-----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, LBUFfrjmfxRZpeGkEOVOVTcOJJhH1nG/J5DxmJ17x760jqLXxtZSpCEDJiYjzgJ3 JV1f4c586A2v3w+1APaj1g== 0000821189-95-000013.txt : 19951109 0000821189-95-000013.hdr.sgml : 19951109 ACCESSION NUMBER: 0000821189-95-000013 CONFORMED SUBMISSION TYPE: 10-Q PUBLIC DOCUMENT COUNT: 2 CONFORMED PERIOD OF REPORT: 19950930 FILED AS OF DATE: 19951108 SROS: NYSE FILER: COMPANY DATA: COMPANY CONFORMED NAME: ENRON OIL & GAS CO CENTRAL INDEX KEY: 0000821189 STANDARD INDUSTRIAL CLASSIFICATION: UNKNOWN SIC - 0000 [0000] IRS NUMBER: 470684736 STATE OF INCORPORATION: DE FISCAL YEAR END: 1231 FILING VALUES: FORM TYPE: 10-Q SEC ACT: 1934 Act SEC FILE NUMBER: 001-09743 FILM NUMBER: 95587994 BUSINESS ADDRESS: STREET 1: 1400 SMITH ST CITY: HOUSTON STATE: TX ZIP: 77002 BUSINESS PHONE: 7138535482 10-Q 1 FORM 10-Q SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 (X) Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 For the quarterly period ended September 30, 1995 ( )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 of (I.R.S. Employer Identification No.) incorporation or organization) 1400 Smith Street, P.O. Box 4362 Houston, Texas 77210-4362 (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 October 31, 1995. Common Stock, $.01 Par Value 159,799,955 shares Class Number of Shares ENRON OIL & GAS COMPANY TABLE OF CONTENTS Page No. PART I. FINANCIAL INFORMATION ITEM 1. Financial Statements Consolidated Statements of Income - Three Months Ended September 30, 1995 and 1994 and Nine Months Ended September 30, 1995 and 1994 3 Consolidated Balance Sheets - September 30, 1995 and December 31, 1994 4 Consolidated Statements of Cash Flows - Nine Months Ended September 30, 1995 and 1994 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 6. Exhibits and Reports on Form 8-K 16 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 Nine Months Ended September 30, September 30, 1995 1994 1995 1994 NET OPERATING REVENUES Natural Gas Associated Companies $ 55,893 $ 57,382 $177,963 $198,743 Trade 58,992 48,929 154,052 166,911 Crude Oil, Condensate and Natural Gas Liquids Associated Companies 14,293 13,130 44,304 31,142 Trade 17,982 7,424 46,038 21,490 Gains on Sales of Reserves and Related Assets 3,268 33,264 62,546 52,212 Other 2,578 554 7,439 3,842 Total 153,006 160,683 492,342 474,340 OPERATING EXPENSES Lease and Well 19,309 13,416 52,918 44,782 Exploration 9,636 9,958 31,590 29,647 Dry Hole 1,681 2,709 8,586 10,803 Impairment of Unproved Oil & Gas Properties 6,337 6,864 20,453 17,364 Depreciation, Depletion and Amortization 56,172 54,628 157,875 181,645 General and Administrative 14,003 13,766 41,186 38,050 Taxes Other Than Income 7,943 7,322 25,606 22,010 Total 115,081 108,663 338,214 344,301 OPERATING INCOME 37,925 52,020 154,128 130,039 OTHER INCOME(EXPENSE) (1,033) 555 (1,143) 2,238 INCOME BEFORE INTEREST EXPENSE AND INCOME TAXES 36,892 52,575 152,985 132,277 INTEREST EXPENSE Incurred Affiliate 103 275 591 275 Other 5,050 3,306 13,218 10,352 Capitalized (1,605) (1,503) (4,999) (4,516) Net Interest Expense 3,548 2,078 8,810 6,111 INCOME BEFORE INCOME TAXES 33,344 50,497 144,175 126,166 INCOME TAX PROVISION 376 9,529 33,444 20,728 NET INCOME $ 32,968 $ 40,968 $110,731 $105,438 EARNINGS PER SHARE OF COMMON STOCK $ .21 $ .26 $ .69 $ .66 AVERAGE NUMBER OF COMMON SHARES 159,916 159,777 159,951 159,826 The accompanying notes are an integral part of these consolidated financial statements.
PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Continued) ENRON OIL & GAS COMPANY CONSOLIDATED BALANCE SHEETS (In Thousands) September 30, December 31, 1995 1994 (Unaudited) ASSETS CURRENT ASSETS Cash and Cash Equivalents $ 8,456 $ 5,810 Accounts Receivable Associated Companies 60,233 57,352 Trade 102,589 68,781 Inventories 11,640 15,731 Other 8,628 8,744 Total 191,546 156,418 OIL AND GAS PROPERTIES (Successful Efforts Method) 3,266,736 3,015,435 Less: Accumulated Depreciation, Depletion and Amortization (1,423,586) (1,330,624) Net Oil and Gas Properties 1,843,150 1,684,811 OTHER ASSETS 75,275 20,638 TOTAL ASSETS $2,109,971 $1,861,867 LIABILITIES AND SHAREHOLDERS' EQUITY CURRENT LIABILITIES Accounts Payable Associated Companies $ 17,631 $ 13,353 Trade 101,437 117,791 Accrued Taxes Payable 23,404 17,631 Dividends Payable 4,797 4,800 Other 9,237 11,026 Total 156,506 164,601 LONG-TERM DEBT Affiliate 16,320 25,000 Other 247,552 165,337 OTHER LIABILITIES 13,915 10,035 REDEEMABLE PREFERRED STOCK 19,000 - DEFERRED INCOME TAXES 292,298 269,292 DEFERRED REVENUE 224,085 184,183 COMMITMENTS AND CONTINGENCIES (Note 8) SHAREHOLDERS' EQUITY Common Stock, $.01 Par, 160,000,000 Shares Authorized and Issued 201,600 201,600 Additional Paid In Capital 399,192 403,488 Cumulative Foreign Currency Translation Adjustment (8,075) (15,298) Retained Earnings 550,147 453,810 Common Stock Held in Treasury, 115,045 shares at September 30,1995 and 9,173 shares at December 31,1994 (2,569) (181) Total Shareholders' Equity 1,140,295 1,043,419 TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY $2,109,971 $1,861,867 The accompanying notes are an integral part of these consolidated financial statements.
PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Continued) ENRON OIL & GAS COMPANY CONSOLIDATED STATEMENTS OF CASH FLOWS (In Thousands) (Unaudited) Nine Months Ended September 30, 1995 1994 CASH FLOWS FROM OPERATING ACTIVITIES Reconciliation of Net Income to Net Operating Cash Inflows: Net Income $ 110,731 $105,438 Items Not Requiring (Providing) Cash Depreciation, Depletion and Amortization 157,875 181,645 Impairment of Unproved Oil and Gas Properties 20,453 17,364 Deferred Income Taxes 15,586 25,846 Other, Net 3,968 (3,241) Exploration Expenses 31,590 29,647 Dry Hole Expenses 8,586 10,803 Gains on Sales of Reserves and Related Assets (62,546) (52,212) Other, Net (148) 3,622 Changes in Components of Working Capital and Other Liabilities Accounts Receivable (9,093) 30,978 Inventories 4,091 (4,335) Accounts Payable (12,076) (33,196) Accrued Taxes Payable 5,773 104 Other Liabilities 2,842 4,675 Other, Net (1,848) (4,186) Amortization of Deferred Revenue (Note 6) (32,418) (32,419) Changes in Components of Working Capital Associated with Investing and Financing Activities (14,156) 20,328 NET OPERATING CASH INFLOWS 229,210 300,861 INVESTING CASH FLOWS (Note 6) Additions to Oil and Gas Properties (345,351) (313,329) Exploration Expenses (31,590) (29,647) Dry Hole Expenses (8,586) (10,803) Proceeds from Sales of Reserves and Related Assets 100,659 82,167 Changes in Components of Working Capital Associated with Investing Activities 12,338 (20,328) Other, Net (9,106) (708) NET INVESTING CASH OUTFLOWS (281,636) (292,648) FINANCING CASH FLOWS Long-Term Debt Affiliate (8,680) 25,000 Other (Note 7) 83,300 (32,000) Dividends Paid (14,397) (14,387) Treasury Stock Purchased (13,231) (4,778) Proceeds from Sales of Treasury Stock 6,262 1,654 Changes in Components of Working Capital Associated with Financing Activities 1,818 - NET FINANCING CASH INFLOWS(OUTFLOWS) 55,072 (24,511) INCREASE(DECREASE) IN CASH AND CASH EQUIVALENTS 2,646 (16,298) CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD 5,810 103,129 CASH AND CASH EQUIVALENTS AT END OF PERIOD $ 8,456 $ 86,831 The accompanying notes are an integral part of these consolidated financial statements.
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, 1994. Certain reclassifications have been made to prior period financial statements to conform with the current presentation. 2. Income Tax Provision for the three-month periods and the nine- month periods ended September 30, 1995 and 1994 includes tax benefits of $3.1 million, $14.2 million, $15.8 million and $29.4 million, respectively, related to tight gas sand federal income tax credit utilization. Income Tax Provision for the three-month and nine-month periods ended September 30, 1994 also includes a $4.6 million deferred tax benefit resulting from a reduction in estimated composite state income tax rates and a $1.5 million current U.S. tax benefit arising from the discontinuance of operations in Malaysia. Income tax provision for the three-month and nine-month periods ended September 30, 1995 also includes a $10 million and a $12 million benefit, respectively, associated with the successful resolution on audit of federal income taxes for certain prior years. 3. Natural Gas and Crude Oil, Condensate and Natural Gas Liquids Net Operating Revenues Natural Gas Net Operating Revenues are comprised of the following (in millions): Three Months Ended Nine Months Ended September 30, September 30, 1995 1994 1995 1994 Wellhead Natural Gas Revenues Associated Companies (1)(2) $ 36.4 $ 56.2 $120.2 $218.3 Trade 48.5 35.8 121.9 125.0 Total $ 84.9 $ 92.0 $242.1 $343.3 Other Natural Gas Marketing Activities Gross Revenues from: Associated Companies $ 16.8 $ 38.5 $ 60.4 $124.2 Trade (3) 23.5 26.8 74.9 90.8 Total 40.3 65.3 135.3 215.0 Associated Cost from: Associated Companies (1)(5) 17.4 41.4(4) 64.5(4) 141.6(4) Trade 13.1 13.7 43.3 48.8 Total 30.5 55.1 107.8 190.4 Net 9.8 10.2 27.5 24.6 Commodity Price Swap Gain(Loss) Trading - - 11.3(6) - Non-Trading (7) 20.2 4.1 51.1 (2.3) Total 20.2 4.1 62.4 (2.3) Total $ 30.0 $ 14.3 $ 89.9 $ 22.3 PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Continued) ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Crude Oil, Condensate and Natural Gas Liquids, Net Operating Revenues are comprised of the following (in millions): Three Months Ended Nine Months Ended September 30, September 30, 1995 1994 1995 1994 Wellhead Crude Oil, Condensate and Natural Gas Liquid Revenues Associated Companies $ 13.2 $ 12.9 $ 43.4 $ 30.0 Trade 18.0 7.4 46.0 21.5 Total $ 31.2 $ 20.3 $ 89.4 $ 51.5 Other Crude Oil and Condensate Marketing Activities Commodity Price Hedging Gain (7) $ 1.1 $ 0.3 $ 0.9 $ 1.1 (1) Wellhead Natural Gas Revenues include $17.0 million, $27.4 million, $55.0 million and $100.4 million for the three-month periods and the nine-month periods ended September 30, 1995 and 1994, respectively, associated with deliveries by Enron Oil & Gas Company to Enron Oil & Gas Marketing, Inc., a wholly-owned subsidiary, reflected as a cost in Other Natural Gas Marketing Activities - Associated Costs. (2) Includes $2.8 million, $5.0 million, $10.0 million and $17.4 million for the three-month periods and the nine-month periods ended September 30, 1995 and 1994, respectively, associated with the equivalent wellhead value of volumes delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended, net of transportation. (3) Includes $10.9 million for the three-month periods and $32.4 million for the nine-month periods ended September 30, 1995 and 1994 associated with the amortization of deferred revenues under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (4) Includes the effect of a price swap agreement with a third party which in effect fixed the price of certain purchases through February 1995. (5) Includes $6.3 million, $7.9 million, $19.8 million and $26.2 million for the three-month periods and the nine-month periods ended September 30, 1995 and 1994, respectively, for volumes delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended, including equivalent wellhead value, any applicable transportation costs and location differentials. (6) Represents gain associated with commodity price swap transactions with an Enron Corp. affiliated company designated for trading purposes. The Company had no open trading positions at September 30, 1995. Subsequently, the Company sold call options with a notional volume of 50 billion British thermal units per day at an average price of $2.10 per million British thermal units for the period January through December, 1996. (7)Represents gain or loss associated with commodity price swap transactions primarily with Enron Corp. affiliated companies based on NYMEX-related commodity prices in effect on dates of execution, less customary transaction fees. These transactions serve as price hedges for a portion of wellhead sales. PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Continued) ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 4. In March 1995, in a series of transactions with Enron Corp. and an affiliate of Enron Corp., the Company exchanged all of its fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant (the "Cogen Contracts") for certain natural gas price swap agreements of equivalent value issued by the affiliate that are designated as hedges (the "Swap Agreements"). Such Swap Agreements were closed on March 31, 1995. As a result of the transactions, the Company has been relieved of all performance obligations associated with the Cogen Contracts. Such operating revenues and associated cost through February 28, 1995 were classified as Other Natural Gas Marketing Activities-Gross Revenues and Associated Cost from Associated Companies. The Company will realize net operating revenues classified as Other Natural Gas Marketing Activities-Commodity Price Swap Gain, Non-Trading, and receive corresponding cash payments of approximately $91 million during the period extending through December 31, 1999 under the terms of the closed Swap Agreements. The estimated fair value of the Swap Agreements was approximately $81 million at the date the Swap Agreements were received in exchange for the Cogen Contracts. The net effect of this series of transactions will result in increases in net operating revenues and cash receipts for the Company during 1995 and 1996 of approximately $13 million and $7 million, respectively, with offsetting decreases in 1998 and 1999 versus those anticipated under the Cogen Contracts. The total cash payments receivable under the terms of the Swap Agreements, approximately $72 million at September 30, 1995, are presented in the accompanying balance sheet as Accounts Receivable - Associated Companies for the $30 million current portion and as Other Assets for the $42 million noncurrent portion. The corresponding total future revenue is classified as Deferred Revenue. 5. In March 1995, a subsidiary of the Company issued to an unrelated third party 19,000 shares of the subsidiary's non- voting redeemable preferred stock, with a liquidation/redemption value of $1,000 per share and dividends payable semi-annually at an annual rate of $70.00 per share, in exchange for certain oil and gas properties. Such dividends have been classified as interest expense - other in the accompanying statement of income. The mandatory redemption date of the preferred stock is March 31, 2005; however, both parties have an option to require the stock to be exchanged at any time on or subsequent to March 31, 1997 for 633,333 shares of Enron Corp. common stock. In the event of a tax deconsolidation between Enron Corp. and the Company, the third party has the option to require the exchange of the redeemable preferred stock for 950,000 shares of the common stock of the Company rather than for the Enron Corp. common stock. As of September 30, 1995, the Company has acquired 633,333 shares of Enron Corp. common stock at a cost of approximately $19.3 million to be held in anticipation of the possible future exchange. The cost of the Enron Corp. common stock is included in Other Assets in the accompanying balance sheet. 6. Gains on sales of certain oil and gas reserves and related assets in the amount of $62.5 million and $52.2 million for the nine-month periods ended September 30, 1995 and 1994, respectively, are required by current accounting guidelines to be removed from Net Income in connection with determining Net Operating Cash Inflows while the related proceeds are classified as Investing Cash Flows. The Company believes the proceeds from the sales of reserves and related assets should be considered in analyzing the elements of operating cash flows. The current federal income tax impact of these sales transactions was calculated by the Company to be $24.3 million and $18.7 million for the nine-month periods ended September 30, 1995 and 1994, respectively, which entered into the overall calculation of current federal income tax. The Company believes that this current federal income tax impact should also be considered in analyzing the elements of the cash flow statement. The consolidated statement of cash flows for the first nine months of 1994 has been revised to reflect the elimination of the non-cash amortization of deferred revenue from net operating cash flows rather than investing cash flows as previously reported. This revision was made following discussion with the Staff of the Securities and Exchange Commission. PART I. FINANCIAL INFORMATION - (Continued) ITEM 1. FINANCIAL STATEMENTS - (Concluded) ENRON OIL & GAS COMPANY NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Non-cash investing and financing activities for the nine- month period ended September 30, 1995 include the issuance by a subsidiary of the Company of redeemable preferred stock with a liquidation/redemption value of $19 million in exchange for certain oil and gas properties (see Note 5). An approximate $7 million step-up in property basis was made relating to deferred taxes associated with the difference between the tax and book bases of the acquired properties as required by Statement of Financial Accounting Standards (SFAS) No. 109 - "Accounting for Income Taxes" for a nontaxable business combination. 7. Long-Term Debt, Other at September 30, 1995 and December 31, 1994 consisted of the following: September 30, December 31, 1995 1994 Senior Notes $ 70,000 $ 70,000 Promissory Notes 71,000 56,000 Commercial Paper 50,000 6,700 Uncommitted Bank Lines of Credit 50,000 - Loan Payable - 25,000 Capitalized Lease Obligation 6,552 7,637 $247,552 $165,337 The commercial paper and uncommitted bank lines of credit with two banks are used to fund current transactions and are classified as long-term based on the Company's intent and ability to replace such obligations with other long-term debt. The interest rates for commercial paper and the uncommitted bank lines of credit at September 30, 1995 were 5.88% and 6.85%, respectively. 8. On November 19, 1992, TransAmerican Natural Gas Corporation ("TransAmerican") filed a petition against the Company alleging breach of contract, tortious interference with contract, misappropriation of trade secrets and violation of state antitrust laws. The petition, as amended, sought actual damages of at least $100 million plus exemplary damages of $300 million. The Company filed counterclaims against TransAmerican and a third- party claim against its sole shareholder, John R. Stanley, alleging fraud, negligent misrepresentation and breach of state antitrust laws. On October 16, 1995, the Company, TransAmerican and Stanley entered into an agreement which resolved all claims. The settlement terms will not have a materially adverse effect on the Company's financial condition or results of operations. 9. In March 1995, the Financial Accounting Standards Board issued SFAS No. 121 - "Accounting for the Impairment of Long- Lived Assets and for Long-Lived Assets to be Disposed Of" (the "Standard"). The Standard requires, among other things, that long-lived assets and certain identifiable intangibles to be held and used by an entity be reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. The Company is required to adopt the Standard no later than the first quarter of 1996. While the Company has not finalized its evaluation of the effect of adoption of the Standard, its evaluation to date indicates that application of the Standard to its current portfolio of assets could result in impairment charges ranging from $5 million to $60 million before federal income taxes ($3 million to $39 million after federal income taxes). However, such impairment charges would be non-cash. 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 the nine-month periods ended September 30, 1995 and 1994 should be read in conjunction with the consolidated financial statements of the Company and Notes thereto. Results of Operations Three Months Ended September 30, 1995 vs. Three Months Ended September 30, 1994 In the third quarter of 1995, Enron Oil & Gas Company (the "Company") realized net income of $33.0 million compared to net income of $41.0 million for the same period in 1994. Net operating revenues for the third quarter of 1995 were $153.0 million as compared to $160.7 million for the same period a year ago. Wellhead volume and price statistics are as follows: 1995 1994 Natural Gas Volumes (MMcf/d)(1) North America (2) 657 606 Trinidad 112 66 Total 769 672 Average Natural Gas Prices ($/Mcf)(3) North America (4) $ 1.24 $ 1.55 Trinidad 0.97 0.93 Composite 1.20 1.49 Crude/Condensate Volumes (MBbl/d)(1) North America 12.0 10.1 Trinidad 5.9 2.7 India 2.3 - Total 20.2 12.8 Average Crude/Condensate Prices ($/Bbl)(3) North America $16.57 $16.81 Trinidad 15.76 16.28 India 16.10 - Composite 16.28 16.70 (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 September 30, 1995 and 1994 delivered under the terms of volumetric production payment and exchange agreements 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 $.62/Mcf and $1.13/Mcf for the three-month periods ended September 30, 1995 and 1994, respectively, for the volumes described in note (2), net of transportation costs. Third quarter 1995 average wellhead natural gas prices were down approximately 19% from the same period in 1994 reducing net operating revenues by approximately $20 million. An increase of 14% in wellhead natural gas volumes from the third quarter of 1994 increased net operating revenues by approximately $13 million. The Company voluntarily curtailed its United States wellhead natural gas delivered volumes by an average of approximately 150 MMcf/d during the third quarter of 1995 compared to an average of approximately 140 MMcf/d during the same period in 1994 due to significantly lower United States wellhead natural gas prices. The third quarter 1995 North America increase in natural gas volumes was primarily the result of acquisitions made during 1995. Offshore Trinidad natural gas volumes also continued to increase when compared to 1994 as a result of increased annual takes under the existing contract. Third quarter 1995 wellhead crude oil and condensate average prices decreased 3% reducing net operating revenues approximately $1 million from the third quarter of 1994. Crude oil and condensate wellhead volumes increased 58% adding approximately $11 million to net operating revenues compared to the same period a year ago primarily reflecting new volumes on stream offshore India, higher volumes offshore Trinidad due to increased annual takes under the existing contract and new well additions related to the 1995 drilling program and a 19% increase in North America volumes. PART I. FINANCIAL INFORMATION - (Continued) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Continued) ENRON OIL & GAS COMPANY Other marketing activities associated with sales and purchases of natural gas, natural gas price swap transactions, other commodity price hedging of natural gas and crude oil and condensate prices utilizing NYMEX-related commodity market transactions, and margins relating to the volumetric production payment added approximately $31 million to net operating revenues during the third quarter of 1995, an increase of approximately $17 million over the same period in 1994. This increase primarily results from a gain of $20 million on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in the third quarter of 1995 compared to a gain of $4 million in the third quarter of 1994. The average associated costs of natural gas marketing, price swap and volumetric production payment transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, decreased $.67 per Mcf. The average price received for these transactions decreased $.61 per Mcf. Related other natural gas marketing volumes decreased 16%. The reduction in other natural gas marketing volumes and prices relates primarily to the exchange of the fuel contracts discussed below and lower wellhead market prices. The reduction in other natural gas marketing volumes partially offset by the $.06 per Mcf increased margin reduced net operating revenues by approximately $.4 million compared to the third quarter of 1994. The impact of these other marketing activities, a substantial portion of which serve as hedges of commodity price risks for a portion of wellhead deliveries, were more than offset by reductions in revenues associated with market responsive prices for wellhead deliveries. (See Note 3 to Consolidated Financial Statements). In March 1995, the Company exchanged existing fuel supply and purchase contracts and related price swap agreements associated with a Texas City cogeneration plant for certain natural gas price swap agreements of equivalent value issued by an Enron Corp. affiliated company. As a result of these transactions, the Company realized a $4 million increase in net operating revenues in the third quarter of 1995 over the amount realized from the exchanged fuel supply and purchase contracts in the same period of 1994. (See also Note 4 to the Consolidated Financial Statements). Gains on sales of reserves and related assets during the third quarter of 1995 decreased $30 million when compared to the same period in 1994 due to one major sale being made during the 1994 period and no such sales being made during the 1995 period. During the third quarter of 1995, operating expenses were approximately $6 million higher than in the third quarter of 1994. Lease and well expenses increased approximately $6 million primarily due to increased volumes and expanded international activities. Depreciation, depletion and amortization ("DD&A") expense increased approximately $2 million to $56 million reflecting an increase in production volumes partially offset by a decrease in the average DD&A rate from $.79 per thousand cubic feet equivalent ("Mcfe") in the third quarter of 1994 to $.68 per Mcfe in the third quarter of 1995. The decrease in the DD&A rate is due to an increase in the mix of North America volumes coming from lower cost fields, the disposition of higher cost properties and increases in international volumes at lower than average domestic DD&A rates. The Company's per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income averaged $1.23 per Mcfe during the third quarter of 1995 compared to $1.32 per Mcfe during the same period in 1994. 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 decreased $9 million for the third quarter of 1995 as compared to the same period in 1994 primarily resulting from lower income before income taxes, lower benefits associated with tight gas sand federal income tax credits and a $10 million benefit associated with the successful resolution on audit of federal income taxes for certain prior years. Federal income taxes accrued in interim periods are calculated using the estimated annual effective income tax rate method. Nine Months Ended September 30, 1995 vs. Nine Months Ended September 30, 1994 In the first nine months of 1995, the Company realized net income of $110.7 million compared to net income of $105.4 million for the same period in 1994. Net operating revenues for the first nine months of 1995 were $492.3 million as compared to $474.3 million for the same period a year ago. Wellhead volume and price statistics are as follows: 1995 1994 Natural Gas Volumes (MMcf/d) North America (1) 609 680 Trinidad 110 63 Total 719 743 Average Natural Gas Prices ($/Mcf) North America (2) $ 1.28 $ 1.76 Trinidad 0.97 0.93 Composite 1.23 1.69 Crude/Condensate Volumes (MBbl/d) North America 11.5 9.4 Trinidad 4.8 2.6 India 2.3 - Total 18.6 12.0 Average Crude/Condensate Prices ($/Bbl) North America $17.01 $15.25 Trinidad 16.16 15.20 India 16.82 - Composite 16.77 15.24 (1) Includes 48 MMcf per day for the nine-month periods ended September 30, 1995 and 1994 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $.76/Mcf and $1.32/Mcf for the nine-month periods ended September 30, 1995 and 1994, respectively, for the volumes described in note (1), net of transportation costs. Average wellhead natural gas prices for the first nine months of 1995 were down approximately 27% from the same period in 1994 reducing net operating revenues by approximately $90 million. A decrease of 3% in wellhead natural gas volumes from the first nine months of 1994 reduced net operating revenues by approximately $11 million. The Company voluntarily curtailed its United States wellhead natural gas delivered volumes by an average of approximately 140 MMcf/d during the first nine months of 1995 compared to approximately 110 MMcf/d during the same period in 1994 due to significantly lower United States wellhead natural gas prices. In addition, the impact of sales of oil and gas reserves and related assets net of purchases of similar assets resulted in a reduction of approximately 40 MMcf per day in delivered volumes for the first nine months of 1995 as compared to the first nine months of 1994. The Company's decision early in the year to curtail drilling activities primarily related to increasing United States natural gas deliverability in favor of drilling for reserve additions and the definition of future opportunities reduced the rate of growth in producing capacity. Wellhead crude oil and condensate average prices increased 10% adding approximately $8 million to net operating revenues over the first nine months of 1994. Crude oil and condensate wellhead volumes increased 55% adding approximately $27 million to net operating revenues compared to the same period a year ago primarily reflecting new volumes on stream offshore India, higher volumes offshore Trinidad and a 22% increase in North America volumes. PART I. FINANCIAL INFORMATION - (Continued) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Continued) ENRON OIL & GAS COMPANY Other marketing activities associated with sales and purchases of natural gas, natural gas price swap transactions, other commodity price hedging of natural gas and crude oil and condensate prices utilizing NYMEX-related commodity market transactions, and margins relating to the volumetric production payment added approximately $91 million to net operating revenues during the first nine months of 1995, an increase of approximately $67 million from the same period in 1994. This increase primarily results from a gain of $51 million on natural gas commodity price hedging activities utilizing NYMEX-related commodity market transactions in the first nine months of 1995 versus a $2 million loss during 1994 and increased margins associated with other natural gas marketing activities. The average associated costs of natural gas marketing, price swap and volumetric production payment transactions, including, where appropriate, average wellhead value, transportation costs and exchange differentials, decreased $.64 per Mcf. The average price received for these transactions decreased $.54 per Mcf. Related other natural gas marketing volumes decreased 19%. The reduction in other natural gas marketing volumes and prices relates primarily to the exchange of the fuel contracts noted below, lower wellhead market prices and decreased other marketing activities. The $.10 per Mcf margin increase partially offset by the reduction in other natural gas marketing volumes increased net operating revenues by approximately $3 million compared to the first nine months of 1994. The Company realized an $11 million gain in the first nine months of 1995 related to certain NYMEX-related commodity market transactions with an Enron Corp. affiliated company that were designated for trading purposes in late 1994. The Company had no open trading positions at September 30, 1995. Subsequently, the Company sold call options with a notional volume of 50 billion British thermal units per day ("BBtu/d") at an average price of $2.10 per million British thermal units ("MMBtu") for the period January through December, 1996. The impact of these other marketing activities, a substantial portion of which serve as hedges of commodity price risks for a portion of wellhead deliveries, were more than offset by reductions in revenues associated with market responsive prices for wellhead deliveries. (See Note 3 to Consolidated Financial Statements). The Company realized an $8.4 million increase in net operating revenues in the first nine months of 1995 over the amount realized in the same period of 1994 from the exchanged fuel supply and purchase contracts previously mentioned. Gains on sales of reserves and related assets during the first nine months of 1995 increased $10 million when compared to the same period in 1994 which increase was attributable to the Company's continuing efforts in optimizing the use of its assets. During the first nine months of 1995, operating expenses of $338 million were $6 million lower than the $344 million incurred in the same period in 1994. Lease and well expenses increased approximately $8 million to $53 million primarily due to expanded international operations partially offset by reductions in United States lease and well expenses. Exploration expenses increased $2 million to $32 million due to increased exploration activities. Impairment of unproved oil and gas properties for the first nine months of 1995 increased $3 million from the comparable period a year ago primarily due to impairments associated with certain offshore Gulf of Mexico leases. DD&A expense decreased $24 million to $158 million reflecting primarily a decrease in the average DD&A rate from $.81 per Mcfe in the first nine months of 1994 to $.69 per Mcfe in the first nine months of 1995. The DD&A rate decrease is primarily attributable to increased production from international operations with lower average DD&A rates than incurred for North America operations. General and administrative expenses increased approximately $3 million to $41 million due to expanded international activities and overall higher costs associated with certain employee related expenses. Taxes other than income were $4 million higher in the first nine months of 1995 compared to the same period in 1994 primarily due to a benefit included in 1994 associated with reductions in state franchise taxes and higher production related taxes associated with new production offshore India in the first nine months of 1995 partially offset by decreases in state severance taxes due to lower taxable North America wellhead volumes and average prices in 1995. 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 Company reduced its total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense, and taxes other than income by $.06 per Mcfe, averaging $1.25 per Mcfe during the first nine months of 1995 compared to $1.31 per Mcfe during the same period in 1994. This decrease is primarily attributable to the reduction in the average DD&A rate as noted above partially offset by increases in per unit lease and well, general and administrative expenses, and taxes other than income. Income tax provision increased $13 million for first nine months of 1995 as compared to the same period in 1994 primarily resulting from higher income before income taxes and lower benefits associated with tight gas sand federal income tax credits utilized in the first nine months of 1995 as compared to the same period in 1994 partially offset by a $12 million benefit associated with the successful resolution on audit of federal income taxes for certain prior years. Capital Resources and Liquidity The Company's primary sources of cash during the nine months ended September 30, 1995 included funds generated from operations, proceeds from the sales of selected oil and gas reserves and related assets and commercial paper and uncommitted bank lines. Primary cash outflows included funds used in operations, exploration and development expenditures, dividends and repayment of debt. With the objective of enhancing the certainty of future revenue expectations, the Company has, as of October 23, 1995, entered into hedging related transactions for approximately 400 BBtu/d (approximately 381 MMcf/d) and 529 BBtu/d (approximately 504 MMcf/d) of its North America natural gas volumes for the last three months of 1995 and the year 1996, respectively. A significant portion of the 1995 and substantially all of the 1996 hedge related transactions involve NYMEX-based commodity price swap agreements totaling 260 BBtu/d at an average price of $1.98 per MMBtu and 447 BBtu/d at an average price of $2.00 per MMBtu for the last three months of 1995 and the year 1996, respectively. The remaining hedged transactions of 140 BBtu/d and 82 BBtu/d for the last three months of 1995 and the year 1996, respectively, include notional and physical transactions that involve fixed price sales contracts and volumetric production payment and exchange agreements. Included in the 1996 hedge transactions are commodity price swap agreements totaling 200 BBtu/d of notional volumes at a weighted average NYMEX-based price of $1.97 per MMBtu which include one-time options exercisable by the counterparty on or before December 17, 1996 totaling 200 BBtu/d of notional volumes in 1997 and 1998 at the same weighted average NYMEX-based price of $1.97 per MMBtu. The Company has also, as of October 16, 1995, hedged approximately 10,100 Bbl per day and 9,600 Bbl per day of its North America crude oil and condensate volumes using commodity price swap agreements at NYMEX-based West Texas Intermediate Crude Oil ("WTI") prices averaging $18.77 per Bbl and $18.90 per Bbl for the last three months of 1995 and the year 1996, respectively. Included in the 1995 and 1996 hedge transactions are commodity price swap agreements totaling up to 3,000 Bbl per day at WTI prices ranging between $18.70 and $18.80 per Bbl each of which includes a one-time option exercisable by the counterparty at various times up to and including December 31, 1996 and for various periods some of which extend through December 31, 2000 at the same respective NYMEX-based prices as are applicable in the individual agreements for the 1995 and 1996 periods. The Company continues to evaluate the potential for entering into and may enter into, additional hedging transactions related to certain of the remaining months in 1995, and in future years. In addition, the Company may close out any portion of the existing or yet to be entered into hedges as determined appropriate by management of the Company. PART I. FINANCIAL INFORMATION - (Concluded) ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - (Concluded) ENRON OIL & GAS COMPANY 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 depreciation, depletion and amortization, 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 and to include proceeds from sales of reserves and related assets. The Company generated discretionary cash flow of $387 million during the first nine months of 1995, a 3% decrease from the $401 million generated for the same period in 1994, primarily reflecting lower net operating revenues, higher cash expenses and a decrease in benefits associated with tight gas sand federal income tax credits. Net operating cash flows of $229 million for the first nine months of 1995 decreased approximately $72 million as compared to the same period in 1994 primarily reflecting the same factors addressed above with regard to discretionary cash flow and higher working capital requirements. Based upon existing economic and market conditions, management believes net operating cash flow and available financing alternatives in 1995 will be sufficient to fund net investing and other cash requirements of the Company for the remainder of the year. Exploration and development expenditures for the first nine months of 1995 and 1994 are as follows ($ Millions): 1995 1994 North America $ 343 $ 291 International Trinidad 32 52 India 14 2 Other 16 9 Total $ 405 $ 354 Higher exploration and development expenditures for the first nine months of 1995 reflect primarily the acquisitions of certain properties in the United States. Property acquisitions during the first nine months of 1995 were approximately $114 million as compared to $14 million for the first nine months of 1994. Property acquisitions were completed at an estimated cost per Mcfe of $.53 during 1995 while sales of reserves and related assets were completed at $2.45 per Mcfe sold based on the Company's estimate of reserves. 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. PART II. OTHER INFORMATION ENRON OIL & GAS COMPANY ITEM 6. Exhibits and Reports on Form 8-K (a) Exhibits - None (b) Reports on Form 8-K - There were no reports on Form 8-K filed for the quarterly period ended September 30, 1995. 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: November 8, 1995 By /S/ W. C. WILSON W. C. Wilson Senior Vice President and Chief Financial Officer (Principal Financial Officer) Date: November 8, 1995 By /S/ BEN B. BOYD Ben B. Boyd Vice President and Controller (Principal Accounting Officer) EX-27 2
5 9-MOS DEC-31-1995 SEP-30-1995 8,456 0 162,822 0 11,640 191,546 3,266,736 (1,423,586) 2,109,971 156,506 0 201,600 0 0 938,695 2,109,971 422,357 492,342 0 338,214 1,143 0 8,810 144,175 33,444 110,731 0 0 0 110,731 0.69 0.00
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