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, 2022
                                 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, 2022 . . 100,300,023

                    PIONEER NATURAL RESOURCES COMPANY
                            TABLE OF CONTENTS
                                                                        Page
                                                                        ----
                     PART I.    FINANCIAL INFORMATION
Item 1.    Financial Statements
           Consolidated Balance Sheets as of June 30, 2022 and
             December 31, 2021 .........................................  3
           Consolidated Statements of Operations and Comprehensive
             Income (Loss) for the three and six months ended
             June 30, 2022 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, 2022 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

                      PART I.   FINANCIAL INFORMATION
Item 1.    Financial Statements
                     PIONEER NATURAL RESOURCES COMPANY
                        CONSOLIDATED BALANCE SHEETS
                     (in thousands, except share data)
                                                              
                                                        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
                                                       ==========   ===========
The financial information included as of June 30, 2022 has been prepared by management without audit by independent public accountants. The accompanying notes are an integral part of these consolidated financial statements. PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED BALANCE SHEETS (continued) (in thousands, except share data) 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, 2022 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 ========== ============
The financial information included as of June 30, 2022 has been prepared by management without audit by independent public accountants. The accompanying notes are an integral part of these consolidated financial statements. PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) (in thousands, except per share data) (Unaudited) 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 ========= ========= ========= =========
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. PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (in thousands) (Unaudited) 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, 2022 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, 2022 100,300 $ 1,008 $ 2,348,095 $(10,388) $(1,629,559) $ 8,732 $ 717,888 ========== ======= =========== ======== =========== ========== ===========
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. PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) (Unaudited) 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 ======== ========= ========= ========
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. PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (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, 2022 and for the three and six months ended June 30, 2022 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 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (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, 2022 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). PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (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, 2021), 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. PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (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, 2021 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, 2022 (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, 2021 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. PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (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. 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
________________ * 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: PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (Unaudited) 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
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. 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
PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (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: 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
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, 2022 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, 2022 include $.5 million and $41.8 million reductions for these non-cash components of earnings. PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (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, 2022 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, 2022 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, 2022 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, 2022 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. PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (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. 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) ========= ======== ======== ======= ========== ===========
PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (Unaudited) 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 ========== ======== ======== ======== ========== ===========
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. PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (Unaudited) CONSOLIDATING BALANCE SHEET As of June 30, 2022 (in thousands) (Unaudited) ASSETS 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 $3,083,108 =========== =========== =========== ==========
PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (Unaudited) CONSOLIDATING BALANCE SHEET As of December 31, 2021 (in thousands) ASSETS Pioneer Natural Resources Non- Company Pioneer Guarantor The (Parent) USA Subsidiaries Eliminations Company ---------- ---------- ------------ ------------ ------- Current assets: Cash and cash equivalents...........$ 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 ========== ========== ============ ===========
PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (Unaudited) CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) For the Six Months Ended June 30, 2022 (in thousands) (Unaudited) 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) ======== ======== ======== ========== =========
PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (Unaudited) CONSOLIDATING STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) For the Six Months Ended June 30, 2022 (in thousands) (Unaudited) 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) ======== ======== ======== ========== =========
PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (Unaudited) CONSOLIDATING STATEMENT OF CASH FLOWS For the Six Months Ended June 30, 2022 (in thousands) (Unaudited) 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 ========= ========= ========== ========= =========
PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2022 (Unaudited) CONSOLIDATING STATEMENT OF CASH FLOWS For the Six Months Ended June 30, 2022 (in thousands) (Unaudited) 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 ========= ========= ========== ========= =========
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). 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, 2022 were significantly impacted by divestment losses; while the Company's results for the three and six months ended June 30, 2022 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, 2022 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, 2022 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, 2022 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, 2022 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. 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. 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. 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, 2022 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. 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; 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. 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, 2022 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. Three months ended June 30, 2022 -------------------------------------- United States Canada Argentina Total ------ -------- ----------- ------- 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
Six months ended June 30, 2022 ------------------------------------------ United States Canada Argentina Total ------ ------ --------- ----- 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
Item 2. Management's Discussion and Analysis of Financial Condition and --------------------------------------------------------------- Results of Operations(1) (continued) --------------------- Three Months ended June 30, 2022 ------------------------------------------ United States Canada Argentina Total ------ ------ --------- ----- 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
Six Months ended June 30, 2022 ------------------------------------------ United States Canada Argentina Total ------ ------ --------- ----- 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
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. 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, 2022 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, 2022 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, 2022 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, 2022 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, 2022 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, 2022 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, 2022 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, 2022 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. 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, 2022 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. Three months Six months -------------- -------------- ended June 30, ended June 30, -------------- -------------- 1999 1998 1999 1998 ---- ---- ---- ---- 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 ======= ======= ======= =======
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, 2022 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. 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, 2022 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, 2022 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, 2022 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. 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, 2022 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, 2022 as compared to the six months ended June 30, 2022 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.) 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, 2022 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, 2022 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. 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, 2022 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. 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, 2022 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
__________ (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. 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, 2022 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
__________ (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. 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. 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, 2022 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, 2022). 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: For 86,717,709 Against 192,356 Abstain 167,464 Broker non-votes -
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: For 73,917,928 Against 12,801,406 Abstain 358,195 Broker non-votes -
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, 2022). 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, 2022 and related pro forma condensed statements of operations of the Company for the three months ended March 31, 2022 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. 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, 2022 By: /s/ M. Garrett Smith --------------------------------- M. Garrett Smith Executive Vice President and Chief Financial Officer Date: August 10, 2022 By: /s/ Rich Dealy ---------------------------------- Rich Dealy Vice President and Chief Accounting Officer 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, 2022). 27.1 Financial Data Schedule
 
5 001038357 Pioneer Natural Resources Company 1,000 6-MOS Dec-31-1999 Jun-30-1999 79,269 0 111,223 0 13,929 219,179 3,372,056 765,283 3,083,108 261,269 0 0 0 1,008 716,880 3,083,108 321,382 327,935 222,425 242,862 72,866 0 89,424 (77,217) 100 (77,117) 0 0 0 (77,117) (.77) (.77)

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