 and
December 31, 1998 ......................................... 3
Consolidated Statements of Operations and Comprehensive
Income (Loss) for the three and six months ended
June 30, 1999 and 1998..................................... 5
Consolidated Statement of Stockholders? Equity for the six
months ended June 30, 1999................................. 6
Consolidated Statements of Cash Flows for the three and six
months ended June 30, 1999 and 1998........................ 7
Notes to Consolidated Financial Statements................... 8
Item 2. Management's Discussion and Analysis of Financial
Condition and Results of Operations........................ 24
Item 3. Quantitative and Qualitative Disclosures About Market Risk... 37
PART II. OTHER INFORMATION
Item 1. Legal Proceedings............................................ 42
Item 4. Submission of Matters to a Vote of Security Holders.......... 42
Item 6. Exhibits and Reports on Form 8-K............................. 43
Signatures................................................... 44
Exhibit Index................................................ 45
<PAGE>
PART I. FINANCIAL INFORMATION
Item 1. Financial Statements
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS
(in thousands, except share data)
<TABLE>
<S> <C> <C>
June 30, December 31,
1999 1998
-------- ------------
(Unaudited)
ASSETS
Current assets:
Cash and cash equivalents........................... $ 79,269 $ 59,221
Accounts receivable:
Trade, net........................................ 29,164 33,384
Affiliates........................................ 2,086 3,657
Oil and gas sales................................. 79,973 73,479
Inventories......................................... 13,929 15,221
Deferred income taxes............................... 6,400 7,100
Other current assets................................ 8,358 9,926
---------- -----------
Total current assets............................ 219,179 201,988
---------- -----------
Property, plant and equipment, at cost:
Oil and gas properties, using the successful efforts
method of accounting:
Proved properties................................. 3,067,221 3,621,630
Unproved properties............................... 304,835 342,589
Accumulated depletion, depreciation and amortization (765,283) (930,111)
---------- -----------
2,606,773 3,034,108
---------- -----------
Deferred income taxes................................. 97,500 96,800
Other property and equipment, net..................... 47,733 55,010
Other assets, net..................................... 111,923 93,408
---------- -----------
$3,083,108 $ 3,481,314
========== ===========
</TABLE>
The financial information included as of June 30, 1999 has been prepared by
management without audit by independent public accountants.
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>
<TABLE>
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED BALANCE SHEETS (continued)
(in thousands, except share data)
<S> <C> <C>
June 30, December 31,
1999 1998
-------- ------------
(Unaudited)
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of long-term debt......... $ 69,951 $ 306,521
Accounts payable:
Trade..................................... 76,128 94,937
Affiliates................................ 924 4,492
Accrued interest payable..................... 37,040 33,194
Other current liabilities.................... 77,226 87,688
---------- ------------
Total current liabilities........... 261,269 526,832
---------- ------------
Long-term debt, less current maturities......... 1,859,001 1,868,744
Other noncurrent liabilities.................... 180,350 232,461
Deferred income taxes........................... 64,600 64,200
Stockholders' equity:
Preferred stock, $.01 par value; 100,000,000
shares authorized; one share issued and
outstanding................................ - -
Common stock, $.01 par value; 500,000,000
shares authorized; 100,837,415 and
100,833,615 shares issued as of June 30,
1999 and December 31, 1998, respectively... 1,008 1,008
Additional paid-in-capital................... 2,348,095 2,347,996
Treasury stock, at cost; 537,392 shares as of
June 30, 1999 and December 31, 1998........ (10,388) (10,388)
Retained deficit............................. (1,629,559) (1,552,442)
Accumulated other comprehensive income:
Cumulative translation adjustment......... 8,732 2,903
---------- ------------
Total stockholders' equity.......... 717,888 789,077
---------- ------------
Commitments and contingencies
$3,083,108 $ 3,481,314
========== ============
</TABLE>
The financial information included as of June 30, 1999 has been prepared by
management without audit by independent public accountants.
The accompanying notes are an integral part of these consolidated
financial statements.
<PAGE>
<TABLE>
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS
AND COMPREHENSIVE INCOME (LOSS)
(in thousands, except per share data)
(Unaudited)
<S> <C> <C> <C> <C>
Three months ended Six months ended
June 30, June 30,
------------------ -----------------
1999 1998 1999 1998
---- ---- ---- ----
Revenues:
Oil and gas...................... $ 174,231 $ 183,647 $ 321,382 $ 381,016
Interest and other............... 2,804 1,145 48,777 2,323
Gain (loss) on disposition of
assets, net................... (42,291) 315 (42,224) 325
--------- --------- --------- ---------
134,744 185,107 327,935 383,664
--------- --------- --------- ---------
Costs and expenses:
Oil and gas production........... 41,624 56,613 88,818 111,755
Depletion, depreciation and
amortization................... 64,235 83,808 133,607 160,058
Impairment of oil and gas
properties..................... 17,894 - 17,894 -
Exploration and abandonments..... 17,925 26,573 29,701 50,522
General and administrative....... 10,188 17,387 20,437 37,412
Reorganization................... 1,490 3,372 7,019 20,549
Interest......................... 46,903 41,017 89,424 80,495
Other............................ 9,601 6,846 18,252 13,626
--------- --------- --------- ---------
209,860 235,616 405,152 474,417
--------- --------- --------- ---------
Loss before income taxes........... (75,116) (50,509) (77,217) (90,753)
Income tax benefit................. 500 17,700 100 31,100
--------- --------- --------- ---------
Net loss........................... (74,616) (32,809) (77,117) (59,653)
Other comprehensive income (loss):
Translation adjustment........... 5,734 (3,702) 5,829 (2,762)
--------- --------- --------- ---------
Comprehensive loss................. $ (68,882) $ (36,511) $ (71,288) $ (62,415)
========= ========= ========= =========
Net loss per share:
Basic.......................... $ (.74) $ (.33) $ (.77) $ (.60)
========= ========= ========= =========
Diluted........................ $ (.74) $ (.33) $ (.77) $ (.60)
========= ========= ========= =========
Dividends declared per share....... $ - $ - $ - $ .05
========= ========= ========= =========
Weighted average shares outstanding 100,300 99,939 100,300 100,003
========= ========= ========= =========
</TABLE>
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.
<PAGE>
<TABLE>
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY
(in thousands)
(Unaudited)
<S> <C> <C> <C> <C> <C> <C> <C>
Common Accumulated
Stock Additional Other Total
Shares Common Paid-in Treasury Retained Comprehensive Stockholders'
Outstanding Stock Capital Stock Deficit Income Equity
----------- ----- ----------- -------- ----------- ------------- -------------
Balance as of January 1, 1999 100,296 $ 1,008 $ 2,347,996 $(10,388) $(1,552,442) $ 2,903 $ 789,077
Restricted stock awards........... 3 - 69 - - - 69
Stock option awards............... - - 24 - - - 24
Stock options exercised........... 1 - 6 - - - 6
Net loss.......................... - - - - (77,117) - (77,117)
Other comprehensive income:
Translation adjustment......... - - - - - 5,829 5,829
---------- ------- ----------- -------- ----------- ---------- -----------
Balance as of June 30, 1999 100,300 $ 1,008 $ 2,348,095 $(10,388) $(1,629,559) $ 8,732 $ 717,888
========== ======= =========== ======== =========== ========== ===========
</TABLE>
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.
<PAGE>
<TABLE>
PIONEER NATURAL RESOURCES COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(Unaudited)
<S> <C> <C> <C> <C>
Three months ended Six months ended
June 30, June 30,
------------------ ----------------
1999 1998 1999 1998
---- ---- ---- ----
Cash flows from operating activities:
Net loss............................ $(74,616) $ (32,809) $ (77,117) $ 59,653)
Adjustments to reconcile net loss
to net cash provided by operating
activities:
Depletion, depreciation and
amortization.................. 64,235 83,808 133,607 160,058
Impairment of oil and gas
properties.................... 17,894 - 17,894 -
Exploration expenses, including
dry holes..................... 14,721 19,811 25,031 35,645
Deferred income taxes........... (500) (15,700) (600) (28,400)
(Gain) loss on disposition of
assets, net................... 42,291 (315) 42,224 (325)
Other noncash items............. 11,611 12,676 (18,675) 25,813
Change in operating assets and
liabilities, net of effects from
acquisitions and dispositions:
Accounts receivable............. (1,996) 31,873 299 37,302
Inventory....................... (545) (682) 1,270 143
Other current assets............ 1,292 7,462 1,119 (1,329)
Accounts payable................ 3,987 (16,891) (22,527) (24,723)
Other current liabilities....... 10,714 2,136 (5,146) 15,889
-------- --------- --------- --------
Net cash provided by operating
activities.................. 89,088 91,369 97,379 160,420
-------- --------- --------- --------
Cash flows from investing activities:
Proceeds from disposition of assets. 264,282 3,238 269,432 16,122
Additions to oil and gas properties. (18,274) (134,763) (65,447) (330,072)
Other property additions, net....... 971 (13,530) 1,072 (17,829)
-------- --------- --------- --------
Net cash provided by (used in)
investing activities........ 246,979 (145,055) 205,057 (331,779)
-------- --------- --------- --------
Cash flows from financing activities:
Borrowings under long-term debt..... 12,123 53,018 319,340 826,201
Principal payments on long-term debt (292,530) (15,506) (572,271) (631,225)
Payment of other noncurrent
liabilities....................... (9,810) (10,881) (22,737) (32,315)
Dividends........................... - - - (5,056)
Purchase of treasury stock.......... - (1,206) - (6,778)
Deferred loan fees/issuance costs... - (144) (6,891) (5,434)
-------- --------- --------- --------
Net cash provided by (used in)
financing activities........ (290,217) 25,281 (282,559) 145,393
-------- --------- --------- --------
Net increase (decrease) in cash and
cash equivalents.................. 45,850 (28,405) 19,877 (25,966)
Effect of exchange rate changes on
cash and cash equivalents......... (144) (54) 171 (54)
Cash and cash equivalents, beginning
of period......................... 33,563 74,152 59,221 71,713
-------- --------- --------- --------
Cash and cash equivalents, end of
period............................ $ 79,269 $ 45,693 $ 79,269 $ 45,693
======== ========= ========= ========
</TABLE>
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.
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
NOTE A. Organization and Nature of Operations
Pioneer Natural Resources Company (the "Company") is a Delaware corporation
whose common stock is listed and traded on the New York Stock Exchange and the
Toronto Stock Exchange. The Company was formed by the merger of Parker &
Parsley Petroleum Company and MESA Inc. ("Mesa") on August 7, 1997. The Company
was significantly expanded by the subsequent acquisition of the Canadian and
Argentine oil and gas business of Chauvco Resources Ltd., a publicly traded
independent oil and gas company based in Calgary, Canada on December 18, 1997.
The Company is an oil and gas exploration and production company with ownership
interests in oil and gas properties located principally in the Mid Continent,
Southwestern and onshore and offshore Gulf Coast regions of the United States
and in Argentina, Canada and South Africa.
NOTE B. Basis of Presentation
In the opinion of management, the unaudited consolidated financial statements
of the Company as of June 30, 1999 and for the three and six months ended
June 30, 1999 and 1998 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
1998 Annual Report on Form 10-K.
NOTE C. Property Divestitures
On June 29, 1999, the Company completed a sale of certain United States oil and
gas producing properties, gas plants and other assets to Prize Energy Corp.
("Prize"). The oil and gas producing assets sold to Prize include properties
located in the Gulf Coast, Mid Continent and Permian Basin areas of the
Company's United States region.
In accordance with the terms of the purchase and sale agreement, the Company
received gross sales proceeds of $245 million, comprised of $215 million of cash
and 2,307.693 shares of six percent convertible preferred stock having a
liquidation preference and fair value of $30 million. The convertible preferred
stock provides for a six percent annual dividend payment, payable quarterly in
additional equity shares of Prize through 2001. Subsequent to 2001, Prize has
the option of paying the quarterly dividends on the convertible preferred stock
in equity shares or cash. Each share of the convertible preferred stock may,
at the option of the Company, be converted into one share of Prize common stock,
subject to certain anti-dilution adjustments. The Company recognized a loss of
$46 million from this disposition during the quarter ended June 30, 1999.
The directors of Prize include Mr. Philip P. Smith, the Chief Executive Officer;
Mr. Kenneth A. Hersh; and two directors to be elected by the Company under the
terms of the convertible preferred stock received in this transaction. Messrs.
Smith and Hersh were members of the Board of Directors of the Company and have
resigned their positions with the Company during the second quarter of 1999.
Additionally, Mr. Lon C. Kile resigned his position as Executive Vice President
of the Company to accept the position of President and Chief Operating Officer
of Prize. The sale of the
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
assets to Prize was initiated through an auction process which, upon receipt of
Prize's initial offer, was placed under the supervision of a special independent
committee (comprised of outside directors unrelated to Prize) of the Company's
Board of Directors. The independent committee reviewed and considered all
offers presented to the Company for the purchase of the assets acquired by
Prize.
During the first half of 1999, the Company also completed the sales of certain
other oil and gas properties, gas plants and related assets for gross cash
proceeds of $45 million, subject to normal purchase price adjustments. Such
proceeds included $33 million received under eight separate purchase and sale
agreements that divested non-strategic Canadian oil and gas properties,
$9 million received from the sale of a West Texas oil and gas field and
$3 million received from the sale of an East Texas gas facility. Associated
with these dispositions, the Company recognized a net gain of $4 million during
the six months ended June 30, 1999.
The net cash proceeds realized from the above described divestitures were used
to reduce the Company's outstanding indebtedness under its Credit Facility (as
defined in Note D. Amended Credit Facilities, below).
NOTE D. Amended Credit Facilities
As of June 30, 1999 and December 31, 1998, the Company had $1.01 billion and
$1.25 billion of respective borrowings under credit facility agreements financed
by a syndicate of banks (the "Banks"). As of December 31, 1998, the Company's
credit facility borrowings included $974 million of borrowings (excluding $19.6
million of undrawn letters of credit) outstanding under a $1.075 billion credit
facility (the "Primary Facility"), $276 million of borrowings under a $290
million Canadian credit facility (the "Canadian Facility") and no borrowings
outstanding under the Company's $85 million 364-day credit facility (the
"364-day Facility"). Total loan commitments under these facilities were $1.44
billion on December 31, 1998.
On March 19, 1999, the Company and the Banks executed amendments to the credit
facility agreements that combined the Primary Facility and the Canadian Facility
into one facility (the "Credit Facility"). The 364-day Facility will expire by
its terms in August 1999. The terms of the Credit Facility provide for a
combined reduction in loan commitments to $941 million, prior to December 31,
1999. Additionally, the amendments provide for an increase in the maximum
interest rate margin on LIBOR rate advances under the Credit Facility to 300
basis points, including leverage fees; and, the amendments provide for the
maintenance of certain associated debt covenants, the most restrictive of which
being the maintenance of an annualized ratio of outstanding Company senior debt
to earnings before interest, depletion, depreciation, amortization, income
taxes, exploration and abandonment and other non-cash expenses not to exceed
5.75 to one through September 30, 1999, 4.25 to one for the period of October 1,
1999 through March 31, 2000, and 3.5 to one, thereafter. To satisfy the
commitment reduction provisions of the Credit Facility, the Company intends to
reduce its outstanding borrowings through the use of funds generated by the
individual or combined sources of operating activities, oil and gas property
divestitures, borrowings under subordinated debt agreements or additional
issuances of equity. During the six months ended June 30, 1999, the Company has
reduced its outstanding borrowings under the Credit Facility by $244 million
through the application of net cash provided by operating activities and
property divestitures (see Note C. Property Divestitures, above).
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
NOTE E. 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 reserve as appropriate to reflect the then current status of its
litigation.
Masterson
In February 1992, the current lessors of an oil and gas lease (the "Gas Lease")
dated April 30, 1955, between R.B. Masterson et. al., as lessor, and Colorado
Interstate Gas Company ("CIG"), as lessee, sued CIG in Federal District Court in
Amarillo, Texas, claiming that CIG had underpaid royalties due under the Gas
Lease. Under certain agreements with CIG, the Company, as successor to Mesa,
has an entitlement to gas produced from the Gas Lease. In August 1992, CIG
filed a third-party complaint against the Company for any such royalty
underpayment that may be allocable to the Company. Plaintiffs alleged that the
underpayment was the result of CIG's use of an improper gas sales price upon
which to calculate royalties and that the proper price should have been
determined pursuant to a "favored-nations" clause in a July 1, 1967, amendment
to the Gas Lease. The plaintiffs also sought a declaration by the court as to
the proper price to be used for calculating future royalties.
The plaintiffs alleged royalty underpayments of approximately $500 million
(including interest at 10 percent) dating from July 1, 1967. In March 1995, the
court made certain pretrial rulings that eliminated approximately $400 million
of the plaintiff's claims (which related to periods prior to October 1, 1989),
but which also reduced a number of the Company's defenses. The Company and CIG
filed stipulations with the court whereby the Company would have been liable for
between 50 percent and 60 percent, depending on the time period covered, of an
adverse judgment against CIG for post-February 1988 underpayments of royalties.
On March 22, 1995, a jury trial began and on May 4, 1995, the jury returned its
verdict. Among its findings, the jury determined that CIG had underpaid
royalties for the period after September 30, 1989, in the amount of
approximately $140,000. Although the plaintiffs argued that the
"favored-nations" clause entitled them to be paid for all of their gas at the
highest price voluntarily paid by CIG to any other lessor, the jury determined
that the plaintiffs were estopped from claiming that the "favored-nations"
clause provides for other than a pricing-scheme to pricing-scheme comparison.
In light of this determination, and the plaintiff's stipulation that a
pricing-scheme to pricing-scheme comparison would not result in any "trigger
prices" or damages, defendants asked the court for a judgment that plaintiffs
take nothing. The court, on June 7, 1995, entered final judgment that
plaintiffs recover no monetary damages. The plaintiffs filed a motion for new
trial on June 22, 1995. The court, on July 18, 1997, denied plaintiffs' motion.
The plaintiffs have appealed to the Fifth Circuit Court of Appeals, where oral
arguments were heard in December 1998. The court's decision regarding this
litigation could be announced at any time.
On June 7, 1996, the plaintiffs filed a separate suit against CIG and the
Company in state court in Amarillo, Texas, similarly claiming underpayment of
royalties under the "favored-nations" clause, but based upon the above-described
pricing-scheme to pricing-scheme comparison on a well-by-well monthly basis.
The plaintiffs also claim underpayment of royalties since June 7, 1995, under
the "favored-nations" clause based upon either the pricing-scheme to
pricing-scheme method or their previously alleged hig her price method. The
Company believes it has several defenses to this action and intends to contest
it vigorously. The Company has not yet determined the amount of damages, if
any, which would be payable if such action was determined adversely to the
Company.
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
The federal court in the above-referenced first suit issued an order on July 29,
1996, which stayed the state court suit pending the resolution of the first
suit.
Based on the jury verdict and final judgment in the first suit, the Company does
not currently expect the ultimate resolution of either of these lawsuits to have
a material adverse effect on its financial position or 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 natural gas. Based on a Federal Energy Regulatory Commission ("FERC")
ruling that Kansas ad valorem tax was such a tax, Mesa 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 reasoned 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
limiting 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 natural 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 natural 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). 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 is seeking waiver or set-off from FERC with respect
to that portion of the refund associated with (i) non-recoupable royalties, (ii)
non-recoupable Kansas property taxes based, in part, upon the higher prices
collected, and (iii) interest for all periods. On September 10, 1997, 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 refunds totaling approximately
$30 million were made against the Company. The Company is unable at this time
to predict the final outcome of this matter or the amount, if any, that will
ultimately be refunded. As of June 30, 1999, the Company has set aside
approximately $31 million, including accrued interest, in an escrow account and
has a corresponding amount recorded as other current liabilities in the
accompanying Consolidated Balance Sheet as of June 30, 1999.
NOTE F. Commodity Hedge Derivatives
The Company utilizes various commodity swap and option contracts to (i) reduce
the effect of the volatility of price changes on the commodities the Company
produces and sells, (ii) support the Company's annual capital budgeting and
expenditure plans and (iii) lock in prices to protect the economics related to
certain capital projects.
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
Crude oil. All material purchase contracts governing the Company's oil
production are tied directly or indirectly to NYMEX prices. The following table
sets forth the Company's outstanding oil hedge contracts as of June 30, 1999.
In addition to the outstanding hedge contracts identified in the following
table, the Company has deferred oil hedge gains of $2.7 million that will be
recognized ratably over the remainder of 1999.
<TABLE>
<S> <C> <C> <C> <C> <C>
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
------- ------- ------- ------- -----------
Daily oil production:
1999 - Swap Contracts*
Volume (Bbl)......... 8,696 8,728 8,712
Price per Bbl........ $15.67 $15.67 $15.67
1999 - Collar Contracts
Volume (Bbl.......... 2,000 2,000 2,000
Price per Bbl........ $15.00- $15.00- $15.00-
$17.60 $17.60 $17.60
1999 - Purchased Put
Contracts**
Volume (Bbl)......... 10,000 10,000 10,000
Price per Bbl........ $15.00 $15.00 $15.00
2000 - Swap Contracts
Volume (Bbl)......... 626 538 478 435 521
Price per Bbl........ $15.76 $15.76 $15.76 $15.76 $15.76
2000 - Collar Contracts***
Volume (Bbl)......... 5,000 5,000 5,000 5,000 5,000
Price per Bbl........ $17.00- $17.00- $17.00- $17.00- $17.00-
$20.09 $20.09 $20.09 $20.09 $20.09
2001 - Swap Contracts
Volume (Bbl)......... 411 385 359 337 373
Price per Bbl........ $15.76 $15.76 $15.76 $15.76 $15.76
</TABLE>
________________
* Certain counterparties to the 1999 swap contracts have the contractual
right to buy Year 2000 swap contracts from the Company for 9,000 Bbl's per
day for a fixed price of $16.56 per Bbl.
** Concurrent with the Company's purchase of the put contracts, the Company
sold 1999 put contracts to the counterparties for an equal volume at an
average strike price of $11.00 per Bbl. Consequently, if the average 1999
index price falls below $15.00 per Bbl, the Company will receive the
average index price for the notional contract volumes plus approximately
$4.00 per Bbl.
*** Concurrent with the Company's purchase of the year 2000 collar contracts,
the Company has sold year 2000 put contracts to the counterparties for
equal notional contract volumes at an average index price of $14.00 per
Bbl. Consequently, if the average year 2000 index price falls below
$14.00 per Bbl, the Company will receive the average index price for the
notional contract volumes, plus $3.00 per Bbl. The counterparties have
the contractual right to extend these contracts through 2001 on equal
notial contract volumes at average per Bbl prices of $17.00 - $20.09 for
the collar contracts and $14.00 for the put contracts.
The Company reports average oil prices per Bbl including the effects of oil
quality, gathering and transportation costs and the net effect of the oil
hedges. The following table sets forth the Company's oil prices, both realized
and reported, and net effects of settlements of oil price hedges to revenue:
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
<TABLE>
<S> <C> <C> <C> <C>
Three months ended Six months ended
June 30, June 30,
------------------ ----------------
1999 1998 1999 1998
---- ---- ---- ----
Average price reported per Bbl...... $ 14.90 $ 13.06 $ 13.32 $ 13.52
Average price realized per Bbl...... $ 15.02 $ 11.97 $ 12.97 $ 12.54
Addition (reduction) to revenue
(in millions)...................... $ (.5) $ 6.2 $ 3.0 $ 11.0
</TABLE>
Natural gas. The Company employs a policy of hedging 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. The following table
sets forth the Company's outstanding gas hedge contracts as of June 30, 1999.
Prices included herein represent the Company's weighted average index price per
MMBtu. In addition to the outstanding hedge contracts identified in the
following table, the Company has deferred gas hedge gains of $1.6 million that
will be recognized ratably over the remainder of 1999.
<TABLE>
<S> <C> <C> <C> <C> <C>
Yearly
First Second Third Fourth Outstanding
Quarter Quarter Quarter Quarter Average
------- ------- ------- ------- -----------
Daily gas production:
1999 - Swap Contracts*
Volume (Mcf).............. 29,373 16,297 22,835
Index price per MMBtu..... $2.10 $2.17 $2.12
1999 - Collar Contracts**
Volume (Mcf).............. 82,103 114,991 98,547
Index price per MMBtu..... $2.01- $2.04- $2.03-
$2.53 $2.59 $2.56
2000 - Swap Contracts*
Volume (Mcf).............. 49,223 49,223 49,223 49,223 49,223
Index price per MMBtu..... $2.17 $2.17 $2.17 $2.17 $2.17
2000 - Collar Contracts***
Volume (Mcf).............. 98,223 98,223 98,223 95,571 97,557
Index price per MMBtu..... $2.08- $2.08- $2.08- $2.09- $2.08-
$2.66 $2.66 $2.66 $2.67 $2.66
2001 Swap Contracts*
Volume (Mcf).............. 12,500 12,500 12,500 12,500 12,500
Index price per MMBtu..... $2.36 $2.36 $2.36 $2.36 $2.36
2001 Collar Contracts****
Volume (Mcf).............. 35,000 35,000 35,000 35,000 35,000
Index price per MMBtu..... $2.25- $2.25- $2.25- $2.25- $2.25-
$2.65 $2.65 $2.65 $2.65 $2.65
2002 Swap Contracts*
Volume (Mcf).............. 10,000 10,000 10,000 10,000 10,000
Index price Per MMBtu..... $2.58 $2.58 $2.58 $2.58 $2.58
</TABLE>
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
________________
* Certain counterparties to the 1999, 2000, 2001 and 2002 swap contracts
have the contractual right to extend 20,000; 49,223; 12,500; and 10,000
Mcf per day, respectively, for an additional year at weighted average
strike prices of $2.32; $2.21; $2.52; and $2.58 per MMBtu, respectively.
** Concurrent with the Company's purchase of certain of the 1999 collar
contracts, the Company has sold 1999 put contracts to the counterparties
for an average volume of 68,196 Mcf per day at an average index price
of $1.79 per MMBtu. Consequently, if the weighted average 1999 index
price falls below $1.79 per MMBtu, the Company will receive the weighted
average index price for the notional contract volumes, plus approximately
$.30 per MMBtu. 30,000 Mcf per day of the 1999 collar contracts and
associated put contracts sold are extendable at the option of the
counterparties for a period of one year at average per MMBtu strike prices
of $2.13-$2.73 for the collar contracts and $1.83 for the put contracts.
*** Concurrent with the Company's purchase of the 2000 collar contracts, the
Company sold 2000 put contracts to the counterparties for an equal volume
at an average index price of $1.80 per MMBtu. Consequently, if the
weighted average 2000 index price falls below $1.80 per MMBtu, the Company
will receive the weighted average index price for the notional contract
volumes, plus approximately $.28 per MMBtu. 79,482 Mcf per day of the 2000
collar contracts and associated put contracts are extendable for one year
at the option of the counterparties at average per MMBtu prices of $2.13-
$2.78 for the collar contracts and $1.83 for the put contracts.
**** Concurrent with the Company's purchase of the 2001 collar contracts, the
Company sold 2001 put contracts to the counterparties for an equal volume
at an average index price of $1.95 per MMBTU. Consequently, if the
weighted average 2001 index price falls below $1.95 per MMBTU, the Company
will receive the weighted average index price for the notional contract
volumes, plus approximately $.30 per MMBtu. The 2001 collar contracts and
associated put contracts are extendable for one year at the option of the
counterparties at average per MMBtu prices of $2.25-$2.65 for the collar
contracts and $1.95 for the put contracts.
The Company reports average gas prices per Mcf including the effects of Btu
content, gathering and transportation costs, gas processing and shrinkage and
the net effect of the gas hedges. The following table sets forth the Company's
gas prices, both realized and reported, and net effects of settlements of gas
price hedges to revenue:
<TABLE>
<S> <C> <C> <C> <C>
Three months ended Six months ended
June 30, June 30,
------------------ ----------------
1999 1998 1999 1998
---- ---- ---- ----
Average price reported per Mcf.... $ 1.88 $ 1.81 $ 1.80 $ 1.94
Average price realized per Mcf.... $ 1.80 $ 1.88 $ 1.65 $ 1.91
Addition (reduction) to revenue
(in millions).................... $ 3.6 $ (3.2) $ 12.9 $ 2.3
</TABLE>
NOTE G. Other Income
In December 1998, the Company announced the sale of an exclusive and irrevocable
option to a third party to purchase, on or before March 31, 1999, certain oil
and gas properties of the Company. In consideration for the option, the third
party paid an option fee of $41.3 million to the Company. The third party was
unable to complete the purchase of the Company's oil and gas properties on March
31, 1999. A new purchase and sale agreement was entered into between the
parties that was not completed in April 1999 as specified in the purchase and
sale agreement; resulting in the Company receiving $.5 million of liquidated
damages (in the form of common stock of the third party) during the second
quarter of 1999. Accordingly, interest and other revenue in the accompanying
Consolidated Statement of Operations and Comprehensive Income (Loss) for the
three and six month periods ended June 30, 1999 include other income of $.5
million and $41.8 million, respectively, associated with these transactions.
Other non-cash items in the accompanying Consolidated Statement of Cash Flows
for the three and six month periods ended June 30, 1999 include $.5 million and
$41.8 million reductions for these non-cash components of earnings.
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
NOTE H. Mark-to-Market Financial Instruments
The Company is a party to certain BTU swap agreements that do not qualify as
hedges. Other expenses in the accompanying Consolidated Statements of
Operations and Comprehensive Income (Loss) for the three and six month periods
ended June 30, 1999 include a non-cash mark-to-market decrease of $1.2 million
and an increase of $.9 million, respectively, to the liabilities recognized for
the BTU swap agreements; and, for the three and six month periods ended June 30,
1998, a decrease of $.4 million and an increase of $5.8 million, respectively.
These contracts will continue to be marked-to-market at the end of each
reporting period during their respective lives. The related effects on the
Company's results of operations in future periods could be significant.
During the fourth quarter of 1998, the Company received three million shares of
common stock of a closely held, non-affiliated, publicly traded entity in
partial payment of option fees referred to in Note G, above, which was increased
to four million shares during the second quarter of 1999 in payment of
liquidated damages. During the three and six month periods ended June 30, 1999,
the market quoted value of the shares of common stock declined by $7.0 million
and $11.9 million, respectively. Accordingly, other expenses in the
accompanying Consolidated Statement of Operations and Comprehensive Income
(Loss) for the respective three and six month periods ended June 30, 1999
include non-cash mark-to-market decreases to the carrying value of the
investment of $7.0 million and $11.9 million. During June 1999, the Company
sold its investments in the common stock of the non-affiliated entity for cash
proceeds of $.6 million.
The Company has a series of forward foreign exchange swap agreements to exchange
Canadian dollars for United States dollars at future dates for a fixed amount of
the first currency. As these contracts do not qualify as hedges, the Company
recorded non-cash mark-to-market decreases to the recognized liabilities
associated with these agreements during the three and six month periods ended
June 30, 1999 of $3.4 million and $5.9 million, respectively; and, for the three
and six month periods ended June 30, 1998, an increase of $5.9 million. These
contracts will continue to be marked-to-market until they mature at various
dates in the fourth quarter of 2000. The associated effects on the Company's
future results of operations could be significant.
During the first quarter of 1999, the Company sold NYMEX crude oil calls for
8,000 barrels per day of oil, at a weighted average strike price of $17.15 per
barrel, for a nine month period ending on December 31, 1999. Additionally, the
Company sold call options that provide the counter-party an option to exercise
call provisions on 10,000 barrels per day of oil, at a strike price of $20.00
per barrel, for a twenty-one month period that began on April 1, 1999 and ends
on December 31, 2000, or to exercise call provisions over that same time period
on 100,000 MMBtu per day of natural gas, at a weighted average price of $2.70
per MMBtu. These contracts do not qualify for hedge accounting treatment. Other
expenses in the accompanying Consolidated Statement of Operations and
Comprehensive Income (Loss) for the three and six month periods ended June 30,
1999 include $5.6 million and $8.2 million of non-cash, mark-to-market increases
to the liabilities recognized on these contracts.
NOTE I. Impairment of Oil and Gas Properties
In accordance with Statement of Financial Accounting Standards No. 19,
"Financial Accounting and Reporting by Oil and Gas Producing Companies"
("SFAS 19"), the Company periodically assesses its unproved properties for
impairment by comparing their cost to their estimated value on a project-by-
project basis. During the second quarter of 1999, the Company completed the
analysis of seismic data pertaining to certain unproved properties owned by the
Company in the East Texas area. The results of the analysis of the seismic data
indicated a decline in the recoverability of the carrying value of the
properties. Accordingly, the Company has recognized a $17.9 million provision
for impairment of unproved properties during the three and six month periods
ended June 30, 1999.
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
NOTE J. Reorganization
During 1998, the Company announced its intentions to reorganize its operations
to realize additional operational and administrative efficiencies. During the
three and six month periods ended June 30, 1999, the Company recorded
reorganization costs of $1.5 million and $7.0 million, respectively, primarily
consisting of relocation costs that were related to the 1998 reorganization
initiatives, but that were not incurred until 1999, and certain costs associated
with the second quarter 1999 centralization, in Irving, Texas, of certain
operational functions that were previously located in Midland, Texas. During
the three and six month periods ended June 30, 1998, the Company recorded
severance, relocation, lease termination and other costs of $3.4 million and
$20.5 million, respectively, relating to the reorganization.
NOTE K. Geographic Operating Segment Information
The Company has operations in only one industry segment, that being the oil and
gas exploration and production industry; however, the Company is
organizationally structured along geographic operating segments, or regions.
The Company has reportable operations in the United States, Argentina and
Canada.
The following table provides the interim geographic operating segment data
required by Statement of Financial Accounting Standards No. 131, "Disclosure
about Segments of an Enterprise and Related Information." 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.
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
United Other Headquarters Consolidated
States Argentina Canada Foreign and Other Total
------ --------- ------ ------- ------------ ------------
(in thousands)
Three months ended
June 30, 1999:
Oil and gas
revenue........ $ 134,002 $ 19,803 $ 20,426 $ - $ - $ 174,231
Interest and
other.......... - - - - 2,804 2,804
Loss on
disposition of
assets......... (40,339) - (1,897) - (55) (42,291)
--------- -------- -------- ------- ---------- -----------
93,663 19,803 18,529 - 2,749 134,744
--------- -------- -------- ------- ---------- -----------
Production costs 31,275 3,924 6,425 - - 41,624
Depletion,
depreciation and
amortization.... 41,516 9,508 8,619 - 4,592 64,235
Impairment of oil
and gas
properties .0000 17,894 - - - - 17,894
Exploration and
abandonments.... 11,422 4,067 1,433 1,003 - 17,925
General and
administrative.. - - - - 10,188 10,188
Reorganization... - - - - 1,490 1,490
Interest......... - - - - 46,903 46,903
Other............ - - - - 9,601 9,601
--------- -------- -------- ------- ---------- -----------
102,107 17,499 16,477 1,003 72,774 209,860
--------- -------- -------- ------- ---------- -----------
Income (loss)
before income
taxes.......... (8,444) 2,304 2,052 (1,003) (70,025) (75,116)
Income tax benefit
(provision)..... 3,125 (806) (896) 351 (1,274) 500
--------- -------- -------- ------- ---------- -----------
Net income
(loss)..........$ (5,319)$ 1,498 $ 1,156 $ (652) $ (71,299) $ (74,616)
========= ======== ======== ======= ========== ===========
Three months ended June 30, 1998:
Oil and gas
revenue.........$ 150,389 $ 16,299 $ 16,959 $ - $ - $ 183,647
Interest and
other........... - - - - 1,145 1,145
Gain on
disposition of
assets.......... 274 - - - 41 315
--------- -------- -------- ------- ---------- -----------
150,663 16,299 16,959 - 1,186 185,107
--------- -------- -------- ------- ---------- -----------
Production costs. 44,135 5,780 6,698 - - 56,613
Depletion,
depreciation
and amortization 59,847 10,092 10,432 - 3,437 83,808
Exploration and
abandonments.... 13,934 5,032 4,100 3,507 - 26,573
General and
administrative.. - - - - 17,387 17,387
Reorganization... - - - - 3,372 3,372
Interest......... - - - - 41,017 41,017
Other............ - - - - 6,846 6,846
--------- -------- -------- ------- ---------- -----------
117,916 20,904 21,230 3,507 72,059 235,616
--------- -------- -------- ------- ---------- -----------
Income (loss)
before income
taxes........... 32,747 (4,605) (4,271) (3,507) (70,873) (50,509)
Income tax benefit
(provision)..... (12,116) 1,520 1,858 1,227 25,211 17,700
--------- -------- -------- ------- ---------- -----------
Net income
(loss)..........$ 20,631 $ (3,085)$ (2,413)$(2,280) $ (45,662) $ (32,809)
========= ======== ======== ======= ========== ===========
</TABLE>
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
United Other Headquarters Consolidated
States Argentina Canada Foreign and Other Total
------ --------- ------ ------- ------------ ------------
(in thousands)
Six months ended
June 30, 1999:
Oil and gas
revenue........ $ 251,475 $ 34,350 $ 35,557 $ - $ - $ 321,382
Interest and
other.......... - - - - 48,777 48,777
(Loss) gain on
disposition of
assets......... (40,339) - (1,897) - 12 (42,224)
--------- -------- -------- ------- ---------- -----------
211,136 34,350 33,660 - 48,789 327,935
--------- -------- -------- ------- ---------- -----------
Production costs 68,794 8,317 11,707 - - 88,818
Depletion,
depreciation and
amortization... 90,503 17,709 16,200 - 9,195 133,607
Impairment of oil
and gas
properties..... 17,894 - - - - 17,894
Exploration and
abandonments... 19,279 4,886 3,244 2,292 - 29,701
General and
administrative. - - - - 20,437 20,437
Reorganization.. - - - - 7,019 7,019
Interest........ - - - - 89,424 89,424
Other........... - - - - 18,252 18,252
--------- -------- -------- ------- ---------- -----------
196,470 30,912 31,151 2,292 144,327 405,152
--------- -------- -------- ------- ---------- -----------
Income (loss)
before income
taxes.......... 14,666 3,438 2,509 (2,292) (95,538) (77,217)
Income tax benefit
(provision).... (5,426) (1,203) (1,096) 802 7,023 100
--------- -------- -------- ------- ---------- -----------
Net income
(loss).........$ 9,240 $ 2,235 $ 1,413 $(1,490) $ (88,515) $ (77,117)
========== ======== ======== ======= ========== ===========
Segment assets
(as of June 30)$1,983,710 $679,114 $292,885 $ 8,464 $ 118,935 $ 3,083,108
========== ======== ======== ======= ========== ===========
Six months ended
June 30, 1998:
Oil and gas
revenue........$ 315,092 $ 32,523 $ 33,401 $ - $ - $ 381,016
Interest and
other.......... - - - - 2,323 2,323
Gain on
disposition of
assets......... 274 - - - 51 325
---------- -------- -------- -------- --------- -----------
315,366 32,523 33,401 - 2,374 383,664
---------- -------- -------- -------- --------- -----------
Production costs 88,480 10,902 12,373 - - 111,755
Depletion,
depreciation and
amortization... 114,621 19,532 19,373 - 6,532 160,058
Exploration and
abandonments... 24,361 8,231 11,943 5,987 - 50,522
General and
administrative. - - - - 37,412 37,412
Reorganization.. - - - - 20,549 20,549
Interest........ - - - - 80,495 80,495
Other........... - - - - 13,626 13,626
---------- -------- -------- -------- --------- -----------
227,462 38,665 43,689 5,987 158,614 474,417
---------- -------- -------- -------- --------- -----------
Income (loss)
before income
taxes.......... 87,904 (6,142) (10,288) (5,987) (156,240) (90,753)
Income tax benefit
(provision).... (32,524) 2,027 4,496 2,095 55,006 31,100
---------- -------- -------- -------- ---------- -----------
Net income
(loss) $ 55,380 $ (4,115)$ (5,792)$ (3,892)$ (101,234) $ (59,653)
========== ======== ======== ======== ========== ===========
Segment assets
(as of June 30) $2,490,730 $809,935 $417,523 $ 958 $ 279,275 $ 3,998,421
========== ======== ======== ======== ========== ===========
</TABLE>
NOTE L. 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. The Company has not prepared financial statements
and related disclosures for Pioneer USA under separate cover because management
of the Company has determined that such information is not material to
investors. In accordance with practices accepted by the SEC, the Company has
prepared Consolidating Financial Statements in order to quantify the assets of
Pioneer USA as a subsidiary guarantor. The following Consolidating Balance
Sheets, Consolidating Statements of Operations and Comprehensive Income (Loss)
and Consolidating Statements of Cash Flows 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), 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.
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
CONSOLIDATING BALANCE SHEET
As of June 30, 1999
(in thousands)
(Unaudited)
ASSETS
<TABLE>
<S> <C> <C> <C> <C> <C>
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Eliminations Company
---------- ---------- ------------ ------------ -------
Current assets:
Cash and cash $ 2 $ 51,317 $ 27,950 $ $ 79,269
equivalents...........
Accounts receivable:
Trade................. 26 69,191 39,920 109,137
Affiliate............. 2,308,670 (1,665,517) (641,067) 2,086
Inventories........... - 7,697 6,232 13,929
Deferred income taxes. 6,400 - - 6,400
Other current assets.. 136 7,248 974 8,358
---------- ----------- ---------- ----------
Total current assets. 2,315,234 (1,530,064) (565,991) 219,179
---------- ----------- ---------- ----------
Property, plant and
equipment, at cost:
Oil and gas
properties, using
the successful
efforts method of
accounting:
Proved properties.... - 2,284,792 782,429 3,067,221
Unproved properties.. - 33,684 271,151 304,835
Accumulated depletion,
depreciation and
amortization......... - (628,889) (136,394) (765,283)
---------- ----------- ---------- ----------
- 1,689,587 917,186 2,606,773
---------- ----------- ---------- ----------
Deferred income taxes.. 97,500 - - 97,500
Other property and
equipment, net........ - 32,185 15,548 47,733
Other assets, net...... 14,874 59,432 37,617 111,923
Investment in
subsidiaries.......... 135,246 149,680 - (284,926) -
---------- ----------- ---------- ----------
$2,562,854 $ 400,820 $ 404,360 $3,083,108
========== =========== =========== ==========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of
long-term debt....... $ 69,016 $ 935 $ - $ 69,951
Accounts payable:
Trade................ 471 52,244 23,413 76,128
Affiliates........... - 924 - 924
Other current
liabilities.......... 36,804 70,765 6,697 114,266
---------- ----------- ----------- ----------
Total current
liabilities........ 106,291 124,868 30,110 261,269
---------- ----------- ----------- ----------
Long-term debt, less
current maturities... 1,858,612 389 - 1,859,001
Other noncurrent
liabilities.......... - 142,887 37,463 180,350
Deferred income taxes. - - 64,600 64,600
Stockholders' equity:
Partners' capital..... - - 22 (22) -
Common stock.......... 968 1 42 (3) 1,008
Additional paid-in-
capital.............. 2,236,014 2,022,076 590,210(2,500,205) 2,348,095
Treasury stock, at
cost................. (10,388) - - (10,388)
Retained deficit...... (1,628,643) (1,889,401) (326,819)2,215,304 (1,629,559)
Cumulative translation
adjustment........... - - 8,732 8,732
----------- ----------- ----------- ----------
Total stockholders'
equity............. 597,951 132,676 272,187 717,888
----------- ----------- ----------- ----------
Commitments and
contingencies
$ 2,562,854 $ 400,820 $ 404,360 $3,083,108
=========== =========== =========== ==========
</TABLE>
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
CONSOLIDATING BALANCE SHEET
As of December 31, 1998
(in thousands)
ASSETS
<TABLE>
<S> <C> <C> <C> <C> <C>
Pioneer
Natural
Resources Non-
Company Pioneer Guarantor The
(Parent) USA Subsidiaries Eliminations Company
---------- ---------- ------------ ------------ -------
Current assets:
Cash and cash
equivalents...........$ 3,161 $ 37,932 $ 18,128 $ $ 59,221
Accounts receivable:
Trade................ 636 75,236 30,991 106,863
Affiliate............ 2,240,421 (1,828,672) (408,092) 3,657
Inventorie............ - 8,930 6,291 15,221
Deferred income taxes. 7,100 - - 7,100
Other current assets.. 87 8,868 971 9,926
---------- ---------- ------------ ----------
Total current
assets........... 2,251,405 (1,697,706) (351,711) 201,988
---------- ---------- ------------ ----------
Property, plant and
equipment, at cost:
Oil and gas properties,
using the successful
efforts method of
accounting:
Proved properties.... - 2,678,637 942,993 3,621,630
Unproved properties.. - 58,989 283,600 342,589
Accumulated depletion,
depreciation and
amortization.......... - (753,570) (176,541) (930,111)
--------- ---------- ------------ ----------
- 1,984,056 1,050,052 3,034,108
--------- ---------- ------------ ----------
Deferred income taxes.. 96,800 - - 96,800
Other property and
equipment, net........ - 38,229 16,781 55,010
Other assets, net...... 9,787 43,557 40,064 93,408
Investment in
subsidiaries.......... 135,204 148,257 - (283,461) -
--------- ---------- ------------ -----------
$2,493,196 $ 516,393 $ 755,186 $ 3,481,314
========== ========== ============ ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities:
Current maturities of
long-term debt........$ 212, 302 $ 1,189 $ 93,030 $ 306,521
Accounts payable:
Trade................. 697 56,723 37,517 94,937
Affiliates............ 29 4,463 - 4,492
Other current
liabilities........... 21,001 84,759 15,122 120,882
---------- ---------- ------------ -----------
Total current
liabilities...... 234,029 147,134 145,669 526,832
---------- ---------- ------------ -----------
Long-term debt, less
current maturities..... 1,676,933 830 190,981 1,868,744
Other noncurrent
liabilities............ - 189,325 43,136 232,461
Deferred income taxes... - - 64,200 64,200
Stockholders' equity:
Partners capital....... - - 22 (22) -
Common stock........... 934 1 76 (3) 1,008
Additional paid-in-
capital............... 2,143,214 2,022,076 589,511(2,406,805) 2,347,996
Treasury stock, at cost (10,388) - - (10,388)
Retained deficit.......(1,551,526)(1,842,973) (281,312)2,123,369 (1,552,442)
Cumulative translation
adjustment............ - - 2,903 2,903
---------- ---------- ------------ -----------
Total stockholders'
equity........... 582,234 179,104 311,200 789,077
---------- ---------- ------------ -----------
Commitments and
contingencies
$2,493,196 $ 516,393 $ 755,186 $ 3,481,314
========== ========== ============ ===========
</TABLE>
<PAGE>
<TABLE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 1999
(in thousands)
(Unaudited)
<S> <C> <C> <C> <C> <C> <C>
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income The
(Parent) USA Subsidiaries Tax Benefit Eliminations Company
--------- ------- ------------ ------------- ------------ -------
Revenues:
Oil and
gas........ $ - $232,882 $ 88,500 $ - $ $ 321,382
Interest
and other.. 11 44,123 4,643 - 48,777
Loss on
disposition
of assets,
net........ - (9,322) (32,902) - (42,224)
-------- -------- -------- ---------- ---------
11 267,683 60,241 - 327,935
-------- -------- -------- ---------- ---------
Costs and
expenses:
Oil and gas
production. - 65,607 23,211 - 88,818
Depletion,
depreciation
and
amortization - 88,986 44,621 - 133,607
Impairment of
oil and gas
properties. - 17,894 - - 17,894
Exploration
and
abandonments - 19,793 9,908 - 29,701
General and
administrative 536 14,293 5,608 - 20,437
Reorganization - 7,019 - - 7,019
Interest.... (16,675) 78,161 27,938 - 89,424
Equity
(income)loss
from
subsidiary. 92,699 (758) - - (91,941) -
Other...... 568 22,628 (4,944) - 18,252
-------- ------- -------- ---------- ---------
77,128 313,623 106,342 - 405,152
-------- ------- -------- ---------- ---------
Loss before
income taxes (77,117) (45,940) (46,101) - (77,217)
Income tax
(provision)
benefit.... - - 594 (494) 100
-------- ------- -------- ---------- ---------
Net loss..... (77,117) (45,940) (45,507) (494) (77,117)
Other
comprehensive
income:
Translation
adjustment. - - 5,829 - 5,829
-------- -------- -------- ---------- ---------
Comprehensive
loss..... $(77,117)$(45,940) $(39,678) $ (494) $ (71,288)
======== ======== ======== ========== =========
</TABLE>
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS)
For the Six Months Ended June 30, 1998
(in thousands)
(Unaudited)
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income The
(Parent) USA Subsidiaries Tax Benefit Eliminations Company
--------- ------- ------------ ------------- ------------ -------
Revenues:
Oil and
gas........ $ - $280,382 $100,634 $ - $ $ 381,016
Interest and
other...... 38 2,173 763 - (651) 2,323
Gain on
disposition
of assets,
net........ - 325 - - 325
-------- -------- -------- ---------- ---------
38 282,880 101,397 - 383,664
-------- -------- -------- ---------- ---------
Costs and
expenses:
Oil and gas
production - 81,490 30,265 - 111,755
Depletion,
depreciation
and
amortization - 103,475 56,583 - 160,058
Exploration
and
abandonments - 28,171 22,351 - 50,522
General and
administrative 1,048 29,011 7,353 - 37,412
Reorganization - 20,549 - - 20,549
Interest... (8,479) 78,593 11,032 - (651) 80,495
Equity (income)
loss from
subsidiary 67,108 (2,459) - - (64,649) -
Other...... 14 6,421 7,191 - 13,626
-------- -------- -------- ---------- ---------
59,691 345,251 134,775 - 474,417
-------- -------- -------- ---------- ---------
Loss before
income taxes (59,653) (62,371) (33,378) - (90,753)
Income tax
benefit..... - - 11,965 19,135 31,100
-------- -------- -------- ---------- ---------
Net loss..... (59,653) (62,371) (21,413) 19,135 (59,653)
Other
comprehensive
loss:
Translation
adjustment.. - - (2,762) - (2,762)
-------- -------- -------- ---------- ---------
Comprehensive
loss........ $(59,653)$(62,371) $(24,175) $ 19,135 $ (62,415)
======== ======== ======== ========== =========
</TABLE>
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 1999
(in thousands)
(Unaudited)
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income The
(Parent) USA Subsidiaries Tax Benefit Eliminations Company
--------- ------- ------------ ------------ ------------ -------
Cash flows
from operating
activities:
Net loss......$ (77,117) $ (45,940) $ (45,507) $ (494) $ 91,941 $ (77,117)
Adjustments to
reconcile net
loss to net
cash provided
by operating
activities:
Depletion,
depreciation
and
amortization - 88,986 44,621 - 133,607
Impairment of
oil and gas
properties... - 17,894 - - 17,894
Exploration and
abandonments. - 17,558 7,473 - 25,031
Deferred income
taxes........ - - (600) - (600)
Loss on
disposition
of assets,
net.......... - 9,322 32,902 - 42,224
Other noncash
items........ 96,990 (18,533) (5,191) - (91,941) (18,675)
Change in
working capital (52,140) (225,893) 252,554 494 (24,985)
--------- --------- ---------- --------- ---------
Net cash
provided by
(used in)
operating
activities (32,267) (156,606) 286,252 - 97,379
--------- --------- ---------- --------- ---------
Cash flows from
investing
activities:
Proceeds from
disposition of
assets...... - 234,428 35,004 - 269,432
Additions to
oil and gas
properties.. - (42,093) (23,354) - (65,447)
Other property
additions
(retirements),
net......... - (2,316) 3,388 - 1,072
--------- --------- ---------- --------- ---------
Net cash
provided
by
investing
activities - 190,019 15,038 - 205,057
--------- --------- ---------- --------- ---------
Cash flows
from financing
activities:
Borrowings
under
long-term
debt........ 319,048 - 292 - 319,340
Principal
payments on
long-term
debt........ (283,049) (696) (288,526) - (572,271)
Payment of
other
noncurrent
liabilities - (19,332) (3,405) - (22,737)
Deferred loan
fees/issuance
costs...... (6,891) - - - (6,891)
--------- --------- ---------- --------- ---------
Net cash
provided
by (used in)
financing
activities 29,108 (20,028) (291,639) - (282,559)
--------- --------- ---------- --------- ---------
Net decrease in
cash and cash
equivalents.. (3,159) 13,385 9,651 - 19,877
Effect of
exchange rate
changes on cash
and cash
equivalents.. - - 171 - 171
Cash and cash
equivalents,
beginning of
period....... 3,161 37,932 18,128 - 59,221
--------- --------- ---------- --------- ---------
Cash and cash
equivalents,
end of period $ 2 $ 51,317 $ 27,950 $ - $ 79,269
========= ========= ========== ========= =========
</TABLE>
<PAGE>
PIONEER NATURAL RESOURCES COMPANY
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
June 30, 1999
(Unaudited)
CONSOLIDATING STATEMENT OF CASH FLOWS
For the Six Months Ended June 30, 1998
(in thousands)
(Unaudited)
<TABLE>
<S> <C> <C> <C> <C> <C> <C>
Pioneer
Natural
Resources Non- Consolidated
Company Pioneer Guarantor Income The
(Parent) USA Subsidiaries Tax Benefit Eliminations Company
--------- ------- ------------ ------------ ------------ -------
Cash flows
from operating
activities:
Net loss......$ (59,653) $ (62,371) $ (21,413) $ 19,135 $ 64,649 $ (59,653)
Adjustments to
reconcile net
loss to net
cash provided
by operating
activities:
Depletion,
depreciation
and
amortization - 103,475 56,583 - 160,058
Exploration and
abandonments. - 17,395 18,250 - 35,645
Deferred income
taxes........ - - (11,965) (16,435) (28,400)
Gain on
disposition
of assets,
net.......... - (325) - - (325)
Other noncash
items........ 72,349 11,065 7,048 - (64,649) 25,813
Change in
working capital(134,928) 126,964) 37,946 (2,700) 27,282
--------- --------- ---------- --------- ---------
Net cash
provided by
(used in)
operating
activities (122,232) 196,203 86,449 - 160,420
--------- --------- ---------- --------- ---------
Cash flows from
investing
activities:
Proceeds from
disposition of
assets...... - 13,930 2,192 - 16,122
Additions to
oil and gas
properties.. - (192,581) (137,491) - (330,072)
Other property
additions
net......... - (10,201) (7,628) - (17,829)
--------- --------- ---------- --------- ---------
Net cash
used in
investing
activities - (188,852) (142,927) - (331,779)
--------- --------- ---------- --------- ---------
Cash flows
from financing
activities:
Borrowings
under
long-term
debt........ 770,890 - 55,311 - 826,201
Principal
payments on
long-term
debt........ (628,239) (319) (2,667) - (631,225)
Payment of
other
noncurrent
liabilities - (29,836) (2,479) - (32,315)
0ividends... (5,056) - - - (5,056)
Purchase of
treasury
stock...... (6,778) - - - (6,778)
Deferred loan
fees/issuance
costs...... (5,434) - - - (5,434)
--------- --------- ---------- --------- ---------
Net cash
provided
by (used in)
financing
activities 125,383 (30,155) 50,165 - 145,393
--------- --------- ---------- --------- ---------
Net increase
(decrease)in
cash and cash
equivalents.. 3,151 (22,804) (6,313) - (25,966)
Effect of
exchange rate
changes on cash
and cash
equivalents.. - - (54) - (54)
Cash and cash
equivalents,
beginning of
period....... 41 49,033 22,639 - 71,713
--------- --------- ---------- --------- ---------
Cash and cash
equivalents,
end of period $ 3,192 $ 26,229 $ 16,272 $ - $ 45,693
========= ========= ========== ========= =========
</TABLE>
Note M. Subsequent Events
Other Income. During July 1999, the Company received a $30.2 million refund of
excise taxes. Due to the uncertainty surrounding the collectability of the
refund, the Company had not recorded a receivable for this matter. Accordingly,
the Company will recognize the tax refund as other income during the third
quarter of 1999. The proceeds from the tax refund are being used by the Company
to reduce its outstanding indebtedness under its Credit Facility during the
third quarter of 1999 (see Note D. Amended Credit Facilities).
<PAGE>
Asset Divestiture. On August 2, 1999, the Company announced the closing of a
transaction for the sale of natural gas properties in south Texas for gross
proceeds of $62.3 million. The net proceeds from the transaction will be used
to further reduce the Company's outstanding indebtedness under its Credit
Facility.
Item 2. Management's Discussion and Analysis of Financial Condition and Results
-----------------------------------------------------------------------
of Operations(1)
-------------
Financial Performance
The Company reported net losses of $74.6 million ($.74 per share) and $77.1
million ($.77 per share) for the three and six months ended June 30, 1999,
respectively, as compared to respective net losses of $32.8 million ($.33 per
share) and $59.7 million ($.60 per share) for the same periods in 1998. The
Company's results for the three and six months ended June 30, 1999 were
significantly impacted by divestment losses; while the Company's results for the
three and six months ended June 30, 1998 were significantly impacted by declines
in commodity prices (see "Trends and Uncertainties" and "Results of Operations",
below). The net losses for the three and six months ended June 30, 1999 include
$42.3 million and $42.2 million, respectively, of net losses from the divestment
of certain United States and Canadian oil and gas properties, gas plants and
other assets. See Note C. of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements" and "Asset Divestitures", below,
for specific discussions of the 1999 asset divestitures. Additionally, the
Company's results of operations for the six months ended June 30, 1999 include
$41.8 million of other income, principally comprised of option fees received for
a terminated property sales agreement. See Note G of Notes to Consolidated
Financial Statements included in "Item 1. Financial Statements" for a specific
discussion of the option fees recognized during the first half of 1999.
Net cash provided by operating activities were $89.1 million and $97.4 million
during the three and six months ended June 30, 1999, respectively, as compared
to net cash provided by operating activities of $91.4 million and $160.4 million
for the same periods in 1998. Net cash provided by operating activities during
the second quarter of 1999, as compared to the second quarter of 1998, was
positively impacted by improving commodity prices and cost structures, but was
negatively impacted by declining production from the Company's United States
properties. Net cash provided by operating activities during the six months
ended June 30, 1999, as compared to the first six months of 1998, was negatively
impacted by declines in commodity prices and by declining production volumes.
Additionally, increases in working capital, excluding cash and cash equivalents
and current maturities of long-term debt, reduced net cash provided by operating
activities by $10.4 million and $52.3 million during the three and six months
ended June 30, 1999, respectively, as compared to the same periods in 1998 (see
"Results of Operations", below).
The Company strives to maintain its outstanding indebtedness at a moderate level
in order to provide sufficient financial flexibility to fund future
opportunities. The Company's total book capitalization at June 30, 1999 was
$2.6 billion, consisting of total debt of $1.9 billion and stockholders' equity
of $.7 billion. Debt as a percentage of total book capitalization was 73
percent at June 30, 1999 and at December 31, 1998. The Company intends to
continue to reduce its outstanding indebtedness during 1999 and 2000 through the
use of funds generated by the individual or combined sources of operating
activities, oil and gas property divestitures or additional issuances of equity.
Drilling Highlights
During the first six months of 1999, the Company spent $65.4 million on capital
projects, including $42.0 million for development activities, $22.3 million for
exploration activities and $1.1 million on acquisitions. The Company
participated in spudding 82 development wells and six exploratory wells,
completed 82 development wells and seven exploratory wells for production and
plugged and abandoned two development wells and eight exploratory wells. As of
June 30, 1999, the Company had 55 development wells and six exploratory wells in
progress.
Domestic. The Company expended $41.4 million during the first six months of
1999 on drilling activities primarily in the Gulf Coast, Permian Basin and Mid
Continent regions of the United States.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
The Company's first deepwater Gulf of Mexico venture at Mississippi Canyon Block
305 was spud in late December 1998. This well was drilled to a total depth of
14,000 feet, at a cost of $10.7 million net to the Company. In March 1999, the
Company announced the results of the Mississippi Canyon Block 305 exploration as
being a significant discovery, as it encountered a hydrocarbon-bearing section
of over 200 gross feet. The Company holds a 25 percent interest in the block.
The Company plans to drill a second appraisal well on the block during the first
quarter of 2000. The Company spudded its second deepwater well during the
second quarter of 1999 at Garden Banks 515, which was unsuccessful. Other
drilling in the Gulf Coast region included spudding two exploratory wells in
East Texas which were plugged and abandoned as non-commercial during the first
quarter of 1999. During the first six months of 1999, the Company also
completed four development wells and one exploratory well and plugged and
abandoned three exploratory wells that were in progress at December 31, 1998.
In the Permian Basin area, the Company completed 27 new development wells and
one exploratory well during the first half of 1999. Of the new development
wells completed, 24 were Spraberry Driver Unit development wells. The Company
began a drilling program during the fourth quarter of 1998 to drill 100 wells at
minimal cost in the Spraberry units of West Texas, primarily the Spraberry
Driver Unit. However, the wells were being shut-in until oil prices rebounded.
In the second quarter of 1999, with the increase in oil prices, the Company
initiated a program to begin completing these wells and placing them on
production. As of June 30, 1999, the Company has 45 Spraberry Driver Unit wells
in progress. During 1999, the Company plans to complete 150 Spraberry Field oil
development wells.
The Company's Mid Continent drilling program has been focused primarily in the
West Panhandle Field in the Texas Panhandle. During the first six months of
1999, the Company has spudded six development wells and one exploratory well.
Five of the development wells were successfully completed; one development well
and one exploratory well remain in progress as of June 30, 1999. The Company
also completed six development wells and two exploratory wells in this area
during the first half of 1999 that were in progress as of December 31, 1998.
Argentina. The Company spent $10.0 million during the first six months of 1999
on drilling activities primarily in the Neuquen Basin of Argentina. Of the
seven wells in progress at December 31, 1998, one exploratory well was completed
and two development wells were completed during the first six months of 1999
with three exploratory wells and one development well still in progress at June
30, 1999. The Company also spud nine development wells and two exploratory
wells during the first six months of 1999 with five development wells and one
exploratory well being completed as producers. One development well and one
exploratory well were plugged and abandoned as non-commercial, leaving three
development wells still in progress at June 30, 1999. As a result, the Company
had four development wells and three exploratory wells in progress at June 30,
1999.
Canada. The Company spent $11.9 million during the first six months of 1999,
principally to complete winter access drilling activities that began during the
fourth quarter of 1998. The drilling operations were focused primarily in the
Chinchaga and Martin Creek areas in northeast British Columbia. Of the three
Canadian wells in progress at December 31, 1998, two development wells were
completed as producers and one exploratory well was plugged and abandoned. The
Company also spud 31 development wells during the first six months of 1999 with
all being completed as producers. New well production from the recently
completed winter access drilling operations began during the first quarter of
1999. Combined initial test rates on the Chinchaga wells totaled 17.6 MMCF per
day, net to the Company. The full impact of new well completions in the
Chinchaga, Martin Creek and Rycroft areas has contributed 15 to 18 MMCF per day
of new production, net to the Company. The Company had no wells in progress in
Canada as of June 30, 1999.
1999 Expenditures. In February 1999, the Company announced a 1999 capital
budget of approximately $100 million, of which approximately 25 percent would be
expended on exploration. The Company also announced its intention to reduce its
outstanding indebtedness through the use of funds generated by the individual or
combined sources of operating activities, oil and gas property divestitures or
additional issuances of equity. Since that time, the Company has reduced its
outstanding indebtedness by $253 million and expects to further reduce its
outstanding indebtedness by approximately $100 million during the third quarter
of 1999 through the use of the net cash proceeds from pending asset divestitures
(see "Asset Divestitures", below). Subject to the successful completion of the
pending third quarter 1999 asset divestitures and the use of the associated net
cash proceeds to further reduce its outstanding indebtedness, the Company has
increased its 1999 capital budget to $180 million.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and Results
-----------------------------------------------------------------------
of Operations(1) (continued)
-------------
Amended Credit Facilities
On March 19, 1999, the Company and a syndicate of banks executed amendments to
the credit facility agreements that combined the Company's existing primary
credit facility and Canadian credit facility agreements into a new primary
credit facility (the "Credit Facility"). The Company's 364-day credit facility
will expire by its terms in August 1999. The amended terms of the Credit
Facility provide for a combined reduction in loan commitments to $941 million
prior to December 31, 1999. Additionally, the amendments provide for an
increase in the maximum interest rate margin on LIBOR rate advances under the
Credit Facility to 300 basis points, including leverage fees; and, maintenance
of certain associated debt covenants (see Note D to Notes to Consolidated
Financial Statements included in "Item 1. Financial Statements" for a specific
discussion of the Credit Facility terms, including restrictive debt covenants).
To satisfy the commitment reduction provisions of the Credit Facility, the
Company intends to reduce outstanding borrowings through the use of funds
generated by the individual or combined sources of operating activities, oil and
gas property divestitures, borrowings under subordinated debt agreements or
additional issuances of equity. During the six months ended June 30, 1999, the
Company has reduced its outstanding indebtedness under the Credit Facility by
$244 million through the application of net cash provided by operating
activities and divestiture proceeds.
Asset Divestitures
During 1998, the Company announced its intentions to sell non-strategic oil and
gas assets for gross proceeds of $500 million to $600 million in 1999 and 2000.
The realization of the Company's plans to divest oil and gas properties in 1999
or in 2000 is contingent upon, among other things, the Company's ability to find
one or more purchasers willing to purchase the assets at prices acceptable to
the Company, and the purchasers' ability to complete the transaction.
Prize Disposition. On June 29, 1999, the Company completed a sale of certain
United States oil and gas producing properties, gas plants and other assets to
Prize Energy Corp. ("Prize"). The oil and gas producing assets sold to Prize
include properties located in the Gulf Coast, Mid Continent and Permian Basin
areas of the Company's United States region.
At December 31, 1998, the Company's interest in these properties contained 63
million BOE of proved reserves (consisting of 26 million Bbls of oil and NGL's,
and 224 Bcf of gas), representing $199 million of SEC 10 value. During 1998,
daily production from these properties averaged 7,390 Bbls of oil, 1,904 Bbls of
NGL's and 68,884 Mcf of gas.
In accordance with the terms of the purchase and sale agreement, the Company
received gross sales proceeds of $245 million, comprised of $215 million of cash
and 2,307.693 shares of six percent convertible preferred stock having a
liquidation preference and fair value of $30 million. The convertible preferred
stock provides for a six percent annual dividend payment (see Note C of Notes
to Consolidated Financial Statements included in "Item 1. Financial Statements"
for a specific discussion of the conversion features of the Prize convertible
preferred stock, as well as information concerning the Prize disposition). The
Company recognized a loss of $46 million from the disposition during the quarter
ended June 30, 1999. The cash sales proceeds realized from the disposition were
used to reduce the Company's outstanding indebtedness under its Credit Facility.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
Other Dispositions. During the first half of 1999, the Company also completed
the sales of certain other oil and gas properties, gas plants and related assets
for gross cash proceeds of $45 million, subject to normal purchase price
adjustments. Such proceeds include $33 million received under eight separate
purchase and sale agreements that divest non-strategic Canadian oil and gas
properties, $9 million received from the sale of a West Texas oil and gas field
and $3 million received from the sale of an East Texas gas facility. Associated
with these dispositions, the Company recognized a net gain of $4 million during
the six months ended June 30, 1999.
During June 1999, the Company executed definitive agreements for the sale of
certain natural gas properties in South Texas for $62 million of gross proceeds
and certain other non-strategic Canadian oil and gas properties for estimated
proceeds of $34 million. During July and August 1999, the Company completed the
sale of the natural gas properties in South Texas and the majority of the
Canadian oil and gas property sales. Additionally, in August 1999, the Company
announced the signing of a definitive purchase and sale agreement for the sale
of a West Texas property for gross proceeds of $35 million. The net proceeds
from these transactions will be used to further reduce the Company's outstanding
indebtedness under the Credit Facility. While the pending dispositions of the
West Texas and Canadian properties are expected to be completed during the third
quarter of 1999, there can be no assurances that the buyers will have the
financial wherewithal to complete the transactions.
At December 31, 1998, the Company's interest in these properties contained 25
million BOE of proved reserves (consisting of 14 million Bbls of oil and NGL's,
and 65 BCF of gas), representing $84 million of SEC 10 value. During 1998, daily
production from these properties averaged 10,319 Bbls of oil, 331 Bbls of NGL's
and 28,834 Mcf of gas. The Canadian oil and gas properties being divested by
the Company represent approximately 57 percent of the Company's Canadian
production during 1998 and 26 percent of the Company's Canadian proved oil and
gas reserves as of December 31, 1998.
1998 Reorganization
In 1998, the Company announced its intentions to combine its six domestic
regions to realize operational and administrative efficiencies. During 1998,
the Company relocated the majority of its administrative services from Midland,
Texas to Irving, Texas; closed its regional offices in Corpus Christi, Texas,
Houston, Texas and Oklahoma City, Oklahoma; and, eliminated approximately 350
employee positions. Additionally, during the second quarter of 1999, the Company
centralized, in Irving, Texas, certain operational functions that were
previously located in Midland, Texas. Associated with these initiatives, the
Company recorded severance, relocation, lease termination and other costs during
the three and six months ended June 30, 1999 of $1.5 million and $7.0 million,
respectively. During the three and six months ended June 30, 1998, the Company
recorded severance, relocation, leave termination and other costs of $3.4
million and $20.5 million related to this reorganization. The Company does not
expect any significant additional reorganization charges during the remainder of
1999. See Note J of Notes to Consolidated Financial Statements included in
"Item 1. Financial Statements".
Events, Trends and Uncertainties
Other Income. During July 1999, the Company received a $30.2 million refund of
excise taxes. Due to the uncertainty surrounding the collectability of the
refund, the Company had not recorded a receiveble for this matter. Accordingly,
the Company will recognize the tax refund as other income during the third
quarter of 1999. The proceeds from the tax refund are being used by the Company
to reduce its outstanding indebtedness under its Credit Facility during the
third quarter of 1999 (see Note M. of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements").
Commodity Prices. The oil and gas prices that the Company reports are based on
the market prices received for the commodities adjusted by the results of the
Company's hedging activities. Historically, worldwide oil and gas prices have
been extremely volatile and subject to significant changes in response to real
and perceived conditions in world politics, weather patterns and other
fundamental supply and demand variables.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
From the third quarter of 1997 through the first quarter of 1999, there was a
declining trend in oil and gas price levels. During the first quarter of 1999,
the Organization of Petroleum Exporting Countries and certain other crude oil
exporting nations announced reductions in their planned export volumes. These
announcements, together with early indications that the nations had initiated
their planned reductions, have had some stabilizing effect on commodity prices
during the latter part of the first quarter of 1999 and into August 1999.
However, no assurances can be given that the stabilizing effect of these
actions, or the planned reductions in export volumes, will be sustained for an
extended period of time.
The volatility of commodity prices has had, and will continue to have, a
significant impact on the Company's results of and cash flows from operations,
capital spending programs and general financial condition.
To mitigate the impact of changing prices on the Company's results of
operations, cash flows and financial condition, the Company from time to time
enters into commodity derivative contracts as hedges against oil and gas price
risk (see Note F of Notes to Consolidated Financial Statements included in
"Item 1. Financial Statements").
Market Sensitive Financial Instruments. The Company is a party to various
financial instruments that, by their terms, cause the Company to be at risk from
future changes in commodity prices, interest and foreign exchange rates, and
other market sensitivities. For specific information concerning the market risk
associated with financial instruments that the Company is a party to, see
"Item 3. Quantitative and Qualitative Disclosures About Market Risk".
Asset Impairments and Valuation Allowances. The recent improvement in commodity
prices may be sustained by market fundamentals. However, if the improvement
proves to be short-lived, re-emergence of the declining price trend, or other
relevant factors, could result in future impairment provisions to the carrying
value of the Company's proved or unproved properties or the recognition of
additional valuation allowances to the Company's deferred tax assets. If
additional asset impairments or valuation allowances were to become necessary in
the future, they could have a material adverse effect on the Company's financial
condition and results of operations. See "Results of Operations", below, for
information concerning the Company's $17.9 million provision for impairment of
oil and gas properties that was recognized during the quarter ended June 30,
1999.
Year 2000 Project Readiness. Historically, many computer programs have been
developed that use only the last two digits in a date to refer to a year. As
the year 2000 nears, the inability of such computer programs and embedded
technologies to distinguish between "1900" and "2000" has given rise to the
"Year 2000" problem. Theoretically, such computer programs and related
technology could fail outright, or communicate inaccurate data, if not
remediated or replaced. With the proliferation of electronic data interchange,
the Year 2000 problem represents a significant exposure to the entire global
community, the full extent of which cannot be accurately assessed.
In proactive response to the Year 2000 problem, the Company established a "Year
2000" project to assess, to the extent possible, the Company's internal Year
2000 problem; to take remedial actions necessary to minimize the Year 2000 risk
exposure to the Company and significant third parties with whom it has data
interchange; and, to test its systems and processes once remedial actions have
been taken. The Company has contracted with IBM Global Services to perform the
assessment and remedial phases of its Year 2000 project.
As of June 30, 1999, the Company estimates that the assessment phase is
approximately 99 percent complete and has included, but is not limited to, the
following procedures:
* the identification of necessary remediation, upgrade and/or replacement of
existing information technology applications and systems;
* the assessment of non-information technology exposures, such as
telecommunications systems, security systems, elevators and process control
equipment;
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
* the initiation of inquiry and dialogue with significant third party business
partners, customers and suppliers in an effort to understand and assess their
Year 2000 problems, readiness and potential impact on the Company and its Year
2000 problem;
* the implementation of processes designed to reduce the risk of reintroduction
of Year 2000 problems into the Company's systems and business processes; and,
* the formulation of contingency plans for mission-critical information
technology systems.
Through June 30, 1999, the Company had distributed Year 2000 problem inquiries
to over 500 entities and has received responses to approximately 52 percent of
the inquiries.
The remedial phase of the Company's Year 2000 project is in varying stages of
completion as it pertains to the remediation of information technology and non-
information technology applications and systems in the United States, Canada and
Argentina. As of June 30, 1999, the Company estimates that the remedial phase
is approximately 83 percent complete, on a worldwide basis, subject to
continuing evaluations of the responses to third party inquiries and to the
testing phase results. The remedial phase has included the upgrade and/or
replacement of certain application and hardware systems. The Company has
upgraded its Artesia general ledger accounting systems through remedial coding
and has completed the testing of the system for Year 2000 compliance. The
remediation of non-information technology is expected to be completed by October
1999. The Company's Year 2000 remedial actions have not delayed other
information technology projects or upgrades.
The testing phase of the Company's Year 2000 project is on schedule. The
Company expects to complete the testing of information technology systems by
October 1999. The testing of the non-information technology remediation is
scheduled to be completed by the end of November 1999.
The Company expects that its total costs related to the Year 2000 problem will
approximate $3.6 million, of which approximately $500 thousand will have been
incurred to replace non-compliant information technology systems. As of June
30, 1999, the Company's total costs incurred on the Year 2000 problem were $2.3
million, of which approximately $200 thousand were incurred to replace non-
compliant systems.
The risks associated with the Year 2000 problem are significant. A failure to
remedy a critical Year 2000 problem could have a material adverse effect on the
Company's results of operations and financial condition. The most likely worst
case scenario which may be encountered as a result of a Year 2000 problem could
include information and non-information system failures, the receipt or
transmission of erroneous data, lost data or a combination of similar problems
of a magnitude that cannot be accurately assessed at this time.
In the business continuity and contingency planning phase of the Company's Year
2000 project, contingency plans were designed to mitigate the exposures to
mission critical information technology systems, such as oil and gas sales
receipts; vendor and royalty cash distributions; debt compliance; accounting;
and employee compensation. Such contingency plans anticipate the extensive
utilization of third-party data processing services, personal computer
applications and the substitution of courier and mail services in place of
electronic data interchange. Given the uncertainties regarding the scope of the
Year 2000 problem and the compliance of significant third parties, there can be
no assurance that contingency plans will have anticipated all Year 2000
scenarios.
Accounting for Derivatives. In June 1998, the Financial Accounting Standards
Board ("FASB") issued Statement of Accounting Standards No. 133 "Accounting for
Derivative Instruments and Hedging Activities" ("SFAS 133"). SFAS 133
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts
(collectively referred to as derivatives), and for hedging activities. It
requires that an entity recognize all derivatives as either assets or
liabilities in the statement of financial position and measure those instruments
at fair value. If certain conditions are met, a derivative may be specifically
designated as (a) a hedge of the exposure to changes in the fair value of a
recognized asset or liability or an unrecognized firm commitment, (b) a hedge of
the exposure to variable cash flows of a forecasted transaction, or (c) a hedge
of the foreign currency exposure of a net investment in a foreign operation, an
unrecognized firm commitment, an available-for-sale security, or a foreign-
currency-denominated forecasted transaction.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
On May 19, 1999, the FASB voted to delay the effective date for SFAS 133 to
fiscal years beginning after June 15, 2000. The Company has not determined what
effect, if any, SFAS 133 will have on its consolidated financial statements.
Results of Operations
Oil and Gas Production.
The following table provides the Company's production volume data, average
prices and per BOE average production and depletion costs for the three and six
months ended June 30, 1999 and 1998. See Note K to the Notes to Consolidated
Financial Statements included in "Item 1. Financial Statements" for the
Company's unaudited results of operations by geographic operating segment.
<TABLE>
Three months ended June 30, 1999
--------------------------------------
United
States Canada Argentina Total
------ -------- ----------- -------
<S> <C> <C> <C> <C>
Production:
Oil (MBbls)............... 3,155 665 526 4,346
NGLs (MBbls).............. 2,232 96 55 2,383
Gas (MMcf)................ 30,422 5,858 9,432 45,712
Total (MBOE).............. 10,457 1,738 2,153 14,348
Average daily production:
Oil (Bbls)................ 34,672 7,312 5,775 47,759
NGLs (Bbls)............... 24,519 1,055 610 26,184
Gas (Mcf)................. 334,307 64,378 103,646 502,331
Total (BOE)............... 114,910 19,096 23,659 157,665
Average oil price (per Bbl). $ 14.75 $ 14.02 $ 16.95 $ 14.90
Average NGL price (per Bbl). $ 9.87 $ 10.70 $ 7.80 $ 9.86
Average Gas price (per Mcf). $ 2.16 $ 1.72 $ 1.11 $ 1.88
Costs (per BOE):
Lease operating expense... $ 2.42 $ 3.37 $ 1.67 $ 2.42
Production taxes.......... .49 - .15 .38
Workover costs............ .08 .33 - .10
-------- ------- -------- --------
Total production costs.. $ 2.99 $ 3.70 $ 1.82 $ 2.90
======== ======= ======== ========
Depletion $ 3.97 $ 4.96 $ 4.42 $ 4.16
</TABLE>
Six months ended June 30, 1999
------------------------------------------
United
States Canada Argentina Total
------ ------ --------- -----
<TABLE>
<S> <C> <C> <C> <C>
Production:
Oil (MBbls)............... 6,466 1,354 1,063 8,883
NGLs (MBbls).............. 4,584 167 110 4,861
Gas (MMcf)................ 61,978 10,460 16,988 89,426
Total (MBOE).............. 21,379 3,264 4,005 28,648
Average daily production:
Oil (Bbls)................ 35,721 7,483 5,872 49,076
NGLs (Bbls)............... 25,327 922 609 26,858
Gas (Mcf)................. 342,418 57,788 93,859 494,065
Total (BOE)............... 118,118 18,036 22,124 158,278
Average oil price (per Bbl). $ 13.44 $ 12.21 $ 13.99 $ 13.32
Average NGL price (per Bbl). $ 8.75 $ 9.03 $ 7.19 $ 8.72
Average Gas price (per Mcf). $ 2.01 $ 1.67 $ 1.10 $ 1.80
Costs (per BOE):
Lease operating expense... $ 2.75 $ 3.31 $ 1.94 $ 2.71
Production taxes.......... .41 - .14 .32
Workover costs............ .06 .28 - .07
-------- ------- ------- --------
Total production costs.. $ 3.22 $ 3.59 $ 2.08 $ 3.10
======== ======= ======= ========
Depletion................. $ 4.23 $ 4.96 $ 4.42 $ 4.34
</TABLE>
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
Three Months ended June 30, 1998
------------------------------------------
United
States Canada Argentina Total
------ ------ --------- -----
<TABLE>
<S> <C> <C> <C> <C>
Production:
Oil (MBbls).............. 3,956 872 792 5,620
NGLs (MBbls)............. 2,614 69 58 2,741
Gas (MMcf)............... 36,280 4,757 6,194 47,231
Total (MBOE)............. 12,617 1,734 1,882 16,233
Average daily production:
Oil (Bbls)............... 43,479 9,577 8,706 61,762
NGLs (Bbls).............. 28,723 753 634 30,110
Gas (Mcf)................ 398,677 52,278 68,067 519,022
Total (BOE).............. 138,648 19,043 20,684 178,375
Average oil price (per Bbl) $ 13.81 $ 11.45 $ 11.11 $ 13.06
Average NGL price (per Bbl) $ 8.91 $ 10.08 $ 10.44 $ 8.97
Average Gas price (per Mcf) $ 2.00 $ 1.32 $ 1.11 $ 1.81
Costs (per BOE):
Lease operating expense.. $ 2.89 $ 3.79 $ 2.89 $ 2.99
Production taxes......... .48 - .18 .40
Workover costs........... .12 .07 - .10
-------- ------- ------- --------
Total production costs $ 3.49 $ 3.86 $ 3.07 $ 3.49
======== ======= ======= ========
Depletion................ $ 4.74 $ 6.02 $ 5.36 $ 4.95
</TABLE>
Six Months ended June 30, 1998
------------------------------------------
United
States Canada Argentina Total
------ ------ --------- -----
<TABLE>
<S> <C> <C> <C> <C>
Production:
Oil (MBbls).............. 7,822 1,757 1,634 11,213
NGLs (MBbls)............. 5,027 131 112 5,270
Gas (MMcf)............... 71,280 8,330 11,651 91,261
Total (MBOE)............. 24,729 3,276 3,688 31,693
Average daily production:
Oil (Bbls)............... 43,217 9,705 9,031 61,953
NGLs (Bbls).............. 27,774 723 617 29,114
Gas (Mcf)................ 393,811 46,025 64,370 504,206
Total (BOE).............. 136,626 18,099 20,376 175,101
Average oil price (per Bbl) $ 14.44 $ 11.64 $ 11.14 $ 13.52
Average NGL price (per Bbl) $ 9.93 $ 11.00 $ 12.20 $ 10.00
Average Gas price (per Mcf) $ 2.14 $ 1.38 $ 1.11 $ 1.94
Costs (per BOE):
Lease operating expense.. $ 2.92 $ 3.73 $ 2.79 $ 2.99
Production taxes......... .52 - .17 .42
Workover costs........... .14 .05 - .12
-------- ------- ------- --------
Total production costs $ 3.58 $ 3.78 $ 2.96 $ 3.53
======== ======= ======= ========
Depletion................ $ 4.64 $ 5.91 $ 5.30 $ 4.84
</TABLE>
Oil and Gas Revenues. Revenues from oil and gas operations totaled $174.2
million and $321.4 million for the three and six months ended June 30, 1999,
respectively, compared to $183.6 million and $381.0 million, respectively, for
the same periods in 1998. The decrease in revenues during the six months ended
June 30, 1999, as compared to the six months ended June 30, 1998, is reflective
of declines in commodity prices and decreased production volumes. The decrease
in revenues during the three months ended June 30, 1999, as compared to the
three months ended June 30, 1998, is reflective of decreased production volumes,
partially offset by increases in commodity prices.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1)(continued)
---------------------
On a BOE basis, production decreased by 12 percent and 10 percent for the three
and six months ended June 30, 1999, respectively, as compared to the same
periods in 1998. For the six months ended June 30, 1999, production, on a BOE
basis, declined 14 percent in the United States, Argentine production increased
by nine percent and Canadian production was consistent between periods. On a
worldwide basis, 77 percent of the decline in production was attributable to
declines in crude oil production, which was primarily due to the Company having
suspended oil development drilling in 1998 following the decline in oil prices.
The average oil price for the six months ended June 30, 1999 decreased one
percent (from $13.52 per Bbl to $13.32 per Bbl for the six months ended June 30,
1998 and 1999, respectively); the average NGL price decreased 13 percent (from
$10.00 per Bbl to $8.72 per Bbl for the six months ended June 30, 1998 and 1999,
respectively); and, the average gas price decreased seven percent (from $1.94
per Mcf to $1.80 per Mcf for the six months ended June 30, 1998 and 1999,
respectively). During the three months ended June 30, 1999, the average oil
price increased 14 percent (from $13.06 per Bbl to $14.90 per Bbl for the three
months ended June 30, 1998 and 1999, respectively); the average NGL price
increased 10 percent (from $8.97 per Bbl to $9.86 per Bbl for the three months
ended June 30, 1998 and 1999, respectively); and, the average gas price
increased four percent (from $1.81 per Mcf to $1.88 per Mcf for the three months
ended June 30, 1998 and 1999, respectively).
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 hedging
activities. The Company from time to time enters into commodity derivative
contracts (swaps, futures and options) in order to (i) reduce the effect of the
volatility of price changes on the commodities the Company produces and sells,
(ii) support the Company's annual capital budgeting and expenditure plans and
(iii) lock in prices to protect the economics related to certain capital
projects. During the three and six months ended June 30, 1999, the Company's
hedging activities decreased the average price received for oil sales by one
percent and increased the average price received for oil sales by three percent,
respectively. The average price received for gas sales were increased by four
percent and nine percent, respectively, as a result of the Company's hedging
activities.
Crude Oil. The majority of sales contracts governing the Company's oil
production are tied directly or indirectly to NYMEX prices. The average oil
price per Bbl that the Company reports includes the effects of oil quality,
gathering and transportation costs and the net effect of the oil hedges. The
Company's average realized price for physical oil sales (excluding hedge
results) for the three and six months ended June 30, 1999 was $15.02 per Bbl,
and $12.97 per Bbl, respectively, while, as a point of reference, the comparable
daily average NYMEX closing for the same periods were $17.66 per Bbl and $15.36
per Bbl, respectively. The Company recorded a net decrease to oil revenues of
$.5 million and a net increase to oil revenues of $3.0 million for the three and
six month periods ended June 30, 1999, respectively, as a result of its
commodity hedges.
During the three and six months ended June 30, 1998, the Company realized an
average price for physical oil sales (excluding hedge results) of $11.97 per Bbl
and $12.54 per Bbl, respectively, while, as a point of reference, the comparable
daily average NYMEX closing per Bbl for the same periods were $14.67 per Bbl and
$15.28 per Bbl, respectively. The Company recorded net increases to oil
revenues of $6.2 million and $11.0 million for the three and six months ended
June 30, 1998, respectively, as a result of its commodity hedges.
Natural Gas. The Company hedges 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. The average gas price per Mcf that the Company
reports includes the effects of Btu content, gathering and transportation costs,
gas processing and shrinkage and the net effect of gas hedges. The Company's
average realized price for physical gas sales (excluding hedge results) for the
three and six months ended June 30, 1999 were $1.80 per Mcf and $1.65 per Mcf,
respectively, while, as a point of reference, the comparable daily average NYMEX
closing for the same periods were $2.13 per Mcf and $1.94 per Mcf, respectively.
The Company recorded net increases to gas revenues of $3.6 million and $12.9
million for the three and six months ended June 30, 1999, respectively, as a
result of its commodity hedges.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
During the three and six months ended June 30, 1998, the Company realized an
average price for physical gas sales (excluding hedge results) of $1.88 per Mcf
and $1.91 per Mcf, respectively, while, as a point of reference, the comparable
daily average NYMEX closing for the same periods were $2.26 and $2.24 per Mcf,
respectively. The Company recorded a net reduction to gas revenues of $3.2
million for the three months ended June 30, 1998 and a net increase to gas
revenues of $2.3 million for the six months ended June 30, 1998, as a result of
its commodity hedges.
See Note F of Notes to Consolidated Financial Statements included in "Item 1.
Financial Statements" for information concerning the Company's open hedge
positions and related contract prices as of June 30, 1999.
Production Costs. During the three and six months ended June 30, 1999, total
production costs per BOE decreased to $2.90 and $3.10, respectively, as compared
to production costs per BOE of $3.49 and $3.53, respectively, during the same
periods in 1998. The quarter-to-quarter decline in production costs per BOE is
reflective of a 19 percent decline in lease operating expenses, primarily
realized as a result of the Company's cost containment initiatives, and a five
percent decline in production taxes. The relative decline in year-to-date
production costs per BOE is reflective of a nine percent decline in lease
operating expenses, a 24 percent decline in production taxes and a 42 percent
decline in workover costs per BOE. The decline in production taxes per BOE is
primarily a function of the decline in period-to-period commodity prices.
Depletion Expense. Depletion expense per BOE decreased to $4.16 per BOE and
$4.34 per BOE during the three and six months ended June 30, 1999, respectively,
as compared to $4.95 per BOE and $4.84 per BOE during the same periods in 1998.
The decline in depletion expense per BOE during 1999 is primarily associated
with the reduction in net depletable basis that resulted from the fourth quarter
1998 impairment charge taken in accordance with Statement of Financial
Accounting Standards No. 121, "Accounting for the Impairment of Long-Lived
Assets and for Long-Lived Assets to Be Disposed Of". A secondary factor to the
decline in per BOE depletion expense is the increase in estimated recoverable
proved reserves resulting from improved commodity prices.
Impairment of Oil and Gas Properties. During the second quarter of 1999, the
Company reduced the carrying value of certain of its East Texas unproved
properties by $17.9 million. The impairment of the associated properties was
recognized after the assessment of seismic data that indicated that the
estimated value of the properties was less than their carrying cost. See Note
I. of Notes to Consolidated Financial Statements included in "Item 1. Financial
Statements".
Exploration and Abandonments/Geological and Geophysical Costs. Exploration and
abandonments and geological and geophysical costs decreased to $17.9 million and
$29.7 million during the three and six month periods ended June 30, 1999,
respectively, from $26.6 million and $50.5 million during the same periods in
1998. The decrease is largely the result of reductions in geological and
geophysical activity and leasehold abandonments, partially offset by increases
in exploratory dry holes.
<TABLE>
Three months Six months
-------------- --------------
ended June 30, ended June 30,
-------------- --------------
1999 1998 1999 1998
---- ---- ---- ----
<S> <C> <C> <C> <C>
Exploratory dry holes:
United States............. $ 5,871 $ 1,055 $ 8,245 $ 2,801
Argentina................. 3,608 1,393 3,656 2,809
Canada.................... 191 324 925 803
Other foreign............. 65 2,249 334 3,936
Geological and geophysical costs:
United States............. 3,975 11,153 8,151 17,604
Argentina................. 352 1,915 1,104 2,905
Canada.................... (126) 3,365 39 7,953
Other foreign............. 984 1,257 1,950 2,051
Leasehold abandonments and other 3,005 3,862 5,297 9,660
------- ------- ------- -------
$17,925 $26,573 $29,701 $50,522
======= ======= ======= =======
</TABLE>
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
The Company's 1999 exploration efforts are concentrated in the Gulf of Mexico
and onshore Gulf Coast regions of the United States. The Company's exploration
programs in South Africa, Gabon and the Gulf Coast transition zone are
undergoing comprehensive studies focusing on analysis, ranking and timing of
prospects during 1999.
Interest and Other Revenue
During the three and six months ended June 30, 1999, the Company recorded
interest and other revenue of $2.8 million and $48.8 million, respectively, as
compared to $1.1 million and $2.3 million during the same periods of 1998. The
increase in interest and other revenue for the quarter ended June 30, 1999, as
compared to the quarter ended June 30, 1998, is primarily comprised of a $1.2
million increase in other revenue related to Argentina operations and $.5
million of liquidated damage recoveries. The increase in revenue during the six
months ended June 30, 1999, as compared to the same period in 1999, was
primarily attributable to the $41.8 million of option income and liquidated
damages referred to in "Financial Performance", above and described in Note G.
of Notes to Consolidated Financial Statements included in "Item 1. Finance
Statements".
Gain (Loss) on Disposition of Assets
The Company recognized net losses of $42.3 million and $42.2 million on the sale
of assets during three and six month periods ended June 30, 1999, respectively,
as compared to net gains of $.3 million during each of the prior year periods
ended June 30, 1998. The losses recognized during 1999 are associated with the
divestitures of oil and gas properties, gas plants and other assets in the
United States and Canada. See Note C. of Notes to Consolidated Financial
Statements included in "Item 1. Financial Statements" and "Asset Divestitures",
above, for discussions pertaining to the divestitures completed during the first
six months of 1999 and pending third quarter 1999 divestitures.
General and Administrative Expense
General and administrative expense was $10.2 million and $20.4 million for the
three and six months ended June 30, 1999, respectively, as compared to $17.4
million and $37.4 million for the same periods ended June 30, 1998, representing
a decrease of 41 percent and 45 percent, respectively. On a per BOE basis,
general and administrative expense declined from $1.07 and $1.18, respectively,
during the three and six months ended June 30, 1998, to $.71 during each of the
same periods in 1999. The decreases are primarily attributable to the
efficiency measures initiated through the 1998 reorganization.
Reorganization Expense
Reorganization expense for the three and six month periods ended June 30, 1999
totaled $1.5 million and $7.0 million, respectively, compared to $3.4 million
and $20.5 million during the same periods in 1998. As announced in 1998, the
Company has consolidated its six domestic operating divisions, relocated most
of its administrative services to Irving, Texas, closed its regional offices in
Corpus Christi, Texas, Houston, Texas and Oklahoma City, Oklahoma, and
eliminated approximately 350 employee positions. Additionally, during the
second quarter of 1999, the Company centralized, in Irving, Texas, certain
operational functions that were previously located in Midland, Texas. The
Company does not expect any significant additional reorganization charges during
the remainder of 1999. See Note J of Notes to Consolidated Financial Statements
included in "Item 1. Financial Statements" for a specific discussion of the
reorganization provisions recognized by the Company.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
Interest Expense
Interest expense for the three and six months ended June 30, 1999 was $46.9
million and $89.4 million, respectively, as compared to $41.0 million and $80.5
million for the same periods in 1998. The $5.9 million increase in interest
expense during the second quarter of 1999 as compared to the second quarter of
1998 is reflective of a $38 million increase in the Company's average debt
outstanding and a 75 basis point increase in the Company's weighted average
interest rate on debt. The $8.9 million increase in interest expense during the
first half of 1999 as compared to the first half of 1998 is reflective of a $77
million increase in the Company's average debt outstanding and a 34 basis point
increase in the Company's weighted average interest rate on debt.
During the three and six months ended June 30, 1999, the Company was a party to
interest rate swap agreements that resulted in a decrease in interest expense of
$305 thousand and $849 thousand, respectively. During the same period in 1998,
such agreements resulted in an increase in interest expense of $78 thousand and
$73 thousand, respectively.
Other Costs and Expenses
Other costs and expenses for the three and six months ended June 30, 1999 were
$9.6 million and $18.3 million, respectively, compared to $6.8 million and $13.6
million for the same periods in 1998. The increase in others costs and expenses
are primarily attributable to fluctuations in mark-to-market provisions on
financial instruments.
The Company is a party to certain BTU swap agreements that do not qualify as
hedges. Other expenses for the three and six month periods ended June 30, 1999
include a non-cash mark-to-market decrease of $1.2 million and an increase of
$.9 million, respectively, to the liabilities recognized for the BTU swap
agreements; and, for the three and six month periods ended June 30, 1998, a
decrease in the liabilities of $.4 million and an increase of $5.8 million,
respectively. These contracts will continue to be marked-to-market at the end
of each reporting period during their respective lives. The effects on the
Company's results of operations in future periods could be significant.
During the fourth quarter of 1998, the Company received three million shares of
common stock of a closely held, non-affiliated, publicly traded entity in
partial payment of option fees referred to in "Financial Performance," above.
During April 1999, the Company was paid liquidated damages of an additional one
million shares of common stock of the entity. During the three and six months
ended June 30, 1999, the market quoted value of the four million shares of
common stock declined by $7.0 million and $11.9 million, respectively.
Accordingly, other expenses for the three and six months ended June 30, 1999,
includes non-cash mark-to-market decreases to the carrying value of the
investment of $7.0 million and $11.9 million, respectively. In June 1999, the
Company sold its interest in this investment.
The Company has a series of forward foreign exchange swap agreements to exchange
Canadian dollars for United States dollars at future dates for a fixed amount of
the first currency. As these contracts do not qualify as hedges, the Company
recorded non-cash mark-to-market decreases in the recognized liabilities
associated with these agreements during the three and six months ended June 30,
1999, in the amounts of $3.4 million and $5.9 million, respectively. These
contracts will continue to be marked-to-market until they mature at various
dates in the fourth quarter of 2000. The related effects on the Company's
results of operations in future periods could be significant.
During the first quarter of 1999, the Company sold certain NYMEX crude oil calls
and other crude oil and natural gas call options that do not qualify for hedge
accounting treatment. Other expenses for the three and six months ended June
30, 1999, include $5.6 million and $8.2 million, respectively, of non-cash mark-
to-market increases to the liabilities recognized on these contracts.
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
Income Taxes
During 1998, the Company determined that it was more likely than not that
certain of its net operating loss carryforwards and other credit carryforwards
may expire unused. Accordingly, the Company has established a valuation reserve
to reduce the carrying value of its deferred tax assets. As a result of this
situation, it is likely that the Company's effective tax rate during the
remainder of 1999 will be minimal, or nil, if the Company recognizes a loss
before income taxes. If the Company recognizes income before income taxes
during the remainder of 1999, its effective tax rate will be reduced to the
extent that taxable earnings are recognized in those tax jurisdictions where the
Company has established deferred tax valuation allowances.
During the three and six month periods ended June 30, 1999, the Company
recognized income tax benefits of $500 thousand and $100 thousand,
respectively, as compared to tax benefits of $17.7 million and $31.1 million for
the three and six month periods ended June 30, 1998, respectively. The minimal
income tax benefit recognized during the six months ended June 30, 1999 is
primarily due to the continuing uncertainties regarding the Company's ability to
utilize net operating loss carryforwards and other credit carryforwards prior to
their expiration.
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 principal
and interest on outstanding indebtedness and working capital obligations.
The Company's cash expenditures during the first half of 1999 for additions to
oil and gas properties totaled $65.4 million. This amount includes $1.1 million
for the acquisition of prospects and properties and $64.3 million for
development and exploratory drilling. Drilling expenditures during the first
half of 1999 included $41.3 million of expenditures in the United States, $11.9
million of expenditures in Canada, $10.0 million of expenditures in Argentina
and $1.1 million of expenditures in other international areas. See "Drilling
Highlights", above, for a specific discussion of capital investments made during
the first six months of 1999.
Funding for the Company's working capital obligations is provided by internally-
generated cash flows. Funding for the repayment of principal and interest on
outstanding debt has been principally funded by proceeds from the disposition of
non-strategic assets in 1999, but it may be provided by any combination of
internally-generated cash flows, 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 in 1999.
Operating Activities. Net cash provided by operating activities was
$89.1 million and $97.4 million during the three and six month periods ended
June 30, 1999, respectively, as compared to net cash provided by operating
activities of $91.4 million and $160.4 million for the same respective periods
in 1998. The decrease in net cash provided by operating activities during the
six months ended June 30, 1999 as compared to the six months ended June 30, 1998
was primarily attributable to declines in revenue from oil and gas operations
due to declines in commodity prices and production volumes, and to a
$52.3 million relative increase in working capital, excluding cash and cash
equivalents and current maturities of long-term debt (see "Oil and Gas
Revenues", above.)
<PAGE>
Item 2. Management's Discussion and Analysis of Financial Condition and
---------------------------------------------------------------
Results of Operations(1) (continued)
---------------------
Financing Activities. The Company had an outstanding balance under its Credit
Facility at June 30, 1999 of $1.03 billion (including outstanding, undrawn
letters of credit of $19 million), leaving approximately $178 million of unused
borrowing capacity immediately available. However, under commitment reduction
provisions of the Credit Facility, the Company must reduce its borrowings under
the Credit Facility to $941 million prior to December 31, 1999. To satisfy the
commitment reduction provisions of the Credit Facility, the Company intends to
further reduce outstanding borrowings through the use of funds generated by the
individual or combined sources of operating activities, oil and gas property
divestitures, borrowings under subordinated debt agreements or additional
issuances of equity. See Note D to Notes to the Consolidated Financial
Statements included in "Item 1. Financial Statements" and "Amended Credit
Facilities", above, for specific discussions of the Credit Facility terms.
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.
Sales of Non-strategic Assets. During the three and six month periods ended
June 30, 1999, net cash proceeds from the sale of non-strategic assets totaled
$264.3 million and $269.4 million, respectively. The proceeds from these sales
were primarily utilized to reduce the Company's outstanding bank indebtedness.
Since June 30, 1999, the Company has also executed definitive agreements for the
sale of certain natural gas properties in South Texas for $62 million of gross
proceeds, a West Texas property for gross proceeds of $35 million and non-
strategic Canadian oil and gas properties for estimated proceeds of $34 million.
During July and August, the Company completed the sale of the natural gas
properties in South Texas and the majority of the Canadian oil and gas property
sales. While the pending dispositions are expected to be completed during the
third quarter of 1999, there can be no assurances that the buyers will have the
financial wherewithal to complete the transactions. See "Asset Divestitures",
above, for a description of the Company's completed and pending divestitures.
Liquidity. As of June 30, 1999, the Company had $79.3 million of cash and cash
equivalents on hand, compared to $59.2 million as of December 31, 1998. The
Company's ratio of current assets to current liabilities was .84 to one at June
30, 1999 and .38 to one at December 31, 1998.
Item 3. Quantitative and Qualitative Disclosures About Market Risk(1)
----------------------------------------------------------
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 fiscal year ended December 31,
1998. 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
fiscal year ended December 31, 1998.
The disclosures provided below provide specific information about material
changes during the six months ended June 30, 1999 in the Company's portfolio of
financial instruments. The Company may incur future earnings gains or losses on
these instruments from changes in market interest rates, foreign exchange rates,
commodity prices or common stock prices.
<PAGE>
Item 3. Quantitative and Qualitative Disclosures About Market Risk(1)
----------------------------------------------------------
(continued)
Interest rate sensitivity. On March 19, 1999, the Company and a syndicate of
banks executed amendments to the Company's variable rate credit facility
agreements. The amendments combined the Company's existing primary credit
facility and Canadian credit facility agreements into a new primary credit
facility (the "Credit Facility"). The terms of the Credit Facility provide for
a $495 million combined reduction in loan commitments, to $941 million prior to
December 31, 1999. Additionally, the amendments provide for an increase in the
maximum interest rate margin on LIBOR rate advances under the Credit Facility to
300 basis points, including leverage fees; and, maintenance of certain
associated debt covenants (see Note D to Notes to Consolidated Financial
Statements included in "Item 1. Financial Statements" for a specific discussion
of the Credit Facility). The quantitative information provided in the Company's
Annual Report on Form 10-K was reflective of the terms of the March 19, 1999
amendments described above. During the six months ended June 30, 1999, the
Company reduced its combined borrowings under its Credit Facility to $1.01
billion, representing a $244 million decrease in variable rate borrowings and
1999 debt maturities.
During the six months ended June 30, 1999, there were no material changes to the
Company's interest rate derivatives related to total debt.
Foreign exchange rate sensitivity. As of June 30, 1999, the recognized
liability for the fair value of the Company's foreign currency swaps declined to
$9.4 million. The terms of the foreign currency swaps provide for the Company
to pay a fixed Canadian to United States dollar rate on notional United States
dollar amounts of $72 million in 1999 and 2000.
During the six months ended June 30, 1999, there were no other material changes
to the Company's foreign exchange rate sensitive derivatives.
Commodity price sensitivity. During the six months ended June 30, 1999, the
Company entered into certain hedge and non-hedge crude oil derivatives and
changed its portfolio of natural gas hedge derivatives.
The following tables provide information about the crude oil and natural gas
derivative financial instruments that the Company was a party to as of June 30,
1999. The tables segregate hedge derivative contracts from those that do not
qualify as hedges.
Commodity hedge instruments. The Company hedges commodity price risk with swap
contracts, collar contracts, collar contracts with short put options, and put
spread contracts. Swap contracts provide a fixed price for a notional amount of
sales volumes. Collar contracts provide a floor price for the Company on a
notional amount of sales volumes while allowing some additional price
participation if the relevant index price closes above the floor price. Collar
contracts with short put options differ from other collar contracts by virtue of
the short put option price, below which the Company's realized price will exceed
variable market prices by the long put-to-short put price differential. With
put spread contracts, the Company purchases a put contract and concurrently
sells a put contract at a lower index price. The put spread contracts are
similar to the collar contracts with short put options, except that the Company
participates in all prices above the tentative floor price.
Commodity non-hedge instruments. The Company has also entered into BTU swap
contracts that do not qualify for hedge accounting. Under the terms of the BTU
swap, the Company receives 10 percent of the NYMEX oil price and pays the NYMEX
gas price on 13,036 notional MMBtu daily volume.
The Company has also sold crude oil calls and optional calls that do not qualify
for hedge accounting treatment. The terms of the optional calls provide the
counter-parties with the option to elect to call either notional crude oil
volumes or natural gas volumes at specific index prices.
See Notes F and H 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
natural gas and crude oil commodity prices.
<PAGE>
Item 3. Quantitative and Qualitative Disclosures About Market Risk(1)
----------------------------------------------------------
(continued)
Pioneer Natural Resources Company
Crude Oil Price Sensitivity
Derivative Financial Instruments as of June 30, 1999
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
1999 2000 2001 2002 2003 Thereafter Fair value
---- ---- ---- ---- ---- ---------- ----------
(in thousands except volumes and prices)
Crude Oil Hedge
Derivatives:
Average daily
notional Bbl
volumes (1):
Swap contracts
(2):.............. 8,712 521 373 $(14,410)
Weighted average
per Bbl fixed
price............. $15.67 $15.76 $15.76
Collar contracts:.. 2,000 $(592)
Weighted average
short call per Bbl
ceiling price..... $17.60
Weighted average
long put per Bbl
floor price....... $15.00
Collar contracts
with short puts:.. - 5,000 $(1,696)
Weighted average
short call per Bbl
ceiling price..... - $20.09
Weighted average
long put per Bbl
floor price....... - $17.00
Weighted average
short put per Bbl
price below which
floor becomes
variable.......... - $14.00
Put spread
contracts:......... 10,000 $157
Weighted average
long put per Bbl
contingent floor
price............. $15.00
Weighted average
short put per Bbl
price below which
floor becomes
variable.......... $11.00
Crude Oil Non-hedge
Derivatives:
Call option
contracts sold..... 8,000 $(2,977)
Weighted average
short put per Bbl
price below which
the floor becomes
variable.......... $17.15
Daily notional
crude oil Bbl
volumes under
optional calls
sold (3).......... 10,000 10,000 $(8,825)
Weighted average
short call per Bbl
ceiling price..... $20.00 $20.00
Average forward
NYMEX crude oil
price per Bbl..... $20.35 $18.95
Daily notional
MMBtu volumes
under swap of
NYMEX gas price
for 10 percent of
NYMEX WTI price... 13,036 13,036 13,036 13,036 13,036 13,036 $(15,083)
Average forward
NYMEX gas prices(4) $2.76 $2.53 $2.49 $2.52 $2.55 $2.58
Ave. forward NYMEX
oil prices(4)..... $20.35 $18.95 $17.83 $17.40 $17.27 $17.17
</TABLE>
__________
(1) See Note F of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for hedge volumes and weighted average prices by
calendar quarter for 1999, 2000 and 2001.
(2) Certain counterparties to the 1999 swap contracts have the contractual right
to extend 9,000 Bbl's per day for one additional year at a strike price of
$16.56 per Bbl.
(3) The counterparties to the 1999 and 2000 optional call contracts have the
contractual right to elect to call crude volumes or gas volumes at the
indicated prices. See the "Natural Gas Price Sensitivity" table for the
optional natural gas volumes and call prices available to the
counterparties.
(4) Average forward NYMEX oil and gas prices are as of August 5, 1999.
<PAGE>
Item 3. Quantitative and Qualitative Disclosures About Market Risk(1)
----------------------------------------------------------
(continued)
Pioneer Natural Resources Company
Crude Oil Price Sensitivity
Derivative Financial Instruments as of June 30, 1999
<TABLE>
<S> <C> <C> <C> <C> <C> <C> <C>
1999 2000 2001 2002 2003 Thereafter Fair value
---- ---- ---- ---- ---- ---------- ----------
(in thousands except volumes and prices)
Crude Oil Hedge
Derivatives:
Average daily
notional Bbl
volumes (2):
Swap contracts
(2):.............. 22,835 49,223 12,500 10,000 $(6,938)
Weighted average
MMBtu fixed price $2.12 $2.17 $2.36 $2.58
Collar contracts.. 30,351 $(601)
Weighted average
short call MMBtu
ceiling price.... $2.56
Weighted average
long put MMBtu
floor price...... $1.91
Collar contracts
with short puts(4) 68,196 97,557 35,000 $(5,951)
Weighted average
short call MMBtu
ceiling price.... $2.57 $2.66 $2.65
Weighted average
long put MMBtu
contingent floor
price............ $2.08 $2.08 $2.25
Weighted average
short put MMBtu
price below which
floor becomes
variable......... $1.79 $1.80 $1.95
Natural Gas Non-hedge
Derivatives:
Daily nominal gas
MMBtu volumes
under optional
calls sold (5)... 100,000 100,000 $(8,825)
Weighted average
short call per
MMBtu ceiling
price............ $2.64 $2.76
Average forward
NYMEX gas price
per MMBtu........ $2.76 $2.53
Daily notional
MMBtu volumes
under agreement
to swap NYMEX
gas price for 10
percent of NYMEX
WTI price........ 13,036 13,036 13,036 13,036 13,036 13,036 $(15,083)
Average forward
NYMEX gas prices
(6).............. $2.76 $2.53 $2.49 $2.52 $2.55 $2.58
Average forward
NYMEX oil prices
(6).............. $20.35 $18.95 $17.83 $17.40 $17.27 $17.17
</TABLE>
__________
(1) When necessary, to minimize basis risk the Company enters into natural gas
basis swaps to connect the index price of the hedging instrument from a
NYMEX index to an index that reflects the geographic area of production.
The Company considers these basis swaps as part of the associated swap and
option contracts and, accordingly, the effects of the basis swaps have been
presented together with the associated contracts.
(2) See Note F of Notes to Consolidated Financial Statements included in "Item
1. Financial Statements" for hedge volumes and weighted average prices by
calendar quarter for 1999, 2000, 2001 and 2002.
(3) Counterparties to the 1999, 2000, 2001 and 2002 swap contracts have the
contractual right to extend 20,000; 49,223; 12,500; and 10,000 MMBtu per
day, respectively, for one additional year at average strike prices of
$2.32; $2.21; $2.52; and $2.58 per MMBtu, respectively.
(4) 30,000; 79,482; and 35,000 MMBtu per day of the 1999, 2000 and 2001 collar
option contracts with short puts are extendable at the option of the
counterparties for a period of one year at respective average per MMBtu
prices of $2.73, $2.78 and $2.65 for the short call, $2.13, $2.13 and $2.25
for the long put and $1.83, $1.83 and $1.95 for the short put.
(5) The counterparties to the 1999 and 2000 optional call contracts have the
contractual right to elect to call crude volumes or gas volumes at the
indicated prices. See the "Crude Oil Price Sensitivity" table for the
optional crude oil volumes and call prices available to the counterparties.
(6) Average forward NYMEX oil and gas prices are as of August 5, 1999.
<PAGE>
Item 3. Quantitative and Qualitative Disclosures About Market Risk(1)
-------------------------------------------------------------
(continued)
Other price sensitivity. During June 1999, the Company sold its investment in
Costilla Energy Inc. common stock for $.6 million.
______________
(1) The information in this document includes forward-looking statements that
are made pursuant to the Safe Harbor Provisions of the Private Securities
Litigation Reform Act of 1995. Forward-looking statements, and the business
prospects of Pioneer Natural Resources Company, 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, 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. These and other risks are described in the Company's
1998 Annual Report on Form 10-K that is available from the United States
Securities and Exchange Commission.
<PAGE>
PART II. OTHER INFORMATION
Item 1. Legal Proceedings
In addition to the specific litigation discussed in Note E of Notes to
Consolidated Financial Statements included in "Item 1. Financial Statements",
the Company is a party to various other legal actions incidental to its
business. The claims for damages from such legal actions are not in excess of
10 percent of the Company's current assets and the Company believes none of
these actions to be material.
Item 4. Submission of Matters to a Vote of Security Holders
The Company's annual meeting of stockholders was held on May 20, 1999 in Dallas,
Texas. At the meeting, three proposals were submitted for vote of stockholders
(as described in the Company's Proxy Statement dated April 15, 1999).
The following is a brief description of the proposals and results of the
stockholders' votes.
Election of Directors. Prior to the meeting, the Company's Board of Directors
designated four nominees as Class II directors with their terms to expire at the
annual meeting in 2002 when their successors are elected and qualified. Messrs.
Baroffio, Hersh, Sheffield and Stillwell were, at the time of such nomination
and at the time of the meeting, directors of the Company. Each nominee was
reelected as a director of the Company, with the results of the stockholder
voting being as follows:
Authority Broker
For Withheld Abstain Non-Votes
------------ --------- ---------- -----------
James R. Baroffio 86,635,257 442,272 - -
Kenneth A. Hersh 86,564,834 512,695 - -
Scott D. Sheffield 86,631,801 445,728 - -
Robert L. Stillwell 86,626,926 450,603 - -
Messrs. Philip B. Smith and Kenneth A. Hersh resigned their positions as
Directors of the Company in June 1999. The term of office for the following
directors continues as of June 30, 1999: I. Jon Brumley, Scott D. Sheffield,
James R. Baroffio, R. Hartwell Gardner, James L. Houghton, Jerry P. Jones,
Richard E. Rainwater, Charles E. Ramsey, Jr., and Robert L. Stillwell.
Ratification of selection of auditors. The engagement of Ernst & Young LLP as
the Company's independent auditors for 1999 was submitted to the stockholders
for ratification. Such selection was ratified, with the results of the
stockholder voting being as follows:
<TABLE>
<S> <C>
For 86,717,709
Against 192,356
Abstain 167,464
Broker non-votes -
</TABLE>
Amendment to the Long-Term Incentive Plan. An amendment to the Company's Long-
Term Incentive Plan (the "Plan"), to make non-employee directors of the Company
eligible to receive certain types of awards under the Plan (rather than solely
restricted stock awards), was submitted to the stockholders for approval. The
amendment was approved, with the results of the stockholder voting being as
follows:
<TABLE>
<S> <C>
For 73,917,928
Against 12,801,406
Abstain 358,195
Broker non-votes -
</TABLE>
<PAGE>
Item 6. Exhibits and Reports on Form 8-K
Exhibits
10.1 Purchase and Sale Agreement, dated May 16, 1999, by and between Pioneer
Natural Resources USA, Inc. and Pioneer Resources Producing, L.P. as
Seller and Prize Energy Corp. as Purchaser (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the
Securities and Exchange Commission on July 13, 1999).
27. Financial Data Schedule
Reports on Form 8-K
During the quarter ended June 30, 1999, the Company did not file any Current
Reports on Form 8-K.
On July 13, 1999, the Company filed a Current Report on Form 8-K to report the
disposition of assets under Items 2. and 7. of Form 8-K, related pro forma
condensed balance of the Company as of March 31, 1999 and related pro forma
condensed statements of operations of the Company for the three months ended
March 31, 1999 and the year ended December 31, 1998. See Note C of the Notes
to Consolidated Financial Statements included in "Item 1. Financial Statements"
for disclosures regarding the dispositions of assets.
<PAGE>
S I G N A T U R E S
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 thereto duly authorized.
PIONEER NATURAL RESOURCES COMPANY
Date: August 10, 1999 By: /s/ M. Garrett Smith
---------------------------------
M. Garrett Smith
Executive Vice President and Chief
Financial Officer
Date: August 10, 1999 By: /s/ Rich Dealy
----------------------------------
Rich Dealy
Vice President and Chief
Accounting Officer
<PAGE>
Exhibit Index Page
- ------------- ------
10.2 Purchase and Sale Agreement, dated May 16, 1999, by and between Pioneer
Natural Resources USA, Inc. and Pioneer Resources Producing, L.P. as
Seller and Prize Energy Corp. as Purchaser (incorporated by reference to
Exhibit 10.1 to the Company's Current Report on Form 8-K, filed with the
Securities and Exchange Commission on July 13, 1999).
27.1 Financial Data Schedule
<PAGE>
<TABLE> <S> <C>
<ARTICLE> 5
<CIK> 001038357
<NAME> Pioneer Natural Resources Company
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> 6-MOS
<FISCAL-YEAR-END> Dec-31-1999
<PERIOD-END> Jun-30-1999
<CASH> 79,269
<SECURITIES> 0
<RECEIVABLES> 111,223
<ALLOWANCES> 0
<INVENTORY> 13,929
<CURRENT-ASSETS> 219,179
<PP&E> 3,372,056
<DEPRECIATION> 765,283
<TOTAL-ASSETS> 3,083,108
<CURRENT-LIABILITIES> 261,269
<BONDS> 0
0
0
<COMMON> 1,008
<OTHER-SE> 716,880
<TOTAL-LIABILITY-AND-EQUITY> 3,083,108
<SALES> 321,382
<TOTAL-REVENUES> 327,935
<CGS> 222,425
<TOTAL-COSTS> 242,862
<OTHER-EXPENSES> 72,866
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 89,424
<INCOME-PRETAX> (77,217)
<INCOME-TAX> 100
<INCOME-CONTINUING> (77,117)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (77,117)
<EPS-BASIC> (.77)
<EPS-DILUTED> (.77)
</TABLE>
