-----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, VGmrWBFuH9OrC4B4TD51eEt2Ybul0NKVrnBJuDszfYo74I6IG6mB4fPEaffG9ELG Vo764MI7VnugmxvOX19rgA== 0000950129-98-003537.txt : 19980817 0000950129-98-003537.hdr.sgml : 19980817 ACCESSION NUMBER: 0000950129-98-003537 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 3 CONFORMED PERIOD OF REPORT: 19980630 FILED AS OF DATE: 19980814 SROS: NYSE 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: 98690570 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138535482 10-Q 1 ENRON OIL & GAS COMPANY - 6/30/98 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, 1998 [ ] 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 31, 1998. Common Stock, $.01 Par Value 154,503,355 shares ---------------------------- ------------------ Class Number of Shares ================================================================================ 2 ENRON OIL & GAS COMPANY TABLE OF CONTENTS PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements Consolidated Statements of Income - Three Months Ended June 30, 1998 and 1997 and Six Months Ended June 30, 1998 and 1997 Consolidated Balance Sheets - June 30, 1998 and December 31, 1997 Consolidated Statements of Cash Flows - Six Months Ended June 30, 1998 and 1997 Notes to Consolidated Financial Statements ITEM 2. Management's Discussion and Analysis of Financial Condition and Results of Operations PART II. OTHER INFORMATION ITEM 1. Legal Proceedings ITEM 6. Exhibits and Reports on Form 8-K 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, ------------------------ ------------------------ 1998 1997 1998 1997 --------- --------- --------- --------- NET OPERATING REVENUES Natural Gas Trade $ 135,113 $ 111,689 $ 264,680 $ 252,860 Associated Companies 15,510 21,247 38,533 18,648 Crude Oil, Condensate and Natural Gas Liquids Trade 27,277 20,499 57,514 51,710 Associated Companies 2,815 9,900 5,554 19,581 Gains on Sales of Reserves and Related Assets and Other, Net 2,592 8,418 16,857 9,605 --------- --------- --------- --------- TOTAL 183,307 171,753 383,138 352,404 OPERATING EXPENSES Lease and Well 22,857 25,973 47,766 49,442 Exploration 16,600 15,019 33,998 30,502 Dry Hole 2,281 1,586 10,162 2,570 Impairment of Unproved Oil and Gas Properties 7,355 6,900 15,703 12,913 Depreciation, Depletion and Amortization 73,071 69,183 145,032 131,822 General and Administrative 15,204 12,114 31,758 25,721 Taxes Other Than Income 13,270 12,359 27,764 29,645 --------- --------- --------- --------- TOTAL 150,638 143,134 312,183 282,615 --------- --------- --------- --------- OPERATING INCOME 32,669 28,619 70,955 69,789 OTHER INCOME (EXPENSE), NET (73) 956 (1,043) 2,212 --------- --------- --------- --------- INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 32,596 29,575 69,912 72,001 INTEREST EXPENSE, NET 10,423 5,464 19,533 10,579 --------- --------- --------- --------- INCOME BEFORE INCOME TAXES 22,173 24,111 50,379 61,422 INCOME TAX PROVISION (BENEFIT) 8,916 (460) 10,117 13,786 --------- --------- --------- --------- NET INCOME $ 13,257 $ 24,571 $ 40,262 $ 47,636 ========= ========= ========= ========= EARNINGS PER SHARE OF COMMON STOCK Basic $ 0.09 $ 0.16 $ 0.26 $ 0.30 ========= ========= ========= ========= Diluted $ 0.09 $ 0.16 $ 0.26 $ 0.30 ========= ========= ========= ========= AVERAGE NUMBER OF COMMON SHARES Basic 154,857 157,489 154,797 158,177 ========= ========= ========= ========= Diluted 155,770 157,950 155,646 158,899 ========= ========= ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 4 PART I. FINANCIAL INFORMATION - (CONTINUED) ITEM 1. FINANCIAL STATEMENTS - (CONTINUED) ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (IN THOUSANDS)
JUNE 30, DECEMBER 31, 1998 1997 ----------- ------------ (UNAUDITED) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 13,568 $ 9,330 Accounts Receivable Trade 161,657 185,979 Associated Companies 26,675 46,120 Inventories 34,816 32,040 Other 8,413 8,566 ----------- ----------- TOTAL 245,129 282,035 OIL AND GAS PROPERTIES (SUCCESSFUL EFFORTS METHOD) 4,487,783 4,291,405 Less: Accumulated Depreciation, Depletion and Amortization (2,027,948) (1,904,198) ----------- ----------- Net Oil and Gas Properties 2,459,835 2,387,207 OTHER ASSETS 57,997 54,113 ----------- ----------- TOTAL ASSETS $ 2,762,961 $ 2,723,355 =========== =========== LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Trade $ 166,066 $ 198,109 Associated Companies 36,803 37,613 Accrued Taxes Payable 14,633 28,841 Dividends Payable 4,724 4,705 Other 16,942 21,729 ----------- ----------- TOTAL 239,168 290,997 LONG-TERM DEBT Trade 850,860 548,775 Affiliate -- 192,500 OTHER LIABILITIES Trade 18,119 37,739 Associated Companies 48,069 44,699 DEFERRED INCOME TAXES 291,498 287,678 DEFERRED REVENUE 15,413 39,918 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 402,647 402,877 Unearned Compensation (5,474) (4,694) Cumulative Foreign Currency Translation Adjustment (26,799) (19,771) Retained Earnings 831,684 800,709 Common Stock Held in Treasury, 5,158,156 shares at June 30, 1998 and 4,935,744 shares at December 31, 1997 (103,824) (99,672) ----------- ----------- TOTAL SHAREHOLDERS' EQUITY 1,299,834 1,281,049 ----------- ----------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $ 2,762,961 $ 2,723,355 =========== ===========
The accompanying notes are an integral part of these consolidated financial statements. 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, ------------------------ 1998 1997 --------- --------- CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income $ 40,262 $ 47,636 Items Not Requiring Cash Depreciation, Depletion and Amortization 145,032 131,822 Impairment of Unproved Oil and Gas Properties 15,703 12,913 Deferred Income Taxes 11,980 6,372 Other, Net 3,520 983 Exploration Expenses 33,998 30,502 Dry Hole Expenses 10,162 2,570 Gains on Sales of Reserves and Related Assets and Other, Net (13,447) (7,492) Other, Net (4,100) (4,141) Changes in Components of Working Capital and Other Liabilities Accounts Receivable 40,213 73,389 Inventories (2,776) (8,727) Accounts Payable (37,391) (42,861) Accrued Taxes Payable (14,208) (8,824) Other Liabilities (23,196) 1,350 Other, Net (5,034) (611) Amortization of Deferred Revenue (21,494) (21,494) Changes in Components of Working Capital Associated with Investing and Financing Activities 14,665 29,456 --------- --------- NET OPERATING CASH INFLOWS 193,889 242,843 INVESTING CASH FLOWS Additions to Oil and Gas Properties (270,684) (297,069) Exploration Expenses (33,998) (30,502) Dry Hole Expenses (10,162) (2,570) Proceeds from Sales of Reserves and Related Assets 54,688 15,822 Changes in Components of Working Capital Associated with Investing Activities (14,518) (30,187) Other, Net (5,604) (1,971) --------- --------- NET INVESTING CASH OUTFLOWS (280,278) (346,477) FINANCING CASH FLOWS Long-Term Debt Trade 302,085 168,600 Affiliate (192,500) -- Dividends Paid (9,268) (9,519) Treasury Stock Purchased (7,969) (49,194) Proceeds from Sales of Treasury Stock 2,222 1,546 Other, Net (3,943) 1,088 --------- --------- NET FINANCING CASH INFLOWS 90,627 112,521 --------- --------- INCREASE IN CASH AND CASH EQUIVALENTS 4,238 8,887 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 9,330 7,644 --------- --------- CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 13,568 $ 16,531 ========= =========
The accompanying notes are an integral part of these consolidated financial statements. 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, 1997. 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 13 to the consolidated financial statements included in the Company's 1997 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. Income tax provision (benefit) for the three-month and six-month periods ended June 30, 1998 and 1997 includes tax benefits of $2.5 million, $2.0 million, $3.8 million and $5.2 million, respectively, related to tight gas sand federal income tax credit utilization. Additionally, the income tax provision for the six-month period ended June 30, 1998 includes a benefit of $3.4 million from certain recently incurred international costs and other benefits of $5.0 million from the resolution of certain domestic and international issues. Income tax provision (benefit) for the three-month and six-month periods ended June 30, 1997 includes benefits of $9.7 million related to the sales of certain international assets and subsidiaries and the refiling of certain Canadian tax returns. 3. Natural gas revenues, trade for the three-month and six-month periods ended June 30, 1998 and 1997, are net of costs of natural gas purchased for sale related to natural gas marketing activities of $11.8 million, $16.3 million, $24.3 million and $39.4 million, respectively. Natural gas revenues, associated for the three-month and six-month periods ended June 30, 1998 and 1997, are net of costs of natural gas purchased for sale related to natural gas marketing activities of $12.0 million, $11.6 million, $24.4 million and $23.2 million, respectively. 7 PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Concluded) ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. The difference between the average number of common shares outstanding for basic and diluted earnings per share of common stock is due to the assumed issuance of common shares relating to employee stock options in each period presented. 5. As reported in the Company's Annual Report on Form 10-K for the year ended December 31, 1997, 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. Although no assurances can be given, based on currently available information the Company believes that the claims made by the petitioners in both actions are without merit, and that the ultimate resolution of these matters will not have a material adverse effect on its financial condition or results of operations. 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. 6. In April 1998, the Company issued, pursuant to a public offering, $150 million of 6.65% Notes due April 1, 2028. 7. The Company has adopted Statement of Financial Accounting Standards ("SFAS") No. 130 - "Reporting Comprehensive Income", which established standards for reporting and displaying comprehensive income and its components in an annual financial statement that is displayed with the same prominence as other financial statements. This statement also requires that an entity report a total for comprehensive income in condensed financial statements of interim periods. The Company's total comprehensive income was $4 million, $24 million, $33 million and $46 million for the three-month and six-month periods ended June 30, 1998 and 1997, respectively. The only adjustment made to net income in the periods was for foreign currency translation adjustment. 8. In June 1998, the Financial Accounting Standards Board issued SFAS No. 133 - "Accounting for Derivative Instruments and Hedging Activities" effective for fiscal years beginning after June 15, 1999. The statement 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 December 31, 1997. 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 or method of adoption. However, based on the Company's current level of derivative and hedging activities, the Company does not expect the impact of adoption to be material. 8 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, 1998 and 1997 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, 1998 vs. Three Months Ended June 30, 1997 The Company generated second quarter net income of $13 million compared to net income of $25 million for the second quarter of 1997. Net operating revenues were $183 million as compared to $172 million for the second quarter of 1997. Operating income of $33 million increased $4 million, or 14%, as compared to the second quarter of last year. Wellhead volume and price statistics are as follows:
1998 1997 ------ ------ NATURAL GAS VOLUMES (MMCF PER DAY)(1) United States (2) 624 689 Canada 98 92 ------ ------ North America 722 781 Trinidad 132 114 India 53 1 ------ ------ TOTAL 907 896 ====== ====== AVERAGE NATURAL GAS PRICES ($/MCF)(3) United States (4) $ 2.04 $ 1.87 Canada 1.41 1.25 North America Composite 1.96 1.80 Trinidad 1.08 1.04 India 2.57 2.97 COMPOSITE 1.87 1.70 CRUDE OIL/CONDENSATE VOLUMES (MBBL PER DAY)(1) United States 12.2 11.2 Canada 2.5 2.4 ------ ------ North America 14.7 13.6 Trinidad 2.9 3.5 India 4.8 -- ------ ------ TOTAL 22.4 17.1 ====== ====== AVERAGE CRUDE OIL/CONDENSATE PRICES ($/BBL)(3) United States $13.10 $19.42 Canada 11.47 16.49 North America Composite 12.82 18.89 Trinidad 13.31 16.09 India 13.41 -- COMPOSITE 13.01 18.31 NATURAL GAS EQUIVALENT VOLUMES (MMCFE PER DAY)(5) United States (2) 713 769 Canada 119 113 ------ ------ North America 832 882 Trinidad 149 135 India 82 1 ------ ------ TOTAL 1,063 1,018 ====== ====== TOTAL BCFE(5)DELIVERIES 97 93
- -------------------------------------------------------------------------------- (1) Million cubic feet per day or thousand barrels per day, as applicable. (2) Includes 48 MMcf per day for the three-month periods ended June 30, 1998 and 1997 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (3) Dollars per thousand cubic feet or per barrel, as applicable. (4) Includes an average equivalent wellhead value of $1.57/Mcf and $1.24/Mcf for the three-month periods ended June 30, 1998 and 1997, respectively, 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. 9 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 8% to $183 million in the second quarter of 1998 compared to $170 million in the second quarter of 1997 primarily due to higher wellhead natural gas prices in North America and increased production volumes of natural gas and crude oil and condensate in India. Second quarter 1998 average wellhead natural gas prices for North America were approximately 9% higher than the comparable period of 1997 increasing net operating revenues by approximately $10 million. Average wellhead crude oil and condensate prices were down by 29% worldwide decreasing net operating revenues by $11 million. Second quarter wellhead natural gas volumes were slightly higher than the comparable period in 1997 increasing net operating revenues by $6 million. This increase was primarily due to 53 MMcf per day from the Tapti and Panna fields in India, which did not begin sales of natural gas until late in the second quarter of 1997. North America wellhead natural gas production was approximately 8% lower than the prior year period. The prior year period reflected benefits from higher production prior to payout of a South Texas property. Wellhead crude oil and condensate volumes were 31% higher than the prior year period increasing net operating revenues by nearly $9 million, primarily due to increased production from the Panna and Mukta fields in India which were shut down during the second quarter of 1997 to allow for the conversion from temporary to permanent production facilities. North America wellhead crude oil and condensate production increased 8% from the second quarter of 1997. Gains on sales of reserves and related assets and other, net totaled $3 million in the second quarter of 1998 compared to $8 million in the comparable period of 1997. Included in 1997 were $5 million in net gains on the sale of certain international assets and subsidiaries and $2 million in gains on the sale of producing properties in North America. During the second quarter of 1998, operating expenses of $151 million were approximately $8 million higher than in the second quarter of 1997. Depreciation, depletion and amortization ("DD&A") expense increased by $4 million reflecting increased international production volumes and a higher per unit rate in North America. General and administrative ("G&A") expense increased approximately $3 million due primarily to expanded worldwide operations. Exploration expenses and dry hole expenses were $2 million higher than the second quarter of 1997 due to increased exploration activities in North America. Lease and well expense decreased $3 million due primarily to certain North America workover expenses included in the prior year period. Taxes other than income were $1 million higher than the second quarter of 1997 due to an increase in taxable wellhead revenues as discussed above. The per unit operating costs of the Company for lease and well, DD&A, G&A, interest expense, and taxes other than income averaged $1.39 per Mcfe during the second quarter of 1998 compared to $1.35 per Mcfe during the second quarter of 1997. This increase is primarily due to a higher per unit rate of interest expense, G&A expense and DD&A expense, partially offset by a lower per unit rate of lease and well expense. Net interest expense increased $5 million as compared to the second quarter of 1997 reflecting a higher level of long-term debt due to expanded worldwide operations and stock repurchases. Income tax provision (benefit) increased $9 million as compared to the second quarter of 1997 primarily due to benefits of $9.7 million related to the sales of certain international assets and subsidiaries and the refiling of certain Canadian tax returns in the prior year period. Federal income taxes accrued in interim periods are calculated using the estimated annual effective income tax rate. 10 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, 1998 vs. Six Months Ended June 30, 1997 In the first half of 1998, the Company generated net income of $40 million compared to net income of $48 million for the first half of 1997. Net operating revenues for the first half of 1998 were $383 million as compared to $352 million for the first half of 1997. Operating income of $71 million increased $1 million as compared to the prior year period. Wellhead volume and price statistics are as follows:
1998 1997 ------ ------ NATURAL GAS VOLUMES (MMCF PER DAY) United States (1) 634 666 Canada 99 93 ------ ------ North America 733 759 Trinidad 121 113 India 50 1 ------ ------ TOTAL 904 873 ====== ====== AVERAGE NATURAL GAS PRICES ($/MCF) United States (2) $ 2.03 $ 2.28 Canada 1.40 1.48 North America Composite 1.94 2.18 Trinidad 1.08 1.04 India 2.63 2.97 COMPOSITE 1.87 2.03 CRUDE OIL/CONDENSATE VOLUMES (MBBL PER DAY) United States 12.4 10.9 Canada 2.6 2.4 ------ ------ North America 15.0 13.3 Trinidad 2.8 3.6 India 4.5 1.4 ------ ------ TOTAL 22.3 18.3 ====== ====== AVERAGE CRUDE OIL/CONDENSATE PRICES ($/BBL) United States $13.90 $20.84 Canada 12.77 17.25 North America Composite 13.70 20.19 Trinidad 13.66 18.86 India 14.31 22.99 COMPOSITE 13.82 20.15 NATURAL GAS EQUIVALENT VOLUMES (MMCFE PER DAY) United States (1) 724 746 Canada 121 115 ------ ------ North America 845 861 Trinidad 138 135 India 78 9 ------ ------ TOTAL 1,061 1,005 ====== ====== TOTAL BCFE DELIVERIES 192 182
- -------------------------------------------------------------------------------- (1) Includes 48 MMcf per day for the six-month periods ended June 30, 1998 and 1997 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $1.59/Mcf and $1.85/Mcf for the six-month periods ended June 30, 1998 and 1997, respectively, for the volumes described in note (1), net of transportation costs. 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 decreased 7% to $367 million in the first half of 1998 compared to $396 million in the first half of 1997, primarily due to lower average wellhead prices for natural gas, crude oil and condensate and natural gas liquids, partially offset by increased production volumes of natural gas and crude oil and condensate in India. First half 1998 average wellhead natural gas prices were approximately 8% lower than the comparable period of 1997 reducing net operating revenues by approximately $34 million. Average wellhead crude oil and condensate prices were down by 31% worldwide decreasing net operating revenues by $26 million. First half wellhead natural gas volumes were approximately 4% higher than the comparable period in 1997 increasing net operating revenues by $18 million. This increase was primarily due to 50 MMcf per day from the Tapti and Panna fields in India, which did not begin sales of natural gas until late in the second quarter of 1997. North America wellhead natural gas production was approximately 4% lower than the prior year period, which reflected benefits from higher production prior to pay-out of a South Texas property. Wellhead crude oil and condensate volumes were 22% higher than the prior year period increasing net operating revenues by nearly $15 million, primarily due to a 13% increase in North America volumes and increased production from the Panna and Mukta fields in India resulting from the ongoing development program and the previously mentioned shut-down in the second quarter of 1997. Other marketing activities associated with sales and purchases of natural gas, natural gas and crude oil price hedging and trading transactions and margins related to the volumetric production payment decreased net operating revenue by less than $1 million during the first half of 1998, compared to a $53 million reduction in the first half of 1997. During the first half of 1998, operating expenses of $312 million were approximately $30 million higher than the first half of 1997. DD&A expense increased approximately $13 million compared to the first half of 1997, primarily reflecting a higher per unit rate in North America and increased international production volumes. Dry hole expenses and exploration expenses increased $8 million and $3 million, respectively, primarily due to an increase in exploratory drilling and other exploration activities in North America during the first half of 1998. G&A expense was $6 million higher than the comparable prior year period due primarily to expanded worldwide operations. The per unit operating costs of the Company for lease and well, DD&A, G&A, interest expense and taxes other than income averaged $1.42 per Mcfe during the first half of 1998 compared to $1.36 per Mcfe in 1997. This increase is primarily due to a higher per unit rate of interest expense, DD&A expense and G&A expense, partially offset by a lower per unit rate of lease and well expense and taxes other than income. Net interest expense increased $9 million during the first half of 1998 reflecting a higher level of long-term debt due to expanded worldwide operations and stock repurchases. Income tax provision decreased $4 million in the first half of 1998 as compared to the first half of 1997 primarily due to lower income before income taxes. The 1998 income tax provision included a $3.4 million benefit associated with certain recently incurred international costs and approximately $5.0 million of other benefits from resolution of certain domestic and international issues. In 1997, the Company recognized $9.7 million in benefits related to the sales of certain international assets and subsidiaries and the refiling of certain Canadian tax returns. Federal income taxes accrued in interim periods are calculated using the estimated annual effective income tax rate. 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 Capital Resources and Liquidity The Company's primary sources of cash during the six months ended June 30, 1998, included funds generated from operations, proceeds from sales of selected oil and gas reserves and related assets and proceeds from new borrowings. Primary cash outflows included funds used in operations, exploration and development expenditures, common stock repurchases, dividends paid to Company shareholders and the repayment of debt. Discretionary cash flow, a frequently used measure of performance for exploration and production companies, is derived by adjusting net income to eliminate the effects of DD&A, impairment of unproved oil and gas properties, deferred income taxes, gains on sales of reserves and related assets, certain other miscellaneous non-cash amounts, except for amortization of deferred revenue, and exploration and dry hole expenses. The Company generated discretionary cash flow of $243 million during the first six months of 1998 compared to $221 million generated for the comparable period in 1997 primarily reflecting increased cash operating revenues and lower current income taxes partially offset by higher interest expense. Net operating cash flows of $194 million for the first half of 1998 decreased approximately $49 million as compared to the first half of 1997 primarily reflecting increased working capital for operating activities. Based upon existing economic and market conditions, management believes net operating cash flow and available financing alternatives in 1998 will be sufficient to fund net investing and other cash requirements of the Company for the remainder of the year. Exploration and development expenditures for the first six months of 1998 and 1997 are as follows (in millions):
1998 1997 ---- ---- NORTH AMERICA $263 $271 OUTSIDE NORTH AMERICA India 25 44 Trinidad 13 -- Other 14 15 ---- ---- TOTAL $315 $330 ==== ====
Exploration and development expenditures of $315 million for the first half of 1998 were $15 million lower than expenditures in the first half of 1997 due primarily to lower expenditures in India due to the completion of production facilities in 1997. Expenditures in North America were lower than the prior year period due to decreased expenditures for unproved leases partially offset by increased exploratory and developmental drilling activities. Spending in Trinidad increased due to expenditures relating to the U(a) block. 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. 13 PART I. FINANCIAL INFORMATION - (Concluded) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Concluded) ENRON OIL & GAS COMPANY Year 2000 The Year 2000 problem results from the use in computer hardware and software of two digits rather than four digits to define the applicable year. The use of two digits was a common practice for decades when computer storage and processing was much more expensive than today. 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, computer programs that have date-sensitive features may recognize a date represented by "00" as the year 1900, instead of 2000. These errors or failures may have limited effects, or the effects may be widespread, depending on the microprocessor, system or software, and its location and function. The effects of the Year 2000 problem are exacerbated because of the interdependence of computer and telecommunications systems in the United States and throughout the world. This interdependence is true for the Company and some of the suppliers, trading partners, and customers that work with the Company, as well as among the governments of countries around the world where the Company does business. The Company has implemented a course of action to identify and remediate Year 2000 problems. Under this course of action, an inventory of computer hardware and software systems and "embedded" microprocessors and related firmware and software is being prepared; assessments are being made of the effects of Year 2000-related problems on the Company; remedies for those problems are being developed to the maximum practicable extent; verification and testing is being done for the systems to which remediation efforts have been applied; and attempts are being made to ameliorate those aspects of the Year 2000 problem that cannot practicably be remediated by January 1, 2000, including the development of contingency plans to cope with consequences of Year 2000 problems that may not have been identified or remediated by that date. The course of action being taken by the Company may be modified as events warrant. The Company has engaged certain outside consultants, technicians and other external resources to aid in formulating and implementing the required changes. The course of action being taken by the Company recognizes that the computer, telecommunications, and other systems ("Outside Systems") of outside entities ("Outside Entities") play a major role in the conduct of the business of the Company. The Company does not have control of these Outside Entities or Outside Systems. (In some cases, Outside Entities are foreign governments or businesses located in foreign countries.) However, the course of action being taken by the Company includes an ongoing process of contacting Outside Entities whose systems have, or may have, a substantial effect on the ability of the Company to continue to conduct business without disruption from Year 2000 problems. The Company will attempt diligently to coordinate with these Outside Entities in an ongoing effort to obtain assurance that these Outside Systems will be Year 2000 compatible well before January 1, 2000. To the extent that Outside Systems are not reasonably expected to be Year 2000 ready, the Company intends to develop contingency plans in an attempt to minimize the disruptions or other adverse effects resulting from Year 2000 incompatibilities. As of August 1, 1998, the Company is in various stages in implementation of the course of action. Although it is difficult to estimate the total costs, through January 1, 2000 and beyond, of implementing the course of action, the Company's preliminary estimate is that such costs will not be material. Although management believes that its estimate is reasonable, there can be no assurance, for the reasons stated in the next paragraph, that the actual costs of implementing the course of action will not differ materially from the estimated costs or that the Company will not be adversely affected by Year 2000-related issues. From a forward-looking perspective, the extent and magnitude of the Year 2000 Problem as it may 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 the most important are the potential complexity of locating embedded microprocessors that may be in a great variety of hardware used for process or flow control, environmental, transportation, access, communications and other systems. The Company believes that it will be able to identify and remediate mission-critical systems containing embedded microprocessors and will have contingency plans to deal with these systems. Other important difficulties relate to the lack of control over, and difficulty associated with inventorying, assessing, remediating, verifying and testing, Outside Systems connected, and vital, to computer, telecommunications or other mission-critical systems of the Company; the complexity of evaluating all software (computer code) internal to the Company that may not be Year 2000 compatible; and the potential limited availability 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 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 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 Company business. If, despite diligent, prudent efforts under its Year 2000 course of action being pursued, there are Year 2000-related failures that create substantial disruptions to Company business, the adverse impact on Company business could be material. Moreover, the estimated costs of pursuing the Company's current course of action do not take into account the costs, if any, that might be incurred as a result of Year 2000-related failures that occur despite completion by the Company of the course of action currently being pursued and as it may be modified over time. 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. Although the Company believes that its expectations are based on reasonable assumptions, it can give no assurance that such expectations will be achieved. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include, but are not limited to, the timing and extent of changes in commodity prices for crude oil, natural gas and related products and interest rates, the extent of the Company's success in discovering, developing, marketing and producing reserves and in acquiring oil and gas properties, political developments around the world and conditions of the capital and equity markets during the periods covered by the forward looking statements. 14 PART II. OTHER INFORMATION ENRON OIL & GAS COMPANY ITEM 1. Legal Proceedings See Part 1, Item 1, Note 5 to Consolidated Financial Statements which is incorporated herein by reference. ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits Exhibit 12 - Computation of Ratio of Earnings to Fixed Charges (b) Reports on Form 8-K Current Report on Form 8-K filed on April 17, 1998 to report the sale on April 8, 1998 of $150 million principal amount of 6.65% notes due April 1, 2028 pursuant to an underwritten public offering. 15 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: August 14, 1998 By /S/ W. C. WILSON ------------------------------- W. C. Wilson Senior Vice President and Chief Financial Officer (Principal Financial Officer) Date: August 14, 1998 By /S/ BEN B. BOYD ------------------------------- Ben B. Boyd Vice President and Controller (Principal Accounting Officer) 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 YEAR ENDED DECEMBER 31, -------------------------------------------------------------------------------------- JUNE 30, 1998 1997 1996 1995 1994 1993 ------------- --------- --------- --------- --------- --------- EARNINGS AVAILABLE FOR FIXED CHARGES: Net Income $ 40,262 $ 121,970 $ 140,008 $ 142,118 $ 147,998 $ 138,025 Less: Capitalized Interest Expense (6,608) (13,706) (9,136) (6,490) (6,124) (5,457) Add: Fixed Charges 26,141 41,423 21,997 18,414 14,613 15,378 Income Tax Provision(Benefit) 10,117 41,500 50,954 41,936 5,937 (25,752) --------- --------- --------- --------- --------- --------- EARNINGS AVAILABLE $ 69,912 $ 191,187 $ 203,823 $ 195,978 $ 162,424 $ 122,194 ========= ========= ========= ========= ========= ========= FIXED CHARGES: Interest Expense $ 19,417 $ 27,369 $ 12,370 $ 11,310 $ 8,135 $ 9,921 Capitalized Interest 6,608 13,706 9,136 6,490 6,124 5,457 Rental Expense Representative of Interest Factor 116 348 491 614 354 -- --------- --------- --------- --------- --------- --------- TOTAL FIXED CHARGES $ 26,141 $ 41,423 $ 21,997 $ 18,414 $ 14,613 $ 15,378 ========= ========= ========= ========= ========= ========= RATIO OF EARNINGS TO FIXED CHARGES 2.67 4.62 9.27 10.64 11.12 7.95
EX-27 3 FINANCIAL DATA SCHEDULE
5 3-MOS DEC-31-1998 APR-01-1998 JUN-30-1998 13,568 0 188,332 0 34,816 245,129 4,487,783 2,027,948 2,762,961 239,168 0 0 0 201,600 1,098,234 2,762,961 180,715 183,307 0 150,638 73 0 10,423 22,173 8,916 13,257 0 0 0 13,257 .09 .09 Basic
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