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Enron Corp – ‘10-K’ for 12/31/95

As of:  Friday, 3/29/96   ·   For:  12/31/95   ·   Accession #:  72859-96-4   ·   File #:  1-03423

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  As Of                Filer                Filing    For·On·As Docs:Size

 3/29/96  Enron Corp                        10-K       12/31/95   22:422K

Annual Report   —   Form 10-K
Filing Table of Contents

Document/Exhibit                   Description                      Pages   Size 

 1: 10-K        Enron Corp. 1995 Form 10-K                           121±   514K 
 2: EX-3.02     Bylaws of Enron Corp.                                 22±    91K 
 3: EX-10.02    First Amendment to Enron Executive Supplemental        1     10K 
                          Survivor Benefits Plan                                 
 4: EX-10.06    First Amendment to Enron Corp. 1988 Deferral Plan      1      9K 
 5: EX-10.07    Second Amendment to Enron Corp. 1988 Deferral Plan     2±    11K 
 6: EX-10.10    First Amendment to Enron Corp. 1992 Deferral Plan      2±    11K 
 7: EX-10.11    Second Amendment to Enron Corp. 1992 Deferral Plan     3±    16K 
 8: EX-10.31    Second Amendment to Employment Agreement of Rodney     3     21K 
                          L. Gray                                                
 9: EX-10.35    Fourth Amendment to Consulting Services Agreement      3±    14K 
                          of John A. Urquhart                                    
10: EX-10.36    Fifth Amendment to Consulting Services Agreement       3±    14K 
                          of John A. Urquhart                                    
11: EX-10.37    Sixth Amendment to Consulting Services Agreement       1     10K 
                          of John A. Urquhart                                    
12: EX-10.46    First Amendment to Enron Corp. Performance Unit        1     10K 
                          Plan                                                   
13: EX-10.48    First Amendment to Enron Corp. 1994 Deferral Plan      1     10K 
14: EX-10.49    Second Amendment to Enron Corp. 1994 Deferral Plan     3±    15K 
15: EX-11       Statement Re Computation of Per Share Earnings         1     10K 
16: EX-12       Statement Re Computation or Ratios                     1      9K 
17: EX-21       Subsidiaries of Registrant                            11±    44K 
18: EX-23.01    Consent of Independent Public Accountants              1     10K 
19: EX-23.02    Consent of Degolyer and Macnaughton                    1     12K 
20: EX-23.03    Letter Report of Degolyer and Macnaughton              3±    15K 
21: EX-24       Powers of Attorney                                    13     37K 
22: EX-27       Article 5 FDS for Year End 1995                        1      9K 


10-K   —   Enron Corp. 1995 Form 10-K
Document Table of Contents

Page (sequential) | (alphabetic) Top
 
11st Page   -   Filing Submission
2Item 1. Business
"Item 2. Properties
"Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters
"Item 8. Financial Statements and Supplementary Data
"Item 10. Directors and Executive Officers of the Registrant
"Item 11. Executive Compensation
"Item 13. Certain Relationships and Related Transactions
"Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
3General
"Business Segments
"Transportation and Operation
"Domestic Gas and Power Services
"International Gas and Power Services
"Exploration and Production
4Regulation
"Natural Gas Rates and Regulations
5Operating Statistics
"Other Revenues
6Current Executive Officers of the Registrant
"Gas Transmission and Liquid Fuels
"Oil and Gas Exploration and Production Properties and Reserves
8Item 3. Legal Proceedings
"Item 4. Submission of Matters to a Vote of Security Holders
9Item 6. Selected Financial Data (Unaudited)
"Common Stock Statistics
10Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
"Eott
"Interest and Related Charges, net
"Information Regarding Forward Looking Statements
11Item 9. Disagreements on Accounting and Financial Disclosure
12Item 12. Security Ownership of Certain Beneficial Owners and Management
13Index to Financial Statements
20Non-Trading Activities
"Second Preferred Stock
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SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D. C. 20549 FORM 10-K ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 1995 TRANSITION REPORT PURSUANT TO SECTION 13 or 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Commission file number: 1-3423 ENRON CORP. (Exact name of registrant as specified in its charter) DELAWARE 47-0255140 (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 Securities registered pursuant to Section 12(b) of the Act: Title of each class Name of each exchange on which registered Common Stock, $.10 Par Value New York Stock Exchange; Chicago Stock Exchange; and Pacific Stock Exchange Cumulative Second Preferred Convertible Stock, New York Stock Exchange $1 Par Value and Chicago Stock Exchange 6-1/4% Exchangeable Notes due New York Stock Exchange December 13, 1998 Securities registered pursuant to Section 12(g) of the Act: None 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 by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. _____ Aggregate market value of the voting stock held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on January 1, 1996, was approximately $9,641,146,000. As of March 1, 1996, there were 251,456,233 shares of registrant's Common Stock, $.10 par value, outstanding. Documents incorporated by reference. Certain portions of the registrant's definitive Proxy Statement for the May 7, 1996 Annual Meeting of Stockholders ("Proxy Statement") are incorporated herein by reference in Part III of this Form 10-K.
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TABLE OF CONTENTS PART I Page Item 1. Business. . . . . . . . . . . . . . . . . . . . . . . . . . . 1 General . . . . . . . . . . . . . . . . . . . . . . . . . 1 Business Segments. . . . . . . . . . . . . . . . . . . . . 1 Transportation and Operation . . . . . . . . . . . . . . . 2 Domestic Gas and Power Services. . . . . . . . . . . . . . 7 International Gas and Power Services . . . . . . . . . . . 9 Exploration and Production . . . . . . . . . . . . . . . . 13 Regulation . . . . . . . . . . . . . . . . . . . . . . . . 17 Operating Statistics . . . . . . . . . . . . . . . . . . . 22 Current Executive Officers of the Registrant . . . . . . . 24 Item 2. Properties. . . . . . . . . . . . . . . . . . . . . . . . . . 25 Gas Transmission and Liquid Fuels. . . . . . . . . . . . . 25 Oil and Gas Exploration and Production Properties and Reserves . . . . . . . . . . . . . . . . . . . . . 26 Item 3. Legal Proceedings . . . . . . . . . . . . . . . . . . . . . . 28 Item 4. Submission of Matters to a Vote of Security Holders . . . . . 32 PART II Item 5. Market for the Registrant's Common Equity and Related Stockholder Matters. . . . . . . . . . . . . 33 Item 6. Selected Financial Data (Unaudited) . . . . . . . . . . . . . 34 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations . . . . . . . 35 Information Regarding Forward Looking Statements . . . . . . . 42 Item 8. Financial Statements and Supplementary Data. . . . . . . . . . 43 Item 9. Disagreements on Accounting and Financial Disclosure . . . . . 43 PART III Item 10. Directors and Executive Officers of the Registrant. . . . . . 44 Item 11. Executive Compensation. . . . . . . . . . . . . . . . . . . . 44 Item 12. Security Ownership of Certain Beneficial Owners and Management . . . . . . . . . . . . . . . . . . . . . 44 Item 13. Certain Relationships and Related Transactions. . . . . . . . 44 PART IV Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K. . . . . . . . . . . . . . . . . . . 45
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PART I Item 1. BUSINESS GENERAL Enron Corp. ("Enron"), a Delaware corporation organized in 1930, is an integrated natural gas company with headquarters in Houston, Texas. Essentially all of Enron's operations are conducted through its subsidiaries and affiliates which are principally engaged in the gathering, transportation and wholesale marketing of natural gas to markets throughout the United States and internationally through approximately 37,000 miles of natural gas pipelines; the exploration for and production of natural gas and crude oil in the United States and internationally; the production, purchase, transportation and worldwide marketing of natural gas liquids and refined petroleum products; the independent (i.e., non-utility) development, promotion, construction and operation of power plants, natural gas liquids facilities and pipelines in the United States and internationally; and the non-price regulated purchasing and marketing of energy related commitments. As of December 31, 1995, Enron employed approximately 6,700 persons. As used herein, unless the context indicates otherwise, "Enron" refers to Enron Corp. and its subsidiaries and affiliates. BUSINESS SEGMENTS Enron's operations are classified into the following four business segments: 1) Transportation and Operation: Interstate transmission of natural gas; construction, management and operation of natural gas and natural gas liquids pipelines, liquids plants, clean fuels plants and power facilities; and investment in crude oil transportation activities and liquids pipeline operations. 2) Domestic Gas and Power Services: Purchasing, marketing and financing of natural gas, natural gas liquids, crude oil and electric power; price risk management in connection with natural gas, natural gas liquids, crude oil and electric power transactions; intrastate natural gas pipelines; development, acquisition and promotion of natural gas- fired power plants in North America; and extraction of natural gas liquids in North America. 3) International Gas and Power Services: Independent (non-utility) development, acquisition and promotion of power plants, natural gas liquids facilities and pipelines outside of North America. 4) Exploration and Production: Natural gas and crude oil exploration and production primarily in the United States, Canada, Trinidad and India. For financial information by business segment for the fiscal years ended December 31, 1993 through December 31, 1995, please see Note 17 to the Consolidated Financial Statements on page F-21. TRANSPORTATION AND OPERATION Interstate Pipelines Enron and its subsidiaries operate domestic interstate pipelines extending from Texas to the Canadian border and across the southern United States from Florida to California. Included in Enron's domestic interstate natural gas pipeline operations are Northern Natural Gas Company ("Northern"), Transwestern Pipeline Company ("Transwestern") and Florida Gas Transmission Company ("FGT") (indirectly 50% owned by Enron). Northern, Transwestern and FGT are interstate pipelines and are subject to the regulatory jurisdiction of the Federal Energy Regulatory Commission (the "FERC"). Each pipeline serves customers in a specific geographical area: Northern, the upper Midwest; FGT, the State of Florida; and Transwestern, principally the California market and pipeline interconnects on the east end of the Transwestern system. In addition, Enron holds a 13% interest in Northern Border Partners, L.P., which owns a 70% interest in the Northern Border Pipeline system. An Enron subsidiary operates the Northern Border Pipeline system, which transports gas from Western Canada to delivery points in the midwestern United States. Also, Enron has an approximately 15% interest in Enron Liquids Pipeline, L.P., which is engaged in pipeline transportation of natural gas liquids, refined petroleum products and carbon dioxide, operates coal terminalling, gas processing and natural gas liquids fractionation facilities, and is operated by a wholly-owned subsidiary of Enron. Northern Natural Gas Company. Through its approximately 17,000-mile natural gas pipeline system stretching from Texas to Michigan's Upper Peninsula and the Canadian Border, Northern transports gas to points in its traditional market area of Illinois, Iowa, Kansas, Michigan, Minnesota, Nebraska, South Dakota and Wisconsin. Gas is transported to town borders for consumption and resale by non-affiliated gas utilities and municipalities and to other pipeline companies and end-users. Northern also transports gas at various points outside its traditional market area in the production areas of Colorado, Kansas, New Mexico, Oklahoma, Texas and Wyoming for utilities, end-users and other pipeline and marketing companies. In Northern's market area, natural gas is an energy source available for traditional residential, commercial and industrial uses. Northern's throughput totaled 2,001 trillion British thermal units ("Tbtu") in 1995, compared to 1,996 Tbtu in 1994. In its traditional market area, Northern's throughput increased to 836 Tbtu in 1995 from 819 Tbtu in 1994. Northern's jurisdictional sales ceased in 1994 as a result of the shift from sales to transportation volumes due to the implementation of open access transportation service. The volume of gas delivered by Northern in its non-traditional market area decreased from 1,177 Tbtu in 1994 to 1,165 Tbtu in 1995 due to lower gathering volumes. Gas gathering is no longer an activity that is needed to support Northern's former merchant service nor is it a means necessary to attach gas supplies to support Northern's other transportation and storage services. In 1994 Northern filed an application with the FERC requesting authority to abandon its gathering assets in the Anadarko, Permian, Hugoton and Rocky Mountain areas by sale to certain non-jurisdictional affiliates pursuant to certain provisions of the Natural Gas Act. On November 29, 1995, Northern's FERC application was granted, and shortly thereafter Northern completed the transfer of all of its gathering assets to non-jurisdictional affiliates. Sales of a substantial portion of these gathering assets were made by Enron affiliates to third parties at year-end 1995. Northern's application with the FERC filed in December 1994 for authority to construct, operate and modify certain compressor stations and town border stations in Iowa, Illinois and Wisconsin to expand capacity on Northern's system in those areas was granted in June 1995. These facilities were designed to provide incremental firm capacity on a portion of Northern's mainline system extending east from the Ogden, Iowa compressor station through the Waterloo, Iowa and Galena, Illinois compressor stations terminating near Eagle, Wisconsin (Northern's "East Leg") in order to transport gas which is to be utilized for natural gas requirements in various shippers' market areas in Iowa, Illinois and Wisconsin. These facilities increase the daily flow rate on the East Leg by approximately 72,200 million British thermal units per day ("MMBtu") for the 1995-1996 heating season and approximately 35,400 MMBtu per day for delivery to markets in 1996, for a total increase in capacity on the East Leg of 107,600 MMBtu per day. The 1995-1996 facilities were completed in November 1995. Northern competes with other interstate pipelines in the transportation and storage of gas. In recent years, the FERC has issued orders designed to introduce more competition into the natural gas industry, having the effect of increasing transportation volumes and decreasing or eliminating sales of natural gas by pipelines. See "Regulation - Natural Gas Rates and Regulations". Transwestern Pipeline Company. Transwestern is an open-access interstate pipeline engaged in the transportation of natural gas. Through its approximately 2,660-mile pipeline system, Transwestern transports natural gas from West Texas, Oklahoma, eastern New Mexico and the San Juan Basin in northwest New Mexico primarily to the California market and to pipeline interconnects off the east end of its system. Transwestern has access to three significant gas basins for its gas supply: the Permian Basin in West Texas and eastern New Mexico, the San Juan Basin in northwestern New Mexico and southern Colorado, and the Anadarko Basin in the Texas and Oklahoma Panhandles. Substantially all of Transwestern's total of approximately 1.1 billion cubic feet ("Bcf") per day of delivery capacity to California is currently held by shippers on a firm basis, although approximately 457 million cubic feet ("Mmcf") of firm capacity will be turned back to Transwestern on November 1, 1996. Anticipating this turnback, Transwestern entered into a settlement agreement with its customers whereby the costs associated with this turnback will be shared by Transwestern and its current firm customers. Transwestern is responsible for 70% of the risk of resubscribing the released capacity, and Transwestern's customers have the remaining 30% of such risk for five years. In addition to this cost-sharing mechanism, Transwestern and its current firm customers also agreed to contract rates through 2006, and agreed that Transwestern would not be required to file a new rate case for rates to be effective prior to November 1, 2006. The settlement also included approval of Transwestern's proposal to transfer its production and gathering facilities to Transwestern Gathering Company ("TGC"), a wholly-owned, non-regulated subsidiary of Transwestern. The FERC approved Transwestern's settlement on July 27, 1995, and the transfer of production and gathering facilities to TGC occurred on September 1, 1995. Subsequently, most of these facilities have been sold by TGC to third parties. Transwestern's mainline capacity includes a lateral pipeline to the San Juan Basin in northwestern New Mexico which allows Transwestern to (i) access the San Juan Basin for gas supply, (ii) service northern California markets, (iii) access the central California enhanced oil recovery market and (iv) enhance its ability to deliver to markets east of California. Total throughput volumes to California averaged approximately 463 Mmcf per day in 1995, compared to 706 MMcf per day in 1994. Transwestern has firm transportation service on the east end of its system and transports Permian and San Juan Basin supplies into Texas, Oklahoma and the midwestern United States. During 1995, Transwestern made certain modifications to its mainline system which for the first time allowed San Juan Basin volumes to physically flow from the San Juan Basin to the east end of the Transwestern system. Transwestern transported an average of 625 Mmcf per day off the east end of its system in 1995, as compared 388 MMcf per day in 1994 and 312 MMcf per day in 1993. On October 4, 1995 Transwestern filed an application with the FERC seeking authorization to expand the capacity of its San Juan lateral pipeline from 520 MMcf per day to 795 MMcf per day on a peak day basis. In its application, Transwestern also proposed to acquire a 78% ownership interest in Northwest Pipeline Company's ("Northwest") La Plata facilities, which consist of a compressor station and approximately 33 miles of 30 inch pipeline located on the southern end of the Northwest system. These facilities tie into Transwestern's system at the Blanco Hub in northwestern New Mexico. If approved by the FERC, this project will give Transwestern direct access to additional gas supplies in the San Juan Basin. Regulatory approval is expected to be received in time to meet a projected January 1, 1997 in-service date. Transwestern is subject to competition from other transporters into the southern California market, including El Paso Natural Gas Company, Kern River Gas Transmission Company, Pacific Gas Transmission Company, and intrastate producers and affiliates of Southern California Gas Company. Florida Gas Transmission Company. An Enron subsidiary owns a 50% interest in FGT by virtue of its 50% interest in Citrus Corp., which owns all of the capital stock of FGT. Another Enron subsidiary operates the FGT pipeline. FGT is an open access interstate pipeline company that transports natural gas for third parties. Its approximately 5,300-mile dual pipeline system extends from South Texas to a point near Miami, Florida. FGT provides a high degree of gas supply flexibility for its customers because of its proximity to the Gulf of Mexico producing region and its interconnections with other interstate pipeline systems which provide access to virtually every major natural gas producing region in the United States. FGT has periodically expanded its system capacity to keep pace with the growing demand for natural gas in Florida. In July 1987, FGT placed its Phase I expansion in service, increasing its firm average delivery capacity from 725 billion British thermal units ("BBtu") per day to 825 Bbtu per day. In December 1991, FGT placed its Phase II expansion in service, increasing its firm average delivery capacity by 100 BBtu per day to a total of 925 BBtu per day. In response to continued growth in demand for natural gas, FGT placed its Phase III expansion in service on March 1, 1995, expanding its pipeline through a combination of the construction of new pipeline and compression facilities and the purchase of third-party facilities and transportation service. These measures were a continuation of FGT's efforts to meet increased natural gas demand in Florida through expansions of its system. The Phase III expansion increased FGT's firm average delivery capacity into Florida by 532 BBtu per day to 1,457 BBtu per day. The Phase III expansion includes in excess of 800 miles of new FGT pipeline facilities, seven additional delivery points and approximately 114,000 additional horsepower of compression. As part of Phase III, FGT also purchased an interest in facilities that link its system to the Mobile Bay producing area and contracted for 100 BBtu per day of capacity on another interstate pipeline system to provide its customers with additional sources of supply. FGT's customers have reserved over 99% of the existing capacity on the FGT system pursuant to firm long-term transportation service agreements. FGT is the only interstate natural gas pipeline serving peninsular Florida. The construction of a new pipeline serving peninsular Florida would require significant capital expenditures and appropriate environmental and other regulatory approvals. While these hurdles are significant, FGT's market is attractive and may be sought by competitors. Because of the firm transportation agreements in effect for the existing capacity and the Phase III facilities, FGT does not believe that any new pipelines, if they are proposed and built, will affect usage of its existing capacity in the near term. Any proposed pipelines could have a negative effect on FGT's ability to expand beyond Phase III and could result in competition for the Phase III facilities when the Phase III transportation agreements begin to expire. FGT also faces competition from residual fuel oil in the Florida market. A primary advantage of the straight fixed variable rate design (a FERC mandated rate design to allow pipelines to recover substantially all fixed costs, a return on equity and income taxes in the capacity reservation component of their rates) is that FGT will recover substantially all of its fixed costs regardless of levels of usage by its customers. See "Regulation - Natural Gas Rates and Regulations". In 1995, FGT held an "open season" for a Phase IV expansion and received a number of requests. FGT is currently contemplating a minor expansion in 1998 in view of the large portion of the requested capacity that has been acquired by shippers in the secondary market. Northern Border Partners, L.P. Northern Border Partners, L.P., a Delaware limited partnership, owns 70% of Northern Border Pipeline Company, a Texas general partnership ("Northern Border"). An Enron subsidiary holds a 13% interest in the limited partnership, and serves as operator of the pipeline. Northern Border owns a 969-mile interstate pipeline system that transports natural gas from the Montana-Saskatchewan border near Port of Morgan, Montana to interconnecting pipelines in the State of Iowa, one of which is Northern. The pipeline system has access to natural gas reserves in the provinces of Alberta, British Columbia and Saskatchewan, as well as the Williston Basin in the United States. The pipeline system also has access to production of synthetic gas from the Great Plains Coal Gasification Project in North Dakota. Interconnecting pipeline facilities provide access to markets in the Midwest, as well as other markets throughout the United States by transportation, displacement and exchange agreements. Therefore, Northern Border is strategically situated to transport significant quantities of natural gas to major gas consuming markets. Northern Border's revenues are derived from agreements for the receipt and delivery of gas at points along the pipeline system as specified in each shipper's individual transportation contract. Northern Border transports gas for shippers under a tariff regulated by the FERC that allows it to recover operations and maintenance costs of the pipeline system, taxes other than income taxes, interest, depreciation and amortization, an allowance for income taxes and a regulated equity return. Northern Border has focused its efforts primarily on being a low cost transporter of Canadian gas exported to the United States. As of December 31, 1995, Northern Border had firm transportation service agreements, other than those under temporary release, with four interstate pipeline companies, 17 domestic and Canadian producers and marketers, including Enron Capital & Trade Resources Corp., and ten local distribution companies. Since 1988, Northern Border has been transporting volumes at or near its maximum capacity. Based upon existing contracts and capacity, 100% of Northern Border's firm capacity (approximately 1.7 Bcf of natural gas per day) is contractually committed through October 2001. At the present time, 6% of the capacity is contracted by interstate pipelines. The remaining capacity is contracted to producers, marketers and local distribution companies. Enron Capital & Trade Resources Corp., along with other marketing affiliates of the general partners in Northern Border, hold approximately 9% of the contracted capacity. Northern Border competes with two other interstate pipeline systems that transport gas from Canada to the Midwest. Northern Border is currently pursuing opportunities to increase its capacity. In February 1995, Northern Border filed a certificate application with the FERC for a proposed project that would expand the current pipeline system and extend 263 miles of pipeline from Harper, Iowa, to Griffith, Indiana. On October 13, 1995, Northern Border filed an amendment to its application to extend and expand its existing system by installing approximately (a) 224 miles of 36-inch pipeline from Northern Border's current terminus near Harper, Iowa, to a point near Manhattan, Illinois (Chicago area); (b) 19 miles of 30-inch pipeline from the end of the proposed 36-inch pipeline extension to two points of interconnection with the facilities of the Peoples Gas Light and Coke Company (Chicago area); (c) 35 miles of 42-inch and 147 miles of 36-inch pipeline loop; (d) a total of 293,000 horsepower of compression at twelve compressor stations; and (e) nine meter stations and one meter station upgrade. The estimated cost of the facilities proposed to be constructed is approximately $800 million. New receipts into the Northern Border pipeline system are proposed to be 700 MMcf per day, and 648 MMcf per day is proposed to be transported through the pipeline extension. The application seeks FERC authorization for a projected in-service date of the facilities of the spring of 1998. Numerous parties have intervened in this proceeding, six of which have filed protests on business issues. Enron Liquids Pipeline, L.P. Enron owns approximately 15% of Enron Liquids Pipeline, L.P., a Delaware limited partnership formed in 1992. An Enron subsidiary serves as general partner and operates the partnership's two interstate common carrier natural gas liquids ("NGL") pipeline systems, and one carbon dioxide pipeline system. The partnership also owns and operates a gas processing plant and the Cora Terminal, a high speed, rail to barge coal transfer facility, and also owns a 25% interest in an NGL fractionator. The North System of Enron Liquids Pipeline, a 1,600-mile interstate common carrier NGL and refined petroleum products pipeline system, transports, stores and delivers a full range of NGLs and refined products from south central Kansas to markets in the Midwest and has interconnects, using third party pipelines, to the eastern United States. The Cypress Pipeline transports ethane from Mont Belvieu, Texas to the Lake Charles, Louisiana area. The Central Basin Pipeline transports carbon dioxide in West Texas for use in enhanced oil recovery operations in the Permian Basin of West Texas. The Painter gas processing plant, located in southwestern Wyoming, processes natural gas for the extraction of natural gas liquids. The Cora Terminal stores coal and transfers coal mined in southern Illinois from railcars to barges that transport it to end users, principally for electricity generation. The North System and the Cypress Pipeline are interstate common carrier pipelines, subject to regulation by the FERC. As an interstate common carrier, the partnership offers interstate transportation services by means of the North System and Cypress Pipeline to any shipper of NGLs who requests such services, provided that the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. The Central Basin Pipeline is not subject to rate regulation. Operation and Management of Power and Pipeline Facilities Enron's subsidiary companies are involved in the independent power and natural gas pipeline industries. In the independent power industry, Enron is involved both as an operator of and as an equity partner in independent (i.e., non-utility) natural gas-fired power plants, some of which use combined cycle and cogeneration technology to generate electricity and steam. Cogeneration is the simultaneous production of thermal energy (primarily steam) and electricity from a single fuel source, such as natural gas. A conventional electric power plant produces electricity and discharges resulting exhaust heat as waste. Cogeneration uses this previously wasted heat to create steam for industrial use and electricity, requiring less fuel than other methods using separate electric and thermal energy plants. In addition, Enron subsidiaries have developed diesel-fired power plants for projects in developing countries, where the development, engineering design and construction are done on an accelerated basis in order to address severe power shortages in such countries. Enron Operations Corp. ("EOC"), a wholly owned subsidiary, provides worldwide power plant and natural gas pipeline engineering expertise, construction management and technical support and currently operates plants in the United Kingdom, the Philippines and Guatemala. Among these facilities is the 1,875 megawatt Teesside, U.K. power facility. EOC also has projects underway in India, Colombia, China and Russia, and is negotiating contracts for proposed projects in Turkey, Puerto Rico, Pakistan, Indonesia and the U.K. It also offers services for third party start-up, operation and maintenance. (See "International Gas and Power Services" for a general description of Enron's international power and pipeline businesses). In North America, Enron subsidiary companies manage the physical operation of a 340-megawatt facility located in Pasadena, Texas, a 450- megawatt facility located in Texas City, Texas, a 250-megawatt facility located in Richmond, Virginia, and a 149-megawatt facility located in Milford, Massachusetts. EOC also operates Houston Pipe Line Company and Louisiana Resource Company, both intrastate pipelines. See "Domestic Gas and Power Services". Crude Oil Transportation Services EOTT Energy Partners, L.P. ("EOTT"), a Delaware limited partnership formed in March 1994, owns and operates the former businesses and assets of EOTT Energy Corp. EOTT is an independent gatherer and marketer of crude oil, and EOTT Energy Corp. (a wholly owned subsidiary of Enron) serves as the general partner of EOTT. Enron owns an approximately 50% interest in EOTT. EOTT is engaged in the purchasing, gathering, transporting, trading, storage and resale of crude oil and refined petroleum products, and related activities. Through its North American crude oil gathering and marketing operations, EOTT purchases crude oil produced from approximately 25,000 leases in 17 states. In addition, EOTT is a purchaser of lease crude oil in Canada. Within the United States, EOTT transports most of the lease crude oil it purchases by means of a fleet of more than 285 owned or leased trucks, and by pipeline, including approximately 1,650 miles of intrastate and interstate pipeline and gathering systems owned by EOTT and common carrier pipeline systems owned by third parties. In addition, EOTT provides transportation and trading services for third party purchasers of crude oil. These pipeline systems and trucking operations cover 17 states. EOTT also purchases crude oil from integrated and independent producers in the United States and Canada. EOTT markets the crude oil to major integrated oil companies and independent refiners throughout the United States and Canada. In its North American crude oil gathering and marketing operations, EOTT purchased approximately 251,000 barrels per day of lease crude oil during 1995. On January 1, 1996, EOTT purchased for approximately $54 million certain pipeline, transportation, storage and crude oil gathering assets (and related crude oil inventory) in Alabama and Mississippi from Amerada Hess Corporation. In 1995, EOTT discontinued its West Coast processing and asphalt marketing businesses and recorded a charge in the second quarter of 1995 to reflect the estimated cost of exiting this business segment. EOTT is still engaged in the marketing of refined petroleum products and natural gas liquids on the West Coast. DOMESTIC GAS AND POWER SERVICES The domestic gas and power services segment includes Enron Capital & Trade Resources Corp. and affiliated companies ("ECT") and the domestic gas processing operations. ECT includes the marketing, purchasing and financing of natural gas, natural gas liquids ("NGL") and electric power and the management of the portfolio of commitments arising from these activities. The domestic gas processing operations consist of the extraction and fractionation of NGLs. Enron Capital & Trade Resources Corp. ECT is responsible for Enron's marketing activities in North America and provides financial services for producers and end-users of energy commodities. ECT offers a broad range of services to provide predictable pricing, reliable delivery and low cost capital to its customers. These services are provided through a variety of products including forward contracts, swap agreements and other contractual commitments. ECT's operations can be categorized into three business lines: cash and physical, risk management and finance. Cash and Physical. The cash and physical operations include the day- to-day purchase, sale, marketing and transportation of physical natural gas, liquids and other commodities under contracts of one year or less and the management of ECT's contract portfolios. ECT's cash and physical business is augmented by its ownership of or access to physical assets consisting of intrastate pipelines, numerous storage facilities, liquids assets and ownership interests in domestic power generation facilities. The day-to-day buying, selling and transporting of commodities is facilitated by using the New York Mercantile Exchange. This allows ECT to manage its portfolio of contracts and to benefit from the relationship between the financial and physical prices for natural gas. Total physical and notional sales volumes for 1995 averaged 41.2 trillion British thermal units ("Tbtu") of natural gas equivalents per day compared to 23.9 Tbtu of natural gas equivalents per day in 1994. Included in these amounts are physical volumes of approximately 8.2 Tbtu per day in 1995 and 7.5 Tbtu per day in 1994. The intrastate pipelines included in ECT are Houston Pipe Line Company ("HPL") and Louisiana Resources Company. HPL owns an approximately 5,500-mile pipeline in Texas which interconnects with Northern, Transwestern, FGT and numerous other interstate and intrastate pipelines. HPL's intrastate natural gas sales, transportation and storage services are subject to seasonal variation because many of its customers have weather-sensitive gas requirements. The Railroad Commission of Texas has jurisdiction over intrastate gas pipeline rates, operations and transactions in Texas. See "Regulation--Natural Gas Rates and Regulations." Louisiana Resources Company is a 540-mile intrastate pipeline which spans the state of Louisiana and serves the industrial complex along the Mississippi River from Baton Rouge to New Orleans. The pipeline interconnects with the Henry Hub and has numerous interconnections with both interstate and intrastate pipelines. ECT's Napoleonville natural gas storage facility located in Louisiana, which accesses the Louisiana Resources Company pipeline, provides approximately four Bcf of working capacity. This facility enhances the benefits of Louisiana Resources Company by improving ECT's ability to meet the firm requirements of industrial markets in Louisiana, and provides the swing and peak capability required by local distribution companies and electric utilities along the Eastern seaboard. ECT's electric power business consists of various activities associated with the North American power market, such as providing natural gas contract services to electric utilities; managing, acquiring, developing and promoting power-related assets and joint ventures; and marketing and supplying electricity. ECT markets natural gas to the electric power generation industry, offering firm contract commitments with both fixed-price and other innovative pricing terms (such contracts of greater than one year are included in ECT's risk management operations). ECT will continue marketing natural gas to independent power projects as well as electric utilities converting to natural gas in response to the Clean Air Act of 1990. ECT's power business is responsible for the commercial management of the 340-megawatt facility located in Pasadena, Texas, the 450-megawatt facility located in Texas City, Texas, the 250-megawatt facility located in Richmond, Virginia, and the 149-megawatt facility located in Milford, Massachusetts. Enron has an indirect 50% ownership interest in each of these facilities. ECT's operations also include the North American NGL marketing activities and the "clean fuels" business which consists of the methanol and methyl tertiary butyl ether (MTBE) businesses. ECT affiliates market the output of Enron's NGL and clean fuels plants as well as product purchased from third parties. Risk Management. The risk management activities consist of market origination activity on long-term contracts (transactions greater than one year) and restructuring of existing long-term contracts. ECT works closely with utilities, local distribution companies and independent power producers to restructure contracts for gas supply. ECT's fixed price contract originations were 5,952 Tbtu of natural gas equivalents in 1995. The risk management activities also include the origination of liquids contracts associated with new product offerings. The risk management group also purchases and sells electrical energy to and from a variety of power generators and wholesalers including investor-owned utilities, rural electric cooperatives and municipal utilities. Finance. ECT's finance operations provide capital to customers through various product offerings including volumetric production payments. The finance business offers debt and equity capital for the energy industry and develops capital funding vehicles that support its financial product offerings. It also manages ECT's relationship in the gas supply area. In 1995, ECT provided $382 million in funding. Of this amount, Joint Energy Development Investments Limited Partnership, a Delaware limited partnership formed in 1993, comprised of an ECT subsidiary as general partner and the California Public Employees Retirement System as limited partner, has provided approximately $271 million for energy investments. Domestic Gas Processing Certain Enron subsidiaries are engaged domestically in the extraction of NGLs (ethane, propane, normal butane, isobutane and natural gasoline). NGLs are typically extracted from natural gas in liquid form under low temperature and high pressure conditions. Among other uses, ethane, propane, normal butane, isobutane and natural gasoline are used as feedstocks for petrochemical plants in the production of plastics, synthetic rubber and other products. Normal butane and natural gasoline are used by refineries in the blending of motor gasoline. Isobutane is used in the alkylation process to enhance the octane content of motor gasoline and is also used in the production of MTBE, which is used to produce cleaner burning motor gasoline. Propane is used as fuel for home heating and cooking, crop drying and industrial facilities and as an engine fuel for vehicles, and ethane is used as a feedstock for synthetic fuels production. Enron's subsidiaries engaged in gas processing operations extracted as NGLs the equivalent of an estimated 39 Bcf of natural gas during 1995. At December 31, 1995, Enron's gas processing businesses had an interest in 14 hydrocarbon extraction and fractionation facilities, 12 of which are operated by Enron, which generally are located along Enron's natural gas pipeline systems. During 1995, Enron's plants extracted 1.1 billion gallons of NGLs. A total of 242 million gallons of product were fractionated for affiliates and others. INTERNATIONAL GAS AND POWER SERVICES Enron's international activities principally involve the development, acquisition, promotion, and operation of natural gas and power projects and the marketing of natural gas liquids and other liquid fuels. In addition, ECT has established commercial marketing offices in London and Buenos Aires to offer the same type of physical commodity products, financial services and risk management services currently available through ECT in North America. As is the case in the United States, Enron's emphasis is on businesses in which natural gas or its components play a significant role. Development projects are focused on power plants, gas processing and terminaling facilities, and gas pipelines, while marketing activities center on fuels used by or transported through such facilities. Enron's international activities include management of direct and indirect ownership interests in and operation of power plants in England, Germany, Guatemala, the Philippines and China; a pipeline system in southern Argentina; retail gas and propane sales in the Caribbean basin; processing of natural gas liquids at Teesside, England; and marketing of natural gas liquids and other liquid fuels worldwide. At December 31, 1995, Enron had a 42.5% ownership interest in an independent power facility with a capacity of approximately 1,875 megawatts at ICI Chemicals & Polymers Limited's Wilton Works Plant on Teesside in northeast England. The gas-fired combined cycle project was originated, developed, constructed and is operated by Enron subsidiaries. The remaining ownership interest is held by four of the twelve regional electric companies operating in England and Wales. The Teesside plant has the capacity to supply approximately 4% of all the electricity consumed in the U.K., and 1,725 megawatts of this capacity is committed under long-term contracts. In addition to the Teesside power plant, Enron also operates an adjacent 300 MMcf per day gas liquids processing facility. Enron and the second largest regional utility company in Germany jointly own an approximately 125 megawatt gas-fired plant in Bitterfeld, Germany. The Bitterfeld project provides Enron with a presence in Germany as well as access to a site for possible expansion. Enron Global Power & Pipelines L.L.C. In November 1994, Enron Global Power & Pipelines L.L.C., a Delaware limited liability company ("EPP"), was formed by Enron to acquire, own and manage operating power plants and natural gas pipelines around the world. EPP's assets consist of interests contributed by Enron in two power plants in the Philippines, a power plant in Guatemala and a natural gas pipeline system in Argentina (see below). Upon completion of a public offering of 10 million Common Shares of EPP in November 1994, Enron owned approximately 52% of the Common Shares. Enron formed EPP to attract public equity capital to emerging market infrastructure projects, to enable public investors to better evaluate and participate directly in the growth of Enron's operating power plant and natural gas pipeline activities in emerging markets and to generate additional capital for Enron to reinvest in future development efforts and for other corporate purposes. In order to provide EPP with a long-term source of project acquisition opportunities, Enron and EPP have entered into a Purchase Right Agreement pursuant to which Enron has agreed to offer to sell to EPP, at prices lower than those that Enron may make available to third parties, all of Enron's ownership interests in any power plant and natural gas pipeline projects developed or acquired by Enron outside the United States, Canada and Western Europe, but only those projects that commence commercial operations prior to the year 2005, subject to certain exceptions. EPP currently has interests in two power plants in the Philippines. The Batangas power project is an approximately 110-megawatt fuel-oil- fired diesel engine plant located at Pinamucan, Batangas, on Luzon Island, which began commercial operation in July 1993. The Subic Bay power project is an approximately 116-megawatt fuel-oil-fired diesel engine plant located at the Subic Bay Freeport complex on Luzon Island, which began commercial operation in February 1994. Both projects were developed by Enron, are 50% owned by EPP and sell power to the National Power Corporation of the Philippines. EPP has a 50% interest in an approximately 110-megawatt fuel-oil- fired diesel engine power plant mounted on two movable barges at Puerto Quetzal on Guatemala's Pacific Coast. The U.S. flagged vessels went into commercial operation in February 1993, and sell all of their power output under a long-term contract to a large Guatemalan electric utility, a majority interest in which is owned by Guatemala's national electric utility. As part of the privatization of Argentina's state-owned industries, in 1992 Enron acquired an indirect interest in Transportadora de Gas del Sur ("TGS"), the formerly state-owned natural gas pipeline in southern Argentina. In November 1994, Enron sold its net 17.5% interest to EPP. The 4,104-mile pipeline system has a capacity of approximately 1.9 Bcf per day and serves four distribution companies under long-term firm transportation contracts. Enron Development Corp. Enron Development Corp. is involved in power and pipeline projects in varying stages of development, financing or construction in India, China, the Dominican Republic, Colombia, Puerto Rico, Turkey, Bolivia and Brazil and elsewhere. The following is a brief description of power and natural gas pipeline projects which, upon commencement of commercial operations and completion of financing arrangements, may be offered for sale to EPP subject to the terms of the Enron/EPP Purchase Right Agreement. These projects are in varying stages of development, financing or construction, thus the information set forth below is subject to change. In addition, these projects are, to varying degrees, subject to all the risks associated with project development, construction and financing in foreign countries, including without limitation, the receipt of permits and consents, the availability of project financing on acceptable terms, expropriation of assets, renegotiation of contracts with foreign governments and political instability, as well as changes in laws and policies governing operations of foreign based businesses generally. Other than as noted below, there can be no assurances that these projects will commence commercial operations. India. In connection with a Power Purchase Agreement dated December 8, 1993, as amended, between Dabhol Power Company, Enron's 80%-owned subsidiary, and the Maharashtra State Electricity Board (the MSEB), Dabhol Power Company has been developing Phase I electricity generating power plant south of Bombay, State of Maharashtra, India. Financial closing occurred and project construction began on March 1, 1995. In August 1995, after a new governing coalition was elected in the State of Maharashtra, the State government of Maharashtra took steps to stop construction and cancel the project. Dabhol Power Company initiated arbitration procedures in London, and renegotiation efforts began in Bombay. In February 1996, Dabhol Power Company, the State government and the MSEB reached a preliminary agreement, subject to full governmental and lender approvals which are currently being sought, to go forward with an expanded project. Phase I will now have an initial capacity of 826 megawatts and will burn naptha (or distillate if naptha is not available) as fuel, with potential expansion up to 2,450 megawatts. It is anticipated that the final phase will be fueled with imported liquefied natural gas. Enron has an 80% equity interest in the project, while Bechtel Enterprises Inc. and GE Capital Corp. each have a 10% equity interest. At or before completion of the project, Enron expects to sell 30% of its interest in the project to a third party, and has offered such 30% interest to the MSEB. See Item 3, "Legal Proceedings". China. In January 1996, Enron completed construction of a 154-megawatt diesel or gas-fired combined cycle power plant on Hainan Island, an economic free trade zone off the southeastern coast of China. The independent power project is the first such project developed by a U.S. company in China. Enron is operator and fuel manager. In March 1996, Enron sold a 50% interest in the facility to Singapore Power PTE Ltd., the electricity and gas supplier in Singapore. Under the terms of the power purchase agreement signed with Hainan Electric Power Company in September 1994, the facility has begun to sell 80 megawatts of combined-cycle power to the utility. The remaining 74 megawatts from the facility is expected to be sold to the utility in two phases during 1996. Dominican Republic. A limited partnership in which Enron affiliated companies have a 50% ownership interest has signed a 19-year power purchase agreement with the Dominican Republic government utility in connection with the development of a 185-megawatt barge-mounted combined cycle power plant on the north coast of the Dominican Republic. The partnership serves as operator and fuel manager of the plant. Commercial operation commenced in January 1996. Colombia. Construction has been completed and commercial operations commenced in February 1996 on Enron's approximately 357-mile natural gas pipeline and related facilities project, which pipeline runs from the northern coast of Colombia to the central region of the country. Ecopetrol, the state-owned oil company of Colombia, has contracted to be the sole customer for the transportation services and has a 15-year commitment to pay for all of the initial capacity. Puerto Rico. Enron has a 50% interest in a 507-megawatt combined cycle power plant, including a liquefied natural gas terminal and desalination facility, to be built in Penuelas, Puerto Rico. Enron is the turnkey contractor and operator of the project, construction of which is expected to commence in 1996, with commercial operation anticipated in early 1998. Turkey. Enron holds a 50% interest in a 478-megawatt gas-fired power plant to be located in Marmara, Turkey. Enron will be operator and turnkey contractor of the plant. A power purchase agreement has been signed with the state power utility, and subject to financing, construction is expected to begin in 1996, with commercial operation expected in 1999. Bolivia/Brazil. As a partner with the national gas company of Bolivia, Enron is developing, along with Petrobras, the national oil and gas company of Brazil, and others, a pipeline from Bolivia to Brazil. The pipeline project includes a 1,120-mile natural gas pipeline from Santa Cruz, Bolivia to Sao Paulo, Brazil. Enron is also negotiating the development of up to 1,600 megawatts of power projects with Sao Paulo utilities. Enron will own 34% of the Bolivia segment of the pipeline, 8% of the Brazilian segment of the pipeline and will hold a significant interest in the power plants. In addition to the projects referenced above, EDC is involved in projects in varying stages of development in Pakistan, Italy and Indonesia. EDC also has signed preliminary agreements on power and pipeline projects in Bolivia, Brazil, Poland and Mozambique, and is pursuing projects in Vietnam, Thailand, the Philippines and elsewhere. Caribbean Basin. Enron's operations in the Caribbean area are conducted through Enron Americas and its subsidiary companies. Enron Americas' subsidiary Industrias Ventane ("Ventane"), organized in 1953, operates the leading natural gas liquids transportation and distribution business in Venezuela. In Venezuela, Enron Americas is also engaged in the manufacture and distribution of appliances in a joint venture with General Electric and local investors. Enron Americas has a gas pipeline operation in Puerto Rico, and liquid fuels businesses in both Puerto Rico and Jamaica. Liquids Marketing. In late 1993 Enron consolidated the management of its international liquids marketing business with the corresponding domestic activities, in order to take advantage of techniques to enhance profitability and manage risks that have proven effective for Enron in the U.S. International liquids marketing volumes increased from 464 million gallons in 1994 to 779 million gallons in 1995. EXPLORATION AND PRODUCTION Enron's natural gas and crude oil exploration and production operations are conducted by its subsidiary, Enron Oil & Gas Company ("EOG"). Enron currently owns 60% of the outstanding common stock of EOG. EOG is an independent (non-integrated) oil and gas company engaged in the exploration for, and development, production and marketing of, natural gas and crude oil primarily in major producing basins in the United States, as well as in Canada, Trinidad, India and, to a lesser extent, selected other international areas. At December 31, 1995, EOG had estimated net proved natural gas reserves of 3,343 Bcf, including 1,180 Bcf of proved undeveloped methane reserves in the Big Piney (Wyoming) deep Paleozoic formations and amounts related to a volumetric production payment, and estimated net proved crude oil, condensate and natural gas liquids reserves of 50 million barrels, and at such date, approximately 78% of EOG's reserves (on a natural gas equivalent basis) was located in the United States, 10% in Canada, 8% in Trinidad and 4% in India. EOG's seven principal U.S. producing areas are the Big Piney area in Wyoming, the South Texas area, the East Texas area, offshore Gulf of Mexico area, the Canyon Trend area located in West Texas, the Pitchfork Ranch area in southwestern New Mexico, and the Vernal area in Utah. Properties in these areas comprised approximately 67% of EOG's U.S. reserves (on a natural gas equivalent basis) and 90% of EOG's maximum U.S. net natural gas deliverability as of December 31, 1995 and are substantially all operated by EOG. EOG's other U.S. natural gas and crude oil producing properties are located primarily in other areas of Texas, Utah, New Mexico, Oklahoma, California and Kansas. EOG is also engaged in the exploration for and the development, production and marketing of natural gas and crude oil and the operation of natural gas processing plants in western Canada, principally in the provinces of Alberta, Saskatchewan, and Manitoba. EOG conducts operations from offices in Calgary. Canadian natural gas deliverability net to EOG at December 31, 1995 was approximately 95 Mmcf per day, and EOG held approximately 347,000 net undeveloped acres in Canada. EOG also has producing operations offshore Trinidad and India and was recently awarded by the government of Venezuela the rights to pursue exploration, exploitation and development of reserves in the Gulf of Paria East Block offshore the eastern state of Soucre, and is conducting exploration in selected other international areas. Properties offshore Trinidad and India comprised 100% of EOG's proved reserves and production outside of North America at year end 1995. In November 1992, EOG was awarded a 95% working interest concession in the South East Coast Consortium ("SECC") Block offshore Trinidad, encompassing three undeveloped fields, previously held by three government-owned energy companies. The Kiskadee field has been developed, the Ibis field is under development and the Oil Bird field is anticipated to be developed over the next three to five years. Existing surplus processing and transportation capacity at the Pelican field facilities owned and operated by Trinidad and Tobago government-owned companies is being used to process and transport the production. Natural gas is being sold into the local market under a take-or-pay agreement with the National Gas Company of Trinidad and Tobago. In 1995, deliveries net to EOG averaged 107 MMcf per day of natural gas and 5.1 MBbl per day of crude oil and condensate. At December 31, 1995, natural gas deliverability net to EOG was approximately 170 MMcf per day and EOG held approximately 71,000 net undeveloped acres in Trinidad. In 1995, EOG was awarded the right to develop the U(a) block adjacent to the SECC Block and is presently negotiating the terms of a production sharing contract with the Government of Trinidad and Tobago. In December 1994, EOG signed agreements covering profit sharing, joint operations and product sales and representing a 30% working interest in, and was designated operator of, the Tapti, Panna and Mukta Blocks located offshore Bombay, India. EOG is designated operator of all three areas. The blocks were previously operated by the Indian national oil company, Oil & Natural Gas Corporation Limited, which retained a 40% working interest. The 363,000 acre Tapti Black contains two major proved gas accumulations delineated by 22 expendable exploration wells that have been plugged. EOG has initiated a development plan for the Tapti Block accumulations. The 106,000 acre Panna Block and the 192,000 acre Mukta Block are partially developed with 30 wells producing from five producing platforms located in the Panna and Mukta fields. The fields were producing approximately 3.3 MBbl per day of crude oil net to EOG as of December 31, 1995; all associated gas was being flared. EOG intends to continue development of the accumulations and to expand processing capacity to allow crude oil production at full deliverability as well as to permit natural gas sales. EOG was awarded exploration, exploitation and development rights for a block offshore the eastern state of Soucre, Venezuela in early 1996. EOG holds an initial 90% working interest in the joint venture. Plans include the completion of a 3-D seismic survey over the most prospective portions of the block in 1996 and initiation of drilling in 1997, with production targeted for mid-1998. EOG continues to evaluate other selected conventional natural gas and crude oil opportunities outside North America. EOG is pursuing other opportunities in countries where indigenous natural gas and crude oil reserves have been identified, particularly where synergies in natural gas transportation, processing and power cogeneration can be optimized with other Enron Corp. affiliated companies. In early 1995, EOG and the Qatar General Petroleum Corporation signed a nonbinding letter of intent concerning the possible development of a liquefied natural gas project for natural gas to be produced from a block within the North Dome Field. EOG may jointly hold up to a 40% equity interest in the joint venture and EOG would drill and develop to-be-agreed-upon reserves. In addition, EOG signed nonbinding letters of intent in early 1995 with Uzbekneftigaz, the national oil and gas company of Uzbekistan, and Gazprom, the Russian natural gas company, to pursue the feasibility of joint venture development and marketing of previously discovered hydrocarbon reserves in Uzbekistan. EOG is also participating in discussions concerning the potential for conventional oil and gas development opportunities in China, Mozambique, Jordan and Algeria. EOG also holds non-operating working interests in two conventional oil and gas exploration prospects in the U.K. North Sea. EOG continues evaluation and assessment of its international opportunity portfolio in the coalbed methane recovery arena, including projects in South Wales in the U.K., the Lorraine Basin in France, Galilee Basin in Australia and the San Jiao area and Hedong Basin in China. EOG actively competes for reserve acquisitions and exploration leases, licenses and concessions, frequently against companies with substantially larger financial and other resources. To the extent EOG's exploration budget is lower than that of certain of its competitors, EOG may be disadvantaged in effectively competing for certain reserves, leases, licenses and concessions. Competitive factors include price, contract terms and quality of service, including pipeline connection times and distribution efficiencies. In addition, EOG faces competition from other producers and suppliers, as well as increased competition from Canadian natural gas. All of EOG's oil and gas activities are subject to the risks normally incident to the exploration for and development and production of natural gas and crude oil, including blowouts, cratering and fires, each of which could result in damage to life and property. Offshore operations are subject to usual marine perils, including hurricanes and other adverse weather conditions, and governmental regulations as well as interruption or termination by governmental authorities based on environmental and other considerations. In accordance with customary industry practices, insurance is maintained by EOG against some, but not all, of the risks. Losses and liabilities arising from such events could reduce revenues and increase costs to EOG to the extent not covered by insurance. EOG's overseas operations are subject to certain risks, including expropriation of assets, risks of increases in taxes and government royalties, renegotiation of contracts with foreign governments, political instability, payment delays, limits on allowable levels of production and current exchange and repatriation losses, as well as changes in laws and policies governing operations of overseas-based companies generally. The following table sets forth certain information regarding EOG's wellhead volumes of and average prices for natural gas per thousand cubic feet ("Mcf"), crude oil and condensate, and natural gas liquids per barrel ("Bbl"), and average lease and well expenses per thousand cubic feet equivalent ("Mcfe" - natural gas equivalents are determined using the ratio of 6.0 Mcf of natural gas to 1.0 barrel of crude oil and condensate or natural gas liquids) delivered during each of the three years in the period ended December 31, 1995: [Download Table] Year Ended December 31, 1995 1994 1993 Volumes (per day) Natural Gas (MMcf) United States(1) 560 614 649 Canada 76 72 58 Trinidad 107 63 2 Total 743 749 709 Crude Oil and Condensate (MBbl) United States 9.1 8.0 6.6 Canada 2.4 2.0 2.2 Trinidad 5.1 2.5 .1 India 2.5 .1 - Total 19.1 12.6 8.9 Natural Gas Liquids (MBbl) United States 1.0 .3 .2 Canada .4 .4 .4 Total 1.4 .7 .6 Average Prices Natural Gas ($/Mcf) United States(2) $ 1.39 $ 1.71 $ 1.97 Canada .97 1.42 1.34 Trinidad .97 .93 .89 Composite 1.29 1.62 1.92 Crude Oil and Condensate ($/Bbl) United States $17.32 $16.06 $ 16.96 Canada 16.22 14.05 14.63 Trinidad 16.07 15.50 14.36 India 16.81 15.70 - Composite 16.78 15.62 16.37 Natural Gas Liquids ($/Bbl) United States $11.88 $12.45 $ 13.85 Canada 9.74 8.45 9.46 Composite 11.31 9.90 11.12 Lease and Well Expenses ($/Mcfe) United States $ .19 $ .19 $ .18 Canada .35 .34 .48 Trinidad .15 .17 1.46 India(3) 1.25 .13 - Composite .22 .20 .21 ___________________ <FN> (1) Includes 48 MMcf per day in 1995 and 1994, and 81 MMcf per day in 1993 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (2) Includes an average equivalent wellhead value of $.80 per Mcf in 1995, $1.27 per Mcf in 1994, and $1.57 per Mcf in 1993 for the volumes described in note (1), net of transportation costs. (3) Based on expense estimates for nine days of production for 1994. Expenses for 1995 include certain non-recurring startup costs.
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The following table sets forth certain information regarding EOG's volumes of natural gas delivered under other marketing and volumetric production payment arrangements, and resulting average per unit gross revenue and per unit amortization of deferred revenues along with associated costs during each of the three years in the period ended December 31, 1995. [Download Table] Year Ended December 31, 1995 1994 1993 Volumes (MMcf per day)(1) . . . . . 264 324 293 Average Gross Revenue ($/Mcf)(2) . . $ 1.88 $ 2.38 $ 2.57 Associated Costs ($/Mcf)(3)(4) . . 1.51 2.06 2.32 Margin ($/Mcf) . . . . . . . . . . $ .37 $ 0.32 $ 0.25 ___________________ <FN> (1) Includes 48 MMcf per day in 1995 and 1994 and 81 MMcf per day in 1993 delivered under the terms of volumetric production payment and exchange agreements effective October 1, 1992, as amended. (2) Includes per unit deferred revenue amortization for the volumes detailed in note (1) at an equivalent of $2.46 per Mcf ($2.36 per million British thermal units) in 1995 and 1994 and $2.50 per Mcf ($2.40 per million British thermal units) in 1993. (3) Includes an average value of $1.57 per Mcf in 1995, $1.92 per Mcf in 1994 and $2.20 per Mcf in 1993 for the volumes detailed in note (1) including average wellhead value and any transportation costs and exchange differentials. (4) Including transportation and exchange differentials. REGULATION General Enron's interstate natural gas pipeline companies are subject to the regulatory jurisdiction of the FERC under the Natural Gas Act ("NGA") with respect to rates, accounts and records, addition of facilities, the extension of services in some cases, the abandonment of services and facilities, the curtailment of gas deliveries and other matters. Enron's intrastate pipeline companies are subject to state and some federal regulation. Enron's importation of natural gas from Canada is subject to approval by the Office of Fossil Energy of the Department of Energy. Certain activities of Enron are subject to the Natural Gas Policy Act of 1978 ("NGPA"). Enron's pipelines which carry natural gas liquids and refined petroleum products are subject to the regulatory jurisdiction of the FERC under the Interstate Commerce Act as to rates and conditions of service. Domestic legislation affecting the oil and gas industry is under constant review for amendment or expansion. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue and have issued rules and regulations which, among other things, require permits for the drilling of wells, regulate the spacing of wells, prevent the waste of natural gas and crude oil resources through proration, require drilling bonds and regulate environmental and safety matters. The regulatory burden on the oil and gas industry increases its cost of doing business and, consequently, affects its ability to compete and profitability. A substantial portion of EOG's oil and gas leases in the Big Piney area and in the Gulf of Mexico, as well as some in other areas, are granted by the federal government and administered by the Bureau of Land Management (the "BLM") and the Minerals Management Service (the "MMS") federal agencies. Operations conducted by EOG on federal oil and gas leases must comply with numerous statutory and regulatory restrictions. Certain operations must be conducted pursuant to appropriate permits issued by the BLM and the MMS. Various federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, may affect Enron's operations and costs through their effect on the oil and gas exploration, development and production operations as well as their effect on the construction, operation and maintenance of pipeline and terminaling facilities. It is not anticipated that Enron will be required in the near future to expend amounts that are material in relation to its total capital expenditures program by reason of environmental laws and regulations, but inasmuch as such laws and regulations are frequently changed, Enron is unable to predict the ultimate cost of compliance. Enron's non-domestic operations are subject to the jurisdiction of numerous governmental agencies in the countries in which its projects are located with respect to environmental and other regulatory matters. Generally, many of the countries in which Enron does and will do business have recently developed or are in the process of developing new regulatory and legal structures to accommodate private and foreign-owned businesses. These regulatory and legal structures and their interpretation and application by administrative agencies are relatively new and sometimes limited. Many detailed rules and procedures are yet to be issued. The interpretation of existing rules can also be expected to evolve over time. Although Enron believes that its operations are in compliance in all material respects with all applicable environmental laws and regulations in the applicable foreign jurisdictions, Enron also believes that the operations of its projects eventually may be required to meet standards that are comparable in many respects to those in effect in the United States and in countries within the European Community. In addition, as Enron acquires additional projects in various countries, it will be affected by the environmental and other regulatory restrictions of such countries. Natural Gas Rates and Regulations Northern, Transwestern, FGT and Northern Border are "natural gas companies" under the NGA and, as such, are subject to the jurisdiction of the FERC. The FERC has jurisdiction over, among other things, the construction and operation of pipeline and related facilities used in the transportation, storage and sale of natural gas in interstate commerce, including the extension, expansion or abandonment of such facilities. The FERC also has jurisdiction over the rates and charges for the transportation of natural gas in interstate commerce and the sale by a natural gas company of natural gas in interstate commerce for resale. Northern, Transwestern, FGT and Northern Border hold the required certificates of public convenience and necessity issued by the FERC authorizing them to construct and operate all of their pipelines, facilities and properties for which certificates are required in order to transport and sell natural gas for resale in interstate commerce. As necessary, Northern, Transwestern, FGT and Northern Border file applications with the FERC for changes in their rates and charges designed to allow them to recover fully their costs of providing service to resale and transportation customers, including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period, and in certain cases are subject to refund under applicable law, until such time as the FERC issues an order on the allowable level of rates. Although the FERC's jurisdiction extends to the regulation of gas transported in interstate commerce or sold in interstate commerce for resale, the price at which gas is sold to direct industrial customers by a natural gas company is not subject to the FERC's jurisdiction. In June 1988, the FERC issued Order No. 497 ("Order 497") which imposes requirements on interstate pipelines with marketing affiliates, intended to eliminate an interstate pipeline's ability to give its marketing affiliates preferential treatment. Among other things, Order 497 requires interstate pipelines to separate their operating personnel and facilities from those of their marketing affiliates to the maximum extent practicable. In 1994, the FERC issued Order Nos. 566, 566-A and 566-B, in which it extended indefinitely its Order No. 497 regulations governing relationships between interstate pipelines and their marketing affiliates, subject to revisions to delete an out of date standard and revise certain reporting and record keeping requirements. Among other matters, these new rules require pipelines to post on their electronic bulletin boards, within 24 hours of gas flow, information concerning discounted transportation provided to marketing affiliates to enable competing marketers to request comparable discounts. The rules retain existing standards, as revised by Order No. 497-E, requiring the contemporaneous disclosure to all shippers of transportation related information provided to a marketing affiliate, and prohibiting disclosure of certain information to marketing affiliates. Since 1985, the FERC has endeavored to make natural gas transportation more accessible to gas buyers and sellers on an open and non-discriminatory basis. These efforts have significantly altered the marketing and pricing of natural gas. The FERC's Order No. 636, issued in April 1992, mandated a fundamental restructuring of interstate pipeline sales and transportation services. Order No. 636 required interstate natural gas pipelines to "unbundle" or segregate the sales, transportation, storage, and other components of their existing sales service, and to separately state the rates for each unbundled service. Order No. 636 also required interstate pipelines to assign capacity rights they have on upstream pipelines to such pipelines' former sales customers and provides for the recovery by interstate pipelines of costs associated with the transition from providing bundled sales services to providing unbundled transportation and storage services. The purpose of Order No. 636 is to further enhance competition in the natural gas industry by assuring the comparability of pipeline sales service and services offered by a pipelines' competitors. A key effect of Order No. 636 and its progeny has been to substantially eliminate merchant sales by pipelines like Northern, Transwestern and FGT. Various aspects of Order No. 636 were challenged, including alleged shifts of costs between pipeline customer groups and the continuing reliability of unbundled services. In two subsequent orders on rehearing of Order No. 636 (Order Nos. 636-A and 636-B), the FERC modified the original order in response to these and other concerns. Numerous parties filed petitions for court review of Order Nos. 636, 636-A and 636-B, as well as orders in individual pipeline restructuring proceedings. Oral arguments before the District of Columbia Circuit Court of Appeals were heard in late February 1996. Upon judicial review, these orders may be reversed in whole or in part. With Order No. 636 subject to court review, it is difficult to predict with precision its ultimate effects. Order Nos. 636, 636-A and 636-B mandate a rate design, known as straight fixed variable, which is designed to allow pipelines to recover substantially all fixed costs, a return on equity and income taxes in the capacity reservation component of their rates. Northern, Transwestern and FGT have implemented the service restructuring required by Order Nos. 636, 636-A and 636-B by unbundling their sales service, offering a limited market based merchant service and establishing a straight fixed variable rate design to recover all fixed costs, including return on equity, in the demand component of their rates. The FERC has indicated that Northern, Transwestern and FGT will be authorized to recover all prudently incurred costs associated with a reduced merchant role resulting from the implementation of Order Nos. 636, 636-A, and 636-B. Enron believes that, overall, Order No. 636 has had a positive impact on Enron and the natural gas industry as a whole. The structural changes mandated by Order No. 636 have resulted in a more competitive industry. The straight fixed variable rate design included in Order No. 636 allows pipelines to recover in the demand component of their rates all fixed costs, including income taxes and return on equity, allocated to firm customers. Since a pipeline recovers demand costs regardless of whether gas is ever transported, the straight fixed variable rate design is expected to reduce the volatility of the revenue stream to pipelines. Regulatory issues and rates on Enron's regulated pipelines are subject to final determination by the FERC. Enron's regulated pipelines currently apply accounting standards that recognize the economic effects of regulation and, accordingly, have recorded regulatory assets and liabilities related to their operations. Enron evaluates the applicability of regulatory accounting and the recoverability of these assets through rate or other contractual mechanisms on an ongoing basis. Net regulatory assets at December 31, 1995 are approximately $291 million, which include transition costs incurred related to FERC Order No. 636 of approximately $125 million. The regulatory assets related to the FERC Order No. 636 transition costs are scheduled to be primarily recovered from customers by the end of 1998, while the remaining assets are expected to be recovered over varying time periods. Enron's regulated pipelines have all successfully completed their transitions under FERC Order No. 636 although future transition costs may be incurred subject to ongoing negotiations and market factors. Enron believes, based upon its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of pending regulatory matters will not have a material impact on Enron's financial position or results of operations. Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels as the pipeline restructuring under Order No. 636 is fully completed and implemented. In late 1993, the FERC convened a conference to consider issues relating to gathering services performed by interstate pipelines or their affiliates. Commencing in May 1994, the FERC issued a series of orders in individual cases that delineate its gathering policy as a result of the comments received. Among other matters, the FERC slightly narrowed its statutory tests for establishing gathering status and reaffirmed that, except in situations in which the gatherer acts in concert with an interstate pipeline affiliate to frustrate the FERC's transportation policies, it does not have jurisdiction over natural gas gathering facilities and services and that such facilities and services are properly regulated by state authorities. This FERC action may further encourage regulatory scrutiny of natural gas gathering by state agencies. In addition, the FERC has approved several transfers by interstate pipelines, including certain of Enron's pipeline subsidiaries, of gathering facilities to unregulated independent or affiliated gathering companies. This could increase competition among gatherers in the affected areas. Certain of the FERC's orders delineating its new gathering policy are subject to pending court appeals. Enron cannot predict the effect that any of the aforementioned orders or the challenges to such orders will ultimately have on Enron's operations. Additional proposals and proceedings that might affect the natural gas industry are pending before Congress, the FERC and the courts. Enron cannot predict when or whether any such proposals or proceedings may become effective. It should also be noted that the natural gas industry historically has been very heavily regulated; therefore, there is no assurance that the less regulated approach currently being pursued by the FERC will continue indefinitely. Thus, Enron cannot predict the ultimate outcome or durability of the unbundled regulatory regime mandated by Order No. 636. The rates at which natural gas is sold in Texas to gas utilities serving customers within an incorporated area and directly to customers in rural and unincorporated areas are subject to the original jurisdiction of the Railroad Commission of Texas. The rates set by city councils or commissions for gas sold within their jurisdiction may be appealed to the Railroad Commission. Regulation of intrastate gas sales and transportation by the Railroad Commission is governed by certain provisions of the Texas Gas Utility Regulatory Act of 1983. The Railroad Commission also regulates production activities and to some degree the operation of affiliated special marketing programs. Oil Pipeline Rates and Regulations The North System and Cypress Pipeline of Enron Liquids Pipeline Operating Limited Partnership (the "Partnership") are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act ("ICA"). The ICA requires the Partnership to maintain tariffs on file with the FERC, which tariffs set forth the rates the Partnership charges for providing transportation services on the interstate common carrier pipelines, as well as the rules and regulations governing these services. Environmental Regulations Enron and its subsidiaries are subject to extensive federal, state and local laws and regulations covering the discharge of materials into the environment, or otherwise relating to the protection of the environment, and which require expenditures for remediation at various operating facilities and waste disposal sites, as well as expenditures in connection with the construction of new facilities. Enron believes that its operations and facilities are in general compliance with applicable environmental regulations. Environmental laws and regulations have changed substantially and rapidly over the last 20 years, and Enron anticipates that there will be continuing changes. The clear trend in environmental regulation is to place more restrictions and limitations on activities that may impact the environment, such as emissions of pollutants, generation and disposal of wastes and use and handling of chemical substances. Increasingly strict environmental restrictions and limitations have resulted in increased operating costs for Enron and other businesses throughout the United States, and it is possible that the costs of compliance with environmental laws and regulations will continue to increase. Enron will attempt to anticipate future regulatory requirements that might be imposed and to plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as the "Superfund" law, requires payments for cleanup of certain abandoned waste disposal sites, even though such waste disposal activities were undertaken in compliance with regulations applicable at the time of disposal. Under the Superfund legislation, one party may, under certain circumstances, be required to bear more than its proportional share of cleanup costs at a site where it has responsibility pursuant to the legislation, if payments cannot be obtained from other responsible parties. Other legislation mandates cleanup of certain wastes at facilities that are currently being operated. States also have regulatory programs that can mandate waste cleanup. CERCLA authorizes the Environmental Protection Agency ("EPA") and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. The scope of financial liability under these laws involves inherent uncertainties. Enron has entered into a consent decree with the EPA and other potentially responsible parties ("PRPs") with respect to the cleanup of one Superfund site. Enron has received requests for information from the EPA and state agencies concerning what wastes Enron may have sent to certain sites, and it has also received requests for contribution from other parties with respect to the cleanup of other sites. However, management does not believe that any costs incurred in connection with these sites (either individually or in the aggregate) will have a material impact on Enron's financial position or results of operations. (See Item 3, "Legal Proceedings").
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OPERATING STATISTICS The following table presents selected statistical information for Enron's domestic gas and power services business segment as well as revenue data for all of Enron's businesses. Revenue amounts are in thousands of dollars. [Download Table] Year Ended December 31, 1995 1994 1993 ECT Natural Gas and Crude Oil Physical/Notional Quantities (BBtue/d)* Firm 5,392 4,895 4,558 Interruptible 2,255 2,039 828 Transport Volumes 580 538 571 Subtotal 8,227 7,472 5,957 Financial Settlements (notional) 32,938 16,459 5,027 Total 41,165 23,931 10,984 Electricity (Thousand megawatt hours) Owned Production 3,441 3,481 2,883 Transaction Volumes Marketed 7,767 1,221 - <FN> *Includes intercompany amounts [Download Table] Revenues by Business Segment Year Ended December 31, 1995 1994 1993 Transportation and Operation Natural Gas and Other Products Unaffiliated $ 49,223 $ 87,670 $ 453,621 Intersegment 4,409 9,455 22,779 53,632 97,125 476,400 Transportation Services Unaffiliated 680,338 740,606 751,896 Intersegment 20,353 25,395 35,841 700,691 766,001 787,737 Other Revenues Unaffiliated 75,384 109,248 180,408 Intersegment 848 3,906 21,461 76,232 113,154 201,869 TOTAL 830,555 976,280 1,466,006 Domestic Gas and Power Services Natural Gas and Other Products Unaffiliated 6,289,982 6,633,039 5,214,870 Intersegment 9,715 59,684 95,934 6,299,697 6,692,723 5,310,804 Transportation Services Unaffiliated 11,364 13,511 16,015 Intersegment 352 1,041 506 11,716 14,552 16,521 Other Revenues Unaffiliated 762,405 519,032 219,061 Intersegment (113,043) (47,333) 37,718 649,362 471,699 256,779 TOTAL 6,960,775 7,178,974 5,584,104 International Gas and Power Services Natural Gas and Other Products Unaffiliated 779,605 337,917 598,472 Intersegment 4,275 983 12,697 783,880 338,900 611,169 Other Revenues Unaffiliated 59,520 54,002 152,903 Intersegment 39,482 6,001 6,516 99,002 60,003 159,419 TOTAL 882,882 398,903 770,588 Exploration and Production Natural Gas and Other Products Unaffiliated 410,548 431,907 364,643 Intersegment 164,818 242,008 280,363 575,366 673,915 645,006 Other Revenues Unaffiliated 70,629 56,791 33,911 Intersegment 113,373 48,082 28,208 184,002 104,873 62,119 TOTAL 759,368 778,788 707,125 Intersegment Eliminations (244,583) (349,222) (542,023) Total Revenues $9,188,997 $8,983,723 $7,985,800
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CURRENT EXECUTIVE OFFICERS OF THE REGISTRANT Name and Age Present Principal Position and Other Material Positions Held During Last Five Years Kenneth L. Lay (53) Chairman of the Board and Chief Executive Officer since February 1986. Richard D. Kinder (51) President and Chief Operating Officer since October 1990. Rodney L. Gray (43) President of Enron Global Power & Pipelines L.L.C. since November 1995. Chairman and Chief Executive Officer of Enron Global Power & Pipelines L.L.C. since June 1995. Managing Director, Enron Development Corp., since August 1995. Chairman and Chief Executive Officer, Enron International Inc., since June 1993. Senior Vice President, Finance and Treasurer, Enron Corp., from October 1992 to June 1993. Vice President, Finance and Treasurer, Enron Corp., from 1988 to October 1992. Stanley C. Horton (46) Co-Chairman and Chief Executive Officer of Enron Operations Corp. since February 1996. President and Chief Operating Officer of Enron Operations Corp. from June 1993 to February 1996. President of Northern Natural Gas Company from June 1991 to June 1993. President of Florida Gas Transmission Company from 1988 to May 1991. Jeffrey K. Skilling (42) Chairman, Chief Executive Officer and Managing Director of Enron Capital & Trade Resources Corp. since June 1995. Managing Director, Development, Enron Capital & Trade Resources Corp., from December 1994 to June 1995. Chairman and Chief Executive Officer (Risk Management and Power), Enron Gas Services Corp., from June 1993 to December 1994. Chairman and Chief Executive Officer of Enron Gas Services Corp. from January 1991 to June 1993. Chairman and Chief Executive Officer of Enron Finance Corp. since August 1990; Partner, McKinsey & Company, Consultants, from 1979 to August 1990. Thomas E. White (52) Co-Chairman and Chief Executive Officer of Enron Operations Corp. since February 1996. Chairman and Chief Executive Officer of Enron Operations Corp. from June 1993 to February 1996. Chairman and Chief Executive Officer of Enron Power Corp. since July 1991. Brigadier General, United States Army, from 1988 to 1990. Executive Assistant to Chairman of the Joint Chiefs of Staff from 1989 to 1990. Edmund P. Segner,III(42) Executive Vice President and Chief of Staff since October 1992. Senior Vice President, Investor, Public & Government Relations from October 1990 to October 1992. James V. Derrick, Jr.(51) Senior Vice President and General Counsel since June 1991. Partner, Vinson & Elkins from January 1977 until June 1991. Jack I. Tompkins (50) Senior Vice President and Chief Information, Administrative and Accounting Officer since October 1992. Senior Vice President and Chief Financial Officer from January 1988 to October 1992. Partner, Arthur Andersen & Co. from September 1981 until January 1988. Kurt S. Huneke (42) Vice President, Finance and Treasurer since July 1993. Executive Vice President, Finance and Administration, Enron International Inc., from July 1992 to July 1993. Senior Vice President and Chief Financial Officer, Enron Europe Limited, from January 1991 to July 1992. Assistant Treasurer, Enron Corp., from February 1989 to January 1991. Item 2. PROPERTIES Gas Transmission and Liquid Fuels Enron's natural gas facilities include approximately 37,000 miles of transmission and gathering lines, 110 mainline compressor stations, four underground gas storage fields and two liquefied natural gas storage facilities. Other properties in which Enron and its affiliates have an ownership interest or lease include 14 natural gas liquids extraction plants in Texas, Louisiana, Wyoming, Kansas, Florida, New Mexico and North Dakota. A large number of railroad tank and hopper cars, truck transports and bulk vehicles are owned or leased and used for the delivery of liquids products. Enron also owns interests in pipeline and related facilities associated with its participation and investments in jointly-owned pipeline systems. Substantially all the gathering and transmission lines of Enron are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens which have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of majority interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets and state highways, and in some instances, such permits are revocable at the election of the grantor. Permits have also been obtained from railroad companies to cross over or under lands or rights-of-way, many of which are also revocable at the grantor's election. Some such permits require annual or other periodic payments. In a few minor cases, property for pipeline purposes was purchased in fee. Most of Enron's transmission subsidiaries have the right of eminent domain to acquire rights-of-way and lands necessary for their pipelines and appurtenant facilities. Enron's gas processing plants, regulator and compressor stations, clean fuel facilities and offices are located on tracts of land owned by it in fee or leased from others. In the case of oil and gas leases, definitive examination and curing of title defects are usually deferred until such time as funds are expended in connection with drilling of such properties. Enron is of the opinion that it has generally satisfactory title to its rights-of-way and lands used in the conduct of its businesses, subject to liens for current taxes, liens incident to operating agreements and minor encumbrances, easements and restrictions which do not materially detract from the value of such property or the interest of Enron therein or the use of such properties in such businesses. Oil and Gas Exploration and Production Properties and Reserves Reserve Information For estimates of EOG's net proved reserves and proved developed reserves of natural gas and liquids, including crude oil, condensate and natural gas liquids, see Note 18 to the Consolidated Financial Statements. Estimates of proved and proved developed reserves at December 31, 1995, 1994 and 1993 were based on studies performed by EOG's engineering staff for reserves in the United States, Canada, Trinidad and India. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1995, 1994 and 1993 covering producing areas containing 73%, 59% and 65%, respectively, of proved reserves of EOG on a net-equivalent- cubic-feet-of-gas basis, indicate that the estimates of proved reserves prepared by EOG's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ materially from the estimates prepared by DeGolyer and MacNaughton. Such estimates by DeGolyer and MacNaughton in the aggregate varied by not more than 5% from those prepared by EOG's engineering staff. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by EOG. There are numerous uncertainties inherent in estimating quantities of proved reserves and in projecting future rates of production and timing of development expenditures, including many factors beyond the control of the producer. The reserve data set forth in Note 18 to the Consolidated Financial Statements represents only estimates. Reserve engineering is a subjective process of estimating underground accumulations of natural gas and liquids, including crude oil, condensate and natural gas liquids, that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the amount and quality of available data and of engineering and geological interpretation and judgment. As a result, estimates of different engineers normally vary. In addition, results of drilling, testing and production subsequent to the date of an estimate may justify revision of such estimate. Accordingly, reserve estimates are often different from the quantities ultimately recovered. The meaningfulness of such estimates is highly dependent upon the accuracy of the assumptions upon which they were based. In general, the volume of production from oil and gas properties owned by EOG declines as reserves are depleted. Except to the extent EOG acquires additional properties containing proved reserves or conducts successful exploration and development activities, or both, the proved reserves of EOG will decline as reserves are produced. Volumes generated from future activities of EOG are therefore highly dependent upon the level of success in acquiring or finding additional reserves and the costs incurred in doing so. EOG's estimates of reserves filed with other federal agencies agree with the information set forth in Note 18. Producing Oil and Gas Wells The following table reflects EOG's ownership at December 31, 1995 in gas and oil wells located in Texas, the Gulf of Mexico, Oklahoma, New Mexico, Utah, Wyoming and various other states, Canada, Trinidad and India. "Net" is obtained by multiplying "Gross" by EOG's working interests in the properties. Gross oil and gas wells include 205 with multiple completions. [Download Table] Productive Productive Total Gas Wells Oil Wells Productive Wells Gross Net Gross Net Gross Net 4,627 3,170 774 435 5,401 3,605
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Acreage The following table summarizes EOG's developed and undeveloped acreage at December 31, 1995. Excluded is acreage in which EOG's interest is limited to owned royalty, overriding royalty and other similar interests. [Enlarge/Download Table] Developed Undeveloped Total Gross Net Gross Net Gross Net United States California 10,215 6,368 638,199 637,454 648,414 643,822 Offshore Gulf of Mexico 315,745 132,505 455,133 352,577 770,878 485,082 Texas 454,256 221,207 272,990 214,233 727,246 435,440 Wyoming 161,867 117,815 316,330 246,758 478,197 364,573 Oklahoma 214,363 72,279 106,074 58,162 320,437 130,441 New Mexico 75,487 35,056 88,013 47,924 163,500 82,980 Utah 57,820 46,512 35,863 30,365 93,683 76,877 Kansas 14,176 9,498 25,055 22,766 39,231 32,264 Colorado 9,153 1,447 35,006 16,755 44,159 18,202 Michigan 11 10 14,213 13,650 14,224 13,660 Mississippi 2,490 1,853 12,171 8,445 14,661 10,298 Montana 1,301 1,169 2,082 1,075 3,383 2,244 Other 15,225 2,831 10,986 5,204 26,211 8,035 Total 1,332,109 648,550 2,012,115 1,655,368 3,344,224 2,303,918 Canada Alberta 364,328 168,503 192,429 146,739 556,757 315,242 Saskatchew 179,343 155,588 222,975 199,604 402,318 355,192 Manitoba 11,531 9,702 480 480 12,011 10,182 British Columbia 656 164 -- -- 656 164 Total Canada 555,858 333,957 415,884 346,823 971,742 680,780 Other International Australia -- -- 9,600,000 4,800,000 9,600,000 4,800,000 China -- -- 1,208,805 604,403 1,208,805 604,403 Russia -- -- 1,425,000 712,500 1,425,000 712,500 France -- -- 1,063,925 1,063,925 1,063,925 1,063,925 India 60,000 18,000 602,207 180,662 662,207 198,662 Trinidad 4,200 3,990 74,851 71,108 79,051 75,098 United Kingdom -- -- 173,600 86,800 173,600 86,800 Total Other International 64,200 21,900 14,148,388 7,519,398 14,212,588 7,541,388 Total 1,952,167 1,004,497 16,576,387 9,521,589 18,528,554 10,526,086
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Drilling and Acquisition Activities During each of the years ended December 31, 1995, 1994 and 1993, EOG spent approximately $513.8 million, $493.9 million, and $430.1 million, respectively, for exploratory and development drilling and acquisition of leases and producing properties. EOG drilled, participated in the drilling of or acquired wells as set out in the table below for the periods indicated: [Enlarge/Download Table] Year Ended December 31, 1995 1994 1993 Gross Net Gross Net Gross Net Development Wells Completed Gas 337 253.91 558 434.53 579 469.10 Oil 72 58.01 45 34.67 49 22.51 Dry 62 50.16 54 43.65 70 54.43 Exploratory Wells Completed Gas 11 9.03 22 17.70 28 21.43 Oil 8 3.61 4 3.07 5 3.40 Dry 21 13.28 37 30.67 42 29.43 Total 511 388.00 720 564.29 773 600.30 Wells in Progress at End of Period 52 32.71 45 28.79 82 61.09 Total 563 420.71 765 593.08 855 661.39 Wells Acquired Gas 277 101.70* 41 40.90* 44 26.44 Oil 5 .46 60 38.99* - 12.80* Total 282 102.16 101 79.89 44 39.24 <FN> * Includes acquisition of additional interests in certain wells in which EOG previously held an interest. All of EOG's drilling activities are conducted on a contract basis with independent drilling contractors. EOG owns no drilling equipment. Item 3. LEGAL PROCEEDINGS Enron is a party to various claims and litigation arising in the ordinary course of its business, the significant items of which are discussed below. Management recognizes the uncertainties of litigation and the possibility that one or more adverse rulings could materially impact operating results. However, although no assurances can be given, Enron believes, based on the nature of and Enron's understanding of the facts and circumstances which give rise to such actions and claims, and after considering appropriate reserves that have been established, that the ultimate resolution of such items, individually or in the aggregate, will not have a materially adverse effect on Enron's financial position or results of operations. Litigation In November 1992, TransAmerican Natural Gas Corporation (TransAmerican) filed a suit in the 93rd District Court, Hidalgo County, Texas, against Enron Corp. and EOG alleging breach of confidentiality agreements, misappropriation of trade secrets and unfair competition, with specific reference to four tracts in Webb County, Texas, which EOG leased for their oil and gas exploration and development potential. TransAmerican sought actual damages of $100 million and exemplary damages of $300 million. EOG filed claims against TransAmerican and its sole shareholder alleging common law fraud, negligent misrepresentation and breach of state antitrust laws. On April 6, 1994, Enron Corp. was granted summary judgment, wherein the court ordered that TransAmerican take nothing on its claims against Enron Corp. On October 16, 1995, EOG, TransAmerican and its sole shareholder entered into an agreement which resolved all claims. The settlement terms did not have a materially adverse effect on Enron's financial position or results of operations. The suit was dismissed with prejudice as to all parties by court order entered November 28, 1995. In 1995, several parties (the Plaintiffs) filed suit in Harris County District Court in Houston, Texas against Intratex Gas Company ("Intratex"), Houston Pipe Line Company and Panhandle Gas Company (collectively, the Enron Defendants), each of which is a wholly-owned subsidiary of Enron. The Plaintiffs also sued certain other unaffiliated third parties (collectively, the Other Defendants). The Plaintiffs were either sellers or royalty owners under numerous gas purchase contracts with Intratex, many of which have terminated. Early in 1996, the case was severed by the Court into two matters that will be tried (or otherwise resolved) separately. In the first matter, the Plaintiffs sued only the Enron Defendants, alleging that they committed fraud and negligent misrepresentation in connection with the "Panhandle program," a special marketing program established in the early 1980s. In the second matter, the Plaintiffs allege that Intratex and the Other Defendants violated state regulatory requirements and certain gas purchase contracts by failing to take the Plaintiffs' gas ratably with other producers' gas at certain times between 1978 and 1988. In both matters, the Plaintiffs seek actual and punitive damages, plus prejudgment interest and attorneys fees. All Defendants deny the Plaintiffs' claims and have asserted various affirmative defenses, including the statute of limitations. The Enron Defendants believe they have strong legal and factual defenses, and intend to vigorously contest the claims brought in each matter. Although no assurances can be given, Enron believes that the ultimate resolution of these matters will not have a materially adverse effect on its financial position or results of operations. Environmental Matters Enron is subject to extensive Federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments is expected to result in increased operating expenditures. The related future cost is indeterminable, as many of the rules implementing the Clean Air Act's requirements have not yet been finalized. However, any increased operating expenses are not expected to have a material adverse effect on Enron's financial position or results of operations. In connection with FGT's Phase III pipeline expansion, on September 16, 1994, the Florida Department of Environmental Protection (FDEP) entered an order suspending FGT's construction activities in wetland areas in Florida alleging that certain construction activities failed to conform with permits previously issued by that agency. The FDEP also instituted administrative proceedings for the imposition of civil penalties for such alleged violations. On September 23, 1994, FGT and the FDEP entered into a consent order in which the FDEP lifted its suspension of construction south of Suwannee County, Florida and agreed to lift its suspension on northern Florida wetlands areas construction upon FGT's adoption of certain oversight, training and wetlands restoration and mitigation practices, payment of $210,000 into the FDEP's Pollution Recovery Fund and reimbursement of another $16,000 in administrative expenses. The consent order was effective as of September 23, 1994. On October 7, 1994, the FDEP issued notice of its intention to assess FGT with an additional civil penalty of $365,400 for alleged violations of wetlands permits and regulations in northern Florida. FGT did not contest the alleged violations or civil penalties assessed by the FDEP, and FGT has paid such penalty. FGT subsequently retrained construction personnel and took other actions to increase its efforts to comply with all requirements for construction in wetlands areas. On November 23, 1994, the FDEP dissolved the September 16 suspension order, and FGT was authorized to recommence construction in northern Florida. The Phase III expansion was placed in-service on March 1, 1995. During May 1992, Enron entered into a Consent Decree with the EPA concerning the cleanup of the Peoples Natural Gas Superfund Site in Dubuque, Iowa, where a coal gasification plant had operated during the first half of this century. The EPA had claimed that Enron was a PRP because a predecessor company of Enron had purchased the site in the late 1950's after coal gas operations ceased, and had conducted surface operations there, including the dismantling of buildings. In 1992, Enron recorded the expense and related liability for these cleanup costs and under the Consent Decree agreed to make five equal, annual payments of $590,000. Four of such installments have been paid and the fifth installment is due and payable in June 1996. In addition, Enron has received requests for information from the EPA and state environmental agencies inquiring whether Enron has disposed of materials at other waste disposal sites. Enron has also received requests for contribution from other parties with respect to the cleanup of other sites. Enron may be required to share in the costs of the cleanup of some of these sites. However, based upon the amounts claimed and the nature and volume of materials sent to sites at which Enron has an interest, management does not believe that any potential costs incurred in connection with these notices and third party claims, either taken individually or in the aggregate, will have a material impact on Enron's financial position or results of operations. Other In October 1994, an explosion occurred at Enron's methanol plant in Pasadena, Texas. Before the explosion, the plant was producing approximately 420,000 gallons of methanol per day, approximately half of which was being used at Enron's MTBE plant. There were no fatalities or serious injuries as a result of the explosion. The plant was placed back in commercial operation in June 1995. Taking into account business interruption and casualty insurance coverages, Enron currently anticipates that the explosion did not and will not have a material adverse effect on its financial position or results of operations. In connection with a Power Purchase Agreement dated December 8, 1993, as amended, between Dabhol Power Company, Enron's 80%-owned subsidiary, and the Maharashtra State Electricity Board (the MSEB), Dabhol Power Company has been developing Phase I of an electricity generating power plant south of Bombay, State of Maharashtra, India (the Project). Financial closing occurred and Project construction began on March 1, 1995. After construction had begun, and following elections to the Maharashtra Legislative Assembly, a new coalition government took office in the State of Maharashtra. The new coalition government appointed a review committee to study the Project, and on August 3, 1995, announced the State government's intention to terminate the Project. Work on the Project was ordered stopped by the MSEB, and construction ceased on August 8, 1995. Enron believes that such actions were in clear violation of the contract and in response to these actions, Dabhol Power Company, pursuant to its remedies in the agreements with the State government, commenced arbitration proceedings in London against the State government for the actions it has taken to terminate the Project. Dabhol Power Company seeks to recover all of its construction and other expenses, in addition to lost profits. The arbitration tribunal has been appointed and several arbitration hearings have occurred in London. On February 7, 1996, the arbitration tribunal issued an interim award on jurisdiction in favor of Dabhol Power Company. In addition, renegotiation efforts were begun and in February 1996, Dabhol Power Company, the State government and the MSEB reached a preliminary agreement, subject to full governmental and lender approvals which are currently being sought, to go forward with an expanded project. The arbitration proceedings have been stayed until May 1, 1996 to allow the parties time to focus on renegotiation efforts. While the parties are working together in good faith and Enron anticipates construction to resume in the near future, various approvals remain outstanding from government agencies and lenders. Although the outcomes of the arbitration and the renegotiation processes cannot be predicted with certainty, based on currently available information, Enron believes that the ultimate outcome of the Project will not have a materially adverse effect on its financial position. In March 1993, Enron entered into long-term gas contracts with Phillips Petroleum Company United Kingdom Limited, British Gas Exploration and Production Limited and Agip (U.K.) Limited to purchase all of the future gas production from the J-Block field which is located in the North Sea offshore the United Kingdom (the J-Block Contracts). Such agreements provide for Enron to take or pay for the gas at a fixed price (with possible escalations throughout the contract period). Gas paid for, but not taken, may be recovered in later contract years. The J-Block Contracts provide for a first delivery date of not later than October 1, 1996. The contract price for such natural gas is in excess of current spot market prices in the United Kingdom. In September 1995, Enron announced that, in accordance with its contractual rights, it had notified the J-Block sellers that Enron's nominations for gas from the J- Block fields were estimated to be zero from the first delivery date through September 30, 1997. In addition, in accordance with its contractual rights, Enron has made no estimated nominations for J-Block gas to date under the J-Block Contracts for the contract year ending September 30, 1998. Enron continues its good faith efforts to develop mutually beneficial solutions regarding pricing terms so that production from J-Block can begin as soon as possible. Enron believes that there are many commercial reasons for the parties to resolve any contract issues, but efforts have not been successful to date. Enron has advised the J-Block sellers that it intends to assert all legal rights, exercise all available commercial flexibility and pursue all available commercial and legal remedies under the J-Block Contracts, and stands ready and able to perform all legal obligations under the J-Block Contracts, including potential prepayments for gas to be taken in later years. The long-term market demand for J-Block gas supply remains favorable and Enron anticipates being able to meet all of its various short- and long-term market commitments. Although no assurances can be given, based upon the foregoing and other information currently available, Enron does not anticipate that the J-Block Contracts will have a materially adverse effect on its financial position. Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS There were no matters submitted to a vote of security holders during the fourth quarter of 1995. PART II Item 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS Common Stock The following table indicates the high and low sales prices for the common stock of Enron as reported on the New York Stock Exchange (consolidated transactions reporting system), the principal market in which the securities are traded, and dividends paid per share for the calendar quarters indicated. The common stock is also listed for trading on the Chicago Stock Exchange and the Pacific Stock Exchange, as well as The London Stock Exchange and Frankfurt Stock Exchange. [Download Table] 1995 1994 High Low Dividends High Low Dividends First Quarter............. 34 28 $.20 $34 1/4 $27 3/8 $.1875 Second Quarter............ 36 7/8 32 1/2 .20 34 5/8 28 5/8 .1875 Third Quarter............. 36 3/8 31 5/8 .20 34 28 5/8 .1875 Fourth Quarter............ 39 3/8 33 .2125 33 26 3/4 .20 Cumulative Second Preferred Convertible Stock The following table indicates the high and low sales prices for the Cumulative Second Preferred Convertible Stock ("Second Preferred Stock") of Enron as reported on the New York Stock Exchange (consolidated transactions reporting system), the principal market in which the securities are traded, and dividends paid per share for the calendar quarters indicated. The Second Preferred Stock is also listed for trading on the Chicago Stock Exchange. [Download Table] 1995 1994 High Low Dividends High Low Dividends First Quarter............. $398 $393 $2.7304 $450 $376 3/4 $2.625 Second Quarter............ 491 454 2.7304 455 450 2.625 Third Quarter............. 477 454 2.7304 450 427 2.625 Fourth Quarter............ 502 462 2.901 410 410 2.7304 At December 31, 1995, there were approximately 25,600 record holders of common stock and 245 record holders of Second Preferred Stock. Other information required by this item is set forth on page 34 under Item 6 -- "Selected Financial Data (Unaudited) - Common Stock Statistics" for the years 1990-1995.
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Item 6. SELECTED FINANCIAL DATA (UNAUDITED) [Enlarge/Download Table] 1995 1994 1993 1992 1991 1990 Operating Revenues (millions) $ 9,189 $ 8,984 $ 7,986 $ 6,415 $ 5,698 $5,460 Total Assets (millions) $13,239 $11,966 $11,504 $10,312 $10,070 $9,849 Common Stock Statistics Income from continuing operations(a) Total (millions) $519.7 $453.4 $386.5 $328.8 $232.1 $202.2 Per share - primary $2.07 $1.80 $1.55 $1.39 $1.03 $0.88 Per share - fully diluted $1.94 $1.70 $1.46 $1.30 $0.98 $0.86 Earnings on common stock(a) Total (millions) $504.3 $438.4 $369.6 $284.1 $207.4 $177.2 Per share - primary $2.07 $1.80 $1.55 $1.29 $1.03 $0.88 Per share - fully diluted $1.94 $1.70 $1.46 $1.21 $0.98 $0.86 Dividends Total (millions) $204.6 $191.8 $170.5 $148.2 $127.0 $125.0 Per share $0.81 $0.76 $0.71 $0.66 $0.63 $0.62 Shares outstanding (millions) Actual at year-end 244.8 244.2 241.6 237.2 202.4 201.8 Average for the year 243.7 243.4 239.0 220.0 202.1 201.6 Capitalization (millions) Long-term debt $3,065 $2,805 $2,661 $2,459 $3,109 $2,983 Preferred stock of subsidiary 377 377 214 - - - Minority interest 549 290 196 179 101 97 Shareholders' equity 3,165 2,880 2,623 2,518 1,901 1,838 Total capitalization $7,156 $6,352 $5,694 $5,156 $5,111 $4,918 <FN> (a) The 1993 amounts exclude effects of a $54.0 million ($0.23 per share) primarily non-cash charge to income for the increase in the corporate Federal income tax rate from 34% to 35%.
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Enron Corp. and Subsidiaries ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS The following review of the results of operations and financial condition of Enron Corp. and its subsidiaries and affiliates (Enron) should be read in conjunction with the Consolidated Financial Statements. Results of Operations Consolidated Net Income Enron's net income for 1995 was $520 million compared to $453 million in 1994 and $387 million in 1993 (exclusive of a primarily non-cash charge of $54 million in 1993 to adjust the deferred tax liability for the increase in the corporate Federal statutory income tax rate from 34% to 35%). Net income for all three years reflects improved income before interest, minority interest and income taxes as compared to the applicable preceding year, partially offset by higher dividends on preferred stock of subsidiaries and income tax expense. Primary earnings per share of common stock was $2.07 in 1995 as compared to $1.80 in 1994 and $1.32 in 1993, after a $0.23 per share charge applicable to the $54 million tax rate change adjustment. Income Before Interest, Minority Interest and Income Taxes The following table presents income before interest, minority interest and income taxes (IBIT) for each of Enron's operating segments: [Download Table] (In Millions) 1995 1994 1993 Transportation and Operation $ 359 $403 $382 Domestic Gas and Power Services 157 202 197 International Gas and Power Services 142 148 132 Exploration and Production 241 198 129 Corporate and Other 266 (7) (42) Total $1,165 $944 $798 Transportation and Operation The transportation and operation segment includes Enron's interstate natural gas pipelines, including results of Northern Natural Gas Company (Northern), Transwestern Pipeline Company (Transwestern) and Florida Gas Transmission (Florida Gas), and construction, management and operation of pipelines, clean fuels plants and power facilities, including results of Enron Engineering & Construction. Enron's investment in crude oil marketing and transportation operations conducted by EOTT Energy Partners, L.P. (EOTT) and Enron's investment in liquids pipeline operations are also in this segment. The following reflects revenues and IBIT for each of these groups: [Download Table] (In Millions) 1995 1994 1993 Revenues Interstate Natural Gas Pipelines $787 $901 $1,306 Construction, Management and Operation 44 47 37 EOTT - 28 123 Total 831 976 1,466 Cost of gas and other products 39 72 409 Operating expenses 322 442 551 Depreciation and amortization 83 88 116 Taxes, other than income taxes 47 47 49 Equity in earnings of unconsolidated subsidiaries 23 49 23 Other income, net 79 27 18 Total before fourth quarter charges 442 403 382 Fourth quarter regulatory and contingency adjustments (83) - - Income before interest, minority interest and income taxes $359 $403 $ 382 The segment's IBIT decreased $44 million in 1995 as compared to 1994 primarily due to lower earnings from the interstate natural gas pipelines and EOTT and a $19 million charge to reflect the discontinuance of EOTT's West Coast processing and asphalt marketing operations, partially offset by gains of $67 million from the sale of non-strategic gathering and processing assets. The decrease in earnings from the interstate natural gas pipelines was primarily due to fourth quarter charges of $83 million related to regulatory reserves and other contingencies. The segment realized a $21 million increase in IBIT in 1994 as compared to 1993 primarily due to increased IBIT from the interstate natural gas pipelines and the construction, management and operation of assets, partially offset by lower earnings from EOTT primarily due to the reduced ownership interest in the first quarter of 1994 resulting from the exchange by EOTT Energy Corp. of its crude oil trading and transportation operations for common and subordinated units and a 2% general partner interest in EOTT. See Note 8 to the Consolidated Financial Statements. The following discussion analyzes the significant changes in the various components of IBIT for the transportation and operation segment, prior to fourth quarter regulatory and contingency adjustments. Revenues Interstate Natural Gas Pipelines. Revenues of the interstate natural gas pipelines declined $114 million (13%) during 1995 and $405 million (31%) during 1994 as compared to the applicable preceding year. The decrease in revenues from 1994 to 1995 primarily reflects completion of the recovery of certain transition costs for Northern. The 1994 decline reflects the effect of unbundling services which reduced sales revenues of Northern as Northern is now primarily a transporter of natural gas. Transport revenues declined 9% in 1995 and 2% in 1994 as compared to the prior year. Transport volumes for Northern and Transwestern totaled 5.6 trillion British thermal units per day (TBtu/d) in 1995, 5.5 TBtu/d in 1994 and 5.1 TBtu/d in 1993. The increases in volumes were more than offset by lower average transport rates. Construction, Management and Operation Revenues. Revenues earned in connection with the construction, management and operation of power and pipeline projects totaled $44 million in 1995 as compared to $47 million and $37 million during 1994 and 1993, respectively. The 1994 increase reflects fees earned in connection with the operation of additional facilities offset by lower construction revenues as a result of project completions. EOTT. Net revenues from EOTT decreased $28 million in 1995 and $95 million in 1994 as a result of the reduced ownership interest effective in March 1994. Cost of Gas and Other Products Sold The cost of gas and other products sold by the transportation and operation segment decreased by $33 million (46%) during 1995 as compared to 1994 primarily as a result of decreased gas purchases following the termination of the merchant function by Northern. The cost of gas and other products sold by the transportation and operation segment decreased 82% during 1994 as compared to 1993 as a result of lower sales volumes as discussed above combined with lower average cost per unit of natural gas sold. Operating Expenses Operating expenses of the transportation and operation segment declined $120 million (27%) during 1995 and $109 million (20%) during 1994. The 1995 decline primarily reflects a decrease of $64 million in amortization of deferred contract reformation costs due to the completion by Northern of the recovery of certain transition costs in early 1995, combined with lower transmission, compression and storage transition costs. Additionally, operating expenses decreased as a result of the decreased ownership interest in EOTT. The 1994 decline is primarily a result of the decreased ownership interest in EOTT combined with lower operating expenses of the interstate natural gas pipelines reflecting system modernization and reduced expenses resulting from lower sales volumes transported on other pipelines. Depreciation expense for the transportation and operation segment decreased $5 million (6%) during 1995 as compared to 1994 primarily as a result of the decreased ownership interest in EOTT. Depreciation expense decreased $28 million (24%) in 1994 as compared to 1993 primarily as a result of the decreased ownership interest in EOTT and the interstate pipelines' adjustment in 1993 of accumulated depreciation in accordance with a Federal Energy Regulatory Commission (FERC) ruling. Other Income and Deductions Equity in earnings of unconsolidated subsidiaries decreased by $26 million (53%) during 1995 as compared to 1994 primarily reflecting decreased earnings from EOTT and a $19 million charge to reflect the discontinuance of EOTT's West Coast processing and asphalt marketing operations. Equity in earnings of unconsolidated subsidiaries increased by $26 million during 1994 compared to 1993 reflecting a $36 million increase in earnings from the 50% owned Citrus Corp. (Citrus), which owns Florida Gas, and $5 million of equity earnings from EOTT. The increased earnings of Citrus reflect improved sales margins as a result of the renegotiation of the pricing terms of Citrus' gas sales contract with its largest customer and allowance for funds used during construction related to the Florida Gas Phase III pipeline expansion. These increases were offset by reduced earnings resulting from the decreased ownership interest in Northern Border Pipeline Company. Other income, net, increased $52 million (193%) in 1995 as compared to 1994 primarily due to gains related to the disposition of non-strategic natural gas processing and gathering facilities. Other income increased $9 million (50%) in 1994 as compared to 1993 primarily as a result of the continued resolution of regulatory and contractual matters relating to the interstate natural gas pipelines. Outlook The transportation and operation segment should continue to provide stable earnings and cash flows during 1996. The successful settlement of significant regulatory issues and various expansion projects underway or proposed by the interstate natural gas pipelines should provide a reliable stream of cash flow. During 1996, the transportation and operation segment expects to complete sales of certain natural gas gathering facilities as a result of the cessation of its gas merchant function following the implementation of FERC Order 636. Additionally, the segment will actively promote engineering and construction services to provide incremental earnings and will continue to concentrate on reducing its overall cost structure. Domestic Gas and Power Services The domestic gas and power activities are conducted primarily by Enron Capital & Trade Resources (ECT) and include the marketing, purchasing and financing of natural gas, natural gas liquids, crude oil, power and other energy commodities and the management of the portfolio of commitments arising from these activities. The domestic gas processing operations are also included in this segment. ECT's stated objective is to provide solutions to energy problems worldwide. To meet this objective, ECT serves a diverse customer group that includes independent power producers, gas and electric utilities, industrials, oil and gas producers, financial institutions and other energy marketers. This broad customer mix generates a need for a variety of financial structures, products and terms. This diversity requires ECT to manage, on a portfolio basis, the resulting market risks inherent in these transactions. To provide a framework to manage such risks, ECT has defined a set of fundamental portfolio management principles, including formal definition of portfolio management responsibilities; continual evaluation of ECT's market risk, communicated and managed through risk limits and controls approved by Enron's Board of Directors; measurement of risk in accordance with value-at-risk methodologies and evaluation of business performance, including risk/return relationships. ECT has established portfolio management functions for both market and credit risk. Operating separately from the units that create or actively manage these risk exposures, ECT's Risk Control Group reports to an ECT Managing Director who reports extensively to the Audit Committee of the Enron Board of Directors. This group is responsible for the establishment of policies, measurement of the risks within ECT's portfolio and the communication of these risks to senior management and the Enron Board of Directors. This group is committed to the continuous review of the portfolio, policies and procedures to ensure that ECT's portfolio remains aligned with ECT's policies. ECT's services can be categorized into three business lines: Cash and Physical, Risk Management and Finance. The following table reflects IBIT for each business line: [Download Table] 1995 1994 1993 Cash and Physical $146 $170 $171 Risk Management 193 151 93 Finance 31 13 26 Unallocated expenses (138) (132) (93) Total before Non-Recurring Charge 232 202 197 Charge for Clean Fuels Plant Operations (75) - - Total $157 $202 $197 The following discussion analyzes the contributions to IBIT and the outlook for each of the business lines. Cash and Physical. The cash and physical operations include earnings from physical contracts of one year or less involving marketing and transportation of natural gas, liquids, electricity and other commodities, earnings from the management of ECT's contract portfolio and earnings related to the physical assets of ECT. Also included in this line of business are the effects of actual settlements of ECT's long-term physical and notional quantity based contracts. The cash and physical operations earnings before overhead expenses and a $75 million charge in the fourth quarter of 1995 related to the clean fuels plant operations were $146 million in 1995, $170 million in 1994 and $171 million in 1993. ECT markets a substantial quantity of energy commodities on a daily basis as reflected in the following table (including intercompany amounts): [Download Table] 1995 1994 1993 Natural Gas and Crude Oil Physical/Notional Quantities (BBtue/d)(a) Firm(b) 5,392 4,895 4,558 Interruptible 2,255 2,039 828 Transport Volumes 580 538 571 Subtotal 8,227 7,472 5,957 Financial Settlements (notional) 32,938 16,459 5,027 Total 41,165 23,931 10,984 Electricity (Thousand megawatt hours) Owned Production 3,441 3,481 2,883 Transaction Volumes Marketed 7,767 1,221 - <FN> (a) Billion British thermal units equivalent per day. (b) Commitments to deliver a specified volume of gas at a fixed or market responsive price. Exclusive of the $75 million charge related to the clean fuels plant operations, the earnings from cash and physical operations decreased 14% in 1995 as compared to 1994 as a result of lower margins in liquids marketing and an increase in clean fuels operating expenses. Earnings from the marketing of physical natural gas also declined in 1995 as compared to 1994 due to lower margins in all but the fourth quarter. Partially offsetting these declines in earnings were increased earnings from electricity marketing, the sale of certain physical assets and the management of ECT's contract portfolio. During the fourth quarter of 1995, ECT provided for expected losses of $75 million on its clean fuels plant operations resulting from higher natural gas prices and low MTBE prices because of soft demand for MTBE. Earnings for the cash and physical sector in 1994 were virtually unchanged compared to 1993. Earnings from ECT's management of its portfolio of contracts increased in 1994, but were offset by lower gas processing margins. Margins from short-term marketing in the purely physical natural gas market also decreased slightly reflecting the more competitive marketplace. During 1996, ECT anticipates improvement in the cash and physical business over the 1995 results. The existence of its substantial portfolio of contracts as well as the ability to benefit from the relationships between the financial and physical markets and the natural gas and electricity markets provide substantial opportunities for earnings. Additionally, opportunities for the growth in earnings from new markets, including electricity, should enhance future results. Risk Management. ECT's risk management operations consist of market activity on long-term contracts (transactions greater than one year). ECT originates new contracts for the energy sector and evaluates and restructures its existing contracts on an on-going basis to develop additional products and services to meet its customers' changing needs. Fixed price contract market activity totaled 5,952 trillion British thermal units equivalent (TBtue), 6,615 TBtue and 3,781 TBtue for 1995, 1994 and 1993, respectively. In 1995, the earnings before unallocated expenses from the risk management operations were $193 million compared to $151 million in 1994 and $93 million in 1993. Earnings from risk management increased 28% in 1995 as compared to 1994 due primarily to earnings related to the restructuring of existing long-term contracts with independent power producers and local distribution companies. Growth in originations from the Canadian operations also contributed to the earnings increase. For 1995, originations with utilities were lower than in 1994. Earnings from risk management increased 62% in 1994, primarily as a result of the execution of various electricity and new long-term gas contracts and the restructuring of existing long-term contracts with utilities, local distribution companies and independent power producers. ECT expects a strong performance from its risk management business in 1996 as it expands further into electricity and other new markets and pursues opportunities in the international marketplace. The infrastructure for this business has been established and ECT will be capitalizing on its existing customer base, its skills and the emerging competitive marketplace. Finance. ECT's finance operations provide capital to customers through various product offerings including volumetric production payments. The finance sector contributed $31 million of ECT's earnings in 1995 and $13 million and $26 million in 1994 and 1993, respectively. Production payments and financings arranged were $382 million, $503 million and $470 million in 1995, 1994 and 1993, respectively. Earnings from the finance sector increased 138% in 1995 compared with 1994 due primarily to the partial sale of ECT's interests in certain equity investments and earnings associated with the restructuring of long-term gas supply contracts with an independent power plant. This was partially offset by lower earnings from production payments arranged. Although total production payments and financings arranged were greater in 1994 than 1993, the earnings in this business decreased 50% in 1994 due to the difference in the types of transactions originated in each of these periods and the timing of income recognition from these transactions. In 1996, ECT will continue to expand its products and services in its role as a full-service provider of various types of capital. Additionally, opportunities will be pursued in the international marketplace. Other. ECT's net unallocated expenses such as rent, systems expenses and other support group costs were $138 million, $132 million and $93 million in 1995, 1994 and 1993, respectively. These costs increased in both years due to continued expansion into new markets and system upgrades. ECT expects its unallocated expenses to increase during 1996 as it continues to expand into new markets. International Gas and Power Services Enron's international gas and power services segment includes international power and pipeline development activities and operations. IBIT for this group totaled $142 million during 1995, $148 million in 1994 and $132 million in 1993. The decrease in 1995 was a result of decreased earnings related to the formation of Enron Global Power & Pipelines L.L.C. (EPP) and lower earnings from Enron Americas, partially offset by increased earnings from Enron Europe and increased promotion and development activities, while the 1994 increase primarily reflects earnings from the formation of EPP and increased earnings from power and pipeline projects. Net Revenues Revenues net of cost of sales for the international segment increased by $32 million (19%) in 1995 as compared to 1994 and $22 million (15%) during 1994. Included in 1995 were net revenues of $24 million from the promotion of a portion of Enron's interest in its power assets at Teesside in Northeast England. In addition, revenues of $48 million were recognized as a result of the satisfaction of Enron's support obligations related to the formation of EPP. The 1994 results included $65 million of revenues earned in connection with the formation of EPP and $28 million of net revenues earned on the promotion of a portion of Enron's interest in its liquids processing facilities at Teesside. Costs and Expenses Operating expenses for this segment increased $16 million (21%) during 1995 and $7 million (10%) during 1994 as compared to the preceding years primarily as a result of higher operating expenses incurred in connection with increased activities in the power operations area. Depreciation expense of this segment increased $11 million (75%) during 1995 as compared to 1994 as a result of increased international project activities and $6 million (68%) during 1994 as compared to 1993 primarily as a result of increased investment in international natural gas liquids assets. Other Income and Deductions Equity in earnings of unconsolidated subsidiaries of the international gas and power services segment increased $12 million (27%) during 1995 as compared to 1994 primarily as a result of increased earnings from Teesside and improved results from Enron Americas' Venezuelan manufacturing operations. Equity in earnings of unconsolidated subsidiaries of this segment increased $3 million (8%) during 1994 primarily as a result of earnings from two Philippine power projects which began operations in mid-1993 and early 1994, combined with increased earnings from the Argentina pipeline. These increases were partially offset by lower earnings from Enron Americas' manufacturing operations in Venezuela. Other income, net, decreased $21 million in 1995 after increasing $5 million during 1994, primarily as a result of foreign currency gains realized by Enron Americas in 1994. Outlook The objective of the international gas and power services segment is to deliver energy solutions worldwide through the utilization of Enron's extensive portfolio of products and services. Growth opportunities in the international market are expected to result from the current and projected demand for electrical power generation, the under-utilization of natural gas reserves throughout the world and increased environmental awareness. Exploration and Production IBIT of the exploration and production segment totaled $241 million during 1995 as compared to $198 million during 1994 and $129 million during 1993. Enron's exploration and production activities are conducted by Enron Oil & Gas Company (EOG). The exploration and production segment's 1995, 1994 and 1993 IBIT includes approximately $45 million, $35 million and $7 million, respectively, of income related to hedges placed by Enron on commodity positions not hedged by EOG. The increase in IBIT realized by EOG primarily reflects increased crude oil production and prices, strong other marketing results and increased gains on sales of reserves and related assets, combined with a reduction in total per unit operating costs. Wellhead volume and price statistics (including intercompany amounts) are as follows: [Download Table] 1995 1994 1993 Natural Gas Volumes (MMcf/d)(a) North America(b) 636 686 707 Trinidad 107 63 2 Total 743 749 709 Average Natural Gas Prices ($/Mcf) North America(c) $1.34 $1.68 $1.92 Trinidad 0.97 0.93 0.89 Composite $1.29 $1.62 $1.92 Crude/Condensate Volumes (MBbl/d)(a) North America 11.5 10.0 8.8 Trinidad 5.1 2.5 0.1 India 2.5 0.1 - Total 19.1 12.6 8.9 Average Crude/Condensate Prices ($/Bbl) North America $17.09 $15.65 $16.39 Trinidad 16.07 15.50 14.36 India 16.81 15.70 - Composite $16.78 $15.62 $16.37 <FN> (a) Million cubic feet per day or thousand barrels per day, as applicable. (b) Includes an annual average of 48 MMcf per day in 1995 and 1994 and 81 MMcf per day in 1993 delivered under the terms of a volumetric production payment agreement effective October 1, 1992, as amended. (c) Includes an average equivalent wellhead value of $0.80 per Mcf in 1995, $1.27 per Mcf in 1994 and $1.57 per Mcf in 1993 for the volumes detailed in Note (b) above, net of transportation costs. The following discussion analyzes the significant changes in the various components of IBIT for the exploration and production segment. Revenues Gross revenues of the exploration and production segment decreased $19 million (2%) during 1995 after increasing by $72 million (10%) in 1994. The impact of reduced wellhead natural gas sales volumes and prices was partially offset by the positive effects of EOG's hedging strategies which resulted in a gain of $65 million from natural gas commodity price hedging activities during 1995 compared to a gain of $11 million during 1994 and a loss of $18 million in 1993. Gains related to hedges placed by Enron on commodity positions not hedged by EOG increased to $45 million in 1995 from $35 million in 1994 and $7 million in 1993. Because of significantly lower average wellhead natural gas prices beginning in the second half of 1994, U.S. wellhead natural gas volumes were voluntarily curtailed by an average of 105 MMcf/d during 1995 compared to an average of 70 MMcf/d during 1994. In addition, the impact of reduced drilling for U.S. natural gas deliverability and sales of oil and gas reserves and related assets net of purchases resulted in a reduction of 20 MMcf/d in U.S. delivered volumes during 1995 as compared to 1994. Increased production of natural gas, crude oil and condensate from Trinidad contributed to increased revenues in both years, as did new crude oil and condensate volumes associated with the initiation of operations in India and increased crude oil and condensate prices during 1995. Also included in revenues are gains on sales of oil and gas reserves and related assets of $63 million in 1995 compared with $54 million in 1994 and $13 million in 1993. Costs and Expenses The cost of natural gas sold by the exploration and production segment in connection with other natural gas marketing activities declined 44% in 1995 as compared to 1994 and 2% in 1994 as compared to 1993. The 1995 decline was primarily due to lower other natural gas marketing volumes and lower average associated costs per Mcf. The decrease in 1994 as compared to 1993 reflects lower average costs partially offset by higher other natural gas marketing volumes. Operating expenses for the exploration and production segment increased $14 million (13%) in 1995 compared to 1994 and $7 million (7%) in 1994 compared to 1993. The increase in 1995 is due primarily to increased lease and well and general and administrative expenses due to expanded international operations, including the initiation of operations in India in late December 1994. The increase in 1994 reflects increased general and administrative expenses associated with expanded operations. Oil and gas exploration expenses decreased $5 million (6%) in 1995 as compared to 1994 after increasing $8 million in 1994. The 1995 decline was a result of lower dry hole and impairment costs, while the increase in 1994 reflects an increased level of exploration activities and higher impairments associated with certain offshore Gulf of Mexico leases. Depreciation, depletion and amortization (DD&A) expense declined 11% in 1995 and 3% in 1994 as compared to the applicable prior year. The 1995 decline reflects a decrease in the average DD&A rate primarily reflecting an overall decrease of $0.09 per thousand cubic feet equivalent (Mcfe - natural gas equivalents are determined using the ratio of 6 Mcf of natural gas to 1 barrel of crude oil, condensate or natural gas liquids) in certain North America DD&A rates and an increase in the proportion of production from international operations which have lower average DD&A rates than incurred in North America operations. The decline during 1994 reflects increased production from offshore Trinidad at an average DD&A rate significantly less than the North America operations rate including a $0.03 per Mcfe decrease in the North America DD&A rate. On a per unit natural gas equivalent volumes delivered basis, DD&A expense declined 15% in 1995 to $0.68 per Mcfe as compared to $0.80 per Mcfe in 1994 and $0.89 per Mcfe in 1993. Taxes, other than income taxes, increased $4 million (15%) in 1995 and declined $7 million (20%) during 1994. The increase in 1995 was primarily due to higher production related taxes associated with new production in India. The decline in 1994 was primarily due to lower taxable United States wellhead volumes and prices and reductions in 1994 related to revisions of certain prior year production taxes. Total per unit operating costs for lease and well expense, DD&A, general and administrative expense, interest expense and taxes other than income decreased $0.07 per Mcfe, averaging $1.22 per Mcfe during 1995 compared to $1.29 per Mcfe for 1994 and $1.43 per Mcfe for 1993. Outlook Management remains optimistic that continually increasing recognition of natural gas as a more environmentally friendly source of energy along with the availability of significant domestically sourced supplies will result in increases in demand and a strengthening of the overall natural gas market over time. EOG plans to continue to focus a substantial portion of its development and certain exploration expenditures in its major producing areas in North America. However, based on the continuing uncertainty associated with North America natural gas prices and as a result of the recent success realized in Trinidad, opportunities available to EOG in connection with the signing of agreements in India in December 1994 and EOG's selection as the winning bidder on a block offshore Venezuela in January 1996, EOG anticipates spending an increasing part of its available funds in the further development of those opportunities. In addition, EOG will continue limited exploratory expenditures in new areas outside of North America, including the continued evaluation of coalbed methane recovery potential in the United Kingdom, China, France, Australia and certain other countries. Corporate and Other The corporate and other segment's IBIT was $266 million in 1995 as compared to expense of $7 million in 1994 and $42 million in 1993. Results from this segment in 1995 reflect a gain of $367 million on the public offering of 31 million outstanding shares of EOG stock held by Enron, which reduced Enron's interest in EOG from 80% to 61% (see Note 16 to the Consolidated Financial Statements), and amounts recognized following the resolution of certain litigation. These increases were partially offset by $74 million of charges primarily related to the conversion of a compensation plan to more closely align employees' interests to Enron common stock. The improvement during 1994 primarily reflects a $15 million pretax gain realized on the formation of EOTT. Interest and Related Charges, net Interest and related charges, net, is shown on the Consolidated Income Statement net of interest capitalized. The net expense increased $11 million in 1995 primarily due to higher debt levels and increased interest rates. The net expense decreased $27 million during 1994 primarily because of lower overall interest costs on Enron's floating rate obligations as a result of lower rates achieved through hedging activities. Enron periodically enters into certain interest rate swaps to manage its overall interest costs. Dividends on Preferred Stock of Subsidiaries Dividends on preferred stock of subsidiaries relate to the issuance of 8.55 million shares of 8% Cumulative Guaranteed Monthly Income Preferred Shares by Enron Capital L.L.C. in November 1993, the issuance by Enron Capital Resources, L.P. of 3 million shares of 9% Cumulative Preferred Securities, Series A in August 1994 and the issuance in December 1994 by Enron Equity Corp. of 880 shares of 8.57% Preferred Stock, $0.001 par value, in a private transaction. See Note 9 to the Consolidated Financial Statements. Minority Interests Minority interests increased during 1995 as compared to 1994 primarily as a result of the sale in the fourth quarter of 1994 of approximately 48% of Enron's interest in EPP. Income Tax Expense Income tax expense increased during 1995 and 1994 compared to the applicable prior year due to increased pretax income, a decrease in tight gas sand Federal tax credits and the higher effective tax rate on the sale of EOG shares by Enron in 1995. Financial Condition Cash From Operating Activities Net cash used in operating activities totaled $15 million during 1995 as compared to $461 million provided by operating activities during 1994. The decline primarily reflects increased working capital requirements, due in part to reduced sales of accounts receivable, partially offset by increased cash from monetization of price risk management assets. Cash From Investing Activities Net cash provided by investing activities totaled $13 million during 1995 compared to $560 million used in investing activities during 1994. Proceeds from asset sales totaled $997 million during 1995 compared to $440 million during 1994. The 1995 amounts reflect proceeds from the sale of 31 million outstanding shares of EOG common stock held by Enron, as well as sales of oil and gas properties and non- strategic processing and gathering facilities. The 1994 amount primarily reflects proceeds realized on the formation of EPP and the previously discussed sale of Enron's crude oil trading and transportation operations to EOTT. As more fully discussed below, capital expenditures (property additions and other capital expenditures) totaled $777 million in 1995 compared to $669 million in 1994. Equity investments totaled $170 million in 1995 compared to $273 million in 1994. Equity investments during 1995 primarily reflect investments in international power projects. The 1994 amount primarily reflects investments in connection with the Florida Gas Phase III pipeline expansion and investments in Joint Energy Development Investments Limited Partnership and in various international projects. Cash From Financing Activities Net cash used in financing activities totaled $16 million during 1995 compared to cash provided of $92 million during 1994. During 1995, Enron issued $967 million of long-term debt while retiring $448 million principal amount of long- term borrowings. Other cash outflows during 1995 included $254 million of cash dividend payments on common and preferred stock and $65 million for net repurchases of Enron Corp. common stock under Enron's stock repurchase authorization. In addition to the debt issuances discussed above, financing cash outflows during 1995 included a $250 million decrease in short-term borrowings. Working Capital At December 31, 1995, Enron had working capital of $295 million. Should a working capital deficit occur, Enron would be able to fund such a deficit through the utilization of credit facilities which, at December 31, 1995, provided for up to $2.1 billion of committed and uncommitted credit of which no amounts were outstanding. Certain of the credit agreements contain prefunding covenants. However, such covenants are not expected to materially restrict Enron's access to funds under these agreements. In addition, Enron sells commercial paper and has agreements to sell trade accounts receivable, thus providing financing to meet seasonal working capital needs. Management believes that the sources of funding described above are sufficient to meet short- and long-term liquidity needs not met by cash flows from operations. Capital Expenditures Capital expenditures by operating segment are detailed as follows: [Download Table] 1996 (In Millions) Estimate 1995 1994 1993 Transportation and Operation $190 $129 $125 $152 Domestic Gas and Power Services 120 118 83 102 International Gas and Power Services 10 58 14 53 Exploration and Production* 470 464 442 383 Corporate and Other 10 8 5 5 Total $800 $777 $669 $695 <FN> * Excludes exploration expenses of $60 million (estimate), $55 million, $59 million, and $55 million for 1996, 1995, 1994 and 1993, respectively. Capital expenditures increased $108 million during 1995 as compared to 1994 primarily as a result of increased expenditures by ECT primarily related to upgrade of existing facilities and systems costs, combined with higher capital expenditures in the international operations. The increase in international capital expenditures primarily reflects property additions by Enron Europe and Enron Americas. Capital expenditures during 1994 declined slightly as compared to 1993. Reduced capital expenditures by the transportation and operation, domestic gas and power services and international gas and power services segments were partially offset by higher capital spending by the exploration and production segment. The increase in capital expenditures by the exploration and production segment reflects the acquisition of selected properties to complement existing North American producing areas and the addition of new international activities in India. Capital expenditures during 1996 are expected to total approximately $800 million. However, the overall level of capital spending as well as spending by individual business segments will vary depending upon conditions in the energy market and other related economic conditions. In addition, equity investments are expected to be approximately $200 million, primarily relating to international projects. Management believes that the capital spending program will be funded by a combination of internally generated funds, proceeds from dispositions of selected assets and long- and short-term borrowings. Capitalization Total capitalization at December 31, 1995 was $7.2 billion. Debt as a percentage of total capitalization decreased to 42.8% at December 31, 1995 as compared to 44.2% at December 31, 1994. The improvement primarily reflects increased retained earnings and the utilization of proceeds from the previously discussed sale of EOG shares to reduce long-term debt. Assuming the mandatory conversion in late 1998 of 10.5 million Exchangeable Notes into EOG shares held by Enron, the pro-forma debt to capitalization percentage would be approximately 40.5% at December 31, 1995. INFORMATION REGARDING FORWARD LOOKING STATEMENTS This Annual Report 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 Enron believes that its expectations are based on reasonable assumptions, it can give no assurance that its goals will be achieved. Important factors that could cause actual results to differ materially from those in the forward looking statements herein include political developments in foreign countries, the pace of deregulation of retail natural gas and electricity markets in the United States, the timing and extent of changes in commodity prices for crude oil, natural gas, electricity and interest rates, the extent of EOG's success in acquiring oil and gas properties and in discovering, developing and producing reserves, the timing and success of Enron's efforts to develop international power, pipeline and other infrastructure projects and conditions of the capital markets and equity markets during the periods covered by the forward looking statements.
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Item 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA The information required hereunder is included in this report as set forth in the "Index to Financial Statements" on page F-1. Item 9. DISAGREEMENTS ON ACCOUNTING AND FINANCIAL DISCLOSURE None.
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PART III Item 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT The information required by Item 10 of Form 10-K relating to (i) directors who are nominees for election as directors at Enron's Annual Meeting of Stockholders to be held on May 7, 1996, and (ii) compliance by directors and executive officers with Section 16(a) of the Securities Exchange Act of 1934 is set forth, respectively, under the captions entitled "Election of Directors" and "Compensation of Directors and Executive Officers - Certain Transactions" in Enron's Proxy Statement, and is incorporated herein by reference. The information required by Item 10 of Form 10-K with respect to executive officers is set forth in Part I of this Form 10-K under the heading "Current Executive Officers of the Registrant". There are no family relationships among the officers listed, and there are no arrangements or understandings pursuant to which any of them were elected as officers. Officers are appointed or elected annually by the Board of Directors at its first meeting following the Annual Meeting of Stockholders, each to hold office until the corresponding meeting of the Board in the next year or until a successor shall have been elected, appointed or shall have qualified. Item 11. EXECUTIVE COMPENSATION The information regarding executive compensation is set forth in the Proxy Statement under the captions "Compensation of Directors and Executive Officers -Director Compensation; Executive Compensation; Stock Option Grants During 1995; Aggregated Stock Option/SAR Exercises During 1995 and Stock Option/SAR Values as of December 31, 1995; Long-Term Incentive Plan - Awards in 1995; Retirement and Severance Plans; Severance Pay Plan; Employment Contracts; Certain Transactions; and Compensation Committee Interlocks and Insider Participation", and is incorporated herein by reference. Item 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT (a) Security ownership of certain beneficial owners The information regarding security ownership of certain beneficial owners is set forth in the Proxy Statement under the caption "Election of Directors - Stock Ownership of Certain Beneficial Owners", and is incorporated herein by reference. (b) Security ownership of management The information regarding security ownership of management is set forth in the Proxy Statement under the caption "Election of Directors - Stock Ownership of Management and Board of Directors as of January 31, 1996", and is incorporated herein by reference. (c) Changes in control None. Item 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS The information regarding certain relationships and related transactions is set forth in the Proxy Statement under the caption "Compensation of Directors and Executive Officers - Certain Transactions"; and "Compensation Committee Interlocks and Insider Participation", and is incorporated herein by reference. PART IV Item 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K (a)(1) and (2) Financial Statements and Financial Statement Schedules. See "Index to Financial Statements" set forth on page F-1. (a)(3) Exhibits: *3.01 - Restated Certificate of Incorporation of Enron Corp., as amended (Exhibit 3.01 to Enron Form 10-K for 1994, File No. 1-3423). 3.02 - Bylaws of Enron Corp. as currently in effect. *4.01 - Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank, as supplemented and amended by the First Supplemental Indenture dated as of December 1, 1995 (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22-14390, filed October 24, 1985; Exhibit 4(b) to Form S-3 Registration Statement No. 33-64057 filed on November 8, 1995). There have not been filed as exhibits to this Form 10-K other debt instruments defining the rights of holders of long-term debt of Enron, none of which relates to authorized indebtedness that exceeds 10% of the consolidated assets of Enron and its subsidiaries. Enron hereby agrees to furnish a copy of any such instrument to the Commission upon request. *4.02 - Form of Amended and Restated Agreement of Limited Partnership of Enron Capital Resources, L.P. (Exhibit 3.1 to Enron Form 8-K dated August 2, 1994). *4.03 - Form of Payment and Guarantee Agreement dated as of August 3, 1994, executed by Enron Corp. for the benefit of the holders of Enron Capital Resources, L.P. 9% Cumulative Preferred Securities, Series A (Exhibit 4.1 to Enron Form 8-K dated August 2, 1994). *4.04 - Form of Loan Agreement, dated as of August 3, 1994, between Enron Corp. and Enron Capital Resources, L.P. (Exhibit 4.2 to Enron Form 8-K dated August 2, 1994). *4.05 - Articles of Association of Enron Capital LLC (Exhibit 9 to Enron Corp. Form 8-K dated November 12, 1993). *4.06 - Form of Payment and Guarantee Agreement of Enron Corp., dated as of November 15, 1993, in favor of the holders of Enron Capital LLC 8% Cumulative Guaranteed Monthly Income Preferred Shares (Exhibit 2 to Enron Form 8-K dated November 12, 1993). *4.07 - Form of Loan Agreement, dated as of November 15, 1993, between Enron Corp. and Enron Capital LLC (Exhibit 3 to Enron Form 8-K dated November 12, 1993). Executive Compensation Plans and Arrangements Filed as Exhibits Pursuant to Item 14(c) of Form 10-K: Exhibits 10.01 through 10.49 *10.01 - Enron Executive Supplemental Survivor Benefits Plan, effective January 1, 1987 (Exhibit 10.01 to Enron Form 10-K for 1992, File No. 1-3423). 10.02 - First Amendment to Enron Executive Supplemental Survivor Benefits Plan. *10.03 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to Registration Statement No. 33-27893). *10.04 - Executive Incentive Plan (Exhibit 10.13 to Enron Form 10-K for 1987, File No. 1-3423). *10.05 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron Form 10-K for 1987, File No. 1-3423). 10.06 - First Amendment to Enron Corp. 1988 Deferral Plan. 10.07 - Second Amendment to Enron Corp. 1988 Deferral Plan. *10.08 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Form 10-K for 1991, File No. 1-3423). *10.09 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1991, File No. 1-3423). 10.10 - First Amendment to Enron Corp. 1992 Deferral Plan. 10.11 - Second Amendment to Enron Corp. 1992 Deferral Plan. *10.12 - Enron Corp. Directors' Deferred Income Plan (Exhibit 10.09 to Enron Form 10-K for 1992, File No. 1-3423). *10.13 - Employment Agreement between Enron and Kenneth L. Lay dated as of September 1, 1989 (Exhibit 10.12 to Enron Form 10-K for 1989, File No. 1-3423). *10.14 - First Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 21, 1990 (Exhibit 10.11 to Enron Form 10-K for 1993). *10.15 - Second Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated March 5, 1992 (Exhibit 10.12 to Enron Form 10-K for 1993). *10.16 - Third Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 10, 1993 (Exhibit 10.13 to Enron Form 10-K for 1993). *10.17 - Fourth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated October 15, 1993 (Exhibit 10.14 to Enron Form 10-K for 1993). *10.18 - Fifth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated February 28, 1994 (Exhibit 10.15 to Enron Form 10-K for 1993). *10.19 - Sixth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated April 27, 1994 (Exhibit 10.16 to Enron Form 10-K for 1994). *10.20 - Split Dollar Life Insurance Agreement between Enron and the KLL and LPL Family Partnership, Ltd., dated April 22, 1994 (Exhibit 10.17 to Enron Form 10-K for 1994). *10.21 - Employment Agreement between Enron and Richard D. Kinder dated as of September 1, 1989 (Exhibit 10.14 to Enron Form 10-K for 1989, File No. 1-3423). *10.22 - First Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 13, 1990 (Exhibit 10.17 to Enron Form 10-K for 1991, File No. 1-3423). *10.23 - Second Amendment to Employment Agreement between Enron and Richard D. Kinder dated September 10, 1991 (Exhibit 10.18 to Enron Form 10-K for 1991, File No. 1-3423). *10.24 - Third Amendment to Employment Agreement between Enron and Richard D. Kinder dated March 5, 1992 (Exhibit 10.19 to Enron Form 10-K for 1992, File No. 1-3423). *10.25 - Fourth Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 16, 1993 (Exhibit 10.20 to Enron Form 10-K for 1993). *10.26 - Fifth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated October 15, 1993 (Exhibit 10.21 to Enron Form 10-K for 1993). *10.27 - Sixth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated February 28, 1994 (Exhibit 10.22 to Enron Form 10-K for 1993). *10.28 - Seventh Amendment to Employment Agreement between Enron and Richard D. Kinder, dated November 30, 1994 (Exhibit 10.25 to Enron Form 10-K for 1994). *10.29 - Employment Agreement between Enron International Inc. and Rodney L. Gray, dated as of July 1, 1993 (Exhibit 10.23 to Enron Form 10-K for 1993). *10.30 - First Amendment to Employment Agreement between Enron International Inc. and Rodney L. Gray, dated May 2, 1994 (Exhibit 10.27 to Enron Form 10-K for 1994). 10.31 - Second Amendment to Employment Agreement between Enron International Inc. and Rodney L. Gray, dated as of January 1, 1995. *10.32 - Consulting Services Agreement between Enron and John A. Urquhart dated August 1, 1991 (Exhibit 10.23 to Enron Form 10-K for 1991, File No. 1-3423). *10.33 - First Amendment to Consulting Services Agreement between Enron and John A. Urquhart, dated August 27, 1992 (Exhibit 10.25 to Enron Form 10-K for 1992, File No. 1-3423). *10.34 - Second and Third Amendments to Consulting Services Agreement between Enron and John A. Urquhart, dated November 24, 1992 and February 26, 1993, respectively (Exhibit 10.26 to Enron Form 10-K for 1992, File No. 1-3423). 10.35 - Fourth Amendment to Consulting Services Agreement between Enron and John A. Urquhart dated as of May 9, 1994. 10.36 - Fifth Amendment to Consulting Services Agreement between Enron and John A. Urquhart. 10.37 - Sixth Amendment to Consulting Services Agreement between Enron and John A. Urquhart. *10.38 - Employment Agreement between Enron and Edmund P. Segner, III dated October 1, 1991 (Exhibit 10.24 to Enron Form 10-K for 1991, File No. 1-3423). *10.39 - First Amendment to Employment Agreement between Enron and Edmund P. Segner, III dated February 12, 1993 (Exhibit 10.28 to Enron Form 10-K for 1992, File No. 1-3423). *10.40 - Second Amendment to Employment Agreement between Enron and Edmund P. Segner, III, dated May 2, 1994 (Exhibit 10.39 to Enron Form 10-K for 1994). *10.41 - Employment Agreement between Enron and James V. Derrick, Jr., dated June 11, 1991 (Exhibit 10.40 to Enron Form 10-K for 1992, File No. 1-3423). *10.42 - First Amendment to Employment Agreement between Enron and James V. Derrick, Jr., dated May 2, 1994 (Exhibit 10.53 to Enron Form 10-K for 1994). *10.43 - Enron Corp. Performance Unit Plan (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994). *10.44 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994). *10.45 - Enron Corp. Performance Unit Plan (as amended and restated effective May 2, 1995) (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 27, 1995). 10.46 - First Amendment to Enron Corp. Performance Unit Plan. *10.47 - Form of Enron Corp. 1994 Deferral Plan (Exhibit 10.59 to Enron Form 10-K for 1994). 10.48 - First Amendment to Enron Corp. 1994 Deferral Plan. 10.49 - Second Amendment to Enron Corp. 1994 Deferral Plan. 11 - Statement re calculation of earnings per share. 12 - Statement re computation of ratios of earnings to fixed charges. 21 - Subsidiaries of registrant. 23.01 - Consent of Arthur Andersen LLP. 23.02 - Consent of DeGolyer and MacNaughton. 23.03 - Letter Report of DeGolyer and MacNaughton dated January 22, 1996. 24 - Powers of Attorney for the officers and directors signing this Form 10-K. 27 - Financial Data Schedule. * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. (b) Reports on Form 8-K No reports on Form 8-K were filed by Enron during the last quarter of 1995.
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INDEX TO FINANCIAL STATEMENTS ENRON CORP. Page No. Consolidated Financial Statements Report of Independent Public Accountants F-2 Consolidated Income Statement for the years ended December 31, 1995, 1994 and 1993 F-3 Consolidated Balance Sheet as of December 31, 1994 and 1993 F-4 Consolidated Statement of Cash Flows for the years ended December 31, 1995, 1994 and 1993 F-6 Consolidated Statement of Changes in Shareholders' Equity Accounts for the years ended December 31, 1995, 1994 and 1993 F-7 Notes to the Consolidated Financial Statements F-8 Supplemental Financial Information (Unaudited) F-28 Financial Statements Schedule Report of Independent Public Accountants on Financial Statements Schedule S-1 Schedule II - Valuation and Qualifying Accounts S-2 Other financial statement schedules have been omitted because they are inapplicable or the information required therein is included elsewhere in the financial statements or notes thereto.
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS To the Shareholders and Board of Directors of Enron Corp.: We have audited the accompanying consolidated balance sheet of Enron Corp. (a Delaware corporation) and subsidiaries as of December 31, 1995 and 1994, and the related consolidated statements of income, cash flows and changes in shareholders' equity accounts for each of the three years in the period ended December 31, 1995. These financial statements are the responsibility of Enron Corp.'s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with generally accepted auditing standards. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion. In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of Enron Corp. and subsidiaries as of December 31, 1995 and 1994, and the results of their operations, cash flows and changes in shareholders' equity accounts for each of the three years in the period ended December 31, 1995, in conformity with generally accepted accounting principles. ARTHUR ANDERSEN LLP Houston, Texas February 16, 1996
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[Download Table] Enron Corp. and Subsidiaries Consolidated Income Statement Year Ended December 31, (In Thousands, Except Per Share Amounts) 1995 1994 1993 Revenues Natural gas and other products $7,529,357 $7,490,533 $6,652,333 Transportation 691,702 754,117 767,911 Other 967,938 739,073 565,556 9,188,997 8,983,723 7,985,800 Costs and Expenses Cost of gas and other products 6,733,486 6,517,109 5,566,026 Operating expenses 1,218,341 1,123,448 1,146,655 Oil and gas exploration expenses 78,670 83,944 75,743 Depreciation, depletion and amortization 431,706 441,329 458,188 Taxes, other than income taxes 108,792 102,121 108,386 8,570,995 8,267,951 7,354,998 Operating Income 618,002 715,772 630,802 Other Income and Deductions Equity in earnings of unconsolidated subsidiaries 86,018 112,409 73,293 Interest income 26,821 39,162 31,457 Other, net 434,241 77,049 62,115 Income Before Interest, Minority Interest and Income Taxes 1,165,082 944,392 797,667 Interest and Related Charges, net 284,029 273,482 300,149 Dividends on Preferred Stock of Subsidiaries 31,859 19,875 2,137 Minority Interests 44,056 31,041 27,605 Income Taxes 285,444 166,584 89,077 Income Tax Rate Adjustment - - 46,177 Net Income 519,694 453,410 332,522 Preferred Stock Dividends 15,414 15,038 16,919 Earnings on Common Stock $ 504,280 $ 438,372 $ 315,603 Earnings Per Share of Common Stock Primary $ 2.07 $ 1.80 $ 1.32 Fully Diluted $ 1.94 $ 1.70 $ 1.25 Average Number of Common Shares Used in Primary Computation 243,669 243,395 239,019 <FN> The accompanying notes are an integral part of these consolidated financial statements.
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[Download Table] Enron Corp. and Subsidiaries Consolidated Balance Sheet December 31, (In Thousands) 1995 1994 Assets Current Assets Cash and cash equivalents $ 114,917 $ 132,336 Trade receivables (net of allowance for doubtful accounts of $11,642 and $12,729, respectively) 1,115,709 604,985 Other receivables 310,790 233,213 Transportation and exchange gas receivable 149,659 98,787 Inventories 111,463 138,405 Assets from price risk management activities 579,749 449,588 Other 344,620 251,679 Total Current Assets 2,726,907 1,908,993 Investments and Other Assets Investments in and advances to unconsolidated subsidiaries 1,216,474 1,065,189 Assets from price risk management activities 1,197,029 1,027,945 Other 1,230,090 1,225,224 Total Investments and Other Assets 3,643,593 3,318,358 Property, Plant and Equipment, at cost Transportation and operation 3,639,734 3,906,952 Domestic gas and power services 3,797,530 3,811,037 Exploration and production, successful efforts accounting 3,380,924 3,015,435 International gas and power services 181,981 119,740 Corporate and other 107,012 111,237 11,107,181 10,964,401 Less accumulated depreciation, depletion and amortization 4,238,746 4,225,741 Net Property, Plant and Equipment 6,868,435 6,738,660 Total Assets $13,238,935 $11,966,011 <FN> The accompanying notes are an integral part of these consolidated financial statements.
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[Download Table] Enron Corp. and Subsidiaries Consolidated Balance Sheet December 31, 1995 1994 Liabilities and Shareholders' Equity Current Liabilities Accounts payable $ 1,020,599 $ 924,446 Transportation and exchange gas payable 144,141 114,124 Accrued taxes 121,192 90,906 Accrued interest 51,692 58,569 Liabilities from price risk management activities 708,353 522,070 Other 386,015 587,271 Total Current Liabilities 2,431,992 2,297,386 Long-Term Debt 3,064,839 2,805,142 Deferred Credits and Other Liabilities Deferred income taxes 2,185,748 1,893,450 Deferred revenue 311,478 256,298 Liabilities from price risk management activities 590,302 575,377 Other 563,962 591,134 Total Deferred Credits and Other Liabilities 3,651,490 3,316,259 Commitments and Contingencies (Notes 2, 8, 13, 14 and 15) Minority Interests 548,648 290,146 Company-Obligated Preferred Stock of Subsidiaries 376,750 376,750 Shareholders' Equity Preferred stock, cumulative, $100 par value, 1,500,000 shares authorized, no shares issued - - Second preferred stock, cumulative, $1 par value, 5,000,000 shares authorized, 1,375,494 shares and 1,404,983 shares of Cumulative Second Preferred Convertible Stock issued, respectively 137,550 140,498 Preference stock, cumulative, $1 par value, 10,000,000 shares authorized, no shares issued - - Common stock, $0.10 par value, 600,000,000 shares authorized, 253,860,360 shares and 253,069,668 shares issued, respectively 25,386 25,308 Additional paid-in capital 1,791,151 1,788,044 Retained earnings 1,650,949 1,351,297 Cumulative foreign currency translation adjustment (153,563) (158,881) Common stock held in treasury (2,618,034 and 1,394,833 shares, respectively) (92,642) (41,090) Other (including Flexible Equity Trust, Note 10) (193,615) (224,848) Total Shareholders' Equity 3,165,216 2,880,328 Total Liabilities and Shareholders' Equity $13,238,935 $11,966,011 <FN> The accompanying notes are an integral part of these consolidated financial statements.
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[Download Table] Enron Corp. and Subsidiaries Consolidated Statement Of Cash Flows Year Ended December 31, (In Thousands) 1995 1994 1993 Cash Flows From Operating Activities Reconciliation of net income to net cash provided by (used in) operating activities Net income $ 519,694 $ 453,410 $ 332,522 Depreciation, depletion and amortization 431,706 441,329 458,188 Oil and gas exploration expenses 78,670 83,944 75,743 Amortization of deferred contract reformation costs 25,858 90,617 89,240 Deferred income taxes 216,090 92,959 51,200 Gains on sales of stock by subsidiary and other assets (529,990) (91,284) (115,586) Regulatory, litigation and other contingency adjustments 111,666 (25,212) 58,944 Changes in components of working capital (833,647) (141,372) (76,513) Deferred contract reformation costs (18,089) (54,182) (136,383) Net assets from price risk management activities (98,037) (152,642) (115,415) Production payment transaction, net (43,345) (43,345) (73,867) Other, net 124,401 (193,567) (153,651) Net Cash Provided by (Used in) Operating Activities (15,023) 460,655 394,422 Cash Flows From Investing Activities Proceeds from sales of investments and other assets 996,537 439,627 453,977 Additions to property, plant and equipment (730,502) (660,915) (688,032) Equity investments (170,262) (272,517) (267,097) Other, net (82,397) (66,561) (64,224) Net Cash Provided by (Used in) Investing Activities 13,376 (560,366) (565,376) Cash Flows From Financing Activities Net increase (decrease) in short-term borrowings (250,305) 115,326 42,767 Issuance of long-term debt 967,126 190,115 613,938 Repayment of long-term debt (447,734) (161,786) (450,161) Decrease in other long-term obligations - - (22,757) Issuance of company-obligated preferred stock of subsidiaries - 163,000 213,750 Issuance of common stock 19,806 66,372 22,882 Dividends paid (254,262) (231,079) (189,769) Net acquisition of treasury stock (64,654) (41,090) (71,145) Other, net 14,251 (9,051) 10,000 Net Cash Provided by (Used in) Financing Activities (15,772) 91,807 169,505 Decrease in Cash and Cash Equivalents (17,419) (7,904) (1,449) Cash and Cash Equivalents, Beginning of Year 132,336 140,240 141,689 Cash and Cash Equivalents, End of Year $ 114,917 $ 132,336 $ 140,240 <FN> The accompanying notes are an integral part of these consolidated financial statements.
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[Enlarge/Download Table] Enron Corp. and Subsidiaries Consolidated Statement Of Changes In Shareholders' Equity Accounts Cumulative Foreign Convertible Additional Currency (In Thousands, Except Preferred Common Paid-in Retained Translation Treasury Per Share Amounts) Stock Stock Capital Earnings Adjustment Stock Other Balance at December 31, 1992 $182,964 $1,187,661 $ 324,944 $ 959,522 $(118,160) $ (8,100) $ (10,514) Net income 332,522 Cash dividends Common stock (170,457) Preferred stock (16,919) Purchase of treasury stock (86,301) Exchange of common stock for convertible preferred stock (33,296) 3,573 (25,289) 55,012 Benefit and dividend reinvestment plans 3,881 25,426 39,788 (5,347) Sales of stock 14 4,986 Issuance to Flexible Equity Trust 750 219,563 (219,563) Common stock split and reduction of par value to $0.10 (1,170,969) 1,170,969 Translation adjustments (20,544) Other (12,661) 318 (399) 10,000 Balance at December 31, 1993 149,668 24,910 1,707,938 1,104,986 (138,704) - (225,424) Net income 453,410 Cash dividends Common stock (191,839) Preferred stock (15,038) Purchase of treasury stock (55,911) Exchange of common stock for convertible preferred stock (9,170) 125 9,045 Benefit and dividend reinvestment plans 131 29,625 1,392 576 Sales of stock 142 51,594 13,366 Translation adjustments (20,177) Other (10,158) (222) 63 Balance at December 31, 1994 140,498 25,308 1,788,044 1,351,297 (158,881) (41,090) (224,848) Net income 519,694 Cash dividends Common stock (204,628) Preferred stock (15,414) Purchase of treasury stock (118,368) Exchange of common stock for convertible preferred stock (2,948) 22 (2,536) 5,462 Benefit and dividend reinvestment plans 19 (5,189) 61,381 29,569 Sales of stock 37 15,468 Translation adjustments 5,318 Other (4,636) (27) 1,664 Balance at December 31, 1995 $137,550 $ 25,386 $1,791,151 $1,650,949 $(153,563) $(92,642) $(193,615) <FN> The accompanying notes are an integral part of these consolidated financial statements.
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Enron Corp. and Subsidiaries NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS 1 Summary of Significant Accounting Policies A. Consolidation Policy and Use of Estimates The consolidated financial statements include the accounts of all majority-owned subsidiaries of Enron Corp. after the elimination of significant intercompany accounts and transactions. Investments in unconsolidated subsidiaries are accounted for by the equity method. 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. "Enron" is used from time to time herein as a collective reference to Enron Corp. and its subsidiaries and affiliates. In material respects, the businesses of Enron are conducted by Enron Corp.'s subsidiaries and affiliates whose operations are managed by their respective officers. B. Cash Equivalents Enron records as cash equivalents all highly liquid short- term investments with original maturities of three months or less. C. Inventories Inventories consisting primarily of natural gas in storage of $55.9 million and $79.1 million and crude oil and liquid petroleum products of $50.0 million and $54.8 million at December 31, 1995 and 1994, respectively, are priced at the lower of cost or market. D. Depreciation, Depletion and Amortization The provision for depreciation and amortization with respect to operations other than oil and gas producing activities (see below) is computed using the straight-line or Federal Energy Regulatory Commission (FERC) mandated method based on estimated economic lives. Composite depreciation rates are applied to functional groups of property having similar economic characteristics. Provisions for depreciation, depletion and amortization of proved oil and gas properties are calculated using the units- of-production method. Estimated future dismantlement, restoration and abandonment costs, net of salvage credits, are taken into account in determining depreciation, depletion and amortization. In March 1995, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards (SFAS) No. 121 - "Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of," which 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. Enron will adopt SFAS No. 121 in the first quarter of 1996. Enron believes that the adoption of SFAS No. 121 will not have a material impact on its financial position or results of operations. E. Income Taxes Enron accounts for income taxes under the provisions of SFAS No. 109 - "Accounting for Income Taxes," which provides for an asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases (see Note 3). F. Earnings Per Share Primary earnings per share is computed on the basis of the average number of common shares outstanding during the periods. Common shares held by the Enron Corp. Flexible Equity Trust are not included in the computation of earnings per share until such shares are released to fund employee benefits (see Note 10). Dilutive common stock equivalents are not material and are not included in the computation of primary earnings per share. Fully diluted earnings per share is computed based upon the average number of common stock and common stock equivalent shares outstanding plus the average number of common shares issuable upon the assumed conversion of convertible securities. G. Accounting for Price Risk Management Enron engages in price risk management activities for both trading and non-trading purposes. Activities for trading purposes, generally consisting of services provided to the energy sector through Enron Capital & Trade Resources (ECT), are accounted for using the mark-to-market method. Under such method, changes in the market value of outstanding financial instruments are recognized as gain or loss in the period of change. The market prices used to value these transactions reflect management's best estimate considering various factors including closing exchange and over-the- counter quotations, time value and volatility factors underlying the commitments. The values are adjusted to reflect the potential impact of liquidating Enron's position in an orderly manner over a reasonable period of time under present market conditions. Activities for non-trading purposes consist of transactions entered into by Enron's other business units to hedge the impact of market fluctuations on assets, liabilities, production or other contractual commitments. Changes in the market value of these transactions are deferred until the gain or loss on the hedged item is recognized. See Note 2 for further discussion of Enron's price risk management activities. H. Accounting for Oil and Gas Producing Activities Enron accounts for oil and gas exploration and production activities under the successful efforts method of accounting. Under such method, oil and gas lease acquisition costs are capitalized when incurred. Unproved properties with significant acquisition costs are assessed quarterly on a property-by-property basis and any impairment in value is recognized. Amortization of any remaining costs of such leases begins at a point prior to the end of the lease term depending upon the length of such term. Unproved properties with acquisition costs that are not individually significant are aggregated, and the portion of such costs estimated to be nonproductive, based on historical experience, is amortized over the average holding period. If the unproved properties are determined to be productive, the appropriate related costs are transferred to proved oil and gas properties. Lease rentals are expensed as incurred. Oil and gas exploration costs, other than the costs of drilling exploratory wells, are charged to expense as incurred. The costs of drilling exploratory wells are capitalized pending determination of whether the wells have discovered proved commercial reserves. If proved commercial reserves are not discovered, such drilling costs are expensed. The costs of all development wells and related equipment used in the production of crude oil and natural gas are capitalized. Gains and losses associated with the sale of crude oil and natural gas reserves in place with related assets are classified as "Other Revenues" in the Consolidated Income Statement. I. Accounting for Development Activity Enron's project development costs consist of fees, licenses and permits, site testing, bid costs and other charges, including salaries and employee expenses, incurred in developing domestic and international projects. These costs may be recovered through development cost reimbursements from joint venture partners or other third parties, written off against development fees received, or may be included as part of an investment in those ventures where Enron continues to participate. Accumulated costs of project development are otherwise expensed in the period that management determines it is probable that the costs will not be recovered. Development revenue results from Enron's participation in the development, construction, operation and ownership of various projects. Revenue from development fees is recognized when realizable under the development agreement. Revenue from long-term construction contracts is recognized using the percentage-of-completion method and is primarily based on project costs incurred compared with total estimated costs. Estimated contract earnings are reviewed and revised periodically as the work progresses. Development and construction revenues earned from joint ventures in which Enron holds an equity interest are deferred to the extent of Enron's ownership interest and recognized over the life of the facility owned by the joint venture on a straight-line basis. Proceeds from the sale of all or part of Enron's investment in development projects are recognized as revenues at the time of sale to the extent that such sales proceeds exceed the proportionate carrying amount of the investment. Total revenues recognized from the sale of development projects for the years ended December 31, 1995, 1994 and 1993, exclusive of amounts discussed below, were $11 million, $28 million and $65 million, respectively. During November 1994, Enron sold an approximately 48% interest in Enron Global Power & Pipelines L.L.C. (EPP) for net proceeds totaling approximately $225 million. In connection with the sale, Enron recognized revenues of $65 million in 1994 and $48 million in 1995 following the satisfaction of Enron's support obligations. Pursuant to a Purchase Right Agreement, Enron has agreed to offer to sell to EPP Enron's ownership interests in power plant and natural gas pipeline projects developed or acquired outside the United States, Canada and Western Europe, prior to 2005, subject to certain exceptions. J. Foreign Currency Translation For international subsidiaries, asset and liability accounts are translated at year-end rates of exchange and revenue and expenses are translated at average exchange rates prevailing during the year. For subsidiaries whose functional currency is deemed to be other than the U.S. dollar, translation adjustments are included as a separate component of shareholders' equity. Currency transaction gains and losses are recorded in income. K. Reclassifications Certain reclassifications have been made to the consolidated financial statements for prior years to conform with the current presentation. 2 Price Risk Management and Financial Instruments Trading Activities Enron, through ECT, offers price risk management services to the energy sector. These services primarily relate to commodities associated with the energy sector (natural gas, crude oil, natural gas liquids and electricity), but in some instances also include financial products (interest rate swaps and foreign currency contracts). ECT provides these services through a variety of financial instruments including forward contracts involving physical delivery of an energy commodity, swap agreements, which require payments to (or receipt of payments from) counterparties based on the differential between a fixed and variable price for the commodity, options and other contractual arrangements. ECT accounts for these activities using the mark-to-market method of accounting. Under mark-to-market accounting, forwards, swaps, options and other financial instruments with third parties are reflected at market value, net of future servicing costs, with resulting unrealized gains and losses recorded as "Assets and Liabilities From Price Risk Management Activities" in the Consolidated Balance Sheet. Terms regarding cash settlements of these contracts vary with respect to the actual timing of cash receipts and payments. The amounts shown in the Consolidated Balance Sheet related to price risk management activities also include assets or liabilities which arise as a result of the actual timing of settlements related to these contracts. Current period changes in the assets and liabilities from price risk management activities (resulting primarily from newly originated transactions, restructurings and the impact of price movements) are recognized as net gains or losses in "Other Revenues." Notional Amounts and Terms. The notional amounts and terms of these financial instruments at December 31, 1995 are set forth below (volumes in trillions of British thermal units equivalent (TBtue), dollars in millions): [Download Table] Fixed Price Fixed Price Maximum Product Payor Receiver Terms in years Energy Commodities Gas 3,741 4,933 19 Crude and liquids 606 743 10 Electricity 33 165 5 Financial Products Interest rate (a) $14,364 $1,465 19 Foreign currency 1,040 1,045 19 <FN> (a) The interest rate fixed price receiver represents the net notional dollar value of the interest rate sensitive component of the combined commodity portfolio. The interest rate fixed price payor represents the notional contract amount of a portfolio of various financial instruments used to hedge the net present value of the commodity portfolio. The effectiveness of a hedge on the net present value of the combined commodity portfolio is not a function of notional hedge value but, rather, of cash flows resulting from the notional hedge value. Accordingly, the notional dollar values will not be equal. However, the portfolio is substantially balanced from a cash flow perspective and is not sensitive to movement in interest rates. ECT also has sales and purchase commitments associated with contracts based on market prices totaling 4,432 TBtue, with terms extending up to 20 years. Notional amounts reflect the volume of transactions but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure ECT's exposure to market or credit risks. The maximum terms in years detailed above are not indicative of likely future cash flows as these positions may be offset in the markets at any time in response to the company's risk management needs. The volumetric weighted average maturity of ECT's entire portfolio of price risk management activities as of December 31, 1995 was approximately 2.3 years. Fair Value. The fair value of the financial instruments as of December 31, 1995 and the average fair value of those instruments held during the year are set forth below (amounts in millions): [Download Table] Fair Value Average Fair Value as of for the Year Ended 12/31/95 12/31/95(a) Product Assets Liabilities Assets Liabilities Energy Commodities Gas $1,217 $744 $1,190 $477 Crude and liquids 249 363 293 495 Electricity 97 62 29 14 Financial Products Interest rate 357 92 225 60 Foreign currency 64 38 58 35 <FN> (a) Computed using the ending balance at each month end. The net change in the value of ECT's portfolio of price risk management activities for the year ended December 31, 1995, primarily attributable to financial instruments fixing energy commodity pricing, was $98 million and is included in "Other Revenues". All of ECT's operations relate to providing price risk management services. Accordingly, earnings for this operating segment appropriately reflect the net gain arising from trading activities for the year ended December 31, 1995. Market Risk. To provide solutions to energy problems worldwide, ECT serves a diverse customer group that includes independent power producers, industrials, gas and electric utilities, oil and gas producers, financial institutions and other energy marketers. This broad customer mix generates a need for a variety of financial structures, products and terms. This diversity requires ECT to manage, on a portfolio basis, the resulting market risks inherent in these transactions subject to parameters established by Enron's Board of Directors. Market risks are monitored by a risk control group operating separately from the units that create or actively manage these risk exposures to ensure compliance with Enron's stated risk management policies at both the corporate and subsidiary levels. Risk measurement is also supplemented with stress testing and scenario analysis. ECT's fixed price contract portfolio is typically balanced to within approximately 1% of the gross position at the end of each day. ECT measures the risk in its portfolio on a daily basis in accordance with value-at-risk methodologies, which simulate forward price curves in the energy markets to estimate the size and probability of future potential losses. The quantification of market risk using value-at-risk provides a consistent measure of risk across diverse energy markets and products. The use of this methodology requires a number of key assumptions including the selection of a confidence level for losses, the holding period chosen for the value-at- risk calculation and the treatment of risks outside the value-at-risk methodologies, including liquidity risk and event risk. ECT expresses value-at-risk as a percentage of Enron's earnings based on a 95% confidence level using one day holding periods. On a one day basis as of December 31, 1995, ECT's value-at-risk for its price risk management activities was less than 2% (unaudited) of Enron's total income before interest, minority interest and income taxes. Since this is not an absolute measure of risk under all conditions for all products, ECT performs alternative scenario analyses to estimate the economic impact of a sudden market movement on the value of the trading portfolio (stress testing). The results of the stress testing, along with the professional judgments of experienced business and risk managers, are used to supplement the value-at-risk methodology and capture additional market-related risks, including liquidity, event, concentration and correlation reliance risk. Based upon the ongoing policies and controls discussed above, Enron does not anticipate a materially adverse effect on financial position or results of operations as a result of market fluctuations. Credit Risk. Credit risk relates to the risk of loss that Enron would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. The counterparties associated with ECT's assets from price risk management activities as of December 31, 1995 and 1994 are summarized as follows (amounts in millions): [Download Table] December 31, 1995 Assets from Price Risk Management Activities Investment Below Grade(a) Investment Grade Total Independent Power Producers $ 573 $105 $ 678 Gas and Electric Utilities 234 45 279 Oil and Gas Producers 318 109 427 Industrials 35 43 78 Financial Institutions 38 5 43 Energy Marketers 132 103 235 Other 202 42 244 Total $1,532 $452 1,984 Credit and Other Reserves (207) Assets from Price Risk Management Activities(b) $1,777 [Download Table] December 31, 1994 Assets from Price Risk Management Activities Investment Below Grade(a) Investment Grade Total Independent Power Producers $ 447 $ 44 $ 491 Gas and Electric Utilities 287 37 324 Oil and Gas Producers 310 26 336 Industrials 24 21 45 Financial Institutions 176 - 176 Energy Marketers 20 25 45 Other 158 33 191 Total $1,422 $186 1,608 Credit and Other Reserves (130) Assets from Price Risk Management Activities(b) $1,478 <FN> (a) "Investment Grade" is primarily determined using publicly available credit ratings along with consideration of collateral, which encompass standby letters of credit, parent company guarantees and property interests, including oil and gas reserves. Included in "Investment Grade" are counterparties with a minimum Standard & Poor's or Moody's rating of BBB- or Baa3, respectively. (b) Three customers' exposures at December 31, 1995 and 1994 each comprise greater than 5% of Assets From Price Risk Management Activities. This concentration of counterparties may impact ECT's overall exposure to credit risk, either positively or negatively, in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. ECT maintains credit policies with regard to its counterparties that management believes significantly minimize overall credit risk. These policies include an evaluation of potential counterparties' financial condition (including credit rating), collateral requirements under certain circumstances and the use of standardized agreements which allow for the netting of positive and negative exposures associated with a single counterparty. ECT maintains a credit reserve which is based on management's evaluation of the credit risk of the overall portfolio. This reserve is objectively determined using an implied risk profile based on the difference between risk- free rates of return and each counterparty's cost of borrowing. This implied risk is then used to evaluate the exposure (based on current market value) to each counterparty adjusted for collateral provisions and overall concentration of exposure. Based on ECT's policies, its exposures and the credit reserve, Enron does not anticipate a materially adverse effect on financial position or results of operations as a result of counterparty nonperformance. Non-Trading Activities Enron's other businesses also enter into forwards, swaps and other contracts to hedge the impact of market fluctuations on assets, liabilities, production or other contractual commitments. Changes in the market value of these transactions are deferred until the gain or loss is recognized on the hedged item. Interest Rate Swaps. At December 31, 1995, Enron had entered into interest rate swap agreements with a notional principal amount of $4,005 million to manage interest rate exposure. Swap agreements relating to notional amounts of $1,315 million, $700 million and $1,990 million are scheduled to terminate in 1996, 1997 and thereafter, respectively. Energy Commodity Price Swaps. At December 31, 1995, Enron was a party to energy commodity price swaps covering approximately 233 TBtu, 169 TBtu and 427 TBtu of natural gas for the years 1996, 1997 and the period 1998 through 2004, respectively, and 4 million, 4 million and 6 million barrels of crude oil for the years 1996, 1997 and the period 1998 through 2000, respectively. During the first quarter of 1996, Enron removed substantially all of its natural gas commodity price swaps for 1996 by entering into offsetting positions. Foreign Currency Contracts. At December 31, 1995, foreign currency contracts with a notional principal amount of $11.9 million were outstanding. Such contracts will substantially expire in 1996. Credit Risk. While notional amounts are used to express the volume of various derivative financial instruments, the amounts potentially subject to credit risk, in the event of nonperformance by the third parties, are substantially smaller. Counterparties to the forwards, futures and other contracts discussed above are investment grade financial institutions. Accordingly, Enron does not anticipate any material impact to its financial position or results of operations as a result of nonperformance by the third parties on financial instruments related to non-trading activities. Financial Instruments The carrying amounts and estimated fair values of Enron's financial instruments, excluding trading activities which are marked to market, at December 31, 1995 and 1994 were as follows: [Download Table] 1995 1994 Carrying Estimated Carrying Estimated (In Millions) Amount Fair Value Amount Fair Value Long-term debt (Note 5) $3,065 $3,360 $2,805 $2,752 Company-obligated preferred stock of subsidiaries (Note 9) 377 386 377 348 Interest rate swaps - (18) - 5 Energy commodity price swaps - 90 - 80 Foreign currency contracts - - - (1) Enron used the following methods and assumptions in estimating fair values: (a) Long-term debt - the carrying amount of variable-rate debt approximates fair value, the fair value of marketable debt is based on quoted market prices, and the fair value of other debt is based on the discounted present value of cash flows using Enron's current borrowing rates; (b) Company-obligated preferred stock of subsidiaries - the fair value is based on quoted market prices; and (c) Interest rate swaps, Energy commodity price swaps and Foreign currency contracts - estimated fair values have been determined by using available market data and valuation methodologies. Judgement is necessarily required in interpreting market data and the use of different market assumptions or estimation methodologies may affect the estimated fair value amounts (see "Non-Trading Activities" above). The fair market value of cash and cash equivalents, accounts receivable and accounts payable are not materially different from their carrying amounts. Guarantees of liabilities of unconsolidated entities and residual value guarantees have no book value associated with them and the fair values of these items are not readily determinable (see Note 15). 3 Income Taxes The principal components of Enron's net deferred income tax liability at December 31, 1995 and 1994 are as follows: [Download Table] (In Millions) 1995 1994 Deferred income tax assets - Alternative minimum tax credit carryforward $ 231 $ 236 Other 84 51 315 287 Deferred income tax liabilities - Depreciation, depletion and amortization 1,617 1,583 Price risk management activities 427 256 Other 470 406 2,514 2,245 Net deferred income tax liabilities* $2,199 $1,958 <FN> * Includes $13 million and $65 million in other current liabilities for 1995 and 1994,respectively. The components of income before income taxes are as follows: [Download Table] (In Thousands) 1995 1994 1993 U.S. $621,881 $415,011 $336,445 Foreign 183,257 204,983 131,331 $805,138 $619,994 $467,776 Total income tax expense is summarized as follows: [Download Table] (In Thousands) 1995 1994 1993 Payable currently - Federal $ 29,315 $ 49,021 $ 57,093 State 25,955 13,494 14,692 Foreign 14,084 11,110 12,269 69,354 73,625 84,054 Payment deferred - Federal 157,716 77,595 (26,070) State 30,327 (5,948) 15,724 Foreign 28,047 21,312 15,369 216,090 92,959 5,023 285,444 166,584 89,077 Effect of tax rate increase on deferred tax liability(a) - - 46,177 Total Income Tax Expense $285,444 $166,584 $135,254 <FN> (a) In August 1993, the U.S. corporate Federal income tax rate increased from 34% to 35% retroactive to January 1, 1993. Under the provisions of SFAS No. 109, the effect of a change in the tax rate is recognized in income for the period of enactment. The differences between taxes computed at the U.S. Federal statutory tax rate and Enron's effective income tax rate are as follows: [Download Table] 1995 1994 1993 Statutory Federal income tax rate provision 35.0% 35.0% 35.0% Net state income taxes 4.5% 0.8% 4.1% Revision of prior years' tax estimates (1.5)% (0.8)% (5.3)% Tax rate increase - - 9.9% Tight gas sands tax credit (2.8)% (5.9)% (13.9)% Earnings in foreign jurisdictions taxed at rates different from the statutory U.S. Federal rate 0.4% (0.2)% 1.0% Equity earnings (3.8)% (3.7)% (2.6)% Minority interest 1.9% 1.7% 2.1% Asset and stock sale differences 2.1% - - Other (0.3)% - (1.4)% Effective income tax rate 35.5% 26.9% 28.9% Enron has an alternative minimum tax (AMT) credit carryforward of approximately $231 million which can be used to offset regular income taxes payable in future years. The AMT credit has an indefinite carryforward period. U.S. and foreign taxes have been provided for earnings of foreign subsidiary companies that are expected to be remitted to the parent company. Foreign subsidiaries' cumulative undistributed earnings of approximately $195 million are considered to be indefinitely reinvested outside the U.S. and, accordingly, no U.S. income taxes have been provided thereon. In the event of a distribution of those earnings in the form of dividends, Enron may be subject to both foreign withholding taxes and U.S. income taxes net of allowable foreign tax credits. 4 Supplemental Cash Flow Information Cash paid for income taxes and interest expense, including fees incurred on sales of accounts receivable, is as follows: [Download Table] (In Thousands) 1995 1994 1993 Income taxes $ 13,278 $ 56,595 $ 39,307 Interest (net of amounts capitalized) 296,180 268,205 299,568 Non-cash investing and financing activities during 1995, 1994 and 1993 included the exchange of common stock for convertible preferred stock in transactions valued at $2.9 million, $9.2 million and $33.3 million, respectively. In addition, in March 1995, a subsidiary of EOG issued redeemable preferred stock with a liquidation/redemption value of $19 million in exchange for certain oil and gas properties. These preferred shares were exchanged in November 1995 for 633,333 shares of Enron's common stock. Changes in components of working capital are as follows: [Download Table] (In Thousands) 1995 1994 1993 Receivables $(639,173) $(250,295) $(360,206) Inventories 26,942 (25,117) 92,228 Payables 126,170 (91,329) 144,518 Accrued taxes 30,286 12,178 (11,941) Accrued interest (6,877) 5,277 2,913 Other (370,995) 207,914 55,975 Total $(833,647) $(141,372) $ (76,513) 5 Credit Facilities, Short-Term Borrowings and Long-Term Debt Enron and EOG have credit facilities with domestic and foreign banks which provide for an aggregate of $1.1 billion in long-term committed credit. Expiration dates of the committed facilities range from February 1998 to March 2000. Interest rates on borrowings are based upon the London Interbank Offered Rate, certificate of deposit rates or other short-term interest rates. Certain credit facilities contain covenants which must be met to borrow funds. Such debt covenants are not anticipated to materially restrict Enron's ability to borrow funds under such facilities. Compensating balances are not required, but Enron is required to pay a commitment or facility fee. During 1995, no amounts were borrowed under these facilities. Enron and EOG have also entered into agreements which provide for uncommitted lines of credit totaling $995 million at December 31, 1995. The uncommitted lines have no stated expiration dates. Neither compensating balances nor commitment fees are required as borrowings under the uncommitted credit lines are available subject to agreement by the participating banks. At December 31, 1995, no amounts were outstanding under the uncommitted lines. In addition to borrowing from banks on a short-term basis, Enron and certain of its subsidiaries sell commercial paper to provide financing for various corporate purposes. As of December 31, 1995, 1994 and 1993, short-term borrowings of $15.3 million, $259.1 million and $143.8 million, respectively, have been reclassified as long-term debt based upon the availability of committed credit facilities with expiration dates exceeding one year and management's intent to maintain such amounts in excess of one year subject to overall reductions in debt levels. Similarly, at December 31, 1995, 1994 and 1993, $286.5 million, $171.1 million and $132.4 million, respectively, of long-term debt due within one year remained classified as long-term. Detailed information on short-term borrowings by Enron is as follows: [Download Table] (In Millions) 1995 1994 1993 As of end of year Borrowings from - Commercial paper $ - $ 206.1 $ - Banks and other 15.3 53.0 143.8 Amount reclassified as long-term debt (15.3) (259.1) (143.8) Total short-term borrowings $ - $ - $ - Weighted average interest rate at end of year (a) 6.3% 6.2% 3.6% For the year ended Maximum borrowings at any month end (a) $782.9 $1,156.0 $1,087.1 Average borrowings (a)(b) 636.2 768.1 590.9 Weighted average interest rate during the year (a)(c) 6.1% 4.6% 3.3% <FN> (a) Before reclassification as long-term debt. (b) Computed using the average daily balances during each month. (c) Computed using the weighted average interest rates of debt outstanding during each month. Detailed information on long-term debt is as follows: [Download Table] December 31, (In Thousands) 1995 1994 Enron Corp. Debentures 6.75% due 2005 - senior subordinated $ 200,000 $ 200,000 8.25% due 2012 - senior subordinated 150,000 150,000 Notes Payable 8.10% to 9.25% due 1996 250,000 250,000 6.25% due 1998 - mandatorily exchangeable into EOG stock 228,375 - 8.50% to 10.75% due from 1998 to 2001 450,000 342,777 6.75% to 9.875% due from 2003 to 2007 992,200 692,200 7% due 2023 100,000 100,000 Other 9,678 56,508 Northern Natural Gas Company Notes Payable 8.00% due 1999 250,000 250,000 6.875% due 2005 100,000 100,000 Houston Pipe Line Company Notes Payable 12.125% due 1995 - 100,000 Transwestern Pipeline Company Notes Payable 7.55% to 9.10% due 2000 123,000 123,000 9.20% due from 1998 to 2004 27,000 27,000 Enron Oil & Gas Company Notes Payable 8.92% due 1995 - 25,000 9.10% due from 1996 to 1998 70,000 70,000 Other 77,559 67,421 Enron Europe Limited Other 38,933 - Amount reclassified from short-term debt 15,348 259,099 Unamortized debt discount and premium (17,254) (7,863) Total Long-Term Debt $3,064,839 $2,805,142 The aggregate annual maturities of long-term debt outstanding at December 31, 1995 are $286.5 million, $26.7 million, $388.9 million, $299.8 million and $281.4 million for 1996 through 2000, respectively. 6 Accounts Receivable Enron has entered into an agreement which provides for the sale of trade accounts receivable with limited recourse provisions and the rights to certain recoverable pipeline transition surcharges expiring January 31, 1999. Sales of trade receivables under these agreements totaled $100.0 million and $328.0 million at December 31, 1995 and 1994, respectively. Rights to certain recoverable pipeline transition surcharges sold under these agreements totaled $34.9 million and $64.2 million at December 31, 1995 and 1994, respectively. The fees incurred on the sales of accounts receivable totaled $23.7 million, $20.8 million and $20.6 million for 1995, 1994 and 1993, respectively, and are included in "Interest and Related Charges, net." Enron affiliates have concentrations of customers in the electric and gas utility industries. These concentrations of customers may impact Enron's overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. However, Enron's management believes that the portfolio of receivables is well diversified and that such diversification minimizes any potential credit risk. Receivables are generally not collateralized. 7 Production Payment Agreement In September 1992, EOG entered into a transaction with a limited partnership under which EOG conveyed an interest in approximately 124 billion cubic feet equivalent (136 trillion British thermal units) of natural gas and other hydrocarbons for consideration of $326.8 million (the production payment agreement). EOG retains responsibility for its working interest share of the cost of operations. Enron has accounted for the proceeds received in the transaction as deferred revenue which is being amortized into revenue as natural gas and other hydrocarbons are produced and delivered during the terms of the agreement as amended in October 1993. Annual amortization of remaining deferred revenue, based on scheduled deliveries under the production payment agreement, is approximately $43.3 million per year through 1998 and $10.7 million for 1999. See Note 18 for the estimate of proved oil and gas reserves dedicated to the transaction. 8 Unconsolidated Subsidiaries Enron has investments in and advances to unconsolidated subsidiaries as follows: [Download Table] Ownership Investee Interest December 31, (In Thousands) 1995 1994 Citrus Corp. 50% $ 383,351 $ 356,538 Teesside Power Limited 50%(a) 182,937 173,461 Transportadora de Gas del Sur S.A. 18%(a) 97,608 96,451 Joint Energy Development Investments L.P. 50% 83,952 77,024 Northern Border Partners, L.P. 13% 54,143 55,050 Enron/Dominion Cogen Corp. 50% 50,411 43,456 EOTT Energy Partners, L.P. 42% 37,847 63,044 Other(b) 326,225 200,165 $1,216,474 $1,065,189 <FN> (a) Net of minority interests, the ownership is 42.5% for Teesside Power Limited and 9.1% for Transportadora de Gas del Sur S.A. (b) Includes investments in various international development projects which have not reached commercial operation at December 31, 1995. Enron's equity in earnings (losses) of unconsolidated subsidiaries is as follows: [Download Table] Investee Year Ended December 31, (In Thousands) 1995 1994 1993 Citrus Corp. $26,814 $ 27,554 $(8,066) Teesside Power Limited 17,530 12,669 12,444 Transportadora de Gas del Sur S.A. 22,252 22,965 20,721 Joint Energy Development Investments L.P. 4,175 7,321 - Northern Border Partners, L.P. 6,743 6,970 1,368 Enron Dominion Cogen Corp. 6,993 6,213 6,874 EOTT Energy Partners, L.P. (22,717) 4,815 - Other 24,228 23,902 39,952 $86,018 $112,409 $73,293 Summarized combined financial information of Enron's unconsolidated subsidiaries is presented below: [Download Table] December 31, (In Thousands) 1995 1994 Balance Sheet Current assets $1,776,646 $1,805,050 Property, plant and equipment, net 7,813,974 6,072,820 Other noncurrent assets 968,464 1,287,790 Current liabilities 2,049,923 1,189,478 Long-term debt 4,981,680 4,623,035 Other noncurrent liabilities 1,141,911 1,243,241 Owners' equity 2,385,570 2,109,906 [Download Table] Year Ended December 31, (In Thousands) 1995 1994 1993 Income Statement Operating revenues $8,258,113 $7,102,886 $2,351,177 Operating expenses 7,334,801 6,421,637 2,016,977 Net income 225,770 290,089 204,262 Distributions Paid to Enron 68,216 81,100 59,585 Citrus Corp. Enron has a 50% indirect ownership interest in and provides services to Citrus Corp. (Citrus), a joint venture to transport and market natural gas to Florida. Effective March 1, 1995, Citrus' wholly-owned subsidiary, Florida Gas Transmission (Florida Gas), placed into service its Phase III pipeline expansion. The Phase III expansion increased Florida Gas' firm average delivery capacity by 530 MMcf/day to 1.5 Bcf/day. Teesside Power Limited (Teesside). During the first quarter of 1995, Enron reduced its effective interest in Teesside from 50.0% to 42.5% through a sale of an effective 7.5% interest to one of the original joint venture partners in Teesside, a joint venture cogeneration company which owns a 1,875 megawatt independent power facility in northeast England. An affiliate of Enron operates the facility which was placed in commercial operation on March 27, 1993. Enron has guaranteed Teesside's obligation for certain grid charges and other amounts which could become due under certain power sales agreements. The value of such guarantees is included in Note 15. Under the terms of certain gas supply agreements extending through 2008, Teesside is obligated to take-or-pay for an average of up to 240 billion British thermal units (BBtu) of natural gas per day at indexed prices. Enron has guaranteed 70% of Teesside's payment obligation under the gas supply agreements. However, Enron believes there are alternative markets for such gas should the gas not be taken by Teesside. Transportadora de Gas del Sur S.A. EPP holds a 25% interest in Compania de Inversiones de Energia S.A., an Argentine corporation which owns 70% of Transportadora de Gas del Sur S.A. (TGS). TGS is the owner and operator of a 4,000 mile natural gas pipeline system in Argentina which connects major gas fields in southern and western Argentina with distributors of gas in those areas and in the greater Buenos Aires area, the principal population center of Argentina. TGS is one of two transmission systems in Argentina. Joint Energy Development Investments (JEDI). JEDI, a limited partnership which acquires and owns energy investments, was formed in 1993 with an Enron subsidiary and the California Public Employee Retirement System (CalPERS) each owning a 50% interest. Enron and CalPERS have committed to invest a total of $500 million of capital in JEDI through 1996, of which $85 million has been contributed by Enron as of December 31, 1995. Enron intends to meet its required capital commitments primarily by contributing Enron common stock. Northern Border Partners, L.P. During October 1993, Northern Plains Natural Gas Company (Northern Plains), a wholly-owned subsidiary of Enron, contributed its interest in Northern Border Pipeline Company to Northern Border Partners, L.P., a Delaware limited partnership (the Northern Border Partnership), in exchange for general partner interests,subordinated units and common units in the Northern Border Partnership. Northern Plains sold its common units in the Northern Border Partnership in an underwritten public offering, retaining a 13% interest in the Northern Border Partnership. EOTT Energy Partners, L.P. During March 1994, EOTT Energy Corp., a wholly-owned subsidiary of Enron, exchanged its crude oil marketing and transportation operations with EOTT Energy Partners, L.P. (EOTT) for common and subordinated units and a 2% general partnership interest. The common units were subsequently sold in an underwritten public offering resulting in net proceeds to Enron of approximately $186 million and a pretax gain of approximately $15 million. Enron retained seven million subordinated units of EOTT and its general partnership interest. In September 1995, EOTT discontinued its West Coast processing and asphalt marketing business (other than business from its Arizona asphalt terminals). As a result, EOTT recorded a one-time charge of $45.8 million. Also during 1995, Enron entered into an agreement to provide trade credit support on a secured basis to EOTT in the form of trade guarantees, letters of credit, loans and letters of indemnity totaling $450 million through March 31, 1996. Letters of credit and trade guarantees outstanding under this agreement at December 31, 1995 are included in Note 15. During 1995, Enron purchased 296,800 additional common units of EOTT on the open market. In addition, Enron paid $9.1 million to EOTT in support of EOTT's common unit distributions and in exchange received Additional Partnership Interests (APIs). Enron is committed to provide further support, if needed, up to a total of $29 million through March 1998 through the purchase of additional APIs. Subsequent to December 31, 1995, Enron increased its total ownership in EOTT to 50% through the purchase of additional common units. 9 Preferred Stock Second Preferred Stock. The Cumulative Second Preferred Convertible Stock, $1 par value, pays dividends at an amount equal to the higher of $10.50 per share or the equivalent dividend that would be paid if shares of the Cumulative Second Preferred Convertible Stock were converted to Common Stock. The dividend for the fourth quarter of 1995 was $2.901 per share. The dividend for the preceding four quarters was $2.7304 per share. All previous quarterly dividends had been $2.625 per share. Each share of the Cumulative Second Preferred Convertible Stock is convertible at any time at the option of the holder thereof into 13.652 shares of Enron's common stock, subject to certain adjustments. The Convertible Preferred Stock is currently subject to redemption at Enron's option at a price of $100 per share plus accrued dividends. During 1995, 1994 and 1993, 29,489 shares, 91,694 shares and 332,964 shares, respectively, of the Convertible Preferred Stock were converted into common stock. During 1994, Enron authorized and issued to a wholly-owned subsidiary 35.568509 shares of 9.142% Perpetual Second Preferred Stock (a new series of the Second Preferred Stock). Company-Obligated Preferred Stock of Subsidiaries. During December 1994, Enron's wholly-owned subsidiary, Enron Equity Corp., issued 880 shares of 8.57% Preferred Stock, par value $0.001 per share, liquidation preference $100,000 per share, in a private transaction at a price of $100,000 per share with net proceeds of approximately $88 million. The 8.57% Preferred Stock is redeemable at Enron's option after December 1999 at a price of $100,000 per share plus accumulated and unpaid dividends. Dividends on the 8.57% Preferred Stock are guaranteed by Enron. During August 1994, Enron Capital Resources, L.P., a Delaware limited partnership in which Enron is the sole general partner, issued 3 million shares of 9% Cumulative Preferred Securities, Series A, at a price to the public of $25 per share with net proceeds of approximately $73 million. During November 1993, Enron's wholly-owned subsidiary Enron Capital LLC issued 8.55 million shares of 8% Cumulative Guaranteed Monthly Income Preferred Shares (MIPS) at a price of $25 per share with net proceeds of approximately $207 million. The Series A Preferred Securities and the MIPS are redeemable at the option of Enron in whole or in part beginning August 31, 1999 and November 30, 1998, respectively, at a redemption price of $25 per share plus accumulated and unpaid dividends. The liquidation preference of each of the Series A Preferred Securities and the MIPS is $25 per share. 10 Common Stock and Dividends Enron paid quarterly cash dividends on common stock of $.175 per share ($.70 per share annually) from the final quarter of 1992 until the final quarter of 1993, at which time the dividend was increased to $.1875 per share ($.75 per share annually). The dividend was further increased to $.20 per share ($.80 per share annually) for the final quarter of 1994 and was increased to $.2125 per share ($.85 per share annually) for the final quarter of 1995. Enron's debt agreements do not limit the payment of cash dividends on common stock. Common stock information is as follows: [Download Table] 1995 1994 1993(a) Common Stock, beginning of year 253,069,668 249,095,312 237,532,176 Issued to Benefit and Dividend Reinvestment Plans 197,388 1,303,047 1,476,131 Issued for Conversions (b) 219,138 1,251,793 2,446,632 Issued to Flexible Equity Trust - - 7,500,000 Issued to JEDI 374,166 1,419,516 140,373 Common Stock, end of year 253,860,360 253,069,668 249,095,312 <FN> (a) Presented as if the 1993 stock split was January 1, 1993. (b) Conversions of convertible preferred stock. Treasury stock information is as follows: [Download Table] 1995 1994 1993(a) Treasury Stock, beginning of year 1,394,833 - 349,400 Benefit and Dividend Reinvestment Plans Issued (2,418,216) (47,790) (1,482,927) Returned 328,342 - 102,013 Open Market Purchases (b) 3,496,504 1,897,923 3,005,200 Issued for Conversions (c) (183,429) - (2,043,090) Issued to JEDI - (455,300) - Other - - 69,404 Treasury Stock, end of year 2,618,034 1,394,833 - <FN> (a) Presented as if the 1993 stock split was January 1, 1993. (b) Purchased in connection with a stock repurchase program authorized by the Board of Directors. (c) Conversions of convertible preferred stock. Enron has various stock plans (the Plans) under which options for shares of Enron's common stock have been or may be granted to officers, employees and non-employee members of the Board of Directors. Under the Plans, options granted may be either incentive stock options or nonqualified stock options and are granted at not less than the fair market value of the stock at the time of grant. Enron accounts for the Plans under APB Opinion No. 25, and accordingly, no compensation expense has been recognized. Expiration dates of the options outstanding at December 31, 1995 range from February 8, 1998 to December 29, 2005. The Plans provide for options to be granted with stock appreciation rights (SAR); however, Enron does not presently intend to issue additional options with an SAR feature. Summarized information for the Plans is as follows: [Download Table] 1995 1994 1993 Shares under option, beginning of year 24,245,447 9,679,719 7,314,332 Granted (a) 2,971,210 15,805,680 4,253,233 Exercised (3,137,433) (1,019,090) (1,621,680) Cancelled or expired (1,586,541) (220,862) (266,166) Shares under option, end of year 22,492,683 24,245,447 9,679,719 Shares available for grant at end of year (b) 7,830,758 4,006,833 1,500,301 Shares exercisable at end of year 9,599,245 7,183,664 3,104,722 Average price of options exercised during the year $20.91 $13.50 $13.30 Average price of options outstanding at end of year $29.02 $27.38 $19.64 <FN> (a) Includes options granted on December 29, 1995 and December 30, 1994 for 997,095 shares and 9,717,750 shares, respectively, under all-employee stock option grants for the years 1995 through 2000. (b) Excludes up to 5,209,620 shares, 5,245,100 shares and 2,528,560 shares as of December 31, 1995, 1994 and 1993, respectively, which may be issued either as Restricted Stock or pursuant to stock options. Under the Plans, participants may be granted stock without cost to the participant (restricted stock). The shares issued under the Plans vest to the participants at various times ranging from immediate vesting to vesting at the end of a five year period. The following is an analysis of shares of restricted stock: [Download Table] 1995 1994 1993 Outstanding at beginning of year 193,505 221,658 35,588 Granted 44,900 30,190 203,700 Cancelled or expired (9,420) (2,040) (3,632) Issued(a) (69,545) (56,303) (13,998) Outstanding at end of year 159,440 193,505 221,658 Available for grant at end of year 5,209,620 5,245,100 2,528,560 Average price per share on date of grant $31.36 $32.89 $27.50 <FN> (a) Subsequent to December 31, 1995, 1,534,275 shares of restricted stock were issued in connection with the conversion of certain compensation plans. Flexible Equity Trust (the Trust). In December 1993, Enron established the Trust to fund a portion of its obligations arising from its various employee compensation and benefit plans. Enron issued 7.5 million shares of common stock to the Trust in exchange for cash and an interest bearing promissory note. The note held by Enron is reflected as areduction of shareholders' equity. Common shares held by the Trust are not included in the computation of earnings per share until such shares are released to fund employee benefits. During 1995, 1,049,403 shares were released to fund employee benefits. 11 Retirement Benefits Plan and ESOP Enron maintains a retirement plan (the Enron Plan) which is a noncontributory defined benefit plan covering substantially all employees in the United States and certain employees in foreign countries. Through December 31, 1994, participants in the Enron Plan with five years or more of service were entitled to retirement benefits based on a formula that uses a percentage of final average pay and years of service. In connection with a change to the retirement benefit formula, Enron amended the Enron Plan providing, among other things, that all employees became fully vested in retirement benefits earned through December 31, 1994. The formula in place prior to January 1, 1995 was suspended and replaced with a benefit accrual of 5% of annual base pay beginning January 1, 1996. Enron also maintains a noncontributory employee stock ownership plan (ESOP) which covers all eligible employees. Allocations to individual employees' retirement accounts within the ESOP offset a portion of benefits earned under the Enron Plan. At December 31, 1995, all shares included in the ESOP had been allocated to the employee accounts. The components of pension expense are as follows: [Download Table] (In Thousands) 1995 1994 1993 Service cost - benefits earned during the year $ 1,654 $ 16,192 $ 11,709 Interest cost on projected benefit obligation 21,172 25,996 25,230 Actual return on plan assets (32,299) (22,235) (37,507) Amortization and deferrals 8,810 (12,225) 11,184 Pension expense (income) $ (663) $ 7,728 $ 10,616 The valuation date of the Enron Plan and the ESOP is September 30. The funded status as of the valuation date of the Enron Plan and the ESOP reconciles with the amount detailed below which is included in "Other Assets" on the Consolidated Balance Sheet. [Download Table] (In Thousands) 1995 1994 Actuarial present value of accumulated benefit obligation Vested $(275,668) $(253,881) Nonvested (26,875) (25,546) Additional amounts related to projected wage increases (11,536) (54,260) Projected benefit obligation (314,079) (333,687) Plan assets at fair value (a) 294,763 352,608 Plan assets in excess of (less than) projected benefit obligation (19,316) 18,921 Unrecognized net loss 53,524 35,563 Unrecognized prior service cost 44,476 12,416 Unrecognized net asset at transition (36,205) (42,238) Contributions 553 548 Prepaid pension cost at December 31 $ 43,032 $ 25,210 Discount rate 7.5% 8.0% Long-term rate of return on assets 10.5% 10.5% Rate of increase in wages 4.0% 4.0% <FN> (a) Includes plan assets of the ESOP of $152,202 and $235,540 for the years 1995 and 1994, respectively. Assets of the Enron Plan are comprised primarily of equity securities, fixed income securities and temporary cash investments. It is Enron's policy to fund all pension costs accrued to the extent required by Federal tax regulations. 12 Benefits Other Than Pensions Enron provides certain medical, life insurance and dental benefits to eligible employees and their eligible dependents. Benefits are provided under the provisions of contributory defined dollar benefit plans. Enron is currently funding that portion of its obligations under its postretirement benefit plan which is expected to be recoverable through rates by its regulated pipelines. Enron accrues these postretirement benefit costs over the service lives of the employees expected to be eligible to receive such benefits. Enron is amortizing the transition obligation which existed at January 1, 1993 over a period of approximately 19 years. The following table sets forth the plan's funded status reconciled with the amounts reported in the Consolidated Balance Sheet. [Download Table] (In Thousands) 1995 1994 Actuarial present value of accumulated postretirement benefit obligation (APBO) Retirees $(114,271) $ (88,838) Fully eligible active plan participants (2,342) (2,164) Other employees (14,648) (15,712) Total APBO (131,261) (106,714) Plan assets at fair value 10,511 3,073 APBO in excess of plan assets (120,750) (103,641) Unrecognized transition obligation 70,058 74,803 Unrecognized prior service costs 19,176 18,148 Unrecognized net loss 25,915 5,148 Accrued postretirement benefit obligation $ (5,601) $ (5,542) Discount rate 7.5% 8.0% Health care cost trend rate* 11.7% 12.3% <FN> * This rate is assumed to decrease to 5.0% over 10 years. The components of net periodic postretirement benefit expenses are as follows: [Download Table] (In Thousands) 1995 1994 1993 Service costs $ 1,220 $ 1,527 $ 850 Interest costs 9,025 7,964 7,374 Return on plan assets (266) (106) (39) Amortization of transition obligation 6,386 6,003 4,744 Postretirement benefit expense $16,365 $15,388 $12,929 A 1% increase in the health care cost trend rate would have the effect of increasing the APBO and the net periodic expense by approximately $8.8 million and $0.6 million, respectively. 13 Natural Gas Rates and Regulatory Issues Regulatory issues and rates on Enron's regulated pipelines are subject to final determination by the FERC. Enron's regulated pipelines currently apply accounting standards that recognize the economic effects of regulation and, accordingly, have recorded regulatory assets and liabilities related to their operations. Enron evaluates the applicability of regulatory accounting and the recoverability of these assets through rate or other contractual mechanisms on an ongoing basis. Net regulatory assets at December 31, 1995 and 1994, respectively, are approximately $291 million and $305 million, which include transition costs incurred related to FERC Order 636 of approximately $125 million and$158 million. The regulatory assets related to the FERC Order 636 transition costs are scheduled to be primarily recovered from customers by the end of 1998, while the remaining assets are expected to be recovered over varying time periods. Enron's regulated pipelines have all successfully completed their transitions under FERC Order 636 although future transition costs may be incurred subject to ongoing negotiations and market factors. On March 1, 1995, Northern filed a general rate case proceeding with the FERC which fulfilled a commitment made during its FERC Order 636 restructuring proceeding. The rate case included an increase of $31 million to Northern's cost of service. The FERC accepted and suspended the filing to be effective September 1, 1995 subject to refund. Northern effectuated the higher rates January 1, 1996. Enron believes, based upon its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of pending regulatory matters will not have a material impact on Enron's financial position or results of operations. 14 Litigation and Other Contingencies Enron is party to various claims and litigation, the significant items of which are discussed below. Although no assurances can be given, Enron believes, based on its experience to date and after considering appropriate reserves that have been established, that the ultimate resolution of such items, individually or in the aggregate, will not have a materially adverse impact on Enron's financial position or results of operations. Litigation In 1995, several parties (the Plaintiffs) filed suit in Harris County District Court in Houston, Texas against Intratex Gas Company (Intratex), Houston Pipe Line Company and Panhandle Gas Company (collectively, the Enron Defendants), each of which is a wholly-owned subsidiary of Enron. The Plaintiffs also sued certain other unaffiliated third parties (collectively, the Other Defendants). The Plaintiffs were either sellers or royalty owners under numerous gas purchase contracts with Intratex, many of which have terminated. Early in 1996, the case was severed by the Court into two matters that will be tried (or otherwise resolved) separately. In the first matter, the Plaintiffs sued only the Enron Defendants, alleging that they committed fraud and negligent misrepresentation in connection with the "Panhandle program," a special marketing program established in the early 1980s. In the second matter, the Plaintiffs allege that Intratex and the Other Defendants violated state regulatory requirements and certain gas purchase contracts by failing to take the Plaintiffs' gas ratably with other producers' gas at certain times between 1978 and 1988. In both matters, the Plaintiffs seek an unspecified amount of actual and punitive damages, plus prejudgement interest and attorneys fees. All Defendants deny the Plaintiffs' claims and have asserted various affirmative defenses, including the statute of limitations. The Enron Defendants believe they have strong legal and factual defenses, and intend to vigorously contest the claims brought in each matter. Although no assurances can be given, Enron believes that the ultimate resolution of these matters will not have a materially adverse effect on its financial position or results of operations. Environmental Matters Enron is subject to extensive Federal, state and local environmental laws and regulations. These laws and regulations require expenditures in connection with the construction of new facilities, the operation of existing facilities and for remediation at various operating sites. The implementation of the Clean Air Act Amendments is expected to result in increased operating expenses. These increased operating expenses are not expected to have a material impact on Enron's financial position or results of operations. In addition, Enron received requests for information from the Environmental Protection Agency (EPA) and state environmental agencies inquiring whether Enron has disposed of materials at certain waste disposal sites. Enron has received notices from EPA and state agencies that it is a "potentially responsible party" (PRP) under the Comprehensive Environmental Response, Compensation and Liability Act and analogous state statutes, and may be required to share in the costs of the cleanup of other, similar sites. However, Enron believes that any potential assessments in connection with these PRP notices and third party claims, either taken individually or in the aggregate, will not have a material impact on Enron's financial position or results of operations. Other In October 1994, an explosion occurred at Enron's methanol plant in Pasadena, Texas. Before the explosion, the plant was producing approximately 420,000 gallons of methanol per day, approximately half of which was being used at Enron's MTBE plant. There were no fatalities or serious injuries as a result of the explosion. The plant was placed back into commercial operation in June 1995. Taking into account business interruption and other insurance coverages, Enron currently anticipates that the explosion did not and will not have a materially adverse effect on its financial position or results of operations. In connection with a Power Purchase Agreement between Dabhol Power Company, Enron's 80%-owned subsidiary, and the Maharashtra State Electricity Board, Dabhol Power Company has been developing Phase I of an electricity generating power plant south of Bombay, State of Maharashtra, India (the Project). On August 3, 1995, after construction had begun, a new coalition government in the State of Maharashtra announced the State government's intention to terminate the Project, and construction ceased on August 8, 1995. Enron believes that such actions were in clear violation of the contract and in response to these actions, Dabhol Power Company commenced arbitration proceedings in London against the State government for the actions it has taken to terminate the Project. Dabhol Power Company seeks to recover all of its construction and other expenses, in addition to lost profits. In addition, Dabhol Power Company has both orally and in writing communicated to the Maharashtra State government its desire to go forward with construction of the Project and its willingness to resolve any outstanding issues. In January 1996, the Maharashtra State government notified Dabhol Power Company in writing that it had approved a restructured transaction (that includes both Phase I and Phase II and that increases the planned capacity of the facility by 435 megawatts to 2,450 megawatts) on terms that are acceptable to Enron. While the parties are working together in good faith and Enron anticipates construction to resume in the near future, various approvals remain outstanding from government agencies and lenders. Although the outcomes of the arbitration and the renegotiation processes cannot be predicted with certainty, based on currently available information, Enron believes that the ultimate outcome of the Project will not have a materially adverse effect on its financial position. In March 1993, Enron entered into long-term gas contracts with Phillips Petroleum Company United Kingdom Limited, British Gas Exploration and Production Limited and Agip (U.K.) Limited to purchase all of the future gas production from the J-Block field which is located in the North Sea offshore the United Kingdom (the J-Block Contracts). Such agreements provide for Enron to take or pay for the gas at a fixed price (with possible escalations throughout the contract period). Gas paid for, but not taken, may be recovered in later contract years. The J-Block Contracts provide for a first delivery date of not later than October 1, 1996. The contract price for such natural gas is in excess of current spot market prices in the United Kingdom. In September 1995, Enron announced that, in accordance with its contractual rights, it had notified the J-Block sellers that Enron's nominations for gas from the J-Block fields were estimated to be zero from the first delivery date through September 30, 1997. In addition, in accordance with its contractual rights, Enron has made no estimated nominations for J-Block gas to date under the J-Block Contracts for the contract year ending September 30, 1998. Enron continues its good faith efforts to develop mutually beneficial solutions regarding pricing terms so that production from J-Block can begin as soon as possible. Enron believes that there are many commercial reasons for the parties to resolve any contract issues, but efforts have not been successful to date. Enron has advised the J-Block sellers that it intends to assert all legal rights, exercise all available commercial flexibility and pursue all available commercial and legal remedies under the J-Block Contracts, and stands ready and able to perform all legal obligations under the J-Block Contracts, including potential prepayments for gas to be taken in later years. The long- term market demand for J-Block gas supply remains favorable and Enron anticipates being able to meet all of its various short- and long-term market commitments. Although no assurances can be given, based upon the foregoing and other information currently available, Enron does not anticipate that the J-Block Contracts will have a materially adverse effect on its financial position. 15 Commitments Firm Transportation Obligations Enron has firm transportation agreements with various joint venture pipelines. Under these agreements, Enron must make specified minimum payments each month. The estimated aggregate amounts of such required future payments at December 31, 1995, were: [Download Table] (In Millions) 1996 $ 108.5 1997 118.5 1998 122.1 1999 126.9 2000 132.1 Later years 1,194.7 Total $1,802.8 The costs incurred under these agreements, including commodity charges on actual quantities shipped, totaled $18.4 million, $20.8 million and $42.4 million in 1995, 1994 and 1993, respectively. Enron has assigned a firm transportation contract with one of its joint ventures to a third party and guaranteed minimum payments under the contract averaging approximately $45.4 million annually through 2001. Other Commitments Enron leases property, operating facilities and equipment under various operating leases, certain of which contain renewal and purchase options and residual value guarantees. Guarantees under the leases total $1.02 billion at December 31, 1995. Future commitments related to these items at December 31, 1995 are as follows: [Download Table] (In Millions) 1996 $ 164.5 1997 139.2 1998 117.4 1999 92.6 2000 87.4 Later years 434.0 Total minimum payments $1,035.1 Total rent expense incurred during 1995, 1994 and 1993 was $147.2 million, $125.6 million and $103.7 million, respectively. Enron guarantees certain long-term contracts for the sale of electrical power and steam from a cogeneration facility owned by one of Enron's equity investees. Under terms of the contracts, which initially extend through June 1999, Enron could be liable for penalties should, under certain conditions, the contracts be terminated early. Enron also guarantees the performance of certain of its unconsolidated subsidiaries in connection with letters of credit issued on behalf of those unconsolidated subsidiaries. At December 31, 1995, a total of $320.6 million of such guarantees were outstanding, including $116.2 million on behalf of EOTT. In addition, Enron is a guarantor on certain liabilities of unconsolidated subsidiaries and other companies totaling approximately $665.3 million, including $300.7 million related to EOTT trade obligations. The EOTT letters of credit and guarantees of trade obligations are fully secured by the assets of EOTT. Management does not consider it likely that Enron would be required to perform or otherwise incur any losses associated with the above guarantees. In addition, certain commitments have been made related to 1996 planned capital expenditures. 16 Other Income, Net The components of Other Income, Net are as follows: [Download Table] Year Ended December 31, (In Thousands) 1995 1994 1993 Gain on sale of EOG stock $366,695 $ - $ - Gains on sales of other assets and investments 100,476 37,270 102,268 Regulatory, contingency and other adjustments (19,905) 17,700 (55,689) Foreign currency gains (losses) (735) 8,188 - Litigation adjustments and settlements, net (7,605) (1,110) 4,282 Other (4,685) 15,001 11,254 $434,241 $77,049 $ 62,115 In December 1995, Enron completed a public offering of 31 million outstanding shares of its EOG common stock, reducing its ownership interest from 80% to 61%. Enron recognized a pretax gain of $367 million ($161 million after tax) on net proceeds totaling $650 million. Concurrently, Enron issued 6 1/4% Exchangeable Notes which will be mandatorily exchangeable in three years into shares of EOG common stock owned by Enron at a specified exchange rate (or at Enron's option, for cash with an equal value). Proceeds from the issuance of these notes totaled $221 million. At the maturity of the notes, if all of the Exchangeable Notes are exchanged for the maximum number of EOG common shares, Enron's interest in EOG will be reduced to approximately 54%. 17 Geographic and Business Segment Information Enron's operations are classified into four business segments: Transportation and Operation - Interstate transmission of natural gas. Construction, management and operation of pipelines, liquids, clean fuel plants and power facilities. Investment in crude oil transportation activities and liquids pipeline operations. Domestic Gas and Power Services - Purchasing, marketing and financing of natural gas, natural gas liquids, crude oil and power. Price risk management in connection with natural gas, natural gas liquids, crude oil and power transactions. Intrastate natural gas pipelines. Development, acquisition and promotion of natural gas fired power plants in North America. Extraction of natural gas liquids. International Gas and Power Services - Independent (non- utility) development, acquisition and promotion of power plants, natural gas liquids facilities and pipelines outside of North America. Exploration and Production - Natural gas and crude oil exploration and production primarily in the United States, Canada, Trinidad and India. Financial information by geographic and business segment for each of the three years in the period ended December 31, 1995, follows. [Download Table] Geographic Segments Year Ended December 31, (In Thousands) 1995 1994 1993 Operating Revenues from Unaffiliated Customers United States $ 7,855,215 $ 7,604,127 $ 7,071,406 Foreign 1,333,782 1,379,596 914,394 $ 9,188,997 $ 8,983,723 $ 7,985,800 Intersegment Sales United States $ 23,735 $ 48,369 $ 20,785 Foreign 158,812 116,257 66,574 $ 182,547 $ 164,626 $ 87,359 Operating Income United States $ 487,319 $ 609,008 $ 567,274 Foreign 130,683 106,764 63,528 $ 618,002 $ 715,772 $ 630,802 Income Before Interest, Minority Interest and Income Taxes United States $ 968,637 $ 755,686 $ 663,276 Foreign 196,445 188,706 134,391 $ 1,165,082 $ 944,392 $ 797,667 Identifiable Assets United States $10,694,896 $ 9,597,093 $ 9,939,618 Foreign 1,327,565 1,303,729 867,613 $12,022,461 $10,900,822 $10,807,231 [Enlarge/Download Table] Operations In Business and Geographic Segments Business Segments International Transportation Domestic Gas Gas and Exploration Corporate and and Power Power and and (In Thousands) Operation Services Services Production Other(c)(d) Total 1995 Unaffiliated Revenues(a) $ 804,946 $7,063,750 $ 839,125 $ 481,176 $ - $ 9,188,997 Intersegment Revenues(b) 25,610 (102,975) 43,757 278,191 (244,583) - Total Revenues 830,556 6,960,775 882,882 759,367 (244,583) 9,188,997 Depreciation, Depletion and Amortization 82,790 103,582 26,712 216,047 2,575 431,706 Operating Income (Loss) 299,227 114,583 75,192 240,002 (111,002) 618,002 Equity in Earnings of Unconsolidated Subsidiaries 23,156 6,325 57,245 - (708) 86,018 Other Income, net 36,803 36,590 9,531 669 377,469 461,062 Income Before Interest, Minority Interest and Income Taxes 359,186 157,498 141,968 240,671 265,759 1,165,082 Additions to Property, Plant and Equipment 121,208 97,781 58,212 464,045 8,255 749,501 Identifiable Assets 2,360,702 5,991,423 813,868 2,066,952 789,516 12,022,461 Investments in and Advances to Unconsolidated Subsidiaries 533,531 156,805 467,596 - 58,542 1,216,474 Total Assets $2,894,233 $6,148,228 $1,281,464 $2,066,952 $ 848,058 $13,238,935 1994 Unaffiliated Revenues(a) $ 937,524 $7,165,582 $ 391,919 $ 488,698 $ - $ 8,983,723 Intersegment Revenues(b) 38,756 13,392 6,984 290,090 (349,222) - Total Revenues 976,280 7,178,974 398,903 778,788 (349,222) 8,983,723 Depreciation, Depletion and Amortization 87,555 93,795 15,226 242,182 2,571 441,329 Operating Income (Loss) 327,267 164,118 72,206 195,120 (42,939) 715,772 Equity in Earnings of Unconsolidated Subsidiaries 48,695 18,427 45,227 - 60 112,409 Other Income, net 27,012 19,701 30,312 2,783 36,403 116,211 Income Before Interest, Minority Interest and Income Taxes 402,974 202,246 147,745 197,903 (6,476) 944,392 Additions to Property, Plant and Equipment 117,018 83,014 13,887 442,078 4,918 660,915 Identifiable Assets 2,388,517 5,802,989 449,988 1,823,898 435,430 10,900,822 Investments in and Advances to Unconsolidated Subsidiaries 527,822 161,788 351,354 - 24,225 1,065,189 Total Assets $2,916,339 $5,964,777 $ 801,342 $1,823,898 $ 459,655 $11,966,011 1993 Unaffiliated Revenues(a) $1,385,925 $5,449,946 $ 751,375 $ 398,554 $ - $ 7,985,800 Intersegment Revenues(b) 80,081 134,158 19,213 308,571 (542,023) - Total Revenues 1,466,006 5,584,104 770,588 707,125 (542,023) 7,985,800 Depreciation, Depletion and Amortization 115,922 80,960 9,081 249,704 2,521 458,188 Operating Income (Loss) 341,272 155,573 64,582 122,439 (53,064) 630,802 Equity in Earnings of Unconsolidated Subsidiaries 22,427 8,821 41,962 - 83 73,293 Other Income, net 18,437 32,466 24,835 6,635 11,199 93,572 Income Before Interest, Minority Interest and Income Taxes 382,136 196,860 131,379 129,074 (41,782) 797,667 Additions to Property, Plant and Equipment 144,835 102,518 52,545 383,064 5,070 688,032 Identifiable Assets 2,808,816 5,352,163 492,297 1,668,395 485,560 10,807,231 Investments in and Advances to Unconsolidated Subsidiaries 278,912 83,360 315,461 - 19,351 697,084 Total Assets $3,087,728 $5,435,523 $ 807,758 $1,668,395 $ 504,911 $11,504,315 <FN> (a) Unaffiliated revenues include sales to unconsolidated subsidiaries. (b) Intersegment sales are made at prices comparable to those received from unaffiliated customers and in some instances are affected by regulatory considerations. (c) Corporate and Other assets consist of cash and cash equivalents, investments in marketable securities, receivables transferred from subsidiaries in connection with the receivables sale program and miscellaneous other assets. (d) Includes consolidating eliminations. 18 Oil and Gas Producing Activities (Unaudited except for Results of Operations for Oil and Gas Producing Activities) The following information regarding Enron's oil and gas producing activities should be read in conjunction with Note 1. This information includes amounts attributable to a 39% minority interest at December 31, 1995 and a 20% minority interest at December 31, 1994, 1993 and 1992. [Download Table] Capitalized Costs Relating to Oil and Gas Producing Activities December 31, (In Thousands) 1995 1994 Proved properties $ 3,253,593 $ 2,889,242 Unproved properties 127,331 126,193 Total 3,380,924 3,015,435 Accumulated depreciation, depletion and amortization (1,499,379) (1,330,624) Net capitalized costs $ 1,881,545 $ 1,684,811 [Enlarge/Download Table] Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities (a) Foreign (In Thousands) United States Canada Trinidad India Other Total 1995 Acquisition of properties Unproved $ 16,196 $ 4,645 $ - $ - $ 1,482 $ 22,323 Proved 122,369 116 - 5,000 - 127,485 Total 138,565 4,761 - 5,000 1,482 149,808 Exploration 47,463 7,197 374 (98) 17,948 72,884 Development 217,674 28,611 32,692 16,756 577 296,310 Total $403,702 $40,569 $33,066 $21,658 $20,007 $519,002 1994 Acquisition of properties Unproved $ 45,776 $ 6,618 $ - $ - $ (17) $ 52,377 Proved 17,367 4,523 - 12,300 - 34,190 Total 63,143 11,141 - 12,300 (17) 86,567 Exploration 70,669 8,210 850 2,302 11,242 93,273 Development 223,241 35,896 60,778 767 564 321,246 Total $357,053 $55,247 $61,628 $15,369 $11,789 $501,086 1993 Acquisition of properties Unproved $ 23,686 $ 4,556 $ - $ - $ 887 $ 29,129 Proved 6,625 2,598 - - - 9,223 Total 30,311 7,154 - - 887 38,352 Exploration 53,918 9,096 1,367 - 18,595 82,976 Development 247,705 28,045 41,262 - - 317,012 Total $331,934 $44,295 $42,629 $ - $19,482 $438,340 <FN> (a) Costs have been categorized on the basis of Financial Accounting Standards Board definitions which include costs of oil and gas producing activities whether capitalized or charged to expense as incurred. [Enlarge/Download Table] Results of Operations for Oil and Gas Producing Activities (a) The following tables set forth results of operations for oil and gas producing activities for the three years in the period ended December 31, 1995: Foreign (In Thousands) United States Canada Trinidad India Other Total 1995 Operating revenues Associated companies $223,652 $ 6,893 $ - $ - $ - $230,545 Trade 122,567 36,815 71,686 15,411 - 246,479 Gains on sales of reserves and related assets 62,737 84 - - - 62,821 Total 408,956 43,792 71,686 15,411 - 539,845 Exploration expenses, including dry hole costs 35,298 3,839 374 (98) 15,542 54,955 Production costs 63,734 13,825 8,176 10,553 - 96,288 Impairment of unproved oil and gas properties 21,981 1,734 - - - 23,715 Depreciation, depletion and amortization 180,788 19,533 14,633 335 368 215,657 Income (loss) before income taxes 107,155 4,861 48,503 4,621 (15,910) 149,230 Income tax expense (benefit) 1,226 1,133 26,677 2,311 (1,335) 30,012 Results of Operations $105,929 $ 3,728 $21,826 $ 2,310 $(14,575) $119,218 1994 Operating revenues Associated companies $315,866 $ 8,452 $ - $ - $ - $324,318 Trade 115,375 42,017 35,908 509 - 193,809 Gains on sales of reserves and related assets 54,026 (12) - - - 54,014 Total 485,267 50,457 35,908 509 - 572,141 Exploration expenses, including dry hole costs 42,242 4,503 836 2,302 9,125 59,008 Production costs 68,998 12,776 5,083 26 - 86,883 Impairment of unproved oil and gas properties 23,862 1,074 - - - 24,936 Depreciation, depletion and amortization 218,433 16,572 6,572 - 281 241,858 Income (loss) before income taxes 131,732 15,532 23,417 (1,819) (9,406) 159,456 Income tax expense (benefit) (8,617) 6,175 12,804 (910) (2,873) 6,579 Results of Operations $140,349 $ 9,357 $10,613 $ (909) $ (6,533) $152,877 1993 Operating revenues Associated companies $369,824 $ 9,637 $ - $ - $ - $379,461 Trade 140,552 33,228 1,209 - - 174,989 Gains on sales of reserves and related assets 13,724 (406) - - - 13,318 Total 524,100 42,459 1,209 - - 567,768 Exploration expenses, including dry hole costs 35,029 6,657 1,367 - 12,223 55,276 Production costs 75,767 14,063 1,496 - - 91,326 Impairment of unproved oil and gas properties 19,499 968 - - - 20,467 Depreciation, depletion and amortization 234,292 14,630 387 - 154 249,463 Income (loss) before income taxes 159,513 6,141 (2,041) - (12,377) 151,236 Income tax expense (benefit) (15,525) 2,265 (1,020) - (1,742) (16,022) Results of Operations $175,038 $ 3,876 $(1,021) $ - $(10,635) $167,258 <FN> (a) Excludes net revenues associated with other marketing activities, interest charges, general corporate expenses and certain gathering and handling fees for each of the three years in the period ended December 31, 1995. The gathering and handling fees and other marketing net revenues are directly associated with oil and gas operations with regard to required segment reporting, but are not part of required disclosures about oil and gas producing activities. Oil and Gas Reserve Information The following summarizes the policies used by Enron in preparing the accompanying oil and gas supplemental reserve disclosures, Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves and reconciliation of such standardized measure from period to period. Estimates of proved and proved developed reserves at December 31, 1995, 1994 and 1993 were based on studies performed by Enron's engineering staff for reserves in the United States, Canada, Trinidad and India. Opinions by DeGolyer and MacNaughton, independent petroleum consultants, for the years ended December 31, 1995, 1994 and 1993 covering producing areas, in the United States and Canada, containing 73%, 59% and 65%, respectively, of proved reserves of Enron on a net-equivalent-cubic-feet-of-gas basis, indicate that the estimates of proved reserves prepared by Enron's engineering staff for the properties reviewed by DeGolyer and MacNaughton, when compared in total on a net-equivalent-cubic-feet-of-gas basis, do not differ by more than 5% from those prepared by DeGolyer and MacNaughton's engineering staff. All reports by DeGolyer and MacNaughton were developed utilizing geological and engineering data provided by Enron. The standardized measure of discounted future net cash flows does not purport, nor should it be interpreted, to present the fair market value of Enron's crude oil and natural gas reserves. An estimate of fair value would also take into account, among other things, the recovery of reserves not presently classified as proved reserves, anticipated future changes in prices and costs and a discount factor more representative of the time value of money and the risks inherent in reserve estimates. Enron's presentation of estimated proved oil and gas reserves has been restated to exclude, for each of the years presented, those quantities attributable to future deliveries required under a volumetric production payment. In order to calculate such amounts, Enron has assumed that deliveries under the volumetric production payment are made as scheduled at expected British thermal unit factors, and that delivery commitments are satisfied through delivery of actual volumes as opposed to cash settlements. [Enlarge/Download Table] Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves (In Thousands) United States Canada Trinidad India Total 1995 Future cash inflows(a) $3,996,029 $ 502,803 $ 395,328 $ 396,130 $ 5,290,290 Future production costs (747,064) (203,906) (152,287) (202,410) (1,305,667) Future development costs (297,859) (7,153) (3,610) (13,500) (322,122) Future net cash flows before income taxes 2,951,106 291,744 239,431 180,220 3,662,501 Future income taxes (695,843) (46,310) (105,188) (81,349) (928,690) Future net cash flows 2,255,263 245,434 134,243 98,871 2,733,811 Discount to present value at 10% annual rate (1,015,123) (68,861) (19,217) (45,470) (1,148,671) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(a) $1,240,140(b) $ 176,573 $ 115,026 $ 53,401 $ 1,585,140(b) 1994 Future cash inflows(a) $2,315,215 $ 487,050 $ 317,758 $ 168,370 $ 3,288,393 Future production costs (606,932) (196,275) (87,479) (105,840) (996,526) Future development costs (135,768) (9,596) (1,781) (4,500) (151,645) Future net cash flows before income taxes) 1,572,515 281,179 228,498 58,030 2,140,222 Future income taxes (208,163) (57,220) (102,171) (22,482) (390,036) Future net cash flows 1,364,352 223,959 126,327 35,548 1,750,186 Discount to present value at 10% annual rate (401,547) (67,018) (22,897) (14,730) (506,192) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(a) $ 962,805(b) $ 156,941 $ 103,430 $ 20,818 $ 1,243,994(b) 1993 Future cash inflows(a) $3,154,790 $ 592,845 $ 147,542 $ - $ 3,895,177 Future production costs (639,760) (230,230) (45,385) - (915,375) Future development costs (165,473) (21,001) (7,582) - (194,056) Future net cash flows before income taxes 2,349,557 341,614 94,575 - 2,785,746 Future income taxes (487,017) (91,718) (35,477) - (614,212) Future net cash flows 1,862,540 249,896 59,098 - 2,171,534 Discount to present value at 10% annual rate (600,172) (90,125) (9,519) - (699,816) Standardized measure of discounted future net cash flows relating to proved oil and gas reserves(a) $1,262,368(b) $ 159,771 $ 49,579 $ - $ 1,471,718(b) <FN> (a) Based on year-end market prices determined at the point of delivery from the producing unit. (b) Excludes $36.0 million, $60.3 million, $105.3 million and $127.7 million at December 31, 1995, 1994, 1993 and 1992, respectively, associated with a volumetric production payment sold effective October 1, 1992, as amended, to be delivered over a seventy-eight month period beginning October 1, 1992 (see Note 7). [Enlarge/Download Table] Changes in Standardized Measure of Discounted Future Net Cash Flows (In Thousands) United States Canada Trinidad India Total December 31, 1992 $1,183,692 $125,419 $ - $ - $1,309,111 Sales and transfers of oil and gas produced, net of production costs (388,251) (28,802) 287 - (416,766) Net changes in prices and production costs 158,102 28,400 - - 186,502 Extensions, discoveries, additions and improved recovery, net of related costs 275,722 27,785 74,191 - 377,698 Development costs incurred 58,500 13,900 - - 72,400 Revisions of estimated development costs 32,196 (1,345) - - 30,851 Revisions of previous quantity estimates (26,118) 5,668 - - (20,450) Accretion of discount 128,461 15,348 - - 143,809 Net change in income taxes (76,755) (9,795) (24,899) - (111,449) Purchases of reserves in place 9,462 2,707 - - 12,169 Sales of reserves in place (36,919) (1,140) - - (38,059) Changes in timing and other (55,724) (18,374) - - (74,098) December 31, 1993 $1,262,368 $159,771 $ 49,579 $ - $1,471,718 Sales and transfers of oil and gas produced, net of production costs (339,809) (37,693) (30,825) (483) (408,810) Net changes in prices and production costs (506,273) (65,287) 11,002 - (560,558) Extensions, discoveries, additions and improved recovery, net of related costs 225,366 51,006 96,515 - 372,887 Development costs incurred 69,900 6,700 7,582 - 84,182 Revisions of estimated development costs 6,792 5,931 - - 12,723 Revisions of previous quantity estimates (2,909) (3,407) 14,077 - 7,761 Accretion of discount 145,119 19,762 7,448 - 172,329 Net change in income taxes 167,983 19,966 (45,789) (7,752) 134,408 Purchases of reserves in place 16,651 3,404 - 29,053 49,108 Sales of reserves in place (27,980) (461) - - (28,441) Changes in timing and other (54,403) (2,751) (6,159) - (63,313) December 31, 1994 $ 962,805 $156,941 $103,430 $20,818 $1,243,994 Sales and transfers of oil and gas produced, net of production costs (268,463) (29,883) (63,510) (4,858) (366,714) Net changes in prices and production costs 12,079 (5,698) (37,035) 7,857 (22,797) Extensions, discoveries, additions and improved recovery, net of related costs 376,474(a) 38,028 53,674 46,180 514,356(a) Development costs incurred 29,100 2,600 1,800 - 33,500 Revisions of estimated development costs 920 139 28,771 4,500 34,330 Revisions of previous quantity estimates 5,694 (5,217) 10,142 (29) 10,590 Accretion of discount 97,248 17,483 17,412 2,857 135,000 Net change in income taxes (132,614) 10,592 (8,048) (28,127) (158,197) Purchases of reserves in place 193,711 - - - 193,711 Sales of reserves in place (54,441) (569) - - (55,010) Changes in timing and other 17,627 (7,843) 8,390 4,203 22,377 December 31, 1995 $1,240,140 $176,573 $115,026 $53,401 $1,585,140 <FN> (a) Includes approximately $77 million related to the reserves in the Big Piney deep Paleozoic formations. Reserve Quantity Information Enron's estimates of proved developed and net proved reserves of crude oil, condensate, natural gas liquids and natural gas and of changes in net proved reserves were as follows: [Enlarge/Download Table] United States Canada Trinidad India Total Net proved developed reserves Natural gas (Bcf) December 31, 1992 1,054.1(a) 194.4 - - 1,248.5(a) December 31, 1993 1,079.8(a) 250.6 71.4 - 1,401.8(a) December 31, 1994 1,128.2(a) 288.3 206.2 - 1,622.7(a) December 31, 1995 1,218.1(a)(b) 310.1 233.9 - 1,762.1(a)(b) Liquids (MBbl)(c) December 31, 1992 12,762(a) 5,329 - - 18,091(a) December 31, 1993 11,165(a) 5,409 1,591 - 18,165(a) December 31, 1994 16,770(a) 7,073 4,429 7,585 35,857(a) December 31, 1995 19,977(a) 6,505 5,607 11,542 43,631(a) Natural gas (Bcf) Net proved reserves at December 31, 1992 1,326.1(a) 232.5 - - 1,558.6(a) Revisions of previous estimates (31.3) 11.0 - - (20.3) Purchases in place 9.2 2.6 - - 11.8 Extensions, discoveries and other additions 234.9 47.7 101.3 - 383.9 Sales in place (13.7) (1.5) - - (15.2) Production (212.0) (21.3) (0.8) - (234.1) Net proved reserves at December 31, 1993 1,313.2(a) 271.0 100.5 - 1,684.7(a) Revisions of previous estimates (17.1) (6.5) 15.0 - (8.6) Purchases in place 18.8 9.2 - 29.3 57.3 Extensions, discoveries and other additions 233.8 50.2 113.9 - 397.9 Sales in place (29.3) (1.0) - - (30.3) Production (212.0) (26.3) (23.2) - (261.5) Net proved reserves at December 31, 1994 1,307.4(a) 296.6 206.2 29.3 1,839.5(a) Revisions of previous estimates 10.1 (8.1) 17.5 (29.3) (9.8) Purchases in place 174.8 - - - 174.8 Extensions, discoveries and other additions 1,391.6(b) 54.8 60.8 75.0 1,582.2(b) Sales in place (38.1) (1.7) - - (39.8) Production (191.7) (27.7) (39.0) - (258.4) Net proved reserves at December 31, 1995 2,654.1(a)(b) 313.9 245.5 75.0 3,288.5(a)(b) Liquids (MBbl)(c) Net proved reserves at December 31, 1992 13,865 5,358 - - 19,223 Revisions of previous estimates 1,490 (536) - - 954 Purchases in place 15 489 - - 504 Extensions, discoveries and other additions 3,552 1,115 2,251 - 6,918 Sales in place (3,230) (23) - - (3,253) Production (2,520) (932) (33) - (3,485) Net proved reserves at December 31, 1993 13,172 5,471 2,218 - 20,861 Revisions of previous estimates 2,179 (177) 455 - 2,457 Purchases in place 358 - - 7,617 7,975 Extensions, discoveries and other additions 5,332 2,848 2,687 - 10,867 Sales in place (257) - - - (257) Production (2,997) (905) (931) (32) (4,865) Net proved reserves at December 31, 1994 17,787 7,237 4,429 7,585 37,038 Revisions of previous estimates (413) (351) 396 4,874 4,506 Purchases in place 4,264 - - - 4,264 Extensions, discoveries and other additions 8,703 729 3,896 - 13,328 Sales in place (1,241) (9) - - (1,250) Production (3,701) (1,021) (1,851) (917) (7,490) Net proved reserves at December 31, 1995 25,399 6,585 6,870 11,542 50,396 <FN> (a) Excludes approximately 54.2 Bcf, 70.9 Bcf, 87.5 Bcf and 114.3 Bcf at December 31, 1995, 1994 , 1993 and 1992, respectively, associated with a volumetric production payment sold effective October 1, 1992, as amended, to be delivered over a seventy-eight month period beginning October 1, 1992 (see Note 7). (b) Includes 1,180.0 Bcf related to net proved Deep Paleozoic natural gas reserves. (c) Includes crude oil, condensate and natural gas liquids. [Enlarge/Download Table] Enron Corp. and Subsidiaries SUPPLEMENTAL FINANCIAL INFORMATION (UNAUDITED) Quarterly Results Income Before Interest, Minority Fully (In Thousands, Operating Gross Interest and Primary Earnings Diluted Earnings Except Per Share Amounts) Revenues Profit Income Taxes Net Income Per Share(a) Per Share(a) 1995 First Quarter $2,303,949 $684,516 $371,442 $194,950 $.79 $.73 Second Quarter 2,149,346 598,866 230,447 94,045 .37 .35 Third Quarter 2,185,805 629,256 239,328 100,583 .40 .37 Fourth Quarter 2,549,897 542,873 323,865 130,116 .52 .49 1994 First Quarter $2,455,726 $673,333 $336,066 $173,063 $.70 $.65 Second Quarter 1,910,709 539,167 168,703 75,601 .30 .28 Third Quarter 2,030,663 553,774 204,569 95,995 .38 .36 Fourth Quarter 2,586,625 700,340 235,054 108,751 .43 .41 <FN> (a) The sum of earnings per share for the four quarters may not equal the total earnings per share for the year due to changes in the average number of common shares outstanding.
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REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS ON FINANCIAL STATEMENT SCHEDULE To Enron Corp.: We have audited in accordance with generally accepted auditing standards, the consolidated financial statements of Enron Corp. and subsidiaries included in this Form 10-K and have issued our report thereon dated February 16, 1996. Our audits were made for the purpose of forming an opinion on the basic financial statements taken as a whole. The schedule listed in Item 14(a)2 is presented for purposes of complying with the Securities and Exchange Commission's rules and is not part of the basic financial statements. This schedule has been subjected to the auditing procedures applied in the audit of the basic financial statements and, in our opinion, fairly states in all material respects the financial data required to be set forth therein in relation to the basic financial statements taken as a whole. ARTHUR ANDERSEN LLP Houston, Texas February 16, 1996
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[Enlarge/Download Table] SCHEDULE II ENRON CORP. AND SUBSIDIARIES SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS FOR THE YEARS ENDED DECEMBER 31, 1994, 1993 AND 1992 (In Thousands) Column A Column B Column C Column D Column E Additions Deductions Balance at Charged to Charged For Purpose For Beginning Costs and to Other Which Reserves Balance at Description of Year Expenses Accounts Were Created End of Year 1995 Reserves deducted from assets to which they apply Allowance for doubtful accounts $ 12,730 $ 4,248 $ 179 $ 5,515 $ 11,642 Assets from price risk management activities $129,925 $49,619 $ 45,154 $ 17,967 $206,731 Reserve for regulatory issues Current $ 5,740 $13,559 $ 107 $ 5,319 $ 14,087 Noncurrent $ - $37,000 $ - $ - $ 37,000 Reserve for insurance claims and losses - noncurrent $ 25,286 $ 7,510 $ - $ 9,071 $ 23,725 Reserve for Clean Fuels Plant Operations $ - $75,000 $ - $ - $ 75,000 1994 Reserves deducted from assets to which they apply Allowance for doubtful accounts $ 21,873 $ 4,603 $ (278) $ 13,468(1) $ 12,730 Assets from price risk management activities $102,520 $13,367 $ 19,400 $ 5,362 $129,925 Reserve for regulatory issues Current $ 21,730 $14,555 $ 5,472 $ 36,017(2) $ 5,740 Noncurrent $ 21,418 $ 892 $ - $ 22,310 $ - Reserve for insurance claims and losses - noncurrent $ 28,410 $ 1,893 $ - $ 5,017 $ 25,286 1993 Reserves deducted from assets to which they apply Allowance for doubtful accounts $ 14,555 $ 6,558 $ 2,955 $ 2,195 $ 21,873 Assets from price risk management activities $ 74,108 $60,207 $ - $ 31,795 $102,520 Reserve for regulatory issues Current $ 8,799 $29,282 $(24,345) $ (7,994) $ 21,730 Noncurrent $ 3,677 $ 8,069 $ 9,672 $ - $ 21,418 Reserve for insurance claims and losses - noncurrent $ 22,779 $10,355 $ - $ 4,724 $ 28,410 <FN> (1) Includes $10.8 million resulting from the sale of a majority interest in Enron's crude oil trading and transportation assets. (2) Includes amounts credited to income in connection with the resolution of regulatory issues. SIGNATURES Pursuant to the requirements of Section 13 or 15(d) 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, on this 29th day of March, 1996. ENRON CORP. (Registrant) By: JACK I. TOMPKINS (Jack I. Tompkins) Senior Vice President and Chief Information, Administrative and Accounting Officer Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below on March 29th, 1996 by the following persons on behalf of the Registrant and in the capacities indicated. Signature Title KENNETH L. LAY Chairman of the Board, Chief Executive (Kenneth L. Lay) Officer and Director (Principal Executive Officer) JACK I. TOMPKINS Senior Vice President and Chief (Jack I. Tompkins) Information, Administrative and Accounting Officer (Principal Accounting Officer) KURT S. HUNEKE Vice President, Finance and Treasurer (Kurt S. Huneke) (Principal Financial Officer) ROBERT A. BELFER* Director (Robert A. Belfer) NORMAN P. BLAKE, JR.* Director (Norman P. Blake, Jr.) JOHN H. DUNCAN* Director (John H. Duncan) JOE H. FOY* Director (Joe H. Foy) WENDY L. GRAMM* Director (Wendy L. Gramm) ROBERT K. JAEDICKE* Director (Robert K. Jaedicke) RICHARD D. KINDER* Director and President and Chief (Richard D. Kinder) Operating Officer CHARLES A. LEMAISTRE* Director (Charles A. LeMaistre) JOHN A. URQUHART* Director (John A. Urquhart) JOHN WAKEHAM* Director (John Wakeham) CHARLS E. WALKER* Director (Charls E. Walker) HERBERT S. WINOKUR, JR.* Director (Herbert S. Winokur, Jr.) *By: PEGGY B. MENCHACA (Peggy B. Menchaca) (Attorney-in-fact for persons indicated)
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EXHIBIT INDEX Exhibit Number Description *3.01 - Restated Certificate of Incorporation of Enron Corp., as amended (Exhibit 3.01 to Enron Form 10-K for 1994, File No. 1-3423). 3.02 - Bylaws of Enron Corp. as currently in effect. *4.01 - Indenture dated as of November 1, 1985, between Enron and Harris Trust and Savings Bank, as supplemented and amended by the First Supplemental Indenture dated as of December 1, 1995 (Form T-3 Application for Qualification of Indentures under the Trust Indenture Act of 1939, File No. 22-14390, filed October 24, 1985; Exhibit 4(b) to Form S-3 Registration Statement No. 3364057 filed on November 8, 1995). There have not been filed as exhibits to this Form 10-K other debt instruments defining the rights of holders of long-term debt of Enron, none of which relates to authorized indebtedness that exceeds 10% of the consolidated assets of Enron and its subsidiaries. Enron hereby agrees to furnish a copy of any such instrument to the Commission upon request. *4.02 - Form of Amended and Restated Agreement of Limited Partnership of Enron Capital Resources, L.P. (Exhibit 3.1 to Enron Form 8-K dated August 2, 1994). *4.03 - Form of Payment and Guarantee Agreement dated as of August 3, 1994, executed by Enron Corp. for the benefit of the holders of Enron Capital Resources, L.P. 9% Cumulative Preferred Securities, Series A (Exhibit 4.1 to Enron Form 8-K dated August 2, 1994). *4.04 - Form of Loan Agreement, dated as of August 3, 1994, between Enron Corp. and Enron Capital Resources, L.P. (Exhibit 4.2 to Enron Form 8-K dated August 2, 1994). *4.05 - Articles of Association of Enron Capital LLC (Exhibit 9 to Enron Corp. Form 8-K dated November 12, 1993). *4.06 - Form of Payment and Guarantee Agreement of Enron Corp., dated as of November 15, 1993, in favor of the holders of Enron Capital LLC 8% Cumulative Guaranteed Monthly Income Preferred Shares (Exhibit 2 to Enron Form 8-K dated November 12, 1993). *4.07 - Form of Loan Agreement, dated as of November 15, 1993, between Enron Corp. and Enron Capital LLC (Exhibit 3 to Enron Form 8-K dated November 12, 1993). Executive Compensation Plans and Arrangements Filed as Exhibits Pursuant to Item 14(c) of Form 10-K: Exhibits 10.01 through 10.49 *10.01 - Enron Executive Supplemental Survivor Benefits Plan, effective January 1, 1987 (Exhibit 10.01 to Enron Form 10-K for 1992, File No. 1-3423). 10.02 - First Amendment to Enron Executive Supplemental Survivor Benefits Plan. *10.03 - Enron Corp. 1988 Stock Plan (Exhibit 4.3 to Registration Statement No. 33-27893). *10.04 - Executive Incentive Plan (Exhibit 10.13 to Enron Form 10-K for 1987, File No. 1-3423). *10.05 - Enron Corp. 1988 Deferral Plan (Exhibit 10.19 to Enron Form 10-K for 1987, File No. 1-3423). 10.06 - First Amendment to Enron Corp. 1988 Deferral Plan. 10.07 - Second Amendment to Enron Corp. 1988 Deferral Plan. *10.08 - Enron Corp. 1991 Stock Plan (Exhibit 10.08 to Enron Form 10-K for 1991, File No. 1-3423). *10.09 - Enron Corp. 1992 Deferral Plan (Exhibit 10.09 to Enron Form 10-K for 1991, File No. 1-3423). 10.10 - First Amendment to Enron Corp. 1992 Deferral Plan. 10.11 - Second Amendment to Enron Corp. 1992 Deferral Plan. *10.12 - Enron Corp. Directors' Deferred Income Plan (Exhibit 10.09 to Enron Form 10-K for 1992, File No. 1-3423). *10.13 - Employment Agreement between Enron and Kenneth L. Lay dated as of September 1, 1989 (Exhibit 10.12 to Enron Form 10-K for 1989, File No. 1-3423). *10.14 - First Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 21, 1990 (Exhibit 10.11 to Enron Form 10-K for 1993). *10.15 - Second Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated March 5, 1992 (Exhibit 10.12 to Enron Form 10-K for 1993). *10.16 - Third Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated August 10, 1993 (Exhibit 10.13 to Enron Form 10-K for 1993). *10.17 - Fourth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated October 15, 1993 (Exhibit 10.14 to Enron Form 10-K for 1993). *10.18 - Fifth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated February 28, 1994 (Exhibit 10.15 to Enron Form 10-K for 1993). *10.19 - Sixth Amendment to Employment Agreement between Enron and Kenneth L. Lay, dated April 27, 1994 (Exhibit 10.16 to Enron Form 10-K for 1994). *10.20 - Split Dollar Life Insurance Agreement between Enron and the KLL and LPL Family Partnership, Ltd., dated April 22, 1994 (Exhibit 10.17 to Enron Form 10-K for 1994). *10.21 - Employment Agreement between Enron and Richard D. Kinder dated as of September 1, 1989 (Exhibit 10.14 to Enron Form 10-K for 1989, File No. 1-3423). *10.22 - First Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 13, 1990 (Exhibit 10.17 to Enron Form 10-K for 1991, File No. 1-3423). *10.23 - Second Amendment to Employment Agreement between Enron and Richard D. Kinder dated September 10, 1991 (Exhibit 10.18 to Enron Form 10-K for 1991, File No. 1-3423). *10.24 - Third Amendment to Employment Agreement between Enron and Richard D. Kinder dated March 5, 1992 (Exhibit 10.19 to Enron Form 10-K for 1992, File No. 1-3423). *10.25 - Fourth Amendment to Employment Agreement between Enron and Richard D. Kinder dated August 16, 1993 (Exhibit 10.20 to Enron Form 10-K for 1993). *10.26 - Fifth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated October 15, 1993 (Exhibit 10.21 to Enron Form 10-K for 1993). *10.27 - Sixth Amendment to Employment Agreement between Enron and Richard D. Kinder, dated February 28, 1994 (Exhibit 10.22 to Enron Form 10-K for 1993). *10.28 - Seventh Amendment to Employment Agreement between Enron and Richard D. Kinder, dated November 30, 1994 (Exhibit 10.25 to Enron Form 10-K for 1994). *10.29 - Employment Agreement between Enron International Inc. and Rodney L. Gray, dated as of July 1, 1993 (Exhibit 10.23 to Enron Form 10-K for 1993). *10.30 - First Amendment to Employment Agreement between Enron International Inc. and Rodney L. Gray, dated May 2, 1994 (Exhibit 10.27 to Enron Form 10-K for 1994). 10.31 - Second Amendment to Employment Agreement between Enron International Inc. and Rodney L. Gray, dated as of January 1, 1995. *10.32 - Consulting Services Agreement between Enron and John A. Urquhart dated August 1, 1991 (Exhibit 10.23 to Enron Form 10-K for 1991, File No. 1-3423). *10.33 - First Amendment to Consulting Services Agreement between Enron and John A. Urquhart, dated August 27, 1992 (Exhibit 10.25 to Enron Form 10-K for 1992, File No. 1-3423). *10.34 - Second and Third Amendments to Consulting Services Agreement between Enron and John A. Urquhart, dated November 24, 1992 and February 26, 1993, respectively (Exhibit 10.26 to Enron Form 10-K for 1992, File No. 13423). 10.35 - Fourth Amendment to Consulting Services Agreement between Enron and John A. Urquhart dated as of May 9, 1994. 10.36 - Fifth Amendment to Consulting Services Agreement between Enron and John A. Urquhart. 10.37 - Sixth Amendment to Consulting Services Agreement between Enron and John A. Urquhart. *10.38 - Employment Agreement between Enron and Edmund P. Segner, III dated October 1, 1991 (Exhibit 10.24 to Enron Form 10-K for 1991, File No. 1-3423). *10.39 - First Amendment to Employment Agreement between Enron and Edmund P. Segner, III dated February 12, 1993 (Exhibit 10.28 to Enron Form 10-K for 1992, File No. 13423). *10.40 - Second Amendment to Employment Agreement between Enron and Edmund P. Segner, III, dated May 2, 1994 (Exhibit 10.39 to Enron Form 10-K for 1994). *10.41 - Employment Agreement between Enron and James V. Derrick, Jr., dated June 11, 1991 (Exhibit 10.40 to Enron Form 10-K for 1992, File No. 1-3423). *10.42 - First Amendment to Employment Agreement between Enron and James V. Derrick, Jr., dated May 2, 1994 (Exhibit 10.53 to Enron Form 10-K for 1994). *10.43 - Enron Corp. Performance Unit Plan (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994). *10.44 - Enron Corp. Annual Incentive Plan (Exhibit B to Enron Proxy Statement filed pursuant to Section 14(a) on March 25, 1994). *10.45 - Enron Corp. Performance Unit Plan (as amended and restated effective May 2, 1995) (Exhibit A to Enron Proxy Statement filed pursuant to Section 14(a) on March 27, 1995). 10.46 - First Amendment to Enron Corp. Performance Unit Plan. *10.47 - Form of Enron Corp. 1994 Deferral Plan (Exhibit 10.59 to Enron Form 10-K for 1994). 10.48 - First Amendment to Enron Corp. 1994 Deferral Plan. 10.49 - Second Amendment to Enron Corp. 1994 Deferral Plan. 11 - Statement re calculation of earnings per share. 12 - Statement re computation of ratios of earnings to fixed charges. 21 - Subsidiaries of registrant. 23.01 - Consent of Arthur Andersen LLP. 23.02 - Consent of DeGolyer and MacNaughton. 23.03 - Letter Report of DeGolyer and MacNaughton dated January 22, 1996. 24 - Powers of Attorney for the officers and directors signing this Form 10-K. 27 - Financial Data Schedule. * Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith. (b) Reports on Form 8-K No reports on Form 8-K were filed by Enron during the last quarter of1995.

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11/30/9820
9/30/98820
2/8/9820
9/30/97820
1/1/973
11/1/963
10/1/96820
5/7/96112DEF 14A
5/1/968
3/31/962010-Q
Filed on:3/29/96
3/1/961
2/16/961421
2/7/968
1/31/9612U-57
1/22/961223
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For Period End:12/31/9512011-K,  8-K
12/29/9520
12/1/951223
11/29/953
11/28/958
11/8/951223S-3
10/16/958
10/13/953
10/4/953
9/1/95320
8/8/95820
8/3/95820
7/27/953
5/2/951223DEF 14A
3/27/951223DEF 14A
3/1/95320
1/1/951223
12/31/9462210-K,  11-K
12/30/9420
11/30/941223
11/23/948
10/7/948
9/23/948
9/16/948
8/3/9412238-K
8/2/9412238-K
5/9/941223
5/2/941223
4/27/941223
4/22/941223
4/6/948
3/25/941223DEF 14A
2/28/941223
12/31/9332210-K,  11-K,  8-K
12/8/9338
11/15/931223
11/12/931223
10/15/931223
8/16/931223
8/10/931223
7/1/931223
3/27/9320
2/26/931223
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