-----BEGIN PRIVACY-ENHANCED MESSAGE----- Proc-Type: 2001,MIC-CLEAR Originator-Name: webmaster@www.sec.gov Originator-Key-Asymmetric: MFgwCgYEVQgBAQICAf8DSgAwRwJAW2sNKK9AVtBzYZmr6aGjlWyK3XmZv3dTINen TWSM7vrzLADbmYQaionwg5sDW3P6oaM5D3tdezXMm7z1T+B+twIDAQAB MIC-Info: RSA-MD5,RSA, DMP7nKm1Ugy1jVYJ13oR+oSgMp/iKa5YNOD5nm4M+gLlzNs5WbFdoekLEQ6u5ope jKqnHxKu7bjh+0IDGfaUcw== 0001038357-01-500016.txt : 20010808 0001038357-01-500016.hdr.sgml : 20010808 ACCESSION NUMBER: 0001038357-01-500016 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 1 CONFORMED PERIOD OF REPORT: 20010630 FILED AS OF DATE: 20010807 FILER: COMPANY DATA: COMPANY CONFORMED NAME: PIONEER NATURAL RESOURCES CO CENTRAL INDEX KEY: 0001038357 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 752702753 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-13245 FILM NUMBER: 1699264 BUSINESS ADDRESS: STREET 1: 1400 WILLIAMS SQUARE WEST STREET 2: 5205 N OCONNOR BLVD CITY: IRVING STATE: TX ZIP: 75039 BUSINESS PHONE: 9724449001 MAIL ADDRESS: STREET 1: 1400 WILLIAMS SQUARE WEST STREET 2: 5205 N OCONNOR BLVD CITY: IRVING STATE: TX ZIP: 75039 10-Q 1 jun01pnra.txt PIONEER 6/30/2001 FORM 10-Q 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, 2001 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 charter) Delaware 75-2702753 ----------------------------------------- --------------------- (State or other jurisdiction of (I.R.S. Employer incorporation or organization) Identification Number) 5205 N. O'Connor Blvd., Suite 1400, 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 31, 2001..... 98,464,954 Definitions of Oil and Gas Terms and Conventions Used Herein Within this report, the following oil and gas terms and conventions have specific meanings: "Bbl" means a standard barrel containing 42 United States gallons; "BOE" means a barrel-of-oil equivalent and is a standard convention used to express oil and gas volumes on a comparable oil equivalent basis; "Btu" means British thermal unit and is an energy equivalent measure of natural gas; "MBbl" means one thousand Bbls; "MBOE" means one thousand BOE; "Mcf" means one thousand cubic feet and is a measure of natural gas volume; "MMcf" means one million cubic feet; "NGL" means natural gas liquid; "NYMEX" means The New York Mercantile Exchange; "proved reserves" means the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions, i.e., prices and costs as of the date the estimate is made. Prices include consideration of changes in existing prices provided only by contractual arrangements, but not on escalations based upon future conditions. (i) Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test. The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data. In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the power proved limit of the reservoir. (ii) Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the "proved" classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based. (iii) Estimates of proved reserves do not include the following: (A) oil that may become available from known reservoirs but is classified separately as "indicated additional reserves"; (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors; (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources. Gas equivalents are determined under the relative energy content method by using the ratio of 6.0 Mcf of gas to 1.0 Bbl of oil or NGL. Unless otherwise specified, wells, acreage and drilling locations quoted herein represent gross wells, acreage and drilling locations. All dollar amounts quoted herein are expressed in United States dollars. 2 PIONEER NATURAL RESOURCES COMPANY TABLE OF CONTENTS Page PART I. FINANCIAL INFORMATION Item 1. Financial Statements Consolidated Balance Sheets as of June 30, 2001 and December 31, 2000 ........................................ 4 Consolidated Statements of Operations for the three and six months ended June 30, 2001 and 2000............... 5 Consolidated Statement of Stockholders' Equity for the six months ended June 30, 2001........................ 6 Consolidated Statements of Cash Flows for the three and six months ended June 30, 2001 and 2000............... 7 Consolidated Statements of Comprehensive Income (Loss) for the three and six months ended June 30, 2001 and 2000..... 8 Notes to Consolidated Financial Statements................... 9 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations....................... 22 Item 3. Quantitative and Qualitative Disclosures About Market Risk... 34 PART II. OTHER INFORMATION Item 1. Legal Proceedings............................................ 36 Item 4. Submission of Matters to a Vote of Security Holders.......... 36 Item 6. Exhibits and Reports on Form 8-K............................. 36 Signatures................................................... 37 3 PART I. FINANCIAL INFORMATION Item 1. Financial Statements PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED BALANCE SHEETS (in thousands, except share data) June 30, December 31, 2001 2000 ----------- ----------- (Unaudited) ASSETS Current assets: Cash and cash equivalents......................... $ 18,227 $ 26,159 Accounts receivable: Trade, net..................................... 100,222 123,497 Affiliates..................................... 2,460 2,157 Inventories....................................... 15,068 14,842 Deferred income taxes............................. 5,600 4,800 Other current assets: Derivatives.................................... 51,304 11,391 Other.......................................... 8,338 8,545 ---------- ---------- Total current assets......................... 201,219 191,391 ---------- ---------- Property, plant and equipment, at cost: Oil and gas properties, using the successful efforts method of accounting: Proved properties.............................. 3,400,375 3,187,889 Unproved properties............................ 210,808 229,205 Accumulated depletion, depreciation and amortization..................................... (1,003,926) (902,139) ---------- ---------- 2,607,257 2,514,955 ---------- ---------- Deferred income taxes............................... 83,611 84,400 Other property and equipment, net................... 21,425 25,624 Other assets, net................................... 148,542 138,065 ---------- ---------- $ 3,062,054 $ 2,954,435 ========== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities: Accounts payable: Trade.......................................... $ 113,046 $ 96,646 Affiliates..................................... 3,200 5,629 Interest payable.................................. 39,056 38,142 Other current liabilities: Derivatives.................................... 43,020 24,957 Other.......................................... 48,362 51,140 ---------- ---------- Total current liabilities.................... 246,684 216,514 ---------- ---------- Long-term debt...................................... 1,572,227 1,578,776 Other noncurrent liabilities........................ 179,656 225,740 Deferred income taxes............................... 24,485 28,500 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; 101,716,750 and 101,268,754 shares issued as of June 30, 2001 and December 31, 2000, respectively....... 1,017 1,013 Additional paid-in capital........................ 2,357,778 2,352,608 Treasury stock, at cost; 3,251,796 and 2,853,107 shares as of June 30, 2001 and December 31, 2000, respectively................ (44,431) (37,682) Accumulated deficit............................... (1,326,497) (1,422,703) Accumulated other comprehensive income: Deferred hedge gains and losses................ 49,375 - Unrealized gain on available for sale securities................................... - 8,154 Cumulative translation adjustment.............. 1,760 3,515 ---------- ---------- Total stockholders' equity................... 1,039,002 904,905 Commitments and contingencies....................... ---------- ---------- $ 3,062,054 $ 2,954,435 ========== ==========
The financial information included as of June 30, 2001 has been prepared by management without audit by independent public accountants. The accompanying notes are an integral part of these consolidated financial statements. 4 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF OPERATIONS (in thousands, except per share data) (Unaudited) Three months ended Six months ended June 30, June 30, ---------------------- ---------------------- 2001 2000 2001 2000 --------- --------- --------- --------- Revenues: Oil and gas................................... $ 218,611 $ 197,947 $ 476,597 $ 372,322 Interest and other............................ 10,955 5,186 16,122 8,941 Gain (loss) on disposition of assets, net..... 1,472 (4,779) 8,765 3,593 -------- -------- -------- -------- 231,038 198,354 501,484 384,856 -------- -------- -------- -------- Costs and expenses: Oil and gas production........................ 51,974 43,140 107,776 86,262 Depletion, depreciation and amortization...... 57,396 53,549 109,557 105,457 Exploration and abandonments.................. 46,583 27,696 69,466 40,771 General and administrative.................... 8,005 6,963 18,453 16,722 Interest...................................... 34,260 41,863 69,876 81,618 Other......................................... 1,874 30,486 27,091 44,899 -------- -------- -------- -------- 200,092 203,697 402,219 375,729 -------- -------- -------- -------- Income (loss) before income taxes and extraordinary item............................ 30,946 (5,343) 99,265 9,127 Income tax (provision) benefit.................. (2,608) 1,600 (3,008) 1,900 -------- -------- -------- -------- Income (loss) before extraordinary item......... 28,338 (3,743) 96,257 11,027 Extraordinary item - loss on early extinguishment of debt, net of tax............ - (12,318) - (12,318) -------- -------- -------- -------- Net income (loss)............................... $ 28,338 $ (16,061) $ 96,257 $ (1,291) ======== ======== ======== ======== Net income (loss) per share: Basic: Income (loss) before extraordinary item.... $ .29 $ (.04) $ .98 $ .11 Extraordinary item......................... - (.12) - (.12) -------- -------- -------- -------- Net income (loss)........................ $ .29 $ (.16) $ .98 $ (.01) ======== ======== ======== ======== Diluted: Income (loss) before extraordinary item.... $ .28 $ (.04) $ .97 $ .11 Extraordinary item......................... - (.12) - (.12) -------- -------- -------- -------- Net income (loss)........................ $ .28 $ (.16) $ .97 $ (.01) ======== ======== ======== ======== Weighted average shares outstanding: Basic...................................... 98,337 99,683 98,358 99,923 ======== ======== ======== ======== Diluted.................................... 99,700 99,683 99,709 100,187 ======== ======== ======== ========
The financial information included herein has been prepared by management without audit by independent public accountants. The accompanying notes are an integral part of these consolidated financial statements. 5 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENT OF STOCKHOLDERS' EQUITY (in thousands) (Unaudited) Accumlated Other Comprehensive Income (Loss) Common ---------------------------------- Stock Additional Hedge Investment Total Shares Common Paid-in Treasury Accumulated Gains & Gains & Translation Stockholders' Outstanding Stock Capital Stock Deficit Losses Losses Adjustment Equity ----------- ------ ---------- -------- ----------- --------- ---------- ----------- ------------ Balance as of January 1, 2001...................... 98,416 $1,013 $2,352,608 $(37,682) $(1,422,703) $ - $ 8,154 $ 3,515 $ 904,905 Stock options exercised... 471 4 5,170 321 (51) - - - 5,444 Treasury stock purchases.. (422) - - (7,070) - - - - (7,070) Net income................ - - - - 96,257 - - - 96,257 Other comprehensive income (loss): Deferred hedge gains and losses: Transition adjustment. - - - - - (197,444) - - (197,444) Unrealized hedge gains................ - - - - - 194,964 - - 194,964 Net losses included in net income........ - - - - - 51,855 - - 51,855 Gains and losses on available for sale securities: Unrealized holding losses............... - - - - - - (45) - (45) Gains included in net income........... - - - - - - (8,109) - (8,109) Translation adjustment.. - - - - - - - (1,755) (1,755) ------- ----- --------- ------ ---------- -------- ------- ------- --------- Balance as of June 30, 2001...................... 98,465 $1,017 $2,357,778 $(44,431) $(1,326,497) $ 49,375 $ - $ 1,760 $1,039,002 ======= ===== ========= ======= ========== ======== ======= ======= =========
The financial information included herein has been prepared by management without audit by independent public accountants. The accompanying notes are an integral part of these consolidated financial statements. 6 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (in thousands) (Unaudited) Three months ended Six months ended June 30, June 30, ---------------------- ---------------------- 2001 2000 2001 2000 --------- --------- --------- --------- Cash flows from operating activities: Net income (loss)................................. $ 28,338 $ (16,061) $ 96,257 $ (1,291) Adjustments to reconcile net income (loss) to net cash provided by operating activities: Depletion, depreciation and amortization....... 57,396 53,549 109,557 105,457 Exploration expenses, including dry holes...... 40,985 20,320 62,832 30,052 Deferred income taxes.......................... 138 (2,400) (4,662) (3,900) (Gain) loss on disposition of assets, net...... (1,472) 4,779 (8,765) (3,593) Extraordinary item, net of tax................. - 12,318 - 12,318 Other noncash items............................ (4,442) 32,612 9,115 50,276 Changes in operating assets and liabilities: Accounts receivable............................ 1,605 19,857 28,054 907 Inventories.................................... (2,036) (2,130) (912) (2,320) Other current assets........................... 922 2,644 (5,032) 1,995 Accounts payable............................... 6,750 (697) (18,857) (14,460) Interest payable............................... 194 10,724 914 2,212 Other current liabilities...................... 6,953 (13,350) (1,436) (8,287) -------- -------- -------- -------- Net cash provided by operating activities.... 135,331 122,165 267,065 169,366 -------- -------- -------- -------- Cash flows from investing activities: Proceeds from disposition of assets............... 3,292 8,975 15,195 28,522 Additions to oil and gas properties............... (141,004) (52,221) (238,724) (112,255) Other property (additions) dispositions, net...... (977) 325 (3,961) 878 -------- -------- -------- -------- Net cash used in investing activities........ (138,689) (42,921) (227,490) (82,855) -------- -------- -------- -------- Cash flows from financing activities: Borrowings under long-term debt................... 49,000 845,836 109,175 876,675 Principal payments on long-term debt.............. (25,000) (896,970) (124,175) (928,677) Payment of noncurrent liabilities................. (24,089) (7,093) (30,739) (11,002) Exercise of long-term incentive plan stock options................................... 3,272 205 5,444 253 Purchase of treasury stock........................ - (2,195) (7,070) (6,307) Deferred loan fees/issuance costs................. - (13,807) - (13,878) -------- -------- -------- -------- Net cash provided by (used in) financing activities....................... 3,183 (74,024) (47,365) (82,936) -------- -------- -------- -------- Net increase (decrease) in cash and cash equivalents....................................... (175) 5,220 (7,790) 3,575 Effect of exchange rate changes on cash and cash equivalents.................................. 97 (87) (142) (94) Cash and cash equivalents, beginning of period...... 18,305 33,136 26,159 34,788 -------- -------- -------- -------- Cash and cash equivalents, end of period............ $ 18,227 $ 38,269 $ 18,227 $ 38,269 ======== ======== ======== ========
The financial information included herein has been prepared by management without audit by independent public accountants. The accompanying notes are an integral part of these consolidated financial statements. 7 PIONEER NATURAL RESOURCES COMPANY CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (in thousands) (Unaudited) Three months ended Six months ended June 30, June 30, ---------------------- ---------------------- 2001 2000 2001 2000 --------- --------- --------- --------- Net income (loss)..................................... $ 28,338 $ (16,061) $ 96,257 $ (1,291) -------- -------- -------- -------- Other comprehensive income (loss): Deferred hedge gains and losses: Transition adjustment............................ - - (197,444) - Unrealized hedge gains........................... 141,898 - 194,964 - Net losses included in net income................ 17,984 - 51,855 - Gains and losses on available for sale securities: Unrealized holding gains and losses.............. 13 11,465 (45) 43,207 Gains included in net income..................... (1,067) - (8,109) - Translation adjustment.............................. 7,592 (4,189) (1,755) (4,651) -------- -------- -------- -------- Other comprehensive income..................... 166,420 7,276 39,466 38,556 -------- -------- -------- -------- Comprehensive income (loss)........................... $ 194,758 $ (8,785) $ 135,723 $ 37,265 ======== ======== ======== ========
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 8 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (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 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, Gabon, South Africa and Tunisia. NOTE B. Basis of Presentation In the opinion of management, the unaudited consolidated financial statements of the Company as of June 30, 2001 and for the three and six month periods ended June 30, 2001 and 2000 include all adjustments and accruals, consisting only of normal, recurring accrual adjustments, which are necessary for a fair presentation of the results for the interim periods. These interim results are not necessarily indicative of results for a full year. Certain amounts in the prior period financial statements have been reclassified to conform to the current period presentation. Certain information and footnote disclosures normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted in this Form 10-Q pursuant to the rules and regulations of the Securities and Exchange Commission ("SEC"). These consolidated financial statements should be read in connection with the consolidated financial statements and notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 2000. NOTE C. Derivative Financial Instruments In June 1998, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 133, "Accounting for Derivative Instruments and Hedging Activities" ("SFAS 133") as amended, the provisions of which the Company adopted on January 1, 2001. SFAS 133 requires the accounting recognition of all derivative instruments as either assets or liabilities at fair value. Derivative instruments that are not hedges must be adjusted to fair value through net income (loss). Under the provisions of SFAS 133, changes in the fair value of derivative instruments that are fair value hedges are offset against changes in the fair value of the hedged assets, liabilities, or firm commitments, through net income (loss). Effective changes in the fair value of derivative instruments that are cash flow hedges are recognized in other comprehensive income (loss) until such time as the hedged items are recognized in net income (loss). Ineffective portions of a derivative instrument's change in fair value are immediately recognized in net income (loss). The adoption of SFAS 133 on January 1, 2001 resulted in a transition adjustment to (i) reclassify $57.8 million of deferred losses on terminated hedge positions from other assets (including $11.6 million of other current assets), (ii) increase other current assets, other assets and other current liabilities by $7.0 million, $6.2 million and $146.6 million, respectively, to record the fair value of open hedge derivatives, (iii) increase the carrying value of hedged long-term debt by $6.2 million and (iv) reduce stockholders' equity by $197.4 million for the net impact of items (i) through (iii) above. The $197.4 million reduction in stockholders' equity is reflected as a transition adjustment in other comprehensive income (loss) as of January 1, 2001. See "Accumulated other comprehensive income (loss) - deferred hedge gains and losses" below for additional information regarding the impact to stockholders' equity from the provisions of SFAS 133 during the six month period ending June 30, 2001. Under the provisions of SFAS 133, the Company may designate a derivative instrument as hedging the exposure to changes in the fair value of an asset or a liability or an identified portion thereof that is attributable to a particular 9 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) risk (a "fair value hedge") or as hedging the exposure to variability in expected future cash flows that are attributable to a particular risk (a "cash flow hedge"). Both at the inception of a hedge and on an ongoing basis, a fair value hedge must be expected to be highly effective in achieving offsetting changes in fair value attributable to the hedged risk during the periods that a hedge is designated. Similarly, a cash flow hedge must be expected to be highly effective in achieving offsetting cash flows attributable to the hedged risk during the term of the hedge. The Company's policy is to assess actual hedge effectiveness at the end of each calendar quarter. Fair value hedging strategy. The Company has entered into interest rate swap agreements to hedge the fair value of the Company's 8-7/8% Senior Notes due April 15, 2005 and 8-1/4% Senior Notes due August 15, 2007. The terms of the 8-7/8 percent interest rate swap agreements provide for an aggregate notional amount of $150 million of debt; commenced on April 19, 2000 and mature on April 15, 2005; require the counterparties to pay the Company a fixed annual rate of 8-7/8 percent on the notional amount; and, require the Company to pay the counterparties a variable annual rate on the notional amount equal to the periodic three month London Interbank Offered Rate ("LIBOR") plus a weighted average margin rate of 178.2 basis points. The terms of the Company's 8-1/4 percent interest rate swap agreements provide for an aggregate notional amount of $150 million of debt; commenced on May 29, 2001 and mature on August 15, 2007; require the counterparties to pay the Company a fixed annual rate of 8-1/4 percent on the notional amount; and, require the Company to pay the counterparties a variable rate on the notional amounts equal to LIBOR plus a weighted average margin rate of 238.1 basis points. The terms of the above described fair value hedges perfectly match the terms of the underlying hedged fixed rate debt. The Company does not exclude any component of the derivatives' gains or losses from the measurement of hedge effectiveness. During the six month period ended June 30, 2001, the fair value of the interest rate swap agreements increased from $6.2 million to $7.3 million. The following table summarizes the fair values of the above described interest rate swap agreements and the change in the fair value of the underlying long-term debt as of and for the period ending June 30, 2001: Other Other Noncurrent Long-term Assets, Net Liabilities Debt ----------- ----------- --------- Increase (decrease) in millions: 8-7/8% interest rate swaps........ $ 8.4 $ - $ 8.4 8-1/4% interest rate swaps........ - 1.1 (1.1) ----- ----- ----- $ 8.4 $ 1.1 $ 7.3 ====== ====== ======
Cash flow hedging strategy. The Company utilizes commodity swap and collar contracts to (i) reduce the effect of price volatility on the commodities the Company produces and sells, (ii) support the Company's annual capital budgeting and expenditure plans and (iii) reduce commodity price risk associated with certain capital projects. The Company also utilizes interest rate swap agreements to reduce the effect of interest rate volatility on the Company's variable-rate line of credit indebtedness. 10 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) Oil prices. All material sales contracts governing the Company's oil production have been tied directly or indirectly to the New York Mercantile Exchange ("NYMEX") prices. The following table sets forth the Company's outstanding oil hedge contracts and the weighted average NYMEX prices for those contracts as of June 30, 2001: Yearly First Second Third Fourth Outstanding Quarter Quarter Quarter Quarter Average ------------- ------------- ------------- ------------- ------------- Daily oil production: 2001 - Swap Contracts Volume (Bbls).......... 25,033 16,641 20,837 Price per Bbl.......... $ 28.75 $ 28.37 $ 28.60 2001 - Collar Contracts Volume (Bbls).......... 2,000 2,000 2,000 Prices per Bbl......... $25.00-$31.43 $25.00-$31.43 $25.00-$31.43 2002 - Swap Contracts Volume (Bbls).......... 10,000 - - - 2,466 Price per Bbl.......... $ 27.20 $ 27.20 2002 - Collar Contracts Volume (Bbls).......... 10,000 10,000 - - 4,959 Prices per Bbl......... $25.00-$28.56 $25.00-$28.56 $25.00-$28.56 2003 - Swap Contracts Volume (Bbls).......... 6,000 6,000 - - 2,975 Price per Bbl.......... $ 24.02 $ 24.02 $ 24.02
The Company reports average oil prices per Bbl including the effects of oil quality, gathering and transportation costs and the net effect of oil hedges. The following table sets forth the Company's oil prices, both reported and realized (excluding hedge results), and the net effects of settlements of oil price hedges to revenue: Three months ended Six months ended June 30, June 30, ------------------ ------------------ 2001 2000 2001 2000 ------- ------- ------- ------- Average price reported per Bbl......... $ 24.74 $ 22.59 $ 24.89 $ 22.51 Average price realized per Bbl......... $ 25.64 $ 27.28 $ 26.17 $ 27.52 Reduction to revenue (in millions)..... $ (2.8) $ (14.3) $ (8.1) $ (31.0)
Natural gas liquids prices. During the three and six month periods ended June 30, 2001 and 2000, the Company did not enter, nor was it a party to, any NGL hedge contracts. 11 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) Gas prices. The Company employs a policy of hedging a portion of its gas production based on the index price upon which the gas is actually sold in order to mitigate the basis risk between NYMEX prices and actual index prices. The following table sets forth the Company's outstanding gas hedge contracts and the weighted average index price for those contracts as of June 30, 2001: Yearly First Second Third Fourth Outstanding Quarter Quarter Quarter Quarter Average ----------- ----------- ----------- ----------- ----------- Daily gas production: 2001 - Swap Contracts Volume (Mcf)............. 119,169 120,908 120,038 Index price per MMBtu.... $ 4.29 $ 4.31 $ 4.30 2001 - Collar Contracts Volume (Mcf)............. 54,482 54,482 54,482 Index prices per MMBtu... $2.11-$2.74 $2.11-$2.74 $2.11-$2.74 2002 - Swap Contracts Volume (Mcf)............. 80,000 80,000 80,000 80,000 80,000 Index price per MMBtu.... $ 4.71 $ 4.71 $ 4.71 $ 4.71 $ 4.71 2002 - Collar Contracts Volume (Mcf)............. 20,000 20,000 20,000 20,000 20,000 Index prices per MMBtu... $4.50-$6.00 $4.50-$6.00 $4.50-$6.00 $4.50-$6.00 $4.50-$6.00 2003 - Swap Contracts Volume (Mcf)............. 100,000 100,000 100,000 100,000 100,000 Index price per MMBtu.... $ 4.13 $ 4.13 $ 4.13 $ 4.13 $ 4.13 2004 - Swap Contracts Volume (Mcf)............. 100,000 100,000 100,000 100,000 100,000 Index price per MMBtu.... $ 4.13 $ 4.13 $ 4.13 $ 4.13 $ 4.13
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 gas hedges. The following table sets forth the Company's gas prices, both reported and realized (excluding hedge results), and the net effects of settlements of gas price hedges to revenue: Three months ended Six months ended June 30, June 30, ------------------ ------------------ 2001 2000 2001 2000 ------- ------- ------- ------- Average price reported per Mcf........ $ 3.10 $ 2.60 $ 3.80 $ 2.29 Average price realized per Mcf........ $ 3.57 $ 2.73 $ 4.33 $ 2.37 Reduction to revenue (in millions).... $ (15.5) $ (4.7) $ (33.2) $ (5.5)
Interest rates. During the three months ended June 30, 2001, the Company entered into interest rate swap agreements and designated the swap agreements as being cash flow hedges of the interest rate volatility associated with certain of the Company's variable-rate line of credit indebtedness. The terms of the interest rate swap agreements provide for an aggregate notional amount of $55 million of debt; commenced on May 21, 2001 and mature on May 20, 2002; require the counterparties to pay the Company a variable rate equal to the six month LIBOR plus 125 basis points; and, require the Company to pay the counterparties a weighted average rate of 5.43 percent on the notional amount. The fair value of these interest rate swap agreements represented a liability of $59 thousand as of June 30, 2001. 12 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) Hedge ineffectiveness and excluded items. During the three months ended June 30, 2001, the Company recognized a net decrease to other expense of $1.9 million related to the ineffective portion of its cash flow hedging instruments. During the six months ended June 30, 2001, the Company recognized a $9.1 million increase to other expense as a result of hedge ineffectiveness. Prior to April 2001, the Company excluded changes in the time and volatility value components of collar contracts that are designated as cash flow hedges from the measurement of hedge effectiveness. Associated therewith, the Company recorded a net increase to other expense of $2.4 million during the six month period ended June 30, 2001. In April 2001, the Company discontinued the exclusion of time value and volatility from the measurement of hedge effectiveness. Accumulated other comprehensive income (loss) - deferred hedge gains and losses. As described above, the Company recorded a transition adjustment associated with the January 1, 2001 adoption of the provisions of SFAS 133 which reduced stockholders' equity by $197.4 million. The adjustment to stockholders' equity was comprised of the fair value of the Company's derivative instruments that were designated as commodity cash flow hedges, whose fair value amounted to a liability of $139.6 million as of January 1, 2001, and deferred losses realized from the early termination of cash flow hedges of $57.8 million. These adjustments to stockholders' equity were classified as Accumulated other comprehensive income (loss) ("AOCI") - deferred hedge gains and losses at transition. As of June 30, 2001, AOCI - deferred hedge gains and losses is $49.4 million, an increase of $246.8 million in stockholders' equity since the initial transition adjustment. The AOCI - deferred hedge gains and losses balance as of June 30, 2001 is comprised of $103.9 million of unrealized deferred hedge gains on the effective portions of commodity and interest rate cash flow hedges that will mature in the future and $54.5 million of deferred losses from the early termination of cash flow hedges. The increase in AOCI - deferred hedge gains and losses since January 1, 2001 is primarily attributable to decreases in commodity prices during the period which has resulted in an increase in the fair value of the Company's commodity derivative portfolio. During the twelve month period ending June 30, 2002, the Company expects to reclassify $43.3 million of deferred gains associated with cash flow hedges that will mature during future periods and $31.2 million of deferred losses for terminated cash flow hedges from AOCI - deferred hedge gains and losses to oil and gas revenue. Non-hedge commodity derivatives. The Company is a party to certain BTU swap agreements that mature at the end of 2004. The BTU swap agreements were originally transacted by Mesa Inc. ("Mesa"), prior to the Company's acquisition of Mesa. Mesa's strategy for entering into the BTU swap agreements was to shift a portion of their gas price risk to oil prices. As a result of the merger of Parker & Parsley Petroleum Company and Mesa Inc., the Company became obligated under the BTU swap agreements during 1997. The BTU swap agreements do not qualify as hedges. Other revenues in the accompanying Consolidated Statements of Operations for the three and six month periods ended June 30, 2001 include mark-to-market decreases to the liability recognized for the BTU swap agreements of $7.3 million. Other expenses in the accompanying Consolidated Statements of Operations for the six month period ended June 30, 2001 includes a mark-to-market increase to the liabilities recognized for the BTU swap agreements of $6.6 million. During the three and six month periods ended June 30, 2000, the Company recorded mark-to-market increases to the liabilities recognized for the BTU swap agreements of $3.4 million and $2.7 million, respectively. As of June 30, 2001 and December 31, 2000, the Company's BTU swap liabilities totaled $22.3 million and $25.5 million, respectively, of which $5.3 million and $6.4 million, respectively, represent current liabilities. During the six month period ending June 30, 2001, the Company entered into offsetting BTU swap agreements that have fixed the Company's remaining obligation associated with the BTU swap agreements. The undiscounted future settlement obligations of the Company under the BTU swap agreements are $3.6 million during the six months ending December 31, 2001 and $7.2 million per year for each of 2002, 2003 and 2004. 13 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) During 2000, the Company was a party to options that provided the counterparties the right to exercise call provisions on 10,000 barrels per day of oil, at a strike price of $20.00 per barrel, 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 $2.75 per MMBtu. These contracts, which matured on December 31, 2000, did not qualify for hedge accounting treatment. The Company's strategy for entering into these call options was to earn associated call premiums that were used to purchase other in-the- money commodity derivatives that qualified for hedge accounting treatment. For the three and six month periods ended June 30, 2000, other expenses include mark-to-market increases to the liabilities recognized on these contracts of $23.9 million and $38.0 million, respectively. Non-hedge foreign currency agreements. The Company was a party to a series of forward foreign exchange rate swap agreements that exchanged Canadian dollars for United States dollars. These agreements matured during the fourth quarter of 2000. The foreign exchange rate swap agreements were originally transacted by Chauvco Resources Ltd. ("Chauvco"), prior to the Company's acquisition of Chauvco. Chauvco entered into the agreements to hedge a portion of their foreign exchange rate exposure. The Company became obligated under the foreign exchange rate swap agreements upon the acquisition of Chauvco during 1997. The foreign exchange rate swap agreements did not qualify for hedge accounting treatment during 2000. The Company recorded mark-to-market adjustments to increase the associated contract liabilities by $1.1 million and $1.3 million during the three and six month periods ended June 30, 2000, respectively. NOTE D. Investment Securities As of December 31, 2000, the Company owned 613,215 shares of Prize Energy Corp. ("Prize") common stock. The Company classified its investment in the Prize common stock as available for sale securities and carried the investment at its market-quoted fair value in other assets in the accompanying Consolidated Balance Sheets. As of December 31, 2000, the fair value of the Company's investment in Prize common stock was $12.7 million. Associated therewith, the Company had recorded unrealized gains on available for sale securities of $8.2 million within AOCI in stockholders' equity in the accompanying December 31, 2000 Consolidated Balance Sheet. During the three and six month periods ended June 30, 2001, the Company divested its remaining holdings in Prize common stock and realized associated gains of $1.1 million and $8.1 million, respectively. Additionally, during the three and six month periods ended June 30, 2001, the Company recognized, in other comprehensive income (loss) in the accompanying Consolidated Statements of Comprehensive Income (Loss), an unrealized gain of $13 thousand and an unrealized loss of $45 thousand, respectively, from changes in the fair value of investments in Prize common stock. During the three and six month periods ended June 30, 2000, the Company recognized unrealized gains of $11.5 million and $43.2 million, respectively, on the Prize common stock. 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 proceeding described below. The majority of these lawsuits primarily involve claims for damages arising from oil and gas leases and ownership interest disputes. The Company believes that the ultimate disposition of these legal actions will not have a material adverse effect on the Company's consolidated financial position, liquidity, capital resources or future results of operations. The Company will continue to evaluate its litigation matters on a quarter-by- quarter basis and will adjust its litigation reserves as appropriate to reflect the then current status of litigation. 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 14 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) Regulatory Commission ("FERC") ruling that Kansas ad valorem tax was such a tax, Mesa collected the Kansas ad valorem tax in addition to the otherwise maximum lawful price. The FERC's ruling was appealed to the United States Court of Appeals for the District of Columbia ("D.C. Circuit"), which held in June 1988 that the FERC failed to provide a reasoned basis for its findings and remanded the case to the FERC for further consideration. On December 1, 1993, the FERC issued an order reversing its prior ruling, but limiting the effect of its decision to Kansas ad valorem taxes for sales made on or after June 28, 1988. The FERC clarified the effective date of its decision by an order dated May 18, 1994. The order clarified that the effective date applies to tax bills rendered after June 28, 1988, not sales made on or after that date. Numerous parties filed appeals on the FERC's action in the D.C. Circuit. Various natural gas producers challenged the FERC's orders on two grounds: (1) that the Kansas ad valorem tax, properly understood, does qualify for reimbursement under the NGPA; and (2) the FERC's ruling should, in any event, have been applied prospectively. Other parties challenged the FERC's orders on the grounds that the FERC's ruling should have been applied retroactively to December 1, 1978, the date of the enactment of the NGPA and producers should have been required to pay refunds accordingly. The D.C. Circuit issued its decision on August 2, 1996, which holds that producers must make refunds of all Kansas ad valorem tax collected with respect to production since October 4, 1983, as opposed to June 28, 1988. Petitions for rehearing were denied on November 6, 1996. Various natural gas producers subsequently filed a petition for writ of certiori with the United States Supreme Court seeking to limit the scope of the potential refunds to tax bills rendered on or after June 28, 1988 (the effective date originally selected by the FERC). Williams Natural Gas Company filed a cross-petition for certiori seeking to impose refund liability back to December 1, 1978. Both petitions were denied on May 12, 1997. The Company and other producers filed petitions for adjustment with the FERC on June 24, 1997. The Company was seeking waiver or set-off from FERC with respect to that portion of the refund associated with (i) non- recoupable royalties, (ii) non-recoupable Kansas property taxes based, in part, upon the higher prices collected, and (iii) interest for all periods. On September 10, 1997, FERC denied this request, and on October 10, 1997, the Company and other producers filed a request for rehearing. Pipelines were given until November 10, 1997 to file claims on refunds sought from producers and refunds totaling approximately $30 million were made against the Company. During the year ended December 31, 2000, the Company paid $3.9 million in partial settlement of original claims presented under this litigation. 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, 2001 and December 31, 2000, the Company had on deposit $28.5 million and $28.1 million, respectively, including accrued interest, in an escrow account and had corresponding obligations for this litigation recorded in other current liabilities in the accompanying Consolidated Balance Sheets. NOTE F. Extraordinary Item On May 31, 2000, the Company entered into a $575.0 million credit agreement (the "Credit Agreement") that matures on March 1, 2005. The Credit Agreement replaced the Company's prior revolving credit facility that had a maturity date of August 7, 2002 (the "Prior Credit Facility"). As a result of the early extinguishment of the Prior Credit Facility, the Company recognized an extraordinary loss of $12.3 million for the three and six month periods ended June 30, 2000. 15 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) NOTE G. Income (Loss) Per Share Before Extraordinary Item Following is a reconciliation of the basic and diluted income (loss) per share before extraordinary item computation for the three and six month periods ended June 30, 2001: Income (Loss) Income (Loss) Before Weighted Average Per Share Before Extraordinary Common Shares Extraordinary Item Outstanding Item ------------- ---------------- ---------------- (in thousands, except per share amounts) Three Months Ended June 30, 2001: Basic.............................. $ 28,338 98,337 $ .29 Effect of dilutive securities: Common stock options*............ - 1,363 -------- --------- Diluted............................ $ 28,338 99,700 $ .28 ======== ========= Three Months Ended June 30, 2000: Basic.............................. $ (3,743) 99,683 $ (.04) Effect of dilutive securities: Common stock options*............ - - -------- --------- Diluted............................ $ (3,743) 99,683 $ (.04) ======== ========= Six Months Ended June 30, 2001: Basic.............................. $ 96,257 98,358 $ .98 Effect of dilutive securities: Common stock options*............ - 1,351 -------- --------- Diluted............................ $ 96,257 99,709 $ .97 ======== ========= Six Months Ended June 30, 2000: Basic.............................. $ 11,027 99,923 $ .11 Effect of dilutive securities: Common stock options*............ - 264 -------- --------- Diluted............................ $ 11,027 100,187 $ .11 ======== =========
- --------------- * Common stock options to purchase 3,189,653 and 4,725,694 shares of common stock were outstanding but not included in the computations of diluted income (loss) per share for the three month periods ended June 30, 2001 and 2000, respectively, and common stock options to purchase 2,946,318 shares and 4,829,037 shares of common stock were outstanding but not included in the computations of diluted income (loss) per share for the six month periods ended June 30, 2001 and 2000 respectively, because the exercise prices of the options were greater than the average market price of the common shares and would be anti- dilutive to the computations. In-the-money options representing 409,658 weighted average equivalent shares of common stock were not included in the computation of diluted loss per share for the three months ended June 30, 2000, since they have a dilutive effect to the loss recognized for that period. NOTE H. 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. 16 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) The following tables provide the Company's interim geographic operating segment data. 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, 2001: Oil and gas revenue............... $ 163,779 $ 35,918 $ 18,914 $ - $ - $ 218,611 Interest and other................ - - - - 10,955 10,955 Gain on disposition of assets..... 146 - 38 - 1,288 1,472 -------- ------- ------- -------- ------- --------- 163,925 35,918 18,952 - 12,243 231,038 -------- ------- ------- -------- ------- --------- Production costs.................. 42,412 6,062 3,500 - - 51,974 Depletion, depreciation and amortization................... 31,985 14,242 7,798 - 3,371 57,396 Exploration and abandonments...... 29,060 3,873 868 12,782 - 46,583 General and administrative........ - - - - 8,005 8,005 Interest.......................... - - - - 34,260 34,260 Other ............................ - - - - 1,874 1,874 -------- ------- ------- -------- ------- --------- 103,457 24,177 12,166 12,782 47,510 200,092 -------- ------- ------- -------- ------- --------- Income (loss) before income taxes. 60,468 11,741 6,786 (12,782) (35,267) 30,946 Income tax benefit (provision).... (21,164) (4,109) (3,027) 4,474 21,218 (2,608) -------- ------- ------- -------- ------- --------- Net income (loss)................. $ 39,304 $ 7,632 $ 3,759 $ (8,308) $(14,049) $ 28,338 ======== ======= ======= ======== ======= ========= Three months ended June 30, 2000: Oil and gas revenue............... $ 149,894 $ 33,357 $ 14,696 $ - $ - $ 197,947 Interest and other................ - - - - 5,186 5,186 Gain (loss) on disposition of assets....................... 33 - 245 - (5,057) (4,779) -------- ------- ------- -------- ------- --------- 149,927 33,357 14,941 - 129 198,354 -------- ------- ------- -------- ------- --------- Production costs.................. 36,222 5,596 1,322 - - 43,140 Depletion, depreciation and amortization................... 29,811 13,112 6,790 - 3,836 53,549 Exploration and abandonments...... 11,346 11,847 2,306 2,197 - 27,696 General and administrative........ - - - - 6,963 6,963 Interest.......................... - - - - 41,863 41,863 Other ............................ - - - - 30,486 30,486 -------- ------- ------- -------- ------- --------- 77,379 30,555 10,418 2,197 83,148 203,697 -------- ------- ------- -------- ------- --------- Income (loss) before income taxes and extraordinary item......... 72,548 2,802 4,523 (2,197) (83,019) (5,343) Income tax benefit (provision).... (25,392) (981) (2,017) 769 29,221 1,600 -------- ------- ------- -------- ------- --------- Income (loss) before extraordinary item.............. $ 47,156 $ 1,821 $ 2,506 $ (1,428) $(53,798) $ (3,743) ======== ======= ======= ======== ======= =========
17 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) United Other Headquarters Consolidated States Argentina Canada Foreign and Other Total --------- ---------- -------- --------- ------------ ------------ (in thousands) Six months ended June 30, 2001: Oil and gas revenue............... $ 363,200 $ 67,520 $ 45,877 $ - $ - $ 476,597 Interest and other................ - - - - 16,122 16,122 Gain on disposition of assets..... 216 - 38 - 8,511 8,765 -------- ------- ------- ------- -------- -------- 363,416 67,520 45,915 - 24,633 501,484 -------- ------- ------- ------- -------- -------- Production costs.................. 88,680 12,617 6,479 - - 107,776 Depletion, depreciation and amortization................... 61,213 26,377 14,480 - 7,487 109,557 Exploration and abandonments...... 34,275 10,483 7,481 17,227 - 69,466 General and administrative........ - - - - 18,453 18,453 Interest.......................... - - - - 69,876 69,876 Other ............................ - - - - 27,091 27,091 -------- ------- ------- ------- -------- -------- 184,168 49,477 28,440 17,227 122,907 402,219 -------- ------- ------- ------- -------- -------- Income (loss) before income taxes. 179,248 18,043 17,475 (17,227) (98,274) 99,265 Income tax benefit (provision).... (62,737) (6,315) (7,794) 6,029 67,809 (3,008) -------- ------- ------- ------- -------- -------- Net income (loss)................. $ 116,511 $ 11,728 $ 9,681 $(11,198) $ (30,465) $ 96,257 ======== ======= ======= ======= ======== ======== Six months ended June 30, 2000: Oil and gas revenue............... $ 282,336 $ 64,475 $ 25,511 $ - $ - $ 372,322 Interest and other................ - - - - 8,941 8,941 Gain on disposition of assets..... 23 - 252 - 3,318 3,593 -------- ------- ------- ------- -------- -------- 282,359 64,475 25,763 - 12,259 384,856 -------- ------- ------- ------- -------- -------- Production costs.................. 70,634 10,996 4,632 - - 86,262 Depletion, depreciation and amortization................... 60,800 24,292 12,519 - 7,846 105,457 Exploration and abandonments...... 16,296 18,017 2,753 3,705 - 40,771 General and administrative........ - - - - 16,722 16,722 Interest.......................... - - - - 81,618 81,618 Other ............................ - - - - 44,899 44,899 -------- ------- ------- ------- -------- -------- 147,730 53,305 19,904 3,705 151,085 375,729 -------- ------- ------- ------- -------- -------- Income (loss) before income taxes and extraordinary item......... 134,629 11,170 5,859 (3,705) (138,826) 9,127 Income tax benefit (provision).... (47,120) (3,910) (2,613) 1,297 54,246 1,900 -------- ------- ------- ------- -------- -------- Income (loss) before extraordinary item............. $ 87,509 $ 7,260 $ 3,246 $ (2,408) $ (84,580) $ 11,027 ======== ======= ======= ======= ======== ========
NOTE I. Pioneer USA Pioneer Natural Resources USA, Inc. ("Pioneer USA") is a wholly-owned subsidiary of the Company that has fully and unconditionally guaranteed certain debt securities of the Company. In accordance with practices accepted by the SEC, the Company has prepared Consolidating Financial Statements in order to quantify the assets of Pioneer USA as a subsidiary guarantor. The following Consolidating Condensed Balance Sheets, Consolidating Condensed Statements of Operations and Comprehensive Income (Loss) and Consolidating Condensed 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. 18 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) CONSOLIDATING CONDENSED BALANCE SHEET As of June 30, 2001 (in thousands) (Unaudited) ASSETS Non- Pioneer Guarantor The Parent USA Subsidiaries Eliminations Company ---------- ----------- ------------ ------------ ----------- Current assets: Cash and cash equivalents............... $ 51 $ 10,749 $ 7,427 $ $ 18,227 Other current assets.................... 1,961,651 (1,178,670) (599,989) 182,992 --------- ---------- -------- ---------- Total current assets............... 1,961,702 (1,167,921) (592,562) 201,219 --------- ---------- -------- ---------- Property, plant and equipment, at cost: Oil and gas properties, using the successful efforts method of accounting: Proved properties.................... - 2,449,647 950,728 3,400,375 Unproved properties.................. - 22,984 187,824 210,808 Accumulated depletion, depreciation and amortization...................... - (757,010) (246,916) (1,003,926) --------- ---------- -------- ---------- - 1,715,621 891,636 2,607,257 --------- ---------- -------- ---------- Deferred income taxes..................... 83,611 - - 83,611 Other property and equipment, net......... - 17,054 4,371 21,425 Other assets, net......................... 26,121 87,583 34,838 148,542 Investment in subsidiaries................ 481,711 94,810 - (576,521) - --------- ---------- -------- ---------- $2,553,145 $ 747,147 $ 338,283 $ 3,062,054 ========= ========== ======== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities....................... $ 38,266 $ 181,271 $ 27,147 $ $ 246,684 Long-term debt............................ 1,572,227 - - 1,572,227 Other noncurrent liabilities.............. 1,141 144,791 33,724 179,656 Deferred income taxes..................... - - 24,485 24,485 Stockholders' equity...................... 941,511 421,085 252,927 (576,521) 1,039,002 Commitments and contingencies............. --------- ---------- -------- ---------- $2,553,145 $ 747,147 $ 338,283 $ 3,062,054 ========= ========== ======== ==========
CONSOLIDATING CONDENSED BALANCE SHEET As of December 31, 2000 (in thousands) ASSETS Non- Pioneer Guarantor The Parent USA Subsidiaries Eliminations Company ---------- ----------- ------------ ------------ ----------- Current assets: Cash and cash equivalents............... $ 15 $ 18,387 $ 7,757 $ $ 26,159 Other current assets.................... 2,006,496 (1,245,546) (595,718) 165,232 --------- ---------- -------- ---------- Total current assets............... 2,006,511 (1,227,159) (587,961) 191,391 --------- ---------- -------- ---------- Property, plant and equipment, at cost: Oil and gas properties, using the successful efforts method of accounting: Proved properties.................... - 2,291,872 896,017 3,187,889 Unproved properties.................. - 28,103 201,102 229,205 Accumulated depletion, depreciation and amortization...................... - (692,250) (209,889) (902,139) --------- ---------- -------- ---------- - 1,627,725 887,230 2,514,955 --------- ---------- -------- ---------- Deferred income taxes..................... 84,400 - - 84,400 Other property and equipment, net......... - 20,823 4,801 25,624 Other assets, net......................... 18,877 89,632 29,556 138,065 Investment in subsidiaries................ 347,370 100,192 - (447,562) - --------- ---------- -------- ---------- $2,457,158 $ 611,213 $ 333,626 $ 2,954,435 ========= ========== ======== ========== LIABILITIES AND STOCKHOLDERS' EQUITY Current liabilities....................... $ 37,889 $ 140,415 $ 38,210 $ $ 216,514 Long-term debt, less current maturities... 1,578,776 - - 1,578,776 Other noncurrent liabilities.............. - 190,476 35,264 225,740 Deferred income taxes..................... - - 28,500 28,500 Stockholders' equity...................... 840,493 280,322 231,652 (447,562) 904,905 Commitments and contingencies............ --------- ---------- -------- ---------- $2,457,158 $ 611,213 $ 333,626 $ 2,954,435 ========= ========== ======== ==========
19 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS AND COMPREHENSIVE INCOME (LOSS) For the Six Months Ended June 30, 2001 (in thousands) (Unaudited) Non- Consolidated Pioneer Guarantor Income The Parent USA Subsidiaries Tax Benefit Eliminations Company --------- --------- ------------ ------------ ------------ --------- Revenues: Oil and gas..................... $ - $ 351,037 $ 125,560 $ - $ $ 476,597 Interest and other.............. - 12,960 3,162 - 16,122 Gain on disposition of assets, net................... - 8,719 46 - 8,765 -------- -------- -------- ------ -------- - 372,716 128,768 - 501,484 -------- -------- -------- ------ -------- Costs and expenses: Oil and gas production.......... - 87,876 19,900 - 107,776 Depletion, depreciation and amortization.................. - 65,283 44,274 - 109,557 Exploration and abandonments.... - 35,189 34,277 - 69,466 General and administrative...... 417 12,537 5,499 - 18,453 Interest........................ (15,668) 59,298 26,246 - 69,876 Equity income from subsidiaries. (81,018) 8,375 - - 72,643 - Other........................... - 7,203 19,888 - 27,091 -------- -------- -------- ------ -------- (96,269) 275,761 150,084 - 402,219 -------- -------- -------- ------ -------- Income (loss) before income taxes.. 96,269 96,955 (21,316) - 99,265 Income tax provision............... - (783) (2,212) (13) (3,008) -------- -------- -------- ------ -------- Net income (loss).................. 96,269 96,172 (23,528) (13) 96,257 Other comprehensive income (loss): Deferred hedge gains and losses: Transition adjustment......... - (172,007) (25,437) - (197,444) Unrealized hedge gains (losses)..................... (59) 186,271 8,752 - 194,964 Net losses included in net income................... - 35,441 16,414 - 51,855 Gains and losses on available for sale securities: Unrealized holding gains and losses................... - (45) - - (45) Gains included in net income.. - (8,109) - - (8,109) Cumulative translation adjustment..................... - - (1,755) - (1,755) -------- -------- -------- ------ -------- Comprehensive income (loss)........ $ 96,210 $ 137,723 $ (25,554) $ (13) $ 135,723 ======== ======== ======== ====== ========
CONSOLIDATING CONDENSED STATEMENT OF OPERATIONS AND COMPREHENSIVE LOSS For the Six Months Ended June 30, 2000 (in thousands) (Unaudited) Non- Consolidated Pioneer Guarantor Income The Parent USA Subsidiaries Tax Benefit Eliminations Company --------- --------- ------------ ------------ ------------ --------- Revenues: Oil and gas..................... $ - $ 269,500 $ 102,822 $ - $ $ 372,322 Interest and other.............. 18 4,882 4,041 - 8,941 Gain (loss) on disposition of assets, net................... - 7,341 (3,748) - 3,593 -------- -------- -------- ------ --------- 18 281,723 103,115 - 384,856 -------- -------- -------- ------ --------- Costs and expenses: Oil and gas production.......... - 69,275 16,987 - 86,262 Depletion, depreciation and amortization.................. - 64,751 40,706 - 105,457 Exploration and abandonments.... - 18,360 22,411 - 40,771 General and administrative...... 22 11,936 4,764 - 16,722 Interest........................ (24,002) 74,288 31,332 - 81,618 Equity income from subsidiaries. 13,016 (433) - - (12,583) - Other........................... - 43,174 1,725 - 44,899 -------- -------- -------- ------ --------- (10,964) 281,351 117,925 - 375,729 -------- -------- -------- ------ --------- Income (loss) before income taxes and extraordinary item........... 10,982 372 (14,810) - 9,127 Income tax benefit................. - - 1,855 45 1,900 -------- -------- -------- ------ --------- Income (loss) before extraordinary item............... 10,982 372 (12,955) 45 11,027 Extraordinary item - loss on early extinguishment of debt, net of tax....................... (12,318) - - - (12,318) -------- -------- -------- ------ --------- Net income (loss).................. (1,336) 372 (12,955) 45 (1,291) Other comprehensive income (loss): Unrealized gain on available for sale securities........... - 43,207 - - 43,207 Translation adjustment.......... - - (4,651) - (4,651) -------- -------- -------- ------ --------- Comprehensive income (loss)........ $ (1,336) $ 43,579 $ (17,606) $ 45 $ 37,265 ======== ======== ======== ====== =========
20 PIONEER NATURAL RESOURCES COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS June 30, 2001 (Unaudited) CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS For the Six Months Ended June 30, 2001 (in thousands) (Unaudited) Non- Pioneer Guarantor The Parent USA Subsidiaries Company ---------- --------- ------------ --------- Cash flows from operating activities: Net cash provided by operating activities........ $ 16,662 $ 159,009 $ 91,394 $ 267,065 --------- -------- ------- -------- Cash flows from investing activities: Proceeds from disposition of assets.............. - 14,859 336 15,195 Additions to oil and gas properties.............. - (146,033) (92,691) (238,724) Other property additions, net.................... - (3,872) (89) (3,961) --------- -------- ------- -------- Net cash used in investing activities.......... - (135,046) (92,444) (227,490) --------- -------- ------- -------- Cash flows from financing activities: Borrowings under long-term debt.................. 109,175 - - 109,175 Principal payments on long-term debt............. (124,175) - - (124,175) Payment of noncurrent liabilities................ - (31,601) 862 (30,739) Exercise of long-term incentive plan stock options.................................. 5,444 - - 5,444 Purchase of treasury stock....................... (7,070) - - (7,070) --------- -------- ------- -------- Net cash provided by (used in) financing activities.................................... (16,626) (31,601) 862 (47,365) --------- -------- ------- -------- Net increase (decrease) in cash and cash equivalents....................................... 36 (7,638) (188) (7,790) Effect of exchange rate changes on cash and cash equivalents.................................. - - (142) (142) Cash and cash equivalents, beginning of period...... 15 18,387 7,757 26,159 --------- -------- ------- -------- Cash and cash equivalents, end of period............ $ 51 $ 10,749 $ 7,427 $ 18,227 ========= ======== ======= ========
CONSOLIDATING CONDENSED STATEMENT OF CASH FLOWS For the Six Months Ended June 30, 2000 (in thousands) (Unaudited) Non- Pioneer Guarantor The Parent USA Subsidiaries Company ---------- --------- ------------ --------- Cash flows from operating activities: Net cash provided by operating activities........ $ 71,428 $ 59,414 $ 38,524 $ 169,366 --------- -------- ------- -------- Cash flows from investing activities: Proceeds from disposition of assets.............. - 22,622 5,900 28,522 Additions to oil and gas properties.............. - (58,391) (53,864) (112,255) Other property (additions) dispositions, net..... - (2,451) 3,329 878 --------- -------- ------- -------- Net cash used in investing activities.......... - (38,220) (44,635) (82,855) --------- -------- ------- -------- Cash flows from financing activities: Borrowings under long-term debt.................. 876,675 - - 876,675 Principal payments on long-term debt............. (928,176) (501) - (928,677) Payment of noncurrent liabilities................ - (9,780) (1,222) (11,002) Exercise of long-term incentive plan stock options.................................. 253 - - 253 Purchase of treasury stock....................... (6,307) - - (6,307) Deferred loan fees/issuance costs................ (13,878) - - (13,878) --------- -------- ------- -------- Net cash used in financing activities.......... (71,433) (10,281) (1,222) (82,936) --------- -------- ------- -------- Net increase (decrease) in cash and cash equivalents....................................... (5) 10,913 (7,333) 3,575 Effect of exchange rate changes on cash and cash equivalents.................................. - - (94) (94) Cash and cash equivalents, beginning of period...... 5 22,699 12,084 34,788 --------- -------- ------- -------- Cash and cash equivalents, end of period............ $ - $ 33,612 $ 4,657 $ 38,269 ========= ======== ======= ========
21 PIONEER NATURAL RESOURCES COMPANY Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations(1) Financial and Operating Performance The financial and operating performance of Pioneer Natural Resources Company (the "Company" or "Pioneer") during the three and six month periods ended June 30, 2001 was highlighted by increased drilling and seismic activities in the United States Gulf of Mexico, South Africa, Gabon and Tunisia (see "Drilling Highlights", below) and significant increases in net income and operating cash flows. The Company reported net income of $28.3 million ($.28 per diluted share) and $96.3 million ($.97 per diluted share) for the three and six month periods ended June 30, 2001, as compared to net losses of $16.1 million ($.16 per diluted share) and $1.3 million ($.01 per diluted share) for the same respective periods in 2000. During the three months ended June 30, 2001, earnings were positively impacted by favorable commodity prices, a $9.3 million mark-to-market gain primarily related to derivatives not treated as hedges and a $1.5 million gain on the disposition of assets. During the six months ended June 30, 2001, earnings were positively impacted by favorable commodity prices, an $8.8 million gain on the disposition of assets and a $.5 million mark-to-market gain primarily related to derivatives not treated as hedges. The Company's results for the three month period ended June 30, 2000 were impacted by increases in commodity prices, $28.5 million of derivative mark-to-market charges to other expenses, a $12.3 million extraordinary item - loss on early extinguishment of debt and a $4.8 million loss on the disposition of assets. The results for the six months ended June 30, 2000 were significantly impacted by $42.0 million of derivative mark-to-market charges to other expenses, the $12.3 million extraordinary item - loss on early extinguishment of debt and a $3.6 million gain on the disposition of assets. See "Results of Operations" below for additional discussions pertaining to the Company's financial and operating performance. The Company's net cash provided by operating activities grew to $135.3 million during the three months ended June 30, 2001, representing an increase of 11 percent as compared to net cash provided by operating activities of $122.2 million for the same period in 2000. The increase in net cash provided by operating activities was primarily a result of favorable commodity prices. These positive results were partially offset by a three percent production decline primarily resulting from prior year asset divestitures, temporary supply, demand and infrastructure issues and increased production costs primarily resulting from increases in production taxes, ad valorem taxes and field fuel costs associated with higher gas prices. During the three months ended June 30, 2001, the Company used its net cash provided by operating activities, together with proceeds from the dispositions of assets and net borrowings of long-term debt, to fund $141.0 million of additions to oil and gas properties and for other general corporate needs. 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, 2001 was $2.6 billion, consisting of total debt of $1.6 billion and stockholders' equity of $1.0 billion. Debt as a percentage of total book capitalization was 60 percent at June 30, 2001 as compared to 64 percent at December 31, 2000. Total outstanding indebtedness declined by $6.5 million during the six months ended June 30, 2001. Drilling Highlights During the first six months of 2001, the Company spent $238.7 million on capital projects including $113.7 million for development activities, $103.4 million for exploration activities and $21.6 million on acquisitions. The Company successfully completed 159 development wells and 33 exploratory/extension wells and plugged and abandoned 10 development wells and 20 exploratory/extension wells. As of June 30, 2001, the Company had 53 development wells and 12 exploratory/extension wells in progress. Domestic. The Company expended $127.4 million during the first six months of 2001 on drilling and seismic activities in the Gulf Coast, Permian Basin and Mid Continent areas of the United States. Gulf Coast area. The Company expended $98.3 million of drilling and seismic capital during the first six months of 2001 to successfully drill 10 development wells and nine exploratory wells, drill two exploratory dry holes 22 and begin drilling eight exploratory and eight development wells that remained in progress on June 30, 2001. During April 2001, the Company announced Gulf Coast area discoveries including a successful appraisal well completed in the Company's Cyrus prospect and participation in two new deepwater Gulf of Mexico discoveries at the Turnberry and Falcon prospects. The Company owns a 5.5 percent working interest in the Cyrus prospect, where the Texaco-operated High Island Block A-582 #5 well confirmed over 230 feet of pay found in a discovery well drilled during the fourth quarter of 2000. The initial exploratory well drilled on the Dominion E&P-operated Turnberry prospect, where the Company owns a 40 percent working interest, was drilled to a total depth of 15,994 feet and encountered over 100 feet of hydrocarbon-bearing sands. Sidetrack operations on the Turnberry discovery were unsuccessful and evaluations of the initial well are in progress to determine the commerciality of the reservoir. Capital costs of $4.4 million associated with the sidetrack were charged to expense during the second quarter of 2001. At the Mariner Energy-operated Falcon prospect, where the Company owns a 45 percent working interest, an exploratory well was drilled to a total depth of 9,060 feet and found two hydrocarbon-bearing sands. The discovery well was successfully sidetracked to a downdip location to test the extent of the underlying reservoir. The Company expects to sanction the Falcon development during the third quarter of 2001. During the first half of 2001, the Company also participated in three exploratory wells drilled on the Gulf of Mexico shelf which targeted deep gas objectives. An exploratory well on the Pioneer-operated Cruiser prospect in West Cameron 296, in which the Company owns a 70 percent working interest, was drilled to a depth of 17,785 feet and encountered over 200 feet of sand in the Lower Miocene target. Although good hydrocarbon shows were encountered, logs indicated that porosity and hydrocarbon saturation was too low to be commercial. The well has been plugged and abandoned and drilling costs of $9.4 million were charged to expense during the second quarter of 2001. An exploratory well on the Spinnaker-operated Stirrup prospect in Mustang Island 861-L, in which the Company owns a 25 percent working interest, was drilled to a total depth of 17,123 feet and found gas-bearing sands in four major sequences. Three of those sequences have tested gas and the fourth was not tested. One sand sequence was tested at approximately 21 million cubic feet of gas per day with 130 barrels of condensate at flowing pressures exceeding 11,000 pounds per square inch following stimulation. The well will be shut in pending design and fabrication of a production platform, related facilities and flow line. The discovery well is on a large faulted anticline and additional drilling in the third quarter of 2001 will be required to fully delineate its size. The Company also increased its lease holdings in the area at the July 10 Texas state lease sale, adding 2,880 acres in the play. An exploratory well on the Hall Houston-operated Oneida prospect in East Cameron 76, in which the Company owns a 14 percent working interest, was drilled to a depth of 17,766 feet and found over 50 feet of net gas pay in a single sand. The well is currently being completed and well test results should be announced shortly. During the third quarter of 2001, the Company plans to drill two exploratory wells in the Gulf of Mexico. The first well is scheduled to test the Ozona Deep prospect in Garden Banks 515, where the Company currently owns a 32 percent working interest, and the second well will test the Malta prospect, where the Company has a 67.5 percent working interest. During the third quarter of 2001, the Company announced that it had completed drilling on the Argo prospect in Alaminos Canyon 13. The well was unsuccessful and has been plugged and abandoned. The Company expensed $3.1 million of unproved leasehold costs attributable to the Argo prospect during the second quarter of 2001. The Argo drilling costs of approximately $3.1 million will be charged to expense during the third quarter of 2001. In the deepwater Gulf of Mexico area, the Company's development drilling and completion work remains on schedule in the Aconcagua and Camden Hills fields. The first development well at Aconcagua, one of three fields being jointly developed in the Canyon Express gas project, was successfully completed during the first quarter of 2001 and exceeded the Company's expectations. Additionally, facilities construction is underway for the Canyon Express gas project, in which the Company owns an 18 percent interest, with installation scheduled to begin during the third quarter of 2001. Initial sales from the installation are expected during mid-2002. Two appraisal wells were successfully drilled at the Devils Tower field in Mississippi Canyon 773, where the Company increased its working interest to 25 percent during the first quarter 2001, to explore for new reserves in previously undrilled reservoirs and to further extend previously tested zones. With the success of the appraisal wells, the Devils Tower development was sanctioned as a spar development project in June 2001. The spar will either be constructed and purchased by the partners or leased from a third party for the life of the field. Evaluations and negotiations are currently underway to determine which option will be selected. The Company expects to invest approximately $21.8 million of development capital in the deepwater Gulf of Mexico area during the third and fourth quarters of 2001. 23 In South Texas, the Company continues to aggressively develop the Edwards Reef in its Pawnee field, where the Company has a 100 percent working interest. The Company initiated drilling on three of five scheduled vertical wells and two horizontal reentries. The Company currently has four drilling rigs contracted and operating in the East Texas/Gulf Coast area, including three rigs in the East Texas Bossier field. In East Texas, eight wells have been drilled this year with a total of 19 operated wells currently producing or awaiting completion or facilities. Pioneer holds approximately 134,000 gross acres in the play in East Texas and Louisiana with a 65 percent average working interest. Permian Basin area. The Company expended $25.5 million of drilling and seismic capital during the first six months of 2001 to successfully complete 91 development wells and one exploratory well, plug and abandon eight development dry holes and to begin drilling 30 development wells that remain in progress as of June 30, 2001. The Company has also identified 20 to 30 possible future drilling locations at its Myway Clearfork field discovery. Additionally, in the Ozona gas field, Pioneer is drilling the fifteenth well of a 25 well 2001 development program in the Canyon and Strawn formations, where gross average well production is 600 Mcf per day. The Company currently has seven drilling rigs contracted and operating in the Permian Basin area. Mid Continent area. The Company expended $3.6 million of drilling and seismic capital during the first six months of 2001 to successfully complete 17 development wells and to begin drilling seven development wells that remain in progress as of June 30, 2001. The Company's development drilling in the Mid Continent area is focused on West Panhandle and Hugoton gas prospects, where the Company currently has two drilling rigs contracted and operating. Argentina. The Company expended $27.5 million of drilling and seismic capital during the first six months of 2001 to successfully complete 28 wells, eight of which were exploratory/extension discoveries and 15 of which were development wells, and to drill five exploratory/extension wells that were plugged and abandoned and to begin drilling six development wells and two exploratory/extension wells that remain in progress as of June 30, 2001. The Company has had significant success in the Bajo Barda Gonzalez drilling program in Argentina's Neuquen Basin, where 14 wells have been drilled during the first six months of 2001 and approximately eight additional wells are scheduled for the third quarter of 2001. The Company's BBG37H horizontal well encountered the upper Lotena sand with 1,340 feet of horizontal displacement. Initial production from the well during the third quarter of 2001 stabilized over a 20 day period at 1,100 barrels of oil per day and 900 Mcf of gas per day. In the Loma Negra Norte field, the Company has drilled nine successful wells during 2001. The Company plans to drill five to ten additional wells this year to further extend the field which is now producing 1,520 Bbls of oil per day and 2 MMcf of gas per day. In the Lago Fuego block in Tierra del Fuego, the Company recompleted two existing wells that are capable of producing approximately 7 MMcf of gas per day and 200 Bbls of NGL's per day on a combined basis. Commercial production has commenced following the installation of a dehydration plant and construction of an 8-mile, 8-inch pipeline to the city of Ushuaia. Additional drilling plans will be developed to assess the size of this field after performance data is gathered. The Company has also awarded a contract for the construction of an NGL extraction facility at its Loma Negra gas complex near its Al Norte de la Dorsal ("AND") core area. The plant is designed to process 75 MMcf per day inlet gas and is expected to extract up to 3,150 barrels of NGL per day. The NGL produced will be sold to local and export markets and will allow the Company to capture additional value from its Neuquen gas production, increasing the value of twenty percent of the gas stream by a factor of three. The plant is expected to be in service by mid-2002. The Company has also approved the construction of a new 35-mile, 16-inch pipeline from the Loma Negra complex to the TGS NEUBA trunkline in central Neuquen. This pipeline will provide incremental capacity to transport up to 175 MMcf per day of gas to the Buenos Aires market. Construction is expected to begin in August and be completed in the fourth quarter of this year. During the third quarter of 2001, the Company acquired a 100 percent working interest in the Anticlinal Campamento block in the Neuquen Basin of Argentina for $12.2 million. This 80,000-acre block extends the Company's position west from its current core operations in the AND area. The Anticlinal 24 Campamento block includes a mature oil field with nominal production and a recently developed gas field producing 7 MMcf per day into local markets. Total proved reserves are estimated at 31.7 billion cubic feet of gas and 170,000 barrels of oil, yielding a purchase price of $2.24 per barrel oil equivalent. The Company expects to add reserves and production on the property through development of current producing areas and new exploration drilling. The Company also announced it was the successful bidder for the Cerro Vagon block in a recent Neuquen Province land auction. The Company acquired 100 percent of the 169,195-acre block in exchange for a commitment to acquire 440 square kilometers of 3-D seismic data and drill five exploratory wells over the next four years. The Cerro Vagon block is located adjacent to the Company's Al Sur de la Dorsal ("ASD") core area in the Neuquen Basin. The Company has made a number of new discoveries in the last 18 months in adjacent blocks based on new 3-D seismic and expects to continue this trend at Cerro Vagon. During the six month period ended June 30, 2001, the Company closed a $2.5 million acquisition of a 100 percent interest in two exploration blocks covering 51,500 acres in the Dos Hermanas concession of Neuquen Province also adjacent to the core area. The Company has committed to drill two exploratory wells on the blocks. Additionally, the Company acquired the remaining 25 percent interest in the La Calera block in central Neuquen and now operates and owns 100 percent of La Calera which comprises 55,328 acres immediately adjacent to the Loma La Lata gas field, the largest in Argentina. The Company is currently evaluating a large deep gas exploration prospect on the block as well as potential reactivation of an existing oil field. The Company currently has six drilling rigs contracted and operating in Argentina. Canada. The Company expended $31.2 million of drilling and seismic capital during the first six months of 2001 to successfully complete 26 development wells and 14 extension/exploration wells, to drill 10 extension/exploration wells that were plugged and abandoned and to begin drilling two extension/exploration wells that remain in progress as of June 30, 2001. During the first quarter of 2001, the Company completed its annual winter drilling program in the Chinchaga, North Chinchaga and Martin Creek areas that are only accessible to drilling operations during the winter. During the winter drilling program, the Company drilled 32 wells in the Chinchaga area and connected 26 wells to pipelines. In the North Chinchaga area, eight wells were drilled and connected to pipelines. In the Martin Creek and Conroy Black areas, four wells were drilled and 12 wells were connected to pipelines, including 11 wells that were drilled during the previous winter drilling program. Africa. In Africa, the Company expended $31.0 million of drilling and seismic capital during the first six months of 2001 in South Africa, Gabon and Tunisia. South Africa. The Company expended $20.8 million of drilling and seismic capital to drill two exploratory wells on its Company-operated Boomslang prospect, in which the Company has a 49 percent working interest, and to drill an exploratory gas well on the Soekor-operated E-BB tract, in which the Company has a 40 percent working interest and acquire two 3-D seismic surveys. The initial Boomslang well found 108 feet of net pay consisting of an oil leg under a gas column at a depth of 6,600 feet. Well tests flowed at a combined rate of 3,120 Bbls of oil, 300 Bbls of condensate and 26 MMcf of gas per day. An appraisal well was drilled to test a separate fault block within the Boomslang structure approximately two kilometers southwest of the discovery well. The well was drilled to a total depth of 8,110 feet and encountered over 575 feet of high quality sand in the same interval as the discovery well. However, the reservoir sand came in low to the oil-water contact intersected in the Boomslang discovery well and was wet. The Company also recently completed the acquisition of a 1,193 square-kilometer 3-D seismic survey covering the Boomslang trend area where several other prospects have been identified. The Company expects to drill additional appraisal wells after the seismic interpretation has been evaluated. In addition, the Company drilled and tested the E-BB2 gas well. The well was drilled approximately 120 kilometers south of Mossel Bay to test the lateral continuity and productivity of widespread gas- bearing sands in the center of the Bredasdorp Basin. The well found over 325 feet of gas-bearing sandstone in five primary zones. Three of the zones were perforated and tested. Two of the zones exhibited low permeability while a third zone flowed at a sustained daily rate of 10 MMcf of gas and 800 Bbls of liquids. Results of this well and other wells previously drilled in this trend are being assessed as part of the larger gas development project currently being evaluated. In addition, the Company also acquired a 3-D seismic survey in the Port Elizabeth Trough Area of Block 25 14 during the first six months of 2001. The Company plans on spending the rest of 2001 studying the seismic data and evaluating the results from the aforementioned exploration activities and therefore expects limited additional spending in the area for the remainder of 2001. The partners at the Company's Soekor-operated Sable oil discovery, in which the Company currently has a 35 percent working interest, have sanctioned the development of the field. Oil production is scheduled to begin in the first quarter of 2003 with expected initial gross flow rates of up to 40,000 Bbls of oil per day from two reservoirs with 25 million Bbls of estimated recoverable oil reserves. The Sable field is located in 325 feet of water approximately 95 kilometers off the southern coast of South Africa. The field will be developed with six subsea wells tied back to a floating production, storage and offloading ("FPSO") vessel. Bluewater Ltd. has been awarded a contract to provide and operate an FPSO with capacity to process 60,000 Bbls of oil per day, reinject 80 Mcf of gas per day and recover natural gas liquids. Bluewater Ltd. will deploy the FPSO Glas Dowr to the Sable field and is responsible for day-to-day operations including associated shuttle tanker operations. Associated gas will be reinjected to improve liquids recovery but could be produced at a later time as part of the larger gas development project that is currently being evaluated. The Company anticipates spending approximately $21 million over the remainder of this year for development drilling and facilities construction related to the Sable field. Gabon. The Company expended $7.8 million of drilling and seismic capital to drill and test its initial exploratory and sidetrack well on its Bigorneau South prospect, located offshore in the Southern Gabon Basin on its Olowi permit. Pioneer is the operator of the 314,000 acre permit with a 100 percent working interest. The well was initially drilled to a depth of 3,720 feet and subsequently sidetracked 815 feet to the north. The vertical well and sidetrack encountered an oil column with a minimum thickness of 75 feet. To test a section of highly porous Gamba sand covering 27 vertical feet of net oil pay, the Company perforated the sidetrack between the measured depths of 3,605 and 3,655 feet. The well flowed at an average stabilized rate of approximately 1,375 Bbls of oil per day over a 48-hour period on a 32/64 inch choke with no water. The well was subsequently tested on a 40/64 inch choke and flowed at a maximum stabilized rate of approximately 2,100 Bbls of oil per day with no water. The Company has submitted its application to enter the Second Exploration Period on the Olowi Permit, which requires two additional exploratory wells over a two-year period. The Company plans to drill its next exploration well in early 2002. Tunisia. The Company expended $2.4 million of drilling and seismic capital to drill its first exploratory well in the Bazma permit which was unsuccessful and subsequently plugged and abandoned. The Company acquired 50 percent of Eurogas Corporation's rights to explore this permit along with the Jorf and El Hamra permits by agreeing to pay 100 percent of their drilling costs to casing point on the first two wells drilled in these permits. The Company also has the option under this agreement to take over as operator after the rig is released from the initial well. The Company has not exercised its option at this time, but is continuing to assess the merits of doing so by the November deadline. This acquisition provides the Company with 2.7 million acres in the area. In July 2001, the Company announced that subject to Tunisian government approval it has acquired a 30 percent interest in the Anaguid permit in the Ghadames basin onshore southern Tunisia for approximately $1.7 million. The Company will join Anadarko Petroleum Corporation, the operator of the permit, and Nuevo Energy Company in exploring the 1.1 million-acre permit by paying the Company's share of costs going forward. Budgeted capital expenditures. The Company's successful drilling results during 2001 have led to revisions to the Company's capital commitment plans. Based on forecasted 2001 cash flows from operating activities and follow-on capital requirements associated with the Company's successful exploration programs, the Company has increased its 2001 capital expenditures budget to $480 million from the $430 million budget originally established. Results of Operations Oil and gas revenues. Revenues from oil and gas operations totaled $218.6 million and $476.6 million for the three and six month periods ended June 30, 2001, respectively, compared to $197.9 million and $372.3 million for the same respective periods in 2000. The increase in revenues is reflective of commodity price increases which more than offset a slight decrease in production volumes that primarily resulted from prior year asset divestitures and temporary supply, demand and infrastructure issues that are described in more detail below. 26 The following table provides the Company's volumes and average reported price, including the results of hedging activities for the three and six month periods ended June 30, 2001 and 2000: Three months ended Six months ended June 30, June 30, ----------------------- ---------------------- 2001 2000 2001 2000 --------- --------- --------- --------- Production: Oil (MBbls)................. 3,138 3,040 6,300 6,203 NGLs (MBbls)................ 1,961 2,140 3,799 4,203 Gas (MMcf).................. 33,316 34,716 63,258 67,403 Total (MBOE)................ 10,651 10,966 20,462 21,640 Average daily production: Oil (Bbls).................. 34,482 33,404 34,809 34,082 NGLs (Bbls)................. 21,546 23,520 20,989 23,093 Gas (Mcf)................... 366,116 381,490 349,493 370,349 Total (BOE)................. 117,047 120,505 114,047 118,900 Average reported prices: Oil (per Bbl): United States............. $ 24.39 $ 20.86 $ 24.82 $ 20.43 Argentina................. $ 25.68 $ 27.38 $ 25.14 $ 28.40 Canada.................... $ 23.88 $ 25.35 $ 23.85 $ 27.28 Worldwide................. $ 24.74 $ 22.59 $ 24.89 $ 22.51 NGLs (per Bbl): United States............. $ 18.78 $ 18.12 $ 20.59 $ 18.48 Argentina................. $ 22.60 $ 23.58 $ 24.70 $ 21.72 Canada.................... $ 27.34 $ 20.99 $ 25.86 $ 21.67 Worldwide................. $ 19.29 $ 18.37 $ 20.94 $ 18.68 Gas (per Mcf): United States............. $ 3.93 $ 3.24 $ 4.75 $ 2.76 Argentina................. $ 1.34 $ 1.20 $ 1.30 $ 1.16 Canada.................... $ 3.03 $ 2.55 $ 4.29 $ 2.26 Worldwide................. $ 3.10 $ 2.60 $ 3.80 $ 2.29
As discussed above, oil and gas revenues for the three and six month periods ended June 30, 2001 were favorably impacted by commodity price increases. As compared to the three months ended June 30, 2000, the average oil price for the three months ended June 30, 2001 increased ten percent; the average NGL price increased five percent; and the average gas price increased 19 percent. As compared to the six months ended June 30, 2000, the average oil price for the six months ended June 30, 2001 increased 11 percent; the average NGL price increased 12 percent; and the average gas price increased 66 percent. On a BOE basis, average daily production decreased by three percent and four percent during the three and six month periods ended June 30, 2001, respectively, as compared to the same periods in 2000. Per BOE average daily production, based on a second quarter to second quarter comparison, declined six percent in the United States, where the Company completed asset dispositions during 2000, while production in Canada and Argentina increased by ten and two percent, respectively. Comparing the first six months of 2001 to the same period in 2000, per BOE average daily production declined eight percent in the United States, while production in Canada and Argentina increased by ten and three percent, respectively. In addition to prior year asset divestitures in the United States, production levels were also negatively impacted during 2001 by the Company's election not to recover ethane from United States Mid Continent area gas during January 2001 (this election effectively raised the Company's MMBtu content, price realizations per Mcf of natural gas and total revenue, but reduced production volumes by approximately 1,200 BOE per day during the election period); severe weather in the United States Mid Continent area during January 2001 which hampered field operations; increased hydroelectric power availability in Argentina which reduced the demand for natural gas power generation, unscheduled plant downtime at a large gas purchaser in the Tierra del Fuego area in Argentina; and, in the Neuquen Basin area in Argentina, unanticipated compressor maintenance. Third quarter 2001 production volumes are expected to average 117,000 to 120,000 BOE per day. Gas production will continue to benefit from the successful winter drilling program in Canada and increased demand in Argentina during their 27 winter season. Oil production is also expected to increase in Argentina as a result of an active development drilling program. Hedging activities. The oil and gas prices that the Company reports are based on the market price received for the commodities adjusted by the results of the Company's cash flow hedging activities. The Company utilizes commodity derivative instruments (swaps and collar contracts) 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. On January 1, 2001, the Company adopted the provisions of SFAS 133. Although SFAS 133 does not change the economics associated with derivative instruments in general or hedging activities in particular, it has significantly changed the accounting for derivative instruments and hedging activities and the requirements that must be met in order for a derivative instrument to qualify for hedge accounting treatment. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for specific information regarding the adoption of SFAS 133 and the Company's hedging activities. Interest and other revenue. During the three and six months ended June 30, 2001, the Company recorded interest and other revenue of $11.0 million and $16.1 million, respectively, as compared to $5.2 million and $8.9 million, respectively, during the same periods in 2000. Interest and other revenue for the three and six month periods ended June 30, 2001 includes $7.3 million of mark-to-market gains recognized on the Company's BTU swap agreements. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for information regarding the BTU swap agreements. Gain (loss) on disposition of assets. During the three and six months ended June 30, 2001, the Company recorded gains on the disposition of assets of $1.5 million and $8.8 million, respectively, as compared to a net loss of $4.8 million and a gain of $3.6 million during the same periods in 2000. During the three and six month periods ended June 30, 2001, the Company recognized gains of $1.1 million and $8.1 million, respectively, from the sale of its remaining holdings in Prize. The loss recognized during the three months ended June 30, 2000, was primarily associated with the sale of an office building in Midland, Texas. During the first quarter of 2000, the Company recorded an $8.3 million gain from the sale of a portion of the Company's investment in Prize. Production costs. During the three and six month periods ended June 30, 2001, total production costs per BOE averaged $4.88 and $5.22, respectively, representing increases of $.95 and $1.23 per BOE, respectively, as compared to production costs per BOE during the same periods in 2000. Lease operating expenses and workover expenses represent the components of production costs for which the Company has management control, while production taxes, ad valorem taxes and field fuel expenses are directly related to commodity price changes. During the three and six month periods ended June 30, 2001 as compared to the same periods in 2000, per BOE lease operating expenses and workover expenses increased on a combined basis by 19 percent and eight percent, respectively, while per BOE production taxes, ad valorem taxes and field fuel expenses increased on a combined basis by 32 percent and 67 percent, respectively. The increase in production costs per BOE for the three and six month periods ended June 30, 2001, as compared to the same periods in 2000, is primarily due to significant increases in those expenses that are commodity price driven and to a lesser extent, inflation in field service expenses. Three months ended Six months ended June 30, June 30, ------------------ ------------------ 2001 2000 2001 2000 ------- ------- ------- ------- (per BOE) Lease operating expense......... $ 2.58 $ 2.25 $ 2.47 $ 2.28 Taxes: Production................... .76 .67 .92 .67 Ad valorem................... .48 .34 .44 .34 Field fuel expenses............. .90 .61 1.21 .53 Workover costs.................. .16 .06 .18 .17 ------ ------ ------ ------ Total production costs.... $ 4.88 $ 3.93 $ 5.22 $ 3.99 ====== ====== ====== ======
28 Based on market-quoted commodity prices in late July 2001, the Company expects third quarter 2001 production costs to average $4.60 to $4.80 per BOE. Depletion, depreciation and amortization expense. Total depletion, depreciation and amortization expense per BOE was $5.39 and $5.31 during the three and six month periods ended June 30, 2001, respectively, as compared to $4.88 and $4.87 during the three and six month periods ended June 30, 2000. Depletion expense, the largest component of depletion, depreciation and amortization, was $5.07 and $4.94 per BOE during the three and six month periods ended June 30, 2001, respectively, as compared to $4.53 and $4.51 per BOE during the same periods in 2000. The increase in depletion expense per BOE during 2001 is primarily associated with decreases in lower cost basis United States production relative to combined Argentine and Canadian production and to downward revisions to proved reserves during 2001 resulting from price declines. The Company expects third quarter 2001 depletion, depreciation and amortization expense to average $5.30 to $5.60 per BOE. Exploration and abandonments/geological and geophysical costs. Exploration and abandonments/geological and geophysical costs increased to $46.6 million and $69.4 million during the three and six month periods ended June 30, 2001, respectively, from $27.7 million and $40.8 million during the same respective periods in 2000. The increases are largely the result of dry hole costs in the United States, Canada and South Africa; and geological and geophysical costs that are supportive of future exploratory drilling in the United States Gulf Coast and South Africa. Acceleration of drilling schedules during the three months ended June 30, 2001 and the drilling of one unscheduled Tunisian exploratory well, caused total exploration and abandonment costs to exceed forecasts for the period. Consequently, fewer exploratory wells will be drilled during the third and fourth quarters of 2001, reducing potential exploration and abandonment costs. The following table provides the Company's geological and geophysical costs, exploratory dry hole expense, lease abandonments expense and other exploration expense for the three and six month periods ended June 30, 2001 and 2000: United Other States Argentina Canada Foreign Total ------- --------- -------- -------- -------- (in thousands) Three months ended June 30, 2001: Geological and geophysical costs...... $ 9,777 $ 802 $ 272 $ 5,163 $ 16,014 Exploratory dry holes................. 18,121 1,550 401 7,619 27,691 Leasehold abandonments and other...... 1,162 1,521 195 - 2,878 ------ ------ ------ ------ ------- $29,060 $ 3,873 $ 868 $12,782 $ 46,583 ====== ====== ====== ====== ======= Three months ended June 30, 2000: Geological and geophysical costs...... $ 6,831 $ 1,086 $ 274 $ 2,197 $ 10,388 Exploratory dry holes................. 3,366 2,669 873 - 6,908 Leasehold abandonments and other...... 1,149 8,092 1,159 - 10,400 ------ ------ ------ ------ ------- $11,346 $11,847 $ 2,306 $ 2,197 $ 27,696 ====== ====== ====== ====== ======= Six months ended June 30, 2001: Geological and geophysical costs...... $13,801 $ 1,456 $ 499 $ 8,778 $ 24,534 Exploratory dry holes................. 18,279 2,132 5,355 8,441 34,207 Leasehold abandonments and other...... 2,195 6,895 1,627 8 10,725 ------ ------ ------ ------ ------- $34,275 $10,483 $ 7,481 $17,227 $ 69,466 ====== ====== ====== ====== ======= Six months ended June 30, 2000: Geological and geophysical costs...... $10,490 $ 1,870 $ 539 $ 3,698 $ 16,597 Exploratory dry holes................. 3,657 4,180 860 - 8,697 Leasehold abandonments and other...... 2,149 11,967 1,354 7 15,477 ------ ------ ------ ------ ------- $16,296 $18,017 $ 2,753 $ 3,705 $ 40,771 ====== ====== ====== ====== =======
The Company expects third quarter 2001 exploration and abandonment expense to be $15.0 million to $35.0 million. Three Gulf of Mexico exploration wells are scheduled by the Company during the third quarter of 2001: one 29 each on the Malta and Ozona Deep prospects and an appraisal well on the Stirrup discovery. See "Drilling Highlights" above for further discussions regarding the Company's exploration and abandonment activities during 2001. General and administrative expense. General and administrative expense was $8.0 million and $18.5 million for the three and six months ended June 30, 2001, respectively, as compared to $7.0 million and $16.7 million for the same periods in 2000, representing increases of 15 percent and ten percent, respectively. On a per BOE basis, general and administrative expense was $.75 and $.90 during the three and six month periods ended June 30, 2001, as compared to $.63 and $.77 for the same periods in 2000. The Company expects third quarter 2001 general and administrative expense to be approximately $9 million. Interest expense. Interest expense for the three and six months ended June 30, 2001 was $34.3 million and $69.9 million, respectively, as compared to $41.9 million and $81.6 million, respectively, for the same periods in 2000. The $7.6 million and $11.7 million decreases in interest expense during the three and six month periods ended June 30, 2001, as compared to the same periods in 2000, reflect decreases of $167.9 million and $172.4 million, respectively, in the Company's average debt outstanding, the capitalization of $1.4 million and $2.7 million of interest during the three and six month periods ended June 30, 2001, respectively, and decreases in the Company's weighted average borrowing rates of 69 basis points and 37 basis points, respectively. The Company is a party to interest rate swap agreements that hedge a portion of the Company's fixed rate debt. During the three month periods ended June 30, 2001 and 2000, the interest rate swap agreements decreased the Company's interest expense by $.4 million and $.2 million, respectively. The interest rate swap agreements decreased the Company's interest expense by $.7 million and $.2 million during the six month periods ended June 30, 2001 and 2000, respectively. The Company expects third quarter interest expense to be $34 million to $35 million, including approximately $3 million of noncash interest expense. Other costs and expenses. Other costs and expenses for the three and six month periods ended June 30, 2001 was $1.9 million and $27.1 million, respectively, compared to $30.5 million and $44.9 million for the same periods in 2000. The decrease in other costs and expenses is primarily attributable to fluctuations in mark-to-market provisions on financial instruments. Mark-to-market provisions during the three and six month periods ended June 30, 2001 included a decrease in the ineffective portions of liabilities associated with commodity derivatives designated as hedges of $1.9 million during the three months ended June 30, 2001 and an increase in the ineffective portions of liabilities associated with commodity derivatives designated as hedges of $.3 million during the six months ended June 30, 2001. Additionally, an increase in the liabilities associated with the Company's BTU swap agreements of $6.6 million was recognized during the six months ended June 30, 2001. The Company recognized $7.3 million of mark-to-market gains associated with the BTU swaps in interest and other revenue during the three months ended June 30, 2001. During the three and six month periods ended June 30, 2000, mark-to-market provisions included increases in the liabilities associated with non-hedge commodity call contracts of $23.9 million and $38.0 million, respectively; increases in the liabilities associated with the Company's BTU swap agreements of $3.4 million and $2.7 million, respectively; and, increases in the liabilities associated with forward foreign currency swap agreements of $1.1 million and $1.3 million, respectively. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information pertaining to the Company's financial instruments that are recorded at fair value. Income tax provisions (benefits). During the three and six month periods ended June 30, 2001 and 2000, the Company recognized income tax provisions of $2.6 million and $3.0 million, respectively, compared to tax benefits of $1.6 million and $1.9 million for the three and six month periods ended June 30, 2000, respectively. The Company's income tax provisions and income tax benefits for the three and six month periods ended June 30, 2001 and 2000, respectively, are primarily associated with the Company's operations in Argentina. Due to continuing uncertainties regarding the likelihood that certain of the Company's net operating loss carryforwards and other credit carryforwards may expire unused, the Company has established valuation reserves to reduce the carrying value of its deferred tax assets. The Company's deferred tax valuation reserves are reduced when the Company's financial results establish that deferred tax assets previously reserved will be used prior to their expiration. 30 The Company expects that its effective tax rate will be approximately five percent of pre-tax income during the third quarter of 2001. Extraordinary item - loss on early extinguishment of debt. During the second quarter of 2000, the Company replaced its Prior Credit Facility with the Credit Agreement. Associated therewith, the Company recognized a $12.3 million extraordinary loss, comprised of deferred costs associated with the Prior Credit Facility. See Note F of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for additional information regarding this transaction. 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 for additions to oil and gas properties totaled $238.7 million during the first half of 2001. This amount includes $21.6 million for the acquisition of prospects and properties and $217.1 million for development and exploratory drilling and seismic expenditures. Drilling and seismic expenditures during the first half of 2001 included $127.4 million in the United States, $31.2 million in Canada, $27.5 in Argentina and $31.0 million in other international areas. See "Drilling Highlights", above, for a specific discussion of capital investments made during the first half of 2001. Funding for the Company's working capital obligations is provided by internally-generated cash flow. Funding for the repayment of principal and interest on outstanding debt may be provided by any combination of internally- generated cash flows, proceeds from the disposition of non-core assets or alternative financing sources as discussed in "Capital resources" below. The Company expects third quarter 2001 costs incurred for oil and gas producing activities to be $115 million to $125 million. Capital resources. The Company's primary capital resources are net cash provided by operating activities, proceeds from financing activities and proceeds from asset dispositions. The Company expects that its capital resources will be sufficient to fund its remaining capital commitments in 2001 and, assuming continuation of current commodity price levels, may allow for further reductions in debt during the remainder of 2001. Operating activities. Net cash provided by operating activities was $135.3 million and $267.1 million during the three and six months ended June 30, 2001, respectively, as compared to net cash provided by operating activities of $122.2 million and $169.4 million for the same periods in 2000. The increase in net cash provided by operating activities is primarily attributable to increases in commodity prices (see "Oil and gas revenues," above). Financing activities. The Company had an outstanding balance under its revolving line of credit at June 30, 2001 of $237.9 million (including outstanding, undrawn letters of credit of $27.9 million), leaving approximately $337.1 million of unused borrowing capacity immediately available. 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. Asset dispositions. During the three and six months ended June 30, 2001, proceeds from asset dispositions totaled $3.3 million and $15.2 million, respectively, as compared to $9.0 million and $28.5 million for the same periods in 2000. During the three and six month periods ended June 30, 2001, the sale of 80,715 shares and 613,215 shares of Prize common stock for $1.7 million and $12.7 million, respectively, was the primary source of the Company's proceeds from asset dispositions. The primary source of proceeds from asset dispositions 31 during the three months ended June 30, 2000 was the sale of an office building in Midland, Texas. During the six months ended June 30, 2000, the sale of the Midland office building and the sale of 1,404,946 shares of Prize Common for $19.1 million were the primary sources of the Company's proceeds from asset dispositions. The proceeds from these dispositions were used to reduce the Company's outstanding bank indebtedness and for general working capital purposes. Liquidity. At June 30, 2001, the Company had $18.2 million of cash and cash equivalents on hand, compared to $26.2 million at December 31, 2000. The Company's ratio of current assets to current liabilities was .82 to 1 at June 30, 2001 and .88 to 1 at December 31, 2000. Other Items Partnership mergers. On June 29, 2001, the Company filed with the SEC Amendment No. 1 to the Form S-4 Registration Statement (the "preliminary proxy statement/prospectus"), which proposes an agreement and plan of merger among the Company, Pioneer USA and 46 Parker & Parsley limited partnerships. Each partnership that approves the agreement and plan of merger and the other related merger proposals will merge with and into Pioneer USA upon the closing of the transactions and the partnership interests of each such partnership will be converted into the right to receive Pioneer common stock. Pioneer USA is the sole or managing general partner of the partnerships. The preliminary proxy statement/prospectus is non-binding and is subject to, among other things, consideration of offers from third parties to purchase any partnership or its assets and the majority approval of the limited partnership interests in each partnership. Pioneer USA will solicit proxies from limited partners to approve the mergers only when the proxy statement/prospectus is final and declared effective. No solicitation will be made using preliminary materials. Nonetheless, copies of the preliminary proxy statement/prospectus may be obtained without charge upon request from Pioneer Natural Resources Company, 5205 North O'Connor Blvd., Suite 1400, Irving, Texas 75039, Attention: Investor Relations. Stockholder's rights plan. During the third quarter of 2001, the Company announced that its board of directors ("Board of Directors") authorized the adoption of a stockholders rights plan (the "Plan"). The Plan includes safeguards against partial or two-tiered tender offers, squeeze-out mergers and other potentially abusive takeover tactics that limit the ability of all stockholders to realize the long-term value of their investment in Pioneer. Under the Plan, each holder of Pioneer common stock and each holder of exchangeable shares issued by Pioneer Natural Resources Canada, Inc. at the close of business on July 31, 2001, will automatically receive a distribution of one right for each share of common stock or exchangeable share held. Each right will entitle the holder to purchase a new series of junior participating preferred stock. Because the rights may be redeemed by the Board of Directors under certain circumstances, they should not interfere with any merger or other business combination approved by the Board of Directors. The issuance of the rights is not taxable to the stockholders, has no dilutive effect, will not affect Pioneer's reported earnings per share, and will not change the way the common stock or exchangeable shares are currently traded. Bond repurchase. On July 2, 2001, the Company redeemed the remaining $22.5 million of outstanding 11-5/8% Senior Subordinated Discount Notes due July 1, 2006 and $6.8 million of outstanding 10-5/8% Senior Subordinated Notes due July 1, 2006. The total redemption was $31.0 million and was funded from the Company's credit facility. Associated with this redemption, the Company will recognize an extraordinary gain of $1.4 million during the third quarter of 2001. Growth plan. During the third quarter of 2001, the Company announced its future growth plan (the "Base Case Plan"). The Base Case Plan forecasts a mid-range annual production growth of 13 percent in 2002 and 22 percent in 2003. The Base Case Plan includes production from recently sanctioned development projects in the deepwater Gulf of Mexico and South Africa and the proposed partnership mergers beginning October 2, 2001. The forecast does not include potential production from exploration successes currently being tested or from potential future exploration success. 32 The forecasted financial results under the Base Case Plan demonstrate that the Company's discretionary cash flows* are expected to be sufficient to fund the capital required to attain the Base Case Plan's production growth forecast. The Base Case Plan assumes NYMEX prices of $22.00 per barrel for oil and $3.50 per Mcf for gas beginning in August 2001 and held constant in future periods. The Base Case Plan reflects the impact of oil and gas hedges currently in place, including gas hedges that lock in prices of $4.00 per Mcf or greater for approximately 50 percent of the Company's forecasted North American gas production in 2002 and 2003. Using these and other assumptions, the Company forecasts discretionary cash flows of approximately $500 million in 2001, $421 million in 2002 (when production growth is offset by the assumption of lower oil and gas prices) and $626 million in 2003. Using 2002 NYMEX futures prices at the close on July 17, 2001 of $24.60 per barrel for oil and $3.68 per Mcf for gas, forecasted 2002 discretionary cash flows would be $483 million. Costs incurred for oil and gas producing activities ("Costs Incurred") are forecasted to be $480 million in 2001 before the cost of the proposed partnership mergers, $385 million in 2002 and $358 million in 2003. Forecasted Costs Incurred include estimated costs of planned development drilling on sanctioned projects and new exploratory drilling but do not include development capital for exploration successes currently being tested or potential future exploration success. Under the above stated Base Case Plan assumptions, the Company forecasts earnings before interest expense, income taxes, depletion, depreciation, amortization and exploration and abandonment expense ("EBITDAX")** of approximately $617 million in 2001, $545 million in 2002 and $742 million in 2003. Forecasted EBITDAX would be materially higher if current NYMEX futures prices were used for oil and gas. Using the 2002 NYMEX futures prices on July 17, 2001 referenced above, forecasted 2002 EBITDAX would be $605 million. The Base Case Plan applies discretionary cash flows in excess of Costs Incurred to reduce long-term debt. Utilizing the Base Case Plan assumptions, long-term debt is expected to decline to $1.3 billion as of December 31, 2003. - --------------- * Discretionary cash flows equal cash flows from operations before working capital changes and exploration and abandonments. ** Discretionary cash flows and EBITDAX (as defined above) are presented herein because of their wide acceptance as financial indicators of a Company's ability to internally fund exploration and development activities and to service or incur debt. Discretionary cash flows and EBITDAX should not be considered as alternatives to net cash provided by operating activities, net income (loss) or income (loss) from continuing operations, as defined by generally accepted accounting principles. Discretionary cash flows and EBITDAX should also not be considered as indicators of the Company's financial performance, as alternatives to cash flow, as measures of liquidity or as being comparable to other similarly titled measures of other companies. 33 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, 2000. 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, 2000. The following disclosures provide specific information about material changes that have occurred since December 31, 2000 in the Company's portfolio of financial instruments. The Company may recognize future earnings gains or losses on these instruments from changes in market interest rates or commodity prices. Interest rate sensitivity. During the three months ended June 30, 2001, the Company entered into interest rate swap agreements to hedge the fair value of the Company's 8-1/4% Senior Notes due August 15, 2007. The interest rate swap agreements are for an aggregate notional amount of $150.0 million of debt; commenced on May 29, 2001; mature on August 15, 2007; require the counterparties to pay the Company a fixed annual rate of 8-1/4 percent on the notional amount; and, require the Company to pay the counterparties a variable annual rate on the notional amount equal to the three month LIBOR plus a weighted average margin of 238.1 basis points. Additionally, during the three months ended June 30, 2001, the Company also entered into interest rate swap agreements to hedge the interest rate volatility associated with certain of the Company's variable-rate credit agreement indebtedness. The terms of these swap agreements provide for an aggregate notional amount of $55 million of debt; commenced on May 21, 2001 and mature on May 20, 2002; require the counterparties to pay the Company a variable rate equal to the six month LIBOR plus 125 basis points; and, require the Company to pay the counterparties an average annual rate of 5.43 percent on the notional amount. As of June 30, 2001, the aggregate fair value of the Company's interest rate swap agreements was an asset of $7.3 million. Commodity price sensitivity. During the first six months of 2001, the Company entered into additional oil and gas hedge derivatives. The following tables provide information about the Company's oil and gas derivative financial instruments that the Company was a party to as of June 30, 2001. See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for information regarding the terms of the Company's derivative financial instruments that are sensitive to changes in oil and gas commodity prices. The Company continues to be a party to certain BTU swap agreements that mature at the end of 2004. The terms of the BTU swap agreements provide for the Company to be paid ten percent of the NYMEX oil price and to pay the NYMEX gas price on a notional 13,036 MMBtu daily gas volume. These BTU swap agreements do not qualify for hedge accounting treatment. Prior to June 30, 2001, the BTU swap agreements were presented in both of the accompanying Oil Price Sensitivity and Gas Price Sensitivity tables, since their fair values were sensitive to changes in the market prices of each commodity. During the three months ended June 30, 2001, the Company entered into offsetting swap agreements that have fixed the prices that are receivable to and payable by the Company under the BTU swap agreements. Consequently, the fair values of the Company's BTU swap agreements, which represent a discounted liability to the Company of $22.3 million as of June 30, 2001, are no longer sensitive to changes in oil or gas commodity prices. The undiscounted future settlement obligations of the Company under the BTU swap agreements are $3.6 million during the six months ending December 31, 2001 and $7.2 million per year for each of 2002, 2003 and 2004. 34 Pioneer Natural Resources Company Oil Price Sensitivity Derivative Financial Instruments as of June 30, 2001 Fair Value 2001 2002 2003 Asset (Liability) --------- --------- --------- ----------------- (in thousands, except volumes and prices) Oil Hedge Derivatives: Average daily notional Bbl volumes (1): Swap contracts.............................. 20,837 2,466 2,975 $ 10,723 Weighted average per Bbl fixed price..... $ 28.60 $ 27.20 $ 24.02 Collar contracts............................ 2,000 4,959 $ (1,021) Weighted average short call per Bbl ceiling price.......................... $ 31.43 $ 28.56 Weighted average long put per Bbl floor price............................ $ 25.00 $ 25.00 Average forward NYMEX oil prices (2)................................ $ 26.15 $ 24.43 $ 22.81
- --------------- (1) See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for hedge volumes and weighted average prices by calendar quarter. (2) The average forward NYMEX oil prices are based on July 26, 2001 market quotes. Pioneer Natural Resources Company Gas Price Sensitivity Derivative Financial Instruments as of June 30, 2001 2001 2002 2003 2004 Fair Value -------- -------- -------- -------- ---------- (in thousands, except volumes and prices) Gas Hedge Derivatives (1): Average daily notional MMBtu volumes (2): Swap contracts............................. 120,038 80,000 100,000 100,000 $ 91,006 Weighted average per MMBtu fixed price.. $ 4.30 $ 4.71 $ 4.13 $ 4.13 Collar contracts........................... 54,482 20,000 $ 2,979 Weighted average short call per MMBtu ceiling price......................... $ 2.74 $ 6.00 Weighted average long put per MMBtu contingent floor price............... $ 2.11 $ 4.50 Average forward NYMEX gas prices (3)............................... $ 3.33 $ 3.66 $ 3.76 $ 3.81
- --------------- (1) To minimize basis risk, the Company enters into basis swaps for a portion of its gas hedges to connect the index price of the hedging instrument from a NYMEX index to an index which reflects the geographic area of production. The Company considers these basis swaps as part of the associated swap and option contracts and, accordingly, the effects of the basis swaps have been presented together with the associated contracts. (2) See Note C of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements" for hedge volumes and weighted average prices by calendar quarter. (3) The average forward NYMEX oil and gas prices are based on July 26, 2001 market quotes. Other price sensitivity. During the six months ended June 30, 2001, the Company sold its remaining shares of Prize common stock for $12.7 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 2000 Annual Report on Form 10-K which is available from the United States Securities and Exchange Commission. 35 PART II. OTHER INFORMATION Item 1. Legal Proceedings As discussed in Note E of Notes to Consolidated Financial Statements included in "Item 1. Financial Statements", the Company is a party to various legal actions incidental to its business. The probable damages from such legal actions are not expected to be 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 17, 2001 in Irving, Texas. At the meeting, two proposals were submitted for vote of stockholders (as described in the Company's Proxy Statement dated April 9, 2001). The following is a brief description of the proposal and results of the stockholders' votes. Election of Directors. Prior to the meeting, the Company's Board of Directors designated two nominees as Class I directors with their terms to expire at the annual meeting in 2004 when their successors are elected and qualified. Messrs. Gardner and Houghton were, at the time of such nomination and at the time of the meeting, directors of the Company. Each nominee was re-elected as a director of the Company, with the results of the stockholder voting being as follows: Authority Broker For Withheld Abstain Non-Votes ---------- --------- ------- --------- R. Hartwell Gardner 89,871,701 1,505,116 - - James L. Houghton 89,864,551 1,512,266 - - The term of office for the following directors continues as of June 30, 2001: Scott D. Sheffield, James R. Baroffio, R. Hartwell Gardner, James L. Houghton, Jerry P. Jones, 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 2001 was submitted to the stockholders for ratification. Such election was ratified, with the results of the stockholder voting being as follows: For 91,069,059 Against 191,818 Abstain 115,940 Broker non-votes - Item 6. Exhibits and Reports on Form 8-K Exhibits None Reports on Form 8-K On April 27, 2001, the Company filed a Current Report on Form 8-K to report, under Item 7 and Item 9, the Company's financial and operating results for the three month period ended March 31, 2001. 36 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 hereto duly authorized. PIONEER NATURAL RESOURCES COMPANY Date: August 6, 2001 By: /s/ Timothy L. Dove --------------------------------- Timothy L. Dove Executive Vice President and Chief Financial Officer Date: August 6, 2001 By: /s/ Rich Dealy --------------------------------- Rich Dealy Vice President and Chief Accounting Officer 37 -----END PRIVACY-ENHANCED MESSAGE-----