-----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, FEDbQvrtukWsisVkNaWSYvyp/l0W4aBhg1biI1ppglEDgVJNEJU/j9mmSOWxmyJx wl5ohnpIRNWpmwe62+ss7g== 0000950129-99-003398.txt : 19990809 0000950129-99-003398.hdr.sgml : 19990809 ACCESSION NUMBER: 0000950129-99-003398 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19990630 FILED AS OF DATE: 19990730 FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENRON OIL & GAS CO CENTRAL INDEX KEY: 0000821189 STANDARD INDUSTRIAL CLASSIFICATION: CRUDE PETROLEUM & NATURAL GAS [1311] IRS NUMBER: 470684736 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: SEC FILE NUMBER: 001-09743 FILM NUMBER: 99675215 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138535482 10-Q 1 ENRON OIL & GAS COMPANY - 6/30/99 1 ================================================================================ SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 ------------ FORM 10-Q ------------ [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 30, 1999 [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 COMMISSION FILE NUMBER: 1-9743 ENRON OIL & GAS COMPANY (Exact name of registrant as specified in its charter) DELAWARE 47-0684736 (State or other jurisdiction (I.R.S. Employer of incorporation or organization) Identification No.) 1400 SMITH STREET, HOUSTON, TEXAS 77002-7369 (Address of principal executive offices) (zip code) REGISTRANT'S TELEPHONE NUMBER, INCLUDING AREA CODE: 713-853-6161 ------------ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes [X] No [ ]. Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of July 26, 1999.
TITLE OF EACH CLASS NUMBER OF SHARES ------------------- ---------------- Common Stock, $.01 par value 153,914,790 shares
================================================================================ -1- 2 ENRON OIL & GAS COMPANY TABLE OF CONTENTS
PAGE NO. -------- PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements Consolidated Statements of Income - Three Months Ended June 30, 1999 and 1998 and Six Months Ended June 30, 1999 and 1998.............................................................. 3 Consolidated Balance Sheets - June 30, 1999 and December 31, 1998............................................ 4 Consolidated Statements of Cash Flows - Six Months Ended June 30, 1999 and 1998.............................. 5 Notes to Consolidated Financial Statements................................................................... 6 ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations................ 10 PART II. OTHER INFORMATION ITEM 1. Legal Proceedings................................................................................ 21 ITEM 4. Submission of Matters to a Vote of Security Holders.............................................. 21 ITEM 6. Exhibits and Reports on Form 8-K................................................................. 21
-2- 3 PART I. FINANCIAL INFORMATION ITEM 1. FINANCIAL STATEMENTS ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF INCOME (In Thousands Except Per Share Amounts) (Unaudited)
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ---------------------- ---------------------- 1999 1998 1999 1998 --------- --------- --------- --------- NET OPERATING REVENUES Natural Gas Trade $ 127,508 $ 135,113 $ 244,775 $ 264,680 Associated Companies 28,251 15,510 41,094 38,533 Crude Oil, Condensate and Natural Gas Liquids Trade 36,740 27,277 63,257 57,514 Associated Companies 223 2,815 1,259 5,554 Gains (Losses) on Sales of Reserves and Related Assets and Other, Net (5,527) 2,592 (4,236) 16,857 --------- --------- --------- --------- TOTAL 187,195 183,307 346,149 383,138 OPERATING EXPENSES Lease and Well 23,538 22,857 47,607 47,766 Exploration Costs 10,302 16,600 27,091 33,998 Dry Hole Costs 2,130 2,281 2,475 10,162 Impairment of Unproved Oil and Gas Properties 7,984 7,355 15,987 15,703 Depreciation, Depletion and Amortization 88,781 73,071 170,803 145,032 General and Administrative 26,384 15,204 50,019 31,758 Taxes Other Than Income 12,381 13,270 26,076 27,764 --------- --------- --------- --------- TOTAL 171,500 150,638 340,058 312,183 --------- --------- --------- --------- OPERATING INCOME 15,695 32,669 6,091 70,955 OTHER INCOME (EXPENSE), NET 31,352 (73) 58,290 (1,043) --------- --------- --------- --------- INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 47,047 32,596 64,381 69,912 INTEREST EXPENSE, NET 14,774 10,423 29,041 19,533 --------- --------- --------- --------- INCOME BEFORE INCOME TAXES 32,273 22,173 35,340 50,379 INCOME TAX PROVISION 11,635 8,916 9,636 10,117 --------- --------- --------- --------- NET INCOME $ 20,638 $ 13,257 $ 25,704 $ 40,262 ========= ========= ========= ========= NET INCOME PER SHARE OF COMMON STOCK Basic $ 0.13 $ 0.09 $ 0.17 $ 0.26 ========= ========= ========= ========= Diluted $ 0.13 $ 0.09 $ 0.17 $ 0.26 ========= ========= ========= ========= AVERAGE NUMBER OF COMMON SHARES Basic 153,825 154,857 153,779 154,797 ========= ========= ========= ========= Diluted 155,271 155,770 154,943 155,646 ========= ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. -3- 4 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 1. FINANCIAL STATEMENTS - (CONTINUED) ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (In Thousands)
JUNE 30, DECEMBER 31, 1999 1998 ----------- ----------- (UNAUDITED) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 11,411 $ 6,303 Accounts Receivable Trade 159,469 176,608 Associated Companies 12,795 16,980 Inventories 35,175 39,581 Other 6,420 6,878 ----------- ----------- TOTAL 225,270 246,350 OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD) 4,965,113 4,814,425 Less: Accumulated Depreciation, Depletion and Amortization (2,298,265) (2,138,062) ----------- ----------- Net Oil and Gas Properties 2,666,848 2,676,363 OTHER ASSETS 69,928 95,382 ----------- ----------- TOTAL ASSETS $ 2,962,046 $ 3,018,095 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Trade $ 119,664 $ 159,690 Associated Companies 41,014 46,597 Accrued Taxes Payable 16,465 20,087 Dividends Payable 4,736 4,710 Other 17,608 31,550 ----------- ----------- TOTAL 199,487 262,634 LONG-TERM DEBT Trade 1,073,883 942,779 Affiliate 66,000 200,000 OTHER LIABILITIES Trade 19,004 21,516 Associated Companies 26,085 46,327 DEFERRED INCOME TAXES 265,444 260,337 DEFERRED REVENUE 2,099 4,198 SHAREHOLDERS' EQUITY Common Stock, $.01 Par, 320,000,000 Shares Authorized and 160,000,000 Shares Issued 201,600 201,600 Additional Paid In Capital 401,042 401,524 Unearned Compensation (4,183) (4,900) Cumulative Foreign Currency Translation Adjustment (26,124) (35,848) Retained Earnings 854,846 838,371 Common Stock Held in Treasury, 6,104,863 shares at June 30, 1999 and 6,276,156 shares at December 31, 1998 (117,137) (120,443) ----------- ----------- TOTAL SHAREHOLDERS' EQUITY 1,310,044 1,280,304 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 2,962,046 $ 3,018,095 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. -4- 5 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 1. FINANCIAL STATEMENTS - (CONTINUED) ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands) (Unaudited)
SIX MONTHS ENDED JUNE 30, ---------------------- 1999 1998 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income $ 25,704 $ 40,262 Items Not Requiring Cash Depreciation, Depletion and Amortization 170,803 145,032 Impairment of Unproved Oil and Gas Properties 15,987 15,703 Deferred Income Taxes 4,317 11,980 Other, Net 410 3,520 Exploration Costs 27,091 33,998 Dry Hole Costs 2,475 10,162 Losses (Gains) on Sales of Reserves and Related Assets and Other, Net 6,723 (13,447) Gains on Sales of Other Assets (59,647) -- Other, Net (13,322) (4,100) Changes in Components of Working Capital and Other Liabilities Accounts Receivable 19,226 40,213 Inventories 4,406 (2,776) Accounts Payable (46,285) (37,391) Accrued Taxes Payable (3,622) (14,208) Other Liabilities (3,909) (23,196) Other, Net (11,234) (5,034) Amortization of Deferred Revenue -- (21,494) Changes in Components of Working Capital Associated with Investing and Financing Activities 16,019 14,665 --------- --------- NET OPERATING CASH INFLOWS 155,142 193,889 INVESTING CASH FLOWS Additions to Oil and Gas Properties (179,749) (270,684) Exploration Costs (27,091) (33,998) Dry Hole Costs (2,475) (10,162) Proceeds from Sales of Reserves and Related Assets 2,756 54,688 Proceeds from Sales of Other Assets 83,015 -- Changes in Components of Working Capital Associated with Investing Activities (15,811) (14,518) Other, Net (1,201) (5,604) --------- --------- NET INVESTING CASH OUTFLOWS (140,556) (280,278) FINANCING CASH FLOWS Long-Term Debt Trade 131,104 302,085 Affiliate (134,000) (192,500) Dividends Paid (9,203) (9,268) Treasury Stock Purchased -- (7,969) Proceeds from Sales of Treasury Stock 2,949 2,222 Other, Net (328) (3,943) --------- --------- NET FINANCING CASH INFLOWS (OUTFLOWS) (9,478) 90,627 --------- --------- INCREASE IN CASH AND CASH EQUIVALENTS 5,108 4,238 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 6,303 9,330 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 11,411 $ 13,568 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. -5- 6 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 1. FINANCIAL STATEMENTS - (CONTINUED) ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 1. The consolidated financial statements of Enron Oil & Gas Company and subsidiaries (the "Company") included herein have been prepared by management without audit pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they reflect all adjustments which are, in the opinion of management, necessary for a fair presentation of the financial results for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations. However, management believes that the disclosures are adequate to make the information presented not misleading. These consolidated financial statements should be read in conjunction with the consolidated financial statements and the notes thereto included in the Company's Annual Report on Form 10-K for the year ended December 31, 1998. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. Certain reclassifications have been made to prior period financial statements to conform with the current presentation. As more fully discussed in Notes 1 and 14 to the consolidated financial statements included in the Company's 1998 Annual Report on Form 10-K, the Company engages in price risk management activities from time to time primarily for non-trading and to a lesser extent for trading purposes. Derivative financial instruments (primarily price swaps and costless collars) are utilized for non-trading purposes to hedge the impact of market fluctuations on natural gas and crude oil market prices. Hedge accounting is utilized in non-trading activities when there is a high degree of correlation between price movements in the derivative and the item designated as being hedged. Gains and losses on derivative financial instruments used for hedging purposes are recognized as revenue in the same period as the hedged item. Gains and losses on hedging instruments that are closed prior to maturity are deferred in the consolidated balance sheets. In instances where the anticipated correlation of price movements does not occur, hedge accounting is terminated and future changes in the value of the derivative are recognized as gains or losses using the mark-to-market method of accounting. Derivative and other financial instruments utilized in connection with trading activities, primarily price swaps and call options, are accounted for using the mark-to-market method, under which changes in the market value of outstanding financial instruments are recognized as gains or losses in the period of change. The cash flow impact of derivative and other financial instruments used for non-trading and trading purposes is reflected as cash flows from operating activities in the consolidated statements of cash flows. 2. Natural gas revenues, trade for the three-month and six-month periods ended June 30, 1999 and 1998, are net of costs of natural gas purchased for sale related to natural gas marketing activities of $12.5 million, $11.8 million, $20.9 million and $24.3 million, respectively. Natural gas revenues, associated for the three-month and six-month periods ended June 30, 1999 and 1998, are net of costs of natural gas purchased for sale related to natural gas marketing activities of $0.3 million, $12.0 million, $13.4 million and $24.4 million, respectively. 3. The income tax provision for the six-month period ended June 30, 1999 was calculated using the annual effective rate method. The income tax provision for the three-month period ended June 30, 1999 was calculated as the difference between the six-month period ended June 30, 1999 provision and the three-month period ended March 31, 1999 provision, which was calculated using the actual effective rate for that period. The income tax provision for the prior year periods was calculated using the annual effective rate method. Income tax provision for the three-month and six-month periods ended June 30, 1999 and 1998 includes tax benefits of $0.5 million, $2.5 million, $3.2 million and $3.8 million, respectively, related to tight gas sand federal income tax credit utilization. Additionally, the income tax provision for the three-month and six-month periods ended June 30, 1999 includes a benefit of $4.4 million from the anticipated disposition of certain international assets and other benefits of $0.4 million from the resolution of certain domestic issues. The income tax provision for the six-month period ended June 30, 1998 includes a benefit of $3.4 million from certain international costs and other benefits of $5.0 million from the resolution of certain state and international issues. 4. The difference between the average number of common shares outstanding for basic and diluted net income per share of common stock is due to the assumed issuance of approximately 1,446,000, 913,000, 1,164,000 and 849,000 common shares relating to employee stock options in the three-month and six-month periods ended June 30, 1999 and 1998, respectively. -6- 7 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 1. FINANCIAL STATEMENTS - (CONTINUED) ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. The Company's total comprehensive income was $26.9 million, $4.1 million, $35.4 million and $33.3 million for the three-month and six-month periods ended June 30, 1999 and 1998, respectively. The only adjustment made to net income in the periods was for a foreign currency translation gain of $6.3 million, loss of $9.2 million, gain of $9.7 million and loss of $7.0 million for the three-month and six-month periods ended June 30, 1999 and 1998, respectively. 6. Selected financial information about operating segments is reported below for the three-month and six-month periods ended June 30, 1999 and 1998:
THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ---------------------- ---------------------- 1999 1998 1999 1998 --------- --------- --------- --------- NET OPERATING REVENUES United States $ 135,377 $ 132,726 $ 242,269 $ 284,013 Canada 21,086 15,779 37,310 32,710 Trinidad 15,690 16,496 32,689 30,780 India (1) 21,432 18,294 40,265 35,646 China (1) 2 -- 4 -- Other (6,392) 12 (6,388) (11) --------- --------- --------- --------- TOTAL $ 187,195 $ 183,307 $ 346,149 $ 383,138 ========= ========= ========= ========= OPERATING INCOME (LOSS) United States $ 1,904 $ 16,755 $ (16,610) $ 42,129 Canada 6,505 2,275 8,847 4,763 Trinidad 9,506 10,469 19,637 18,696 India (1) 12,324 10,277 15,830 19,452 China (1) (2,631) (1,959) (4,998) (3,904) Other (11,913) (5,148) (16,615) (10,181) --------- --------- --------- --------- TOTAL 15,695 32,669 6,091 70,955 RECONCILING ITEMS Other Income (Expense), Net 31,352 (73) 58,290 (1,043) Interest Expense, Net 14,774 10,423 29,041 19,533 --------- --------- --------- --------- INCOME BEFORE INCOME TAXES $ 32,273 $ 22,173 $ 35,340 $ 50,379 ========= ========= ========= =========
- ------------------ (1) See Note 10. 7. As reported in the Company's Annual Report on Form 10-K for the year ended December 31, 1998, Enron Oil & Gas India Ltd. ("EOGIL"), a wholly-owned subsidiary of the Company, is a respondent in two public interest lawsuits filed in the Delhi High Court, India. The first (the "Wadehra Action") was brought by B. L. Wadehra, an Indian public interest lawyer, against the Union of India, EOGIL, EOGIL co-participants in the Panna and Mukta fields, Reliance Industries Limited ("Reliance") and Oil & Natural Gas Corporation Limited ("ONGC"), and certain other respondents. ONGC is the Indian national oil company and is wholly-owned by the Union of India. The second suit (the "CPIL Action") was brought by the Centre for Public Interest Litigation and the National Alliance of People's Movement against the Union of India, the Central Bureau of Investigation, ONGC, Reliance and EOGIL. Petitioners in both the Wadehra Action and the CPIL Action allege various improprieties in the award of the Panna and Mukta fields to EOGIL, Reliance and ONGC, and seek the cancellation of the Production Sharing Contract for the Panna and Mukta fields. The Union of India is vigorously disputing these allegations. The Company believes that the public competitive bidding process for the fields was fair and that the award of these fields to EOGIL, Reliance and ONGC was proper. Following a series of hearings, the Delhi High Court has entered an order dismissing both lawsuits. The India Supreme Court has agreed to hear the plaintiffs' appeal of the decision of the Delhi High Court. Although no assurances can be given, based on currently available information the Company believes that the ultimate resolution of these matters will not have a material adverse effect on its financial condition or results of operations. -7- 8 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 1. FINANCIAL STATEMENTS - (CONTINUED) ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS On July 21, 1999, two stockholders of the Company filed separate lawsuits purportedly on behalf of the Company against Enron Corp. and the Company's directors, alleging that Enron Corp. and the Company's directors breached their fiduciary duties of good faith and loyalty in approving the Share Exchange described in Note 10 below. The lawsuits seek to temporarily and permanently enjoin the Share Exchange and seek compensatory damages and costs and expenses, including reasonable attorneys' and experts' fees. The Company, Enron Corp. and the Company's directors believe the lawsuits are without merit and intend to vigorously contest them. There are various other suits and claims against the Company that have arisen in the ordinary course of business. However, management does not believe these suits and claims will individually or in the aggregate have a material adverse effect on the Company's financial condition or results of operations. The Company has been named as a potentially responsible party in certain Comprehensive Environmental Response Compensation and Liability Act proceedings. However, management does not believe that any potential assessments resulting from such proceedings will individually or in the aggregate have a materially adverse effect on the financial condition or results of operations of the Company. 8. In June 1998, the Financial Accounting Standards Board ("FASB") issued Statement of Financial Accounting Standards ("SFAS") No. 133 - "Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. In June 1999, the FASB issued SFAS No. 137, which delays the effective date of SFAS No. 133 for one year, to fiscal years beginning after June 15, 2000. SFAS No. 133, as amended by SFAS No. 137, cannot be applied retroactively and must be applied to (a) derivative instruments and (b) certain derivative instruments embedded in hybrid contracts that were issued, acquired or substantively modified after a transition date to be selected by the Company of either December 31, 1997 or December 31, 1998. The statement establishes accounting and reporting standards requiring that every derivative instrument be recorded in the balance sheet as either an asset or liability measured at its fair value. The statement requires that changes in the derivative's fair value be recognized currently in earnings unless specific hedge accounting criteria are met. Special accounting for qualifying hedges allows a derivative's gains and losses to offset related results on the hedged item in the statements of income and requires a company to formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. The Company has not yet quantified the impacts of adopting SFAS No. 133 on its financial statements and has not determined the timing of adoption. Based on the Company's current level of derivative and hedging activities, the Company does not expect the impact of adoption to be material. 9. During the first and second quarters of 1999, the Company sold its 3.2 million options to purchase common stock of Enron Corp. having a strike price of $39.1875 per share. In the first quarter of 1999, the Company sold 1.6 million options at an average price of $24.81 ($64.00 Enron Corp. stock price equivalent), realizing net proceeds of $40 million and a gain of $28 million pre-tax ($18 million after-tax). Early in the second quarter, the Company sold the remaining 1.6 million options at an average price of $27.07 ($66.26 Enron Corp. stock price equivalent), realizing net proceeds of $43 million and a gain of $32 million pre-tax ($21 million after-tax). 10. On July 20, 1999, the Company and Enron Corp. announced an agreement whereby the Company will receive 62,270,000 shares of the Company's common stock out of 82,270,000 shares currently owned by Enron Corp. in exchange for all the stock of the Company's subsidiary, EOGI-India, Inc. Prior to the share exchange, the Company will make an indirect capital contribution of $600,000,000 in cash, plus certain intercompany receivables, to EOGI-India, Inc. At the time of completion of this transaction, this subsidiary will own, through subsidiaries, all of the Company's assets and operations in India and China. The Company expects this transaction to be tax-free to Enron Corp. and the Company. Some time after the share exchange, the Company expects to change its corporate name to "EOG Resources, Inc." and will make appropriate changes to its subsidiaries' names. The completion of the Share Exchange Agreement (the "Share Exchange") is subject to specific conditions and will occur on the later of August 31, 1999 and three days after all conditions have been satisfied or waived. If prior to August 31, 1999, all conditions to the Share Exchange have been satisfied or waived, the Company can require that the Share Exchange take place prior to August 31, 1999. The Company currently expects the Share Exchange to close on or before August 31, 1999. -8- 9 On July 23, 1999, the Company filed a registration statement with the Securities and Exchange Commission for the public offering of 27,000,000 shares of the Company's common stock. The proceeds will be used to fund a significant portion of the cash capital contribution (or to repay debt incurred to fund such capital contribution) in connection with the Share Exchange. PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 1. FINANCIAL STATEMENTS - (CONCLUDED) ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS As a result of the change to the Company's portfolio of assets subsequent to the Share Exchange, the Company is currently re-evaluating its overall business. The Company expects to complete this re-evaluation by the end of third quarter 1999. As a result of this re-evaluation, some of the Company's current projects may no longer be deemed central to its business. In that case, the Company may incur non-cash charges in connection with the disposition of such projects of up to approximately $75 million, after-tax. On July 28, 1999, the Company executed a series of new credit agreements aggregating $1.3 billion (the "Credit Facilities"). At the same time, the Company cancelled its existing credit facilities totaling $450 million. Of the $1.3 billion, $500 million will expire in 364 days (the "Interim Facility"), $400 million is structured as a 364-day revolving credit facility with a one-year term subsequent to the revolving period and $400 million is structured as a five-year revolving credit facility. The Interim Facility will be cancelled (or if advances have been made under the Interim Facility, such advances will be repaid and then the Interim Facility will be cancelled) when the Company receives the proceeds from the equity issuance mentioned above. The Credit Facilities contain financial covenants which may restrict to some extent the Company's ability to incur additional indebtedness. Management of the Company does not view these convenants as being materially restrictive given current market conditions. -9- 10 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS ENRON OIL & GAS COMPANY The following review of operations for the three-month and six-month periods ended June 30, 1999 and 1998 should be read in conjunction with the consolidated financial statements of Enron Oil & Gas Company (the "Company") and Notes thereto. RESULTS OF OPERATIONS Three Months Ended June 30, 1999 vs. Three Months Ended June 30, 1998 The Company generated second quarter net income of $21 million compared to net income of $13 million for the second quarter of 1998. Net operating revenues were $187 million as compared to $183 million for the second quarter of 1998. Following is an explanation of the variances causing this increase. Wellhead volume and price statistics are summarized below:
1999 1998 --------- --------- NATURAL GAS VOLUMES (MMCF PER DAY) (1) United States 642 624 (2) Canada 112 98 --------- --------- North America 754 722 Trinidad 130 132 India (6) 75 53 --------- --------- TOTAL 959 907 ========= ========= AVERAGE NATURAL GAS PRICES ($/MCF) (3) United States $ 1.99 $ 2.04 (4) Canada 1.63 1.41 North America Composite 1.93 1.96 Trinidad 1.07 1.08 India (6) 1.95 2.57 COMPOSITE 1.82 1.87 CRUDE OIL/CONDENSATE VOLUMES (MBBL PER DAY) (1) United States 13.1 12.2 Canada 2.7 2.5 --------- --------- North America 15.8 14.7 Trinidad 2.3 2.9 India (6) 6.4 4.8 --------- --------- TOTAL 24.5 22.4 ========= ========= AVERAGE CRUDE OIL/CONDENSATE PRICES ($/BBL) (3) United States $ 16.48 $ 13.10 Canada 14.26 11.47 North America Composite 16.10 12.82 Trinidad 14.46 13.31 India (6) 14.03 13.41 COMPOSITE 15.41 13.01 NATURAL GAS EQUIVALENT VOLUMES (MMCFE PER DAY) (5) United States 737 713 Canada 135 119 --------- --------- North America 872 832 Trinidad 144 149 India (6) 113 82 --------- --------- TOTAL 1,129 1,063 ========= ========= TOTAL BCFE (5) DELIVERIES 103 97 (2)
- ------------- (1) Million cubic feet per day or thousand barrels per day, as applicable. (2) Includes 48 MMcf per day delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998. (3) Dollars per thousand cubic feet or per barrel, as applicable. (4) Includes an average equivalent wellhead value of $1.57 per Mcf for the volumes described in note (2), net of transportation costs. (5) Million cubic feet equivalent per day or billion cubic feet equivalent, as applicable. (6) See Note 10 to the Consolidated Financial Statements. -10- 11 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED) ENRON OIL & GAS COMPANY Wellhead revenues increased 7% to $196 million in the second quarter of 1999 compared to $183 million in the second quarter of 1998. Average wellhead crude oil and condensate prices were approximately 18% higher than the comparable period in 1998, increasing net operating revenues by $5 million. Average wellhead natural gas prices were down by 3%, decreasing net operating revenues by $4 million. Second quarter 1999 wellhead natural gas deliveries were approximately 6% higher than the comparable period in 1998 increasing net operating revenues by $9 million. Natural gas deliveries in North America increased 4% from the prior year period primarily due to the third quarter 1998 acquisition of producing properties in the Gulf of Mexico, increased deliveries in East Texas and increased natural gas production in the Blackfoot and Sandhills fields in Canada. Natural gas deliveries in India increased 42% to 75 MMcf per day due to continuing development activities in the Tapti and Panna fields. Wellhead crude oil and condensate deliveries were 9% higher than the prior year period increasing net operating revenues by $3 million. The increase is primarily attributable to a 33% increase in India and a 7% improvement in North America primarily in the West Texas and East Texas areas. Gains (losses) on sales of reserves and related assets and other, net totaled a $5.5 million loss in the second quarter of 1999 compared to a $2.6 million gain in the comparable period of 1998. Included in 1999 was a $6.4 million loss related to the anticipated dispostion of certain international assets. Operating expenses of $172 million for the second quarter of 1999 were approximately $21 million higher than the second quarter of 1998. Depreciation, depletion and amortization ("DD&A") expense increased approximately $16 million compared to the prior year period, primarily reflecting a non-recurring charge of $7.8 million recorded pursuant to a change in strategy related to the pursuit of certain offshore operations by the Company, increased worldwide production volumes and a higher per-unit rate in North America. General and administrative ("G&A") expense was $11 million higher than the prior year period primarily due to non-recurring costs of $8.9 million related to the potential sale of the Company and personnel expenses. Exploration and dry hole costs were $6 million lower than the second quarter of 1998 primarily due to decreased exploratory drilling and other exploration activities. The per unit operating costs of the Company for lease and well, DD&A, G&A, interest expense, and taxes other than income averaged $1.61 per Mcfe during the second quarter of 1999 compared to $1.39 per Mcfe during the second quarter of 1998. The increase is primarily due to a higher per unit rate of interest, G&A and DD&A expenses, partially offset by a lower per unit rate of lease and well expense and taxes other than income. Excluding the previously mentioned non-recurring charges of $7.8 million in DD&A and $8.9 million in G&A, the per unit operating costs of the Company were $1.45 per Mcfe in the second quarter of 1999. Interest expense, net increased $4 million as compared to the second quarter of 1998 reflecting a higher level of long-term debt due to expanded worldwide operations. Other income (expense), net for the second quarter of 1999 included a $32 million pre-tax gain on the sale of 1.6 million of the Company's options to purchase Enron Corp. common stock (See Note 9 to the Consolidated Financial Statements). Income tax provision increased $3 million as compared to the second quarter of 1998 primarily due to higher pre-tax income partially offset by tax benefits related to the anticipated disposition of certain international assets. Additionally, the income tax provision for the six-month period ended June 30, 1999 was calculated using the annual effective rate method. The income tax provision for the three-month period ended June 30, 1999 was calculated as the difference between the six-month period ended June 30, 1999 provision and the three-month period ended March 31, 1999 provision, which was calculated using the actual effective rate for that period. The income tax provision for the prior year periods was calculated using the annual effective rate method. -11- 12 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS- (CONTINUED) ENRON OIL & GAS COMPANY Six Months Ended June 30, 1999 vs. Six Months Ended June 30, 1998 In the first half of 1999, the Company generated net income of $26 million compared to net income of $40 million for the first half of 1998. Net operating revenues for the first half of 1999 were $346 million as compared to $383 million for the first half of 1998. Wellhead volume and price statistics are as follows:
1999 1998 --------- --------- NATURAL GAS VOLUMES (MMCF PER DAY) United States 659 634 (1) Canada 108 99 --------- --------- North America 767 733 Trinidad 141 121 India (3) 74 50 --------- --------- TOTAL 982 904 ========= ========= AVERAGE NATURAL GAS PRICES ($/MCF) United States $ 1.80 $ 2.03 (2) Canada 1.51 1.40 North America Composite 1.76 1.94 Trinidad 1.07 1.08 India (3) 1.95 2.63 COMPOSITE 1.67 1.87 CRUDE OIL/CONDENSATE VOLUMES (MBBL PER DAY) United States 13.1 12.4 Canada 2.7 2.6 --------- --------- North America 15.8 15.0 Trinidad 2.6 2.8 India (3) 6.7 4.5 --------- --------- TOTAL 25.1 22.3 ========= ========= AVERAGE CRUDE OIL/CONDENSATE PRICES ($/BBL) United States $ 13.91 $ 13.90 Canada 13.03 12.77 North America Composite 13.76 13.70 Trinidad 11.83 13.66 India (3) 11.80 14.31 COMPOSITE 13.04 13.82 NATURAL GAS EQUIVALENT VOLUMES (MMCFE PER DAY) United States 754 724 (1) Canada 129 121 --------- --------- North America 883 845 Trinidad 156 138 India (3) 114 78 --------- --------- TOTAL 1,153 1,061 ========= ========= TOTAL BCFE DELIVERIES 209 192
- ------------------ (1) Includes 48 MMcf per day delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. Delivery obligations were terminated in December 1998. (2) Includes an average equivalent wellhead value of $1.59 per Mcf for the volumes described in note (1), net of transportation costs. (3) See Note 10 to the Consolidated Financial Statements. -12- 13 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED) ENRON OIL & GAS COMPANY Wellhead revenues decreased approximately 2% to $361 million in the first half of 1999 compared to $367 million in the first half of 1998. Average wellhead natural gas prices for the first half of 1999 were approximately 11% lower than the comparable period of 1998 reducing net operating revenues by approximately $34 million. Average wellhead crude oil and condensate prices were down by 6%, decreasing net operating revenues by $4 million. First half 1999 wellhead natural gas deliveries were approximately 9% higher than the comparable period in 1998 increasing net operating revenues by $26 million. Natural gas deliveries in North America increased 5% from the prior year period primarily due to the third quarter 1998 acquisition of producing properties in the Gulf of Mexico and increased deliveries in East Texas. Natural gas deliveries in India increased 48% to 74 MMcf per day due to continuing development activities in the Tapti and Panna fields. Natural gas deliveries in Trinidad were 17% higher due primarily to additional gas balancing volumes related to a field allocation agreement. Wellhead crude oil and condensate deliveries were 13% higher than the prior year period increasing net operating revenues by $7 million, primarily attributable to a 49% increase in India. Deliveries from the Panna and Mukta fields increased to 6.7 MBbl per day compared to 4.5 MBbl per day in the prior year period. Deliveries of crude oil and condensate in North America were up approximately 5% primarily in the West Texas and South Texas areas. Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price hedging and trading transactions, and 1998 margins related to the volumetric production payment decreased net operating revenues by $11 million compared to a revenue decrease of less than one million in the first half of 1998. This variance was primarily due to a $4 million revenue decrease in 1999 from natural gas hedging contracts closed in prior periods, (See Note 14 to the Consolidated Financial Statements in the Company's 1998 Annual Report on Form 10-K) as compared to a $4 million revenue increase related to natural gas hedging and trading activities in the first half of 1998. Gains (losses) on sales of reserves and related assets and other, net totaled a loss of $4 million in the first half of 1999 compared to a net gain of $17 million in the comparable prior year period. The difference is due primarily to a $6 million loss related to the anticipated disposition of certain international assets in the first half of 1999 compared to a $27 million gain on sale of certain South Texas properties, partially offset by a $14 million provision for loss on certain physical natural gas contracts in the first half of 1998. Operating expenses of $340 million for the first half of 1999 were approximately $28 million higher than the comparable period in 1998. DD&A increased approximately $26 million compared to the prior year period, primarily reflecting a non-recurring charge of $7.8 million recorded pursuant to a change in strategy related to the pursuit of certain offshore operations by the Company, increased worldwide production volumes and a higher per-unit rate in North America. G&A was $18 million higher than the prior year period primarily due to expanded operations, settlement of certain commercial disputes with third parties and non-recurring costs of $8.9 million related to the potential sale of the Company and personnel expenses. Exploration and dry hole costs were $15 million lower than the first half of 1998 primarily due to decreased exploratory drilling and other exploration activities and improved success on wildcat drilling prospects. Taxes other than income were down $2 million primarily due to lower state severance taxes associated with decreased wellhead revenues in the United States. The per unit operating costs of the Company for lease and well, DD&A, G&A, interest expense and taxes other than income averaged $1.55 per Mcfe during the first half of 1999 compared to $1.42 per Mcfe in 1998. This increase is primarily due to a higher per unit rate of G&A, interest and DD&A expenses, partially offset by a lower per unit rate of lease and well expense and taxes other than income. Excluding the previously mentioned non-recurring charges of $7.8 million in DD&A and $8.9 million in G&A, the per unit operating costs for the Company were $1.47 per Mcfe in the first half of 1999. Interest expense, net increased $10 million as compared to the first half of 1998 reflecting a higher level of long-term debt due to expanded worldwide operations and decreased cash flows resulting from the above mentioned decrease in wellhead prices. Other income (expense), net for the first half of 1999 included a $59.6 million pre-tax gain on the sale of 3.2 million options owned by the Company to purchase Enron Corp. common stock (See Note 9 to the Consolidated Financial Statements). -13- 14 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED) ENRON OIL & GAS COMPANY Income tax provision of $9.6 million for the first half of 1999 decreased $0.5 million as compared to the prior year period. The decrease in income taxes was primarily due to the lower pre-tax income partially offset by approximately $8.4 million in tax benefits in the first half of 1998 related to certain international costs and resolution of certain state and international issues as compared to only $4.4 million in 1999 benefits related to the anticipated disposition of certain international assets. Federal income taxes accrued in the six-month interim periods are calculated using the estimated annual effective income tax rate. CAPITAL RESOURCES AND LIQUIDITY The Company's primary sources of cash during the six months ended June 30, 1999 included funds generated from operations, proceeds from the sale of its options to purchase Enron Corp. common stock and proceeds from new borrowings. Primary cash outflows included funds used in operations, exploration and development expenditures, dividends paid to Company shareholders and the repayment of debt. Net operating cash flows of $155 million for the first half of 1999 decreased approximately $39 million as compared to the first half of 1998 primarily reflecting lower operating revenues, higher interest expense and higher cash operating expenses, partially offset by the termination of the volumetric production payment in December of 1998. Net investing cash outflows of approximately $141 million for the first half of 1999 decreased by $140 million versus the comparable prior year period due primarily to reduced exploration and development expenditures and proceeds related to the sale of its options to purchase Enron Corp. common stock, partially offset by lower proceeds from sales of reserves and related assets. Changes in Components of Working Capital Associated with Investing Activities included changes in accounts payable associated with the accrual of exploration and development expenditures and changes in inventories which represent materials and equipment used in drilling and related activities. Exploration and development expenditures for the first six months of 1999 and 1998 are as follows (in millions):
1999 1998 ---- ---- United States $160 $244 Canada 19 19 ---- ---- North America 179 263 Trinidad 2 13 India (1) 19 25 China (1) 6 2 Other 3 12 ---- ---- TOTAL $209 $315 ==== ====
- ----------------- (1) See Note 10 to the Consolidated Financial Statements. Exploration and development expenditures of $209 million for the first half of 1999 were $106 million lower than the prior year period due primarily to a reduced level of service industry costs as well as reduced spending on the North America, Trinidad and India drilling programs. Reduced drilling expenditures were partially offset by the acquisition of producing properties in the Big Piney area. The level of exploration and development expenditures will vary in future periods depending on energy market conditions and other related economic factors. The Company has significant flexibility with respect to financing alternatives and the ability to adjust its exploration and development expenditure budget as circumstances warrant. There are no material continuing commitments associated with expenditure plans. Cash used by financing activities was $9 million for the first half of 1999 versus a cash inflow of $91 million for the comparable prior year period. Financing activities for 1999 included the net repayment of $3 million of long-term debt and dividend payments of $9 million, partially offset by proceeds of $3 million from the exercise of stock options. There were no share repurchases in the first half of 1999, compared to $8 million of repurchases in the prior year period. Based upon existing economic and market conditions, management believes net operating cash flow and available financing alternatives will be sufficient to fund net investing and other cash requirements of the Company for the foreseeable future. -14- 15 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED) ENRON OIL & GAS COMPANY As disclosed in Note 10 to the Consolidated Financial Statements, the Company and Enron Corp. have entered into an agreement relating to a Share Exchange which requires, among other things, that the Company make indirectly a $600 million cash capital contribution to EOG-India, Inc. prior to the closing of the Share Exchange. As mentioned in that Note, the Company has filed a registration statement for the public offering of 27 million shares of its common stock (the "Offering"). As also discussed in that Note, the Company has executed a series of new credit agreements aggregating $1.3 billion (the "Credit Facilities"). If the Company completes the Share Exchange prior to closing the Offering, it will use funds borrowed under the Credit Facilities for the cash capital contribution and subsequently repay a portion of those borrowed funds with the net proceeds of the Offering. If the Company completes the Offering on the same day as the Share Exchange, it will use the proceeds of the Offering to pay a significant portion of the cash capital contribution in connection with the Share Exchange and will borrow the balance of funds needed for the Share Exchange under the Credit Facilities. If the Company is unable to complete the Offering at the time of or reasonably contemporaneously with the Share Exchange, the Company will experience increased interest costs associated with the borrowing of funds necessary to fund the cash capital contribution prior to closing the Share Exchange until the Offering can be completed. However, the Company has the capacity under the Credit Facilities to fund the cash capital contribution for a one-year term and, under current market conditions, has the ability to refinance the indebtedness. The Company also expects to maintain a strong ability to service the interest burden of this additional financing. As a result of the change to the Company's portfolio of assets subsequent to the Share Exchange, the Company is currently re-evaluating its overall business. The Company expects to complete this re-evaluation by the end of third quarter 1999. As a result of this re-evaluation, some of the Company's current projects may no longer be deemed central to its business. In that case, the Company may incur non-cash charges in connection with the disposition of such projects of up to approximately $75 million, after-tax. YEAR 2000 The Year 2000 problem generally results from the use in computer hardware and software of two digits rather than four digits to define the applicable year. When computer systems must process dates both before and after January 1, 2000, two-digit year "fields" may create processing ambiguities that can cause errors and system failures. For example, a date represented by "00" may be interpreted as referring to the year 1900, instead of 2000. The effects of the Year 2000 problem can be exacerbated by the interdependence of computer and telecommunications systems in the United States and throughout the world. This interdependence can affect the Company and its suppliers, trading partners, and customers, as well as governments of countries around the world where the Company does business. State of Readiness The Company Board of Directors has been briefed about the Year 2000 problem. The Board has adopted a Year 2000 Project (the "Project") aimed at preventing the Company's mission-critical functions from being impaired due to the Year 2000 problem. "Mission-critical" functions are those critical functions whose loss would cause an immediate stoppage of or significant impairment to core business processes (a core business process is one of material importance to the Company business). Implementation of the Project is directly supervised by a Year 2000 Oversight Committee, made up of four senior executives of the Company and its affiliates. Each operating division of the Company is implementing procedures specific to it that are part of the overall Project. The Company also has engaged certain outside consultants, technicians and other external resources to aid in formulating and implementing the Project. The Company is actively implementing the Project, which will be modified as events warrant. Under the Project, the Company will continue to inventory mission-critical computer hardware and software systems and embedded microprocessors (microprocessors with date-related functions, contained in a wide variety of devices), and software; assess the effects of Year 2000 problems on the mission-critical functions of the Company; remedy systems, software and embedded microprocessors in an effort to avoid material disruptions or other material adverse effects on mission-critical functions, processes and systems; verify and test the mission-critical systems to which remediation efforts have been applied; and attempt to mitigate those mission-critical aspects of the Year 2000 problem that are not remediated by January 1, 2000, including the development of contingency plans to cope with the mission-critical consequences of Year 2000 problems that have not been identified or remediated by that date. -15- 16 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED) ENRON OIL & GAS COMPANY The Project recognizes that the computer, telecommunications, and other systems ("Outside Systems") of outside entities ("Outside Entities") have the potential for major, mission-critical, adverse effects on the conduct of Company business. The Company does not have control of these Outside Entities or Outside Systems. (In some cases, Outside Entities are U.S., state and local governmental organizations, foreign governments or businesses located in foreign countries.) However, the Project includes an ongoing process of identifying and contacting Outside Entities whose systems in the Company's judgment have, or may have, a substantial effect on the Company's ability to continue to conduct the mission-critical aspects of Company business without disruption from Year 2000 problems. The Project envisions the Company making an attempt to inventory and assess the extent to which these Outside Systems may not be "Year 2000 ready" or "Year 2000 compatible". The Company will attempt reasonably to coordinate with these Outside Entities in an ongoing effort to obtain assurance that the Outside Systems that are mission-critical will be Year 2000 compatible well before January 1, 2000. Consequently, the Company will work with Outside Entities in a reasonable attempt to inventory, assess, analyze, convert (where necessary), test, and develop contingency plans for connections to these mission-critical Outside Systems and to ascertain the extent to which they are, or can be made to be, Year 2000 ready and compatible with the Company's remediation of its own mission-critical systems. As of July 15, 1999, the Company is at various stages in implementation of the Project, as shown in the following tables. Any notation of "complete" conveys the fact only that the initial iteration of this phase has been substantially completed. All dates are only relevant for the initial iteration of the applicable stage of the Project. YEAR 2000 PROJECT READINESS
Inventory Assessment Analysis Conversion Testing Y2K-Ready Contingency Plan --------- ---------- -------- ---------- ------- --------- ---------------- Mission-Critical Internal Items C C C C IP IP IP Mission-Critical Outside Entities C C C IP IP IP IP Legend: C = Complete IP = In Process
YEAR 2000 PROJECT ESTIMATED COMPLETION DATES
Inventory Assessment Analysis Conversion Testing Y2K-Ready Contingency Plan --------- ---------- -------- ---------- ------- --------- ---------------- Mission-Critical Internal Items 12/98 3/99 3/99 6/99 9/99 9/99 9/99 Mission-Critical Outside Entities 3/99 6/99 6/99 9/99 9/99 9/99 9/99
It is important to recognize that the processes of inventorying, assessing, analyzing, converting (where necessary), testing, and developing contingency plans for mission-critical items in anticipation of the Year 2000 event may be iterative processes, requiring a repeat of some or all of these processes as the Company learns more about the Year 2000 problem and its effects on internal business information systems and on Outside Systems, and about the effects of embedded microprocessors on systems and business operations. The Company anticipates that it will continue with these processes through January 1, 2000 and on into the Year 2000 in order to assess and remediate problems that reasonably can be identified only after the start of the new century. The Project envisions verification and validation of certain mission-critical facilities and functions by independent consultants. These consultants will participate to varying degrees in many or all of the stages, including the inventory, assessment, and testing phases. Currently, the Company is utilizing Raytheon Engineers & Constructors, Inc. to assist Company personnel in the inventory and assessment phases of onshore and offshore and domestic and international operations. Costs to Address Year 2000 Issues The Company has not incurred material historical costs for Year 2000 awareness, inventory, assessment, analysis, conversion, testing, or contingency planning and anticipates that any future costs for these purposes, including those for implementing Year 2000 contingency plans, are not likely to be material. -16- 17 Although management believes that its estimates are reasonable, there can be no assurance, for the reasons stated in the "Summary" section below, that the actual costs of implementing the Project will not differ materially from the estimated costs or that the Company will not be materially adversely affected by Year 2000 issues. PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED) ENRON OIL & GAS COMPANY Year 2000 Risk Factors Regulatory requirements. Certain of the Company's operations are regulated by governmental authorities. The Company expects to satisfy these regulatory authority requirements for achieving Year 2000 readiness. If the Company's reasonable expectations in this regard are in error, and if a regulatory authority should order the temporary cessation of operations in one or more of these areas, the adverse effect on the Company could be material. Outside Entities may face similar problems that materially adversely affect the Company. Shortage of Resources. Between now and 2000 it is anticipated that there will be increased competition for people with technical and managerial skills necessary to deal with the Year 2000 problem. While the Company is taking substantial precautions to recruit and retain sufficient people skilled in dealing with the Year 2000 problem, and has hired consultants who bring additional skilled people to deal with the Year 2000 problem, the Company could face shortages of skilled personnel or other resources, such as particular microprocessors or components containing Year 2000 ready microprocessors, and these shortages might delay or otherwise impair the Company's ability to assure that its mission-critical systems are Year 2000 ready. Outside Entities could face similar problems that materially adversely affect the Company. The Company believes that the possible impact of the shortage of skilled people and resources is not, and will not be, unique to the Company. Potential Shortcomings. The Company estimates that mission-critical systems, domestic and international, will be Year 2000-ready substantially before January 1, 2000. However, there is no assurance that the Project will succeed in accomplishing its purpose, or that unforeseen circumstances will not arise during implementation of the Project that would materially adversely affect the Company. Cascading Effect. The Company is taking reasonable steps to identify, assess, and, where appropriate, to replace devices that contain embedded microprocessors. Despite these reasonable efforts, the Company anticipates that it will not be able to find and remediate all embedded microprocessors in all systems. Further, it is anticipated that Outside Entities also will not be able to find and remediate all embedded microprocessors in their systems. Some of the embedded microprocessors that fail to operate or that produce anomalous results may create system disruptions or failures. Some of these disruptions or failures may spread from the systems in which they are located to other systems causing adverse effects upon the Company's ability to maintain safe operations, to serve its customers and otherwise to fulfill certain contractual and other legal obligations. The embedded microprocessor problem is widely recognized as one of the more difficult aspects of the Year 2000 problem across industries and throughout the world. The possible adverse impact of the embedded microprocessor problem is not, and will not be, unique to the Company. Third parties. The Company cannot assure that suppliers upon which it depends for essential goods and services will convert and test their mission-critical systems and processes in a timely manner. Failure or delay by all or some of these entities, including the U.S. and state or local governments and foreign governments, could create substantial disruptions having a material adverse effect on Company business. Contingency Plans As part of the Project, the Company is developing contingency plans that deal with, among others, two primary aspects of the Year 2000 problem: (1) that the Company, despite its good-faith, reasonable efforts, may not have satisfactorily remediated all internal, mission-critical systems; and (2) that Outside Systems may not be Year 2000 ready, despite the Company's good-faith, reasonable efforts to work with Outside Entities. These contingency plans are being designed to mitigate the disruptions or other adverse effects resulting from Year 2000 incompatibilities regarding these mission-critical functions or systems, and to facilitate the early identification and remediation of mission-critical Year 2000 problems that first manifest themselves after January 1, 2000. These contingency plans will contemplate an assessment of all mission-critical internal information technology systems and internal operational systems that use computer-based controls. This process will be pursued continuously into the Year 2000 as -17- 18 circumstances require. Further, the Company will in that time frame assess any mission-critical disruptions due to Year 2000-related failures that are external to the Company. These contingency plans include the creation, as deemed reasonably appropriate, of teams that will be standing by on the eve of the new millennium, prepared to respond rapidly and otherwise as necessary to mission-critical Year 2000-related problems as soon as they become known. The composition of teams that are assigned to deal with Year 2000 problems will vary according to the nature, mission-criticality, and location of the problem. Because the Company operates internationally, some of its Year 2000 contingency teams will be located at mission-critical facilities overseas. -18- 19 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONTINUED) ENRON OIL & GAS COMPANY Worst Case Scenario The Securities and Exchange Commission requires that public companies must forecast the most reasonably likely worst case Year 2000 scenario, assuming that the Company's Year 2000 plan is not effective. Analysis of the most reasonably likely worst case Year 2000 scenarios the Company may face leads to contemplation of the following possibilities which, though considered highly unlikely, must be included in any consideration of worst cases: widespread failure of electrical, natural gas, and similar supplies by utilities serving the Company domestically and internationally; widespread disruption of the services of communications common carriers domestically and internationally; similar disruption to means and modes of transportation for the Company and its employees, contractors, suppliers, and customers; significant disruption to the Company's ability to gain access to, and continue working in, office buildings and other facilities; the failure of substantial numbers of mission-critical hardware and software computer systems, including both internal business systems and systems (such as those with embedded microprocessors) controlling operational facilities such as electrical generation, transmission, and distribution systems and crude oil and natural gas plants and pipelines, domestically and internationally; and the failure, domestically and internationally, of Outside Systems, the effects of which would have a cumulative material adverse impact on the Company's mission-critical systems. Among other things, the Company could face substantial claims by customers for loss of revenues due to supply interruptions, inability to fulfill contractual obligations, inability to account for certain revenues or obligations or to bill or pay customers accurately and on a timely basis, and increased expenses associated with litigation, stabilization of operations following mission-critical failures, and the execution of contingency plans. The Company could also experience an inability by customers, traders, and others to pay, on a timely basis or at all, obligations owed to the Company. Under these circumstances, the adverse effect on the Company, and the diminution of Company revenues, could be material, although not quantifiable at this time. Further in this scenario, the cumulative effect of these failures could have a substantial adverse effect on the economy, domestically and internationally. The adverse effect on the Company, and the diminution of Company revenues, from a domestic or global recession or depression also could be material, although not quantifiable at this time. The Company will continue to monitor business conditions with the aim of assessing and quantifying material adverse effects, if any, that result or may result from the Year 2000 problem. Summary The Company has a plan to deal with the Year 2000 challenge and believes that it will be able to achieve substantial Year 2000 readiness with respect to the mission critical systems that it controls. From a forward-looking perspective, the extent and magnitude of the Year 2000 problem as it will affect the Company, both before and for some period after January 1, 2000, are difficult to predict or quantify for a number of reasons. Among these are: the difficulty of locating "embedded" microprocessors that may be in a great variety of mission-critical hardware used for process or flow control, environmental, transportation, access, communications, and other systems; the difficulty of inventorying, assessing, remediating, verifying and testing, Outside Systems connected, and vital, to the Company's computer, telecommunications, or other mission-critical systems; the difficulty of locating all mission-critical software (computer code) that is not Year 2000 compatible; and the unavailability of certain necessary internal or external resources, including but not limited to trained hardware and software engineers, technicians, and other personnel to perform adequate remediation, verification, and testing of mission-critical Company systems or Outside Systems. Year 2000 costs are difficult to estimate accurately because of unanticipated vendor delays, technical difficulties, the impact of tests of Outside Systems, and similar events. There can be no assurance for example that all Outside Systems with a mission-critical impact will be adequately remediated so that they are Year 2000 ready by January 1, 2000, or by some earlier date, so as not to create a material disruption to the Company's business. If, despite reasonable efforts under the Year 2000 Project, there are mission-critical Year 2000-related failures that create substantial disruptions to Company business, the adverse impact on the Company could be material. Additionally, Year 2000 costs are difficult to estimate accurately because of unanticipated vendor delays, technical difficulties, the impact of tests of Outside Systems and similar events. Moreover, despite the Company's belief that costs for implementing the Project will not be material, the estimated costs of implementing the Project do not take into account the costs, if any, that might be incurred as a result of Year 2000-related failures that occur despite implementation of the Project. -19- 20 PART I. FINANCIAL INFORMATION - (CONCLUDED) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (CONCLUDED) ENRON OIL & GAS COMPANY INFORMATION REGARDING FORWARD LOOKING STATEMENTS This Quarterly Report on Form 10-Q includes forward looking statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical facts, including, among others, statements regarding the Company's future financial position, business strategy, budgets, reserve information, projected levels of production, projected costs and plans and objectives of management for future operations, are forward-looking statements. The Company typically uses words such as "expect", "anticipate", "estimate", "strategy", "intend", "plan" and "believe" or the negative of those terms or other variations of them or by comparable terminology to identify its forward-looking statements. In particular, statements, express or implied, concerning future operating results or the ability to generate income or cash flows are forward-looking statements. Although the Company believes its expectations reflected in forward-looking statements are based on reasonable assumptions, no assurance can be given that these expectations will be achieved. Important factors that could cause actual results to differ materially from the expectations reflected in the forward-looking statements include, among others: timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates; extent of the Company's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties; successful implementation of the Company's Year 2000 Project, the effectiveness of its Year 2000 Project, and the readiness of outside entities; political developments around the world; and financial market conditions. In light of these risks, uncertainties and assumptions, the events anticipated by the Company's forward-looking statements might not occur. The Company undertakes no obligations to update or revise its forward-looking statements, whether as a result of new information, future events or otherwise. -20- 21 PART II. OTHER INFORMATION ENRON OIL & GAS COMPANY ITEM 1. Legal Proceedings See Part 1, Item 1, Note 7 to Consolidated Financial Statements which is incorporated herein by reference. ITEM 4. Submission of Matters to a Vote of Security Holders The Annual Meeting of Shareholders of Enron Oil & Gas Company was held on June 28, 1999, in Houston, Texas, for the purpose of electing a board of directors, approving the Amended and Restated Enron Oil & Gas Company 1992 Stock Plan and ratifying the appointment of auditors. Proxies for the meeting were solicited pursuant to Section 14(a) of the Securities Exchange Act of 1934, and there was no solicitation in opposition to management's solicitations. (a) Each of the directors nominated by the Board and listed in the proxy statement was elected with votes as follows:
Shares Shares Nominee For Withheld ------- ----- -------- Fred C. Ackman 146,788,441 217,627 Richard A. Causey 146,325,089 680,979 James V. Derrick, Jr. 146,313,635 692,433 John H. Duncan 146,790,406 215,662 Ken L. Harrison 146,324,878 681,190 Forrest E. Hoglund 146,327,832 678,236 Kenneth L. Lay 146,329,849 676,219 Mark G. Papa 146,331,844 674,224 Edward Randall, III 146,775,374 230,694 Jeffrey K. Skilling 146,332,412 673,656 Frank G. Wisner 146,792,542 213,526
(b) The Amended and Restated Enron Oil & Gas Company 1992 Stock Plan was approved by the following vote: 129,937,604 shares for; 16,737,923 shares against; and 330,541 shares abstaining. (c) The appointment of Arthur Andersen LLP, independent public accountants, as auditors for the year ending December 31, 1999 was approved by the following vote: 146,849,409 shares for; 70,408 shares against; and 86,251 shares abstaining. ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges Exhibit 27 - Financial Data Schedule (b) Reports on Form 8-K - There were no reports on Form 8-K filed for the quarterly period ended June 30, 1999. -21- 22 SIGNATURES Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized. ENRON OIL & GAS COMPANY (Registrant) Date: July 30, 1999 By /s/ W. C. WILSON -------------------------------- W. C. Wilson Senior Vice President and Chief Financial Officer (Principal Financial and Accounting Officer) -22- 23 INDEX TO EXHIBITS
Exhibit Number Description - -------------- ----------- 12 Computation of Ratio of Earnings to Fixed Charges 27 Financial Data Schedule
EX-12 2 COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES 1 EXHIBIT 12 ENRON OIL & GAS COMPANY Computation of Ratio of Earnings to Fixed Charges (In Thousands) (Unaudited)
SIX MONTHS ENDED JUNE 30, YEAR ENDED DECEMBER 31, ------------- ------------------------------------------------------------- 1999 1998 1997 1996 1995 1994 --------- --------- --------- --------- --------- --------- EARNINGS AVAILABLE FOR FIXED CHARGES: Net Income $ 25,704 $ 56,171 $ 121,970 $ 140,008 $ 142,118 $ 147,998 Less: Capitalized Interest Expense (6,306) (12,711) (13,706) (9,136) (6,490) (6,124) Add: Fixed Charges 35,347 61,290 41,423 21,997 18,414 14,613 Income Tax Provision(Benefit) 9,636 4,111 41,500 50,954 41,936 5,937 --------- --------- --------- --------- --------- --------- EARNINGS AVAILABLE $ 64,381 $ 108,861 $ 191,187 $ 203,823 $ 195,978 $ 162,424 ========= ========= ========= ========= ========= ========= FIXED CHARGES: Interest Expense 29,041 48,463 27,369 12,370 11,310 8,135 Capitalized Interest 6,306 12,711 13,706 9,136 6,490 6,124 Rental Expense Representative of Interest Factor -- 116 348 491 614 354 --------- --------- --------- --------- --------- --------- TOTAL FIXED CHARGES $ 35,347 $ 61,290 $ 41,423 $ 21,997 $ 18,414 $ 14,613 ========= ========= ========= ========= ========= ========= RATIO OF EARNINGS TO FIXED CHARGES 1.82 1.78 4.62 9.27 10.64 11.12
EX-27 3 FINANCIAL DATA SCHEDULE
5 6-MOS DEC-31-1999 JUN-30-1999 11,411 0 172,264 0 35,175 225,270 4,965,113 (2,298,265) 2,962,046 199,487 0 0 0 201,600 1,108,444 2,962,046 350,385 346,149 0 340,058 (58,290) 0 29,041 35,340 9,636 25,704 0 0 0 25,704 0.17 0.17 Basic
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