ITEM 1. BUSINESS
Sonat Inc. ("Sonat") is a diversified energy holding company. It is engaged through Sonat Exploration Company ("Exploration") in domestic oil and natural gas exploration and production; through Southern Natural Gas Company ("Southern") and Citrus Corp. ("Citrus") in the transmission, storage, and sale of natural gas; through Sonat Energy Services Company ("Energy Services") in natural gas marketing, intrastate transportation, and other nonregulated natural gas ventures; and through its investment in Sonat Offshore Drilling Inc. ("Offshore") in contract drilling.
Exploration, which is one of the largest independent natural gas producers in the United States, operates primarily in Texas, Oklahoma, Louisiana, Arkansas, and the Gulf of Mexico. Oil and gas exploration and production activities contributed approximately 11 percent of Sonat's consolidated revenues and approximately 37 percent of Sonat's consolidated operating profit for 1993.
Southern, which has been in the interstate natural gas pipeline business since the early 1930s, is a major transporter of natural gas to the southeastern United States. Its natural gas transmission system extends primarily from gas producing areas of Texas and Louisiana, both onshore and offshore, to markets in a seven-state area of the Southeast. Sonat and Enron Corp. each owns a one-half interest in Citrus, a holding company that owns 100 percent of Florida Gas Transmission Company ("Florida Gas"). Florida Gas is an interstate natural gas pipeline that serves electric generation, resale, and industrial markets in Florida. Energy Services was formed in late 1989 to coordinate the activities of Sonat's subsidiary companies engaged in marketing natural gas, intrastate transportation, and other activities that are not regulated by the U.S. Federal Energy Regulatory Commission (the "FERC"). Its largest subsidiary, Sonat Marketing Company ("Marketing"), sells natural gas throughout much of the United States. In 1993 Marketing assumed responsibility for the sale of almost all of Exploration's production. Natural gas operations, excluding Citrus, contributed approximately 83 percent of Sonat's consolidated revenues and approximately 61 percent of Sonat's consolidated operating profit for 1993. Sonat's share of Citrus' earnings are reflected in Equity in Earnings of Unconsolidated Affiliates.
As a result of the initial public offering of Offshore's common stock, which was completed on June 4, 1993, Sonat currently retains ownership of 39.9 percent of Offshore's outstanding shares. Offshore, which was formed in the early 1950s and had formerly been a wholly owned subsidiary of Sonat, was one of the world's first marine drilling contractors and is recognized as a world leader in offshore drilling technology. It is engaged in exploration and development contract drilling for major international, government-controlled, and independent oil companies in offshore areas throughout the world. Contract drilling activities for the period prior to the public offering contributed approximately six percent of Sonat's consolidated revenues and approximately one percent of Sonat's consolidated operating profit for 1993. Beginning on June 5, 1993, Offshore has been accounted for on the equity method and Sonat's share of Offshore's earnings during that part of 1993 are reflected in Equity in Earnings of Unconsolidated Affiliates.
Sonat was incorporated under the laws of Delaware in 1973 in connection with a restructuring of Southern. At January 1, 1994, Sonat and its subsidiaries employed approximately 2,230 persons.
Sonat's principal executive offices are located at 1900 Fifth Avenue North, AmSouth-Sonat Tower, Birmingham, Alabama 35203, and its telephone number is (205) 325-3800.
Additional business information is contained in Management's Discussion and Analysis of Financial Condition and Results of Operations and in the Notes to Consolidated Financial Statements in Part II of this report, which are hereby incorporated herein by reference. Reference is made to Note 12 of the Notes to Consolidated Financial Statements contained in Part II of this report for further information with respect to the portions of Sonat's revenues, operating profit, and identifiable assets attributable to each of its business segments and geographic areas of operations.
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EXPLORATION AND PRODUCTION
Sonat is engaged in the exploration for and the acquisition, development, and production of oil and natural gas through its wholly owned subsidiary, Sonat Exploration Company, and its subsidiary companies (collectively referred to as "Exploration" unless the context indicates otherwise). Exploration's principal office is located in Houston, Texas. Exploration has regional offices in Tyler, Texas, Oklahoma City, Oklahoma, and Houston, Texas.
The oil and gas properties of Exploration are principally located onshore in the Southern coastal states, in various states in the Southwest and Midwest, and in federal waters offshore Louisiana and Texas. As of December 31, 1993, Exploration had operations or properties in 14 states. Exploration had working interests in approximately 2.4 million gross acres or 1.4 million net acres onshore as of December 31, 1993. Of this onshore acreage, approximately 1.2 million gross or 633,165 net acres were producing oil or gas. In addition, as of such date, Exploration had a working interest in 74 federal offshore blocks in the Gulf of Mexico and one state offshore block, totaling 330,311 gross acres or 155,200 net acres. Of these blocks, 60 were producing oil or gas.
Exploration has a 50-percent interest in a coal seam degasification project near Brookwood, Alabama. Most of the gas from this project is sold to Southern under a long-term contract. The other 50-percent interest in the Brookwood project is owned by Jim Walter Resources, Inc.
Beginning in 1988 Exploration implemented a strategy to acquire gas properties with significant development potential. As a result of this strategy, Exploration has more than quintupled its proved reserves since that time. At the end of 1993 Exploration had total proved reserves of approximately 1.35 trillion cubic feet of natural gas equivalent. Approximately 88 percent of Exploration's proved reserves are natural gas.
In 1993 Exploration continued its strategy of acquiring producing oil and gas properties with potential for additional reserves and production development. Exploration's acquisition activity is being directed generally toward areas in which Exploration currently operates, although it may make investments in other domestic basins.
During 1993 Exploration acquired approximately 313 billion cubic feet ("Bcf") of proved natural gas equivalent reserves in 21 separate transactions totaling $266 million, for an average acquisition cost of $.85 per thousand cubic feet equivalent. The largest single acquisition was from Mobil Exploration and Producing U.S., Inc. in September 1993 of several offshore Gulf of Mexico gas producing lease blocks for which Exploration paid approximately $126 million for 106 Bcf of proved natural gas equivalent reserves.
Other significant 1993 acquisitions included a January 1993 purchase of all of Grace Petroleum Corporation's oil and gas assets in East Texas and North Louisiana for approximately $38 million, which added approximately 60 Bcf of proved natural gas equivalent reserves and 171 wells. Exploration also acquired the limited partnership interest of Prudential Insurance Company of America in the Sonat/P Anadarko Limited Partnership ("Sonat/P") for $11.5 million cash and the assumption of $4.1 million of debt pertaining to Prudential's interest in the partnership. This acquisition added approximately 14 Bcf of proved natural gas equivalent reserves. After closing, the partnership was dissolved. Sonat/P, which was created in 1992, owned oil and gas properties acquired in that year from Louisiana Land and Exploration Company in the Anadarko Basin in Oklahoma. Exploration significantly increased its presence in south Texas with the acquisition of leasehold interests from Tri-C Resources, Inc. for approximately $66 million. These properties added about 94 Bcf proved natural gas equivalent reserves to Exploration's reserve base and greatly enhanced Exploration's drilling operations in that area. The remaining 1993 acquisitions of Exploration totalled approximately $20 million, with proved reserves of approximately 39 Bcf of natural gas equivalent. Many of these interests were within fields and wells already operated by Exploration.
From January 1, 1994, through February 28, 1994, Exploration acquired additional oil and gas interests and properties for a total of approximately $1.4 million, with proved reserves of approximately 2.2 Bcf of natural gas equivalent.
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In 1993 Exploration continued its aggressive drilling program, participating in the drilling of 301 development wells, of which approximately 88 percent were successful. In addition to the large development drilling program, Exploration is continuing to develop its substantial acreage position in the eastern extension of the Austin Chalk trend in Texas and Louisiana. Exploration participated in the drilling of 15 horizontal wells in this trend during 1993, all of which were successful.
Exploration's natural gas production from 344 tight-sand and coal-seam formation wells generated $19 million of Section 29 tax credits for Sonat in 1993, a $5 million increase from 1992. Production from wells that qualify for these credits will begin to decline in 1994 as these wells follow their normal decline pattern.
As of December 31, 1993, Exploration's net proved reserves totaled 27 million barrels of crude oil, condensate, and natural gas liquids and 1,187 Bcf of natural gas. As of December 31, 1992, Exploration's net proved reserves amounted to 20 million barrels of crude oil, condensate, and natural gas liquids and 1,028 Bcf of natural gas. For additional information concerning reserves, see Note 13 of the Notes to Consolidated Financial Statements in Part II of this report.
Exploration's total exploration and production capital expenditures in 1993 were $441 million (including its share of Sonat/P's capital expenditures) compared with $194 million in 1992. Exploration will continue to emphasize producing property acquisitions and development drilling in 1994, when capital spending is expected to be approximately $390 million, including participation in a 328-well development program. While maintaining an active program, Exploration has also continued its cost control and productivity improvement efforts.
There have been no oil or gas reserve estimates filed or included in any reports to any federal agency within the last twelve months, except Form EIA-23 Annual Survey of Domestic Oil and Gas Reserves filed with the FERC and Form 9-1866 (Request for Reservoir Maximum Efficient Rate) filed with the Minerals Management Service of the U.S. Department of the Interior. There are no material differences in the reserves reflected in such reports and the estimated reserves as reflected in Note 13 of the Notes to Consolidated Financial Statements in Part II of this report, except for differences resulting from actual production, acquisitions, property sales, and necessary reserve revisions and additions to reflect actual experience.
Exploration relies on its own technical staff for the selection of its drilling prospects. Leases on desirable, nonproducing offshore prospects are typically acquired in federal and state waters through a competitive bidding process from the federal or state governments. Exploration has, and may in the future, bid for leases on prospective offshore acreage with other companies from time to time. Onshore leases are acquired by Exploration's staff and by independent lease brokers at the direction of Exploration's staff, through farmouts, through participation in prospects developed by others, or by acquisition. Exploration may, as it has in the past, enter into joint venture arrangements where exploration and development activity is performed on behalf of the joint venture by whichever company is designated as operator. Exploration participated in the drilling of a total of 305 wells in 1993 (including four exploratory wells, all of which were successful), of which it operated 177. Drilling for Exploration is conducted by independent drilling contractors.
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The following tables detail the gross lease acreage of both producing and non-producing onshore properties and offshore lease blocks in which Exploration had an interest at December 31, 1993. The following map generally depicts the areas in which Exploration had significant lease interests as of that date.
SONAT EXPLORATION COMPANY
ONSHORE GROSS LEASE ACREAGE
OFFSHORE GROSS LEASE BLOCKS
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(1) Exploration has a 12.5 percent interest below 9,500 feet in West Cameron 290, which is one of the 15 producing blocks. (2) Exploration only has an overriding interest in one of the producing blocks, Eugene Island 10. (3) Exploration is not a lessee of one of the four producing blocks (Mississippi Canyon 150), but this block has been unitized with the three producing lease blocks in the area in which Exploration has working interests.
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SONAT EXPLORATION COMPANY MAP
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In order to focus its exploration and production efforts and to minimize administrative and other costs, Exploration disposed of certain minor, non-strategic oil and gas interests in 1993 in the states of Louisiana, Texas, Oklahoma, and Arkansas. These properties were sold for a total of approximately $20 million and included approximately 61,517 net developed acres of oil and gas leases with interests in approximately 355 gross productive wells. The decrease in Exploration's net proved reserves of approximately 22 Bcf natural gas equivalent resulting from the sale of all of these properties was more than offset by the reserves acquired in 1993. Exploration expects that it will continue to dispose of non-strategic oil and gas interests in the future.
Consolidated Net Production
Exploration had interests in production from 3,423 producing wells onshore and 173 producing wells offshore as of December 31, 1993. Reference is made to the table in Management's Discussion and Analysis of Financial Condition and Results of Operations in Part II of this report showing the consolidated net production (sales volumes) of oil and condensate, natural gas liquids, and natural gas for 1991 to 1993 and the average sales prices for those years (including transfers). The average production (lifting) costs per unit of oil and gas for each of those years was $.38 in 1993, $.38 in 1992, and $.45 in 1991. The average production cost is calculated by converting all units of production to equivalent Mcf of gas using the relative energy content method.
Exploration sells its crude oil production generally at posted prices, subject to adjustments for gravity and transportation. Exploration sells its natural gas primarily to Marketing at spot-market prices. Exploration also sells some of its gas under long-term contracts directly to pipelines, distribution companies, and end-users. Exploration sells natural gas liquids at market prices under monthly or long-term contracts.
During 1993 Marketing assumed responsibility for the marketing of almost all of Exploration's natural gas, natural gas liquids, and oil production. Marketing purchases most of Exploration's natural gas production directly and markets, pursuant to an agency agreement, almost all of the rest of Exploration's natural gas production as well as its natural gas liquids and crude oil production. Marketing hedges a portion of Exploration's production on behalf of Exploration through the use of oil and gas futures transactions and price swaps in order to decrease the volatility of the revenues received from the sale of oil and natural gas.
Consolidated Wells and Acreage
The following table sets forth information concerning Exploration's consolidated working interests in oil and gas properties as of December 31, 1993.
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(1) One of these wells is a multiple completion. (2) 225 of these wells are multiple completions.
Consolidated Exploratory and Development Wells
The following table sets forth certain consolidated information regarding exploratory and development wells drilled during the years 1991 through 1993.
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For information concerning Exploration's (i) capitalized costs of oil and gas producing activities, (ii) costs incurred in oil and gas producing activities, (iii) net revenues from oil and gas production, (iv) estimated proved oil and gas reserves, (v) estimated future oil and gas net revenues, and (vi) present value of estimated future net revenues from estimated production of proved oil and gas reserves, see Note 13 of the Notes to Consolidated Financial Statements in Part II of this report. The standardized measures of discounted future net cash flows relating to Exploration's oil (including condensate) and gas reserves are calculated as prescribed by Statement of Financial Accounting Standards No. 69. The standardized measures of Exploration's proved oil and gas reserves presented in Part II of this report do not represent Sonat's estimate of their fair market value and are not otherwise representative of the value thereof, but rather, as stipulated and required by the Financial Accounting Standards Board, are intended solely to assist financial statement users in making comparisons between companies.
Competition and Current Business Conditions
The oil and gas business is highly competitive in the search for and acquisition of additional reserves and in the marketing of oil and natural gas. Exploration's competitors include the major and intermediate size oil companies, independent oil and gas concerns, and individual producers or operators.
Supply and demand for natural gas are in close balance for the first time in many years and demand appears to be growing. Near term, however, the recent drop in oil prices could put pressure on the price of natural gas. Natural gas prices averaged $1.99 per thousand cubic feet in 1993 compared with $1.71 in 1992. Oil prices were lower, however: $17.42 per barrel in 1993 versus $18.94 per barrel in 1992. Exploration is unable to predict price levels for oil or natural gas in 1994 or beyond. Exploration believes, however, that over the long term the improvement in the balance between natural gas supply and demand should positively impact natural gas prices.
Since 1986 Exploration has marketed gas released from contracts with pipelines and new uncommitted gas production on the spot market. With the exception of gas from the Brookwood coal seam degasification project, most of Exploration's natural gas volumes in 1993 were sold at spot-market prices. Exploration agreed to a contract amendment with Southern during 1993 pursuant to which, in return for a payment from Southern of approximately $34 million, beginning January 1, 1994, all of Exploration's gas from the Brookwood coal seam degasification project is now sold at spot-market prices as well. Sales of natural gas by Exploration to affiliates accounted for approximately 44 percent of Exploration's revenues in 1993 and 23 percent in 1992.
Exploration's business is subject to all of the operating risks normally associated with the exploration for and production of oil and gas, including blowouts, cratering, pollution, and fires, each of which could result in damage to or destruction of oil and gas wells, formations, production facilities, or properties or in personal injury. Sonat maintains broad insurance coverage on behalf of Exploration limiting financial loss resulting from these operating hazards.
See "Governmental Regulation -- Exploration and Production" below for information concerning the effect of various laws and governmental regulations on Exploration's operations.
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TRANSMISSION, SALE AND MARKETING OF NATURAL GAS
SONAT NATURAL GAS GROUP
In March 1991 Sonat formed the Sonat Natural Gas Group to coordinate more efficiently the activities of the various companies comprising its natural gas transmission and marketing segment. Included in the Sonat Natural Gas Group are Southern and its subsidiaries, Energy Services and its subsidiaries, and Sonat's 50-percent interest in Citrus.
Southern Natural Gas Company
The principal business of Southern, which is a wholly owned subsidiary of Sonat, is the transmission of natural gas in interstate commerce. Southern, including its subsidiaries, owns approximately 9,230 miles of interstate pipeline. Its pipeline system has a certificated daily delivery capacity of approximately 2.4 billion cubic feet of natural gas. Southern's pipeline system extends from gas fields in Texas, Louisiana, Mississippi, Alabama, and the Gulf of Mexico to markets in Louisiana, Mississippi, Alabama, Florida, Georgia, South Carolina, and Tennessee. Southern also has pipeline facilities offshore Texas connecting gas supplies to other pipelines that transport such gas to Southern's system. A map of Southern's pipeline system, including pipelines of its subsidiaries, as well as of the pipeline system of Florida Gas, appears on page I-17.
Southern owns and operates Muldon Storage Field ("Muldon"), a large underground natural gas storage field in Mississippi connected to its pipeline system. Based on operating experience, Southern recently sought to have the working storage capacity of Muldon reduced from 52 to 31 billion cubic feet of gas. The FERC approved this reduction for a one-year period ending November 1, 1994, subject to a further review of Muldon's operations during the 1993-94 winter period.
Bear Creek Storage Company ("Bear Creek"), an unincorporated joint venture between wholly owned subsidiaries of Southern and Tenneco Inc., each of which is a 50-percent participant, owns a large underground natural gas storage field located in Louisiana that is operated by Southern and provides storage service to Southern and Tennessee Gas Pipeline Company, a subsidiary of Tenneco Inc. The Bear Creek Storage Field has a total certificated working storage capacity of approximately 65 billion cubic feet of gas, half of which is committed to Southern. At December 31, 1993, Bear Creek's gross facilities cost was approximately $246,923,000 and its participants' equity was $90,907,000. Southern had an investment in Bear Creek, including its equity in undistributed earnings, of $45,453,000 at December 31, 1993.
Under the terms of Order No. 636, discussed below, effective November 1, 1993, Southern commenced providing contract storage services as part of its unbundled and restructured services. Consequently, most of Southern's working storage capacity at Muldon and its half of Bear Creek are now used for such services. As a part of making this new service available, effective November 1, 1993, Southern sold at its cost $123 million of its working storage gas inventory to its new storage customers.
Southern's interstate pipeline business is subject to regulation by the FERC, the U.S. Department of Energy's Economic Regulatory Administration (the "ERA"), and the U.S. Department of Transportation under the terms of the Natural Gas Policy Act of 1978 (the "NGPA"), the Natural Gas Act, and various pipeline safety and environmental laws. See "Governmental Regulation" below for information concerning the regulation of natural gas transmission operations.
Southern's business is subject to the usual operating risks associated with the transmission of natural gas through a pipeline system, which could result in property damage and personal injury. Sonat maintains broad insurance coverage on behalf of Southern limiting financial loss resulting from these operating risks.
Additional information concerning Southern for the year ended December 31, 1993, may be found in Southern's Annual Report on Form 10-K to the Securities and Exchange Commission for such period.
Order No. 636 Restructuring. In 1992 the FERC issued its Order No. 636 (the "Order"). As required by the Order, interstate natural gas pipeline companies, including Southern, South Georgia Natural Gas Company ("South Georgia"), a wholly owned interstate pipeline subsidiary of Southern, and Florida Gas, have made significant changes in the way they operate. The Order required pipelines, among other things, to
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(1) separate (unbundle) their sales, transportation, and storage services; (2) provide a variety of transportation services, including a "no-notice" service pursuant to which the customer is entitled to receive gas from the pipeline to meet fluctuating requirements without having previously scheduled delivery of that gas; (3) adopt a straight-fixed-variable method for rate design (which assigns more costs to the demand component of the rates than do other rate-design methodologies previously utilized by pipelines); and (4) implement a pipeline capacity release program under which firm customers have the ability to "broker" the pipeline capacity for which they have contracted. The Order also authorizes pipelines to offer unbundled sales services at market-based rates and allows for pregranted abandonment of some services.
Interstate pipeline companies, including Southern, are incurring certain costs ("transition costs") as a result of the Order, the principal one being costs related to amendment or termination of existing gas purchase contracts, which are referred to as gas supply realignment ("GSR") costs. The Order provides for the recovery of 100 percent of the GSR costs and other transition costs to the extent the pipeline can prove that they are eligible, that is, incurred as a result of customers' service choices in the implementation of the Order, and were incurred prudently.
In its restructuring settlement discussions, Southern has advised its customers that the amount of GSR costs that it actually incurs will depend on a number of variables, including future natural gas and fuel oil prices, future deliverability under Southern's existing gas purchase contracts, and Southern's ability to renegotiate certain of these contracts. While the level of GSR costs is impossible to predict with certainty because of these numerous variables, based on current spot-market prices, a range of estimates of future oil and gas prices, and recent contract renegotiations, the amount of GSR costs would be approximately $275-$325 million on a present-value basis. This amount includes the payments made to amend or terminate gas purchase contracts described below.
On September 3, 1993, the FERC generally approved a compliance plan for Southern and directed Southern to implement its restructured services pursuant to the Order on November 1, 1993 (the "September 3 order"). Pursuant to Southern's compliance plan, GSR costs that are eligible for recovery include payments to reform or terminate gas purchase contracts. Where Southern can show that it can minimize transition costs by continuing to purchase gas under the contract (i.e., it is more economic to continue to perform), eligible GSR costs would also include the difference between the contract price and the higher of (a) the sales price for gas purchased under the contract or (b) a price established by an objective index of spot-market prices. Recovery of these latter costs is permitted for an initial period of two years.
Southern's compliance plan contains two mechanisms pursuant to which Southern is permitted to recover 100 percent of its GSR costs. The first mechanism is a monthly fixed charge designed to recover 90 percent of the GSR costs from Southern's firm transportation customers. The second mechanism is a volumetric surcharge designed to collect the remaining ten percent of such costs from Southern's interruptible transportation customers. This funding will continue until the GSR costs are fully recovered or funded. The FERC also indicated that Southern could file to recover any GSR costs not recovered through the volumetric surcharge after a period of two years. In addition, Southern's compliance plan provides for the recovery of other transition costs as they are incurred and any remaining transition costs may be recovered through a regular rate filing. Southern's customers have generally opposed the recovery of its GSR costs.
The September 3 order rejected the argument of certain customers that a 1988 take-or-pay recovery settlement bars Southern from recovering GSR costs under gas purchase contracts executed before March 31, 1989, which comprise most of Southern's GSR costs. Those customers subsequently filed motions urging the FERC to reverse its ruling on that issue. On December 16, 1993, the FERC affirmed its September 3 ruling with respect to the 1988 take-or-pay recovery settlement (the "December 16 order"). The December 16 order generally approved Southern's restructuring tariff submitted pursuant to the September 3 order. Various parties have filed motions urging the FERC to modify the December 16 order and have sought judicial review of the September 3 order. Southern and its customers engaged in settlement discussions regarding Southern's restructuring filing prior to the September 3 order, but the parties were unable to reach a settlement. Those discussions are continuing.
During 1993 Southern reached agreements to reduce significantly the price payable under a number of high cost gas purchase contracts in exchange for payments of approximately $114 million. On December 1,
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1993, Southern filed with the FERC to recover such costs and approximately $3 million of prefiling interest (the "December 1 filing"). On December 30, 1993, the FERC accepted such filing to become effective January 1, 1994, subject to refund, and subject to a determination through a hearing before an administrative law judge that such costs were prudently incurred and eligible under Order No. 636. Southern's customers are opposing its recovery of these GSR costs in this proceeding. The December 30 order rejected arguments of various parties that a pipeline's payments to affiliates, in this case Southern's payment to a subsidiary of Exploration that represented approximately $34 million of the December 1 filing, may not be recovered under Order No. 636.
In December 1993 Southern reached agreement to reduce the price under another contract in exchange for payments having a present value of approximately $52 million. Payments will be made in equal monthly installments over an eight-year period ending December 31, 2001. On February 14, 1994, Southern made a rate filing to recover, beginning March 1, 1994, those costs as well as approximately $2 million of other settlement costs and $800,000 of prefiling interest. Southern also incurred approximately $17.5 million of GSR costs, plus prefiling interest, from November 1, 1993, through January 31, 1994, from continuing to purchase gas under contracts that are in excess of current market prices. On March 1, 1994, Southern made a rate filing to recover those costs beginning April 1, 1994. Southern plans to make additional rate filings quarterly to recover these "price differential" costs and any other GSR costs.
Southern is unable to predict all of the elements of the ultimate outcome of its Order No. 636 restructuring proceeding, its settlement discussions with its customers regarding all of the pending issues arising in connection with the proceeding, or its rate filings to recover its transition costs.
In requiring that Southern provide unbundled storage service, the Order resulted in a substantial reduction of Southern's working storage gas inventory and consequently a reduction in its rate base. This reduction was effective on November 1, 1993, when Southern restructured pursuant to the Order and sold at its cost $123 million of its working storage gas inventory to its customers. The Order also resulted in rates that are less seasonal, thereby shifting revenues and earnings for Southern out of the winter months.
Markets -- Transportation and Sales. As described above, effective November 1, 1993, Southern and South Georgia (collectively "Southern" unless the context indicates otherwise), restructured their services in compliance with FERC Order No. 636 by separating their transportation, storage, and merchant services. With the exception of some limited sales necessary to dispose of its gas supply remaining under contract, Southern essentially became solely a transporter of natural gas. Effective May 5, 1992, South Georgia had converted all its sales service to transportation-only service and Southern had begun to provide a gas sales service to South Georgia's former sales customers.
Southern transports or sells gas at wholesale for distribution for domestic, commercial, and industrial uses to nine gas distributing companies, to 114 municipalities and gas districts, and to nine connecting interstate pipeline companies. Southern also transported or sold gas directly to 55 industrial end-users in 1993. Southern principally transports gas to resale and industrial customers and to other pipelines, sells some limited volumes of gas at wholesale for distribution, and sells very minimal volumes of gas directly to industrial customers. The principal industries served directly by Southern's pipeline system and indirectly through its resale customers' distribution systems include the chemical, pulp and paper, textile, primary metals, stone, clay and glass industries.
Transportation volumes in 1993 were 763 Bcf or 91 percent of Southern's total throughput of 836 Bcf, compared with 733 Bcf or 87 percent of Southern's total 1992 throughput of 842 Bcf. Sales to resale distribution customers, including municipalities and gas districts, accounted for virtually all of 1993 sales of 73 Bcf (excluding the sale of storage inventory) and 1992 sales of 109 Bcf. Southern's sales to direct sales customers and interstate pipeline companies in both years were negligible. Southern had sales of 19 Bcf during November and December 1993 (following implementation of its Order No. 636 restructuring) that were made at receipt points where the gas entered its pipeline system; consequently, those volumes are included within the 763 Bcf of transportation volumes for 1993.
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Transportation service is rendered by Southern for its resale customers, direct industrial customers and other end-users, gas producers, other gas pipelines, and gas marketing and trading companies. Southern provides transportation service in both its gas supply and market areas. Transportation service is provided under rate schedules that are subject to FERC regulatory authority. Rates for transportation service depend on whether such service is on a firm or interruptible basis and the location of such service on Southern's pipeline system. Transportation rates for interruptible service (i.e., service of a lower priority than firm transportation) are charged for actual volumes transported. Firm transportation service also includes a demand charge designed so that the customer pays for a significant portion of the service each month based on a contract demand volume regardless of the actual volume transported. Rates for transportation service are discounted by Southern in individual instances to respond to competition in the markets it serves. Continued discounting could, under certain circumstances, increase the risk that Southern may not recover all of its costs allocated to transportation services.
Sales by Southern are anticipated to continue only until Southern's remaining supply contracts expire, are terminated, or are assigned. As a result of Order No. 636 Southern is attempting to terminate its remaining gas purchase contracts through which it had traditionally obtained its long-term gas supply. Some of these contracts contain clauses requiring Southern either to purchase minimum volumes of gas under the contract or to pay for it ("take-or-pay" clauses). Although Southern currently is incurring essentially no take-or-pay liabilities under these contracts, the annual weighted average cost of gas under these contracts is in excess of current spot-market prices. Pending the termination of these remaining supply contracts, Southern has agreed to sell a portion of its remaining gas supply to a number of its firm transportation customers for a one-year term that began November 1, 1993. Recently, the sales agreements with Atlanta Gas Light Company and its subsidiary, Chattanooga Gas Company (collectively "Atlanta") were extended through March 31, 1995. The rest of Southern's remaining supply will be sold on a month-to-month basis. Southern will file to recover as a GSR cost pursuant to Order No. 636 the difference between the cost associated with the gas supply contracts and the revenue from the sale agreements and month-to-month sales and also any cost incurred to reduce the price under or to terminate Southern's remaining gas supply contracts.
When long-term sales service agreements with substantially all of Southern's resale customers expired or were terminated in 1989, Southern entered into a series of short-term agreements on an annual basis with virtually all of such customers. Prior to the implementation of Order No. 636, several customers had already reduced their firm sales contract demand volumes or converted a portion of their firm sales volumes to firm transportation volumes. From 1988 until Southern's implementation of Order No. 636, total daily delivery obligations under firm sales contracts (the "contract demand" upon which monthly demand charges are based) were reduced by approximately 689 million cubic feet ("MMcf") from their level at the end of 1987 of approximately 2.1 Bcf. Prior to Southern's implementation of Order No. 636, approximately 74 percent of this reduction had been replaced with firm transportation volumes under contracts of varying terms and durations, which also provided for fixed monthly charges.
In accordance with the September 3 order approving Southern's Order No. 636 compliance plan, Southern solicited service elections from its customers in order to implement its restructured services on November 1, 1993. Southern's largest customer, Atlanta, bid for firm transportation service on Southern at prices significantly below Southern's filed tariff rates. Southern rejected Atlanta's bids. Southern and Atlanta subsequently entered into an interim agreement under which Atlanta signed firm transportation service agreements with transportation demands of 582 million cubic feet per day for a minimum term of four months beginning November 1, 1993, and 118 million cubic feet per day for a term extending until April 30, 2007, at the maximum FERC-approved rates. This represented an aggregate reduction of 100 million cubic feet per day from Atlanta's level of service prior to November 1, 1993. In January 1994 Atlanta provided notice that it had elected to continue that level of firm service until October 31, 1994. Southern's other customers elected in aggregate to obtain an amount of firm transportation services that represented a slight increase from their level of firm sales and transportation services from Southern prior to Southern's implementation of Order No. 636, at the maximum FERC-approved tariff rates, for terms ranging from one to ten or more years.
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Although management believes that most of Southern's former resale customers ultimately will commit to some type of new long-term firm transportation agreements with Southern under its restructuring program, it is unable to predict at what total volume level or for what duration such commitments will be made.
Transportation and sales by Southern, combined with sales by Marketing, to two unaffiliated distribution customers, Atlanta and Alabama Gas Corporation, accounted for approximately 21 percent and 12 percent, respectively, of Sonat's 1993 consolidated revenues. Atlanta and Alabama Gas Corporation were the only two customers that accounted for ten percent or more of Sonat's consolidated revenues for 1993.
Southern is continuing to pursue growth opportunities to expand the level of services in its traditional market area and to connect new gas supplies. On May 13, 1993, Southern and South Georgia received approval from the FERC for a $27 million expansion of South Georgia's pipeline system into northern Florida and southwestern Georgia that will increase firm daily capacity by 40 million cubic feet per day. Construction on this project is under way and should be completed in mid-1994. In January 1994 Southern reached tentative agreement with a group of new customers to expand its service in the growing eastern Tennessee area. The proposed project entails a 20-mile pipeline extension that would deliver approximately nine million cubic feet of natural gas per day to a delivery point near Chattanooga.
For additional information regarding Southern's transportation and sales of gas, see Management's Discussion and Analysis of Financial Condition and Results of Operations contained in Part II of this report.
Gas Supplies. During 1993 Southern purchased its gas supply from the following areas: 51 percent from southern Louisiana and from the Gulf of Mexico, offshore Louisiana, and Texas; three percent from northern Louisiana and Texas; and 46 percent from Mississippi and Alabama. Southern has approximately 60 gas purchase contracts remaining with gas producers that commit proved recoverable reserves to Southern. As described above, pursuant to Order No. 636, Southern is attempting to terminate its remaining gas purchase contracts.
The following table contains information as to Southern's gas supply and the general sources from which that supply was obtained during the years 1991 through 1993.
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* As used in this report, the term "Mcf" means thousand cubic feet; the term "MMcf" means million cubic feet; and the term "Bcf" means billion cubic feet. All volumes of natural gas referred to in this report are stated at a pressure base of 14.73 pounds per square inch absolute ("psia") and at 60 degrees Fahrenheit.
Southern entered into no new long-term gas purchase agreements in 1993, due to the cessation of its merchant role because of Order No. 636 as discussed above. Since Order No. 636 prohibits Southern from providing its traditional bundled merchant service, Southern does not anticipate at this time that it will need to contract for the long-term purchase of any additional natural gas supplies in the future. Southern will purchase minimal volumes of gas from time to time as may be required for system management purposes. Southern does expect, however, that adequate gas supplies will need to continue to be available to its system; consequently, Southern has continued its efforts to have new gas supplies attached to its system.
Potential Royalty Claims. In connection with its settlements of take-or-pay claims made by producers over the past few years, Southern has in certain limited instances indemnified, to varying degrees, the producer from certain potential claims made by royalty owners. Southern has thus far been notified of 12 potential royalty claims under the indemnity provisions of various settlement agreements. The claims for which Southern may have to indemnify these producers have been asserted by both private lessors with respect to onshore leases and the Minerals Management Service Division of the U.S. Department of the Interior (the
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"MMS") with respect to offshore and Indian leases. Southern settled four of these claims during 1993 for approximately $1.2 million.
In addition to the claims for which Southern has been put on notice, it is possible that other producers may make future claims against Southern for royalty indemnification. The June 26, 1992 decision of the Louisiana Supreme Court in Frey v. Amoco, in which the court held that royalty was due on take-or-pay payments, may form a basis for royalty claims for a share of take-or-pay settlements by private lessors in Louisiana and in other states that may follow the Frey decision. Because courts typically require that interest be paid on the royalty back to the date of settlement, the amount owed can substantially exceed the royalty amount. Management believes that Southern's maximum exposure under all of its various royalty indemnities in onshore take-or-pay settlements, including interest, approximates $15 million. Management is unable to state whether any additional royalty claims based on Southern's indemnification provisions in its take-or-pay settlements will be asserted or to predict the outcome of any such claims or resulting litigation.
In addition to the potential royalty claims related to onshore production, Southern also faces exposure in connection with indemnifications in take-or-pay settlements with producers who have federal offshore or Indian leases. The MMS issued a policy statement and guidelines on May 3, 1993, declaring its intention to collect royalty payments for contract buy-downs, buy-outs, pricing disputes, and on any portion of take-or-pay settlement payments that are subject to future recoupment. In June 1993 the MMS began to issue letters to producers requiring payment of royalty on all such payments received under take-or-pay settlements, along with interest back to the date of payment. The MMS has been aggressively auditing producers since this time and issuing orders to pay. A lawsuit filed by the Independent Petroleum Association of America against the MMS and others challenging the validity of the MMS' new policy is pending in federal district court for the District of Columbia. Management is unable to predict the outcome of this litigation or the ultimate outcome of any collection efforts by the MMS.
Management believes that Southern's maximum exposure for all royalty claims related to offshore production, including interest, approximates $10 million if no recovery from its customers is allowed. Under the terms of a 1988 take-or-pay recovery settlement with Southern's customers, Southern is entitled to seek recovery of these costs under the FERC's Order No. 500 cost-sharing procedures. The customers, however, are entitled to challenge any effort by Southern to recover those costs. Management is unable to predict the outcome of the efforts of the MMS to collect royalty on a portion of any offshore settlement or of Southern's efforts to recover any amounts it may ultimately pay from its customers.
Southern believes that it is adequately reserved for any royalty claims that it may ultimately have to pay or to settle and that, in any event, such claims will not have a material adverse effect on its financial condition or results of operations.
Southern Energy Company. Southern Energy Company ("Southern Energy"), a wholly owned subsidiary of Southern, owns a liquefied natural gas ("LNG") receiving terminal near Savannah, Georgia, which was constructed for a project, now terminated, to import LNG from Algeria. The terminal has been inactive since the early 1980s. On July 22, 1992, the FERC issued an order approving a settlement relating to Southern Energy's LNG facilities. The settlement resolved a number of outstanding rate and accounting issues on a favorable basis and preserved an option for customers of Southern Energy to obtain LNG through this facility at least through the year 1999.
Sea Robin Pipeline Company. For many years Southern was a 50-percent participant, through a wholly owned subsidiary, with a wholly owned subsidiary of United Gas Pipe Line Company ("United"), in Sea Robin Pipeline Company ("Sea Robin"), an unincorporated gas supply pipeline joint venture. Sea Robin was originally constructed to obtain Gulf of Mexico gas supplies for Southern's and United's respective pipeline systems and was operated by United. In December 1990 Southern, through a newly formed subsidiary, acquired the 50-percent interest in Sea Robin formerly owned by the subsidiary of United. As a result of the acquisition, two wholly owned subsidiaries of Southern own 100 percent of Sea Robin, which is now being operated by Southern. Sea Robin has a 436-mile pipeline system located in the Gulf of Mexico through which it transports gas for others under its FERC-regulated tariffs. Sea Robin is a transportation-only pipeline that has restructured in compliance with FERC Order No. 636. Sea Robin's compliance filing has been accepted
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by the FERC. Sea Robin transported approximately 287 Bcf of natural gas in 1993. These Sea Robin volumes are included within the Southern transportation volumes discussed earlier. See Note 9 of the Notes to Consolidated Financial Statements in Part II of this report for additional information regarding Sea Robin.
Sonat Energy Services Company
Energy Services, which is a wholly owned subsidiary of Sonat, acts as a holding company for several of Sonat's largely non-FERC-regulated companies engaged in natural gas marketing, intrastate transportation, and other nonregulated natural gas ventures. Effective January 1, 1990, Marketing, which had been a wholly owned subsidiary of Sonat, became a wholly owned subsidiary of Energy Services.
Sonat Marketing Company. Marketing, which is headquartered in Birmingham, Alabama, provides natural gas marketing services for industrial and commercial users, gas distribution companies, gas producers, and gas pipelines throughout the Gulf Coast, Southeast, Midwest, and Northeast United States. During 1993 Marketing sold 285 Bcf of natural gas purchased from approximately 250 natural gas producers. Based on its year-end 1993 volumes, Marketing is expected to exceed 400 Bcf in sales during 1994.
Marketing continues to expand its natural gas marketing business. At the end of 1992 Marketing's volumes were approximately 500 million cubic feet per day and were primarily on the Southern system. During 1993 Marketing assumed responsibility for marketing almost all of the natural gas and liquids production of Exploration, including execution of Exploration's risk management program. This has allowed Marketing to expand its presence in Gulf Coast, Midwest, and Northeast markets and, in turn, provide attractive markets to unaffiliated producers. As a result of these efforts, Marketing's volumes exceeded 1.1 billion cubic feet per day at the end of 1993, making it one of the twenty largest natural gas marketers in the country.
Sonat Intrastate-Alabama Inc. Sonat Intrastate-Alabama Inc. ("SIA"), a wholly owned subsidiary of Energy Services, owns a 454-mile intrastate pipeline system extending from natural gas fields and coal seam gas production areas in the Black Warrior Basin in northwest and central Alabama to connections with customers in Alabama, as well as interconnections with three other pipelines, including Southern. SIA's throughput in 1993 was approximately 36 Bcf.
Sonat Ventures Inc. Sonat Ventures Inc. ("Ventures"), a wholly owned subsidiary of Energy Services, was created in January 1992 for the purpose of commercializing alternative uses for natural gas and to engage in various activities related to the purchase and marketing of natural gas. Sonat NGV Technology Inc. ("NGV"), a wholly owned subsidiary of Ventures, was created in July 1992. NGV, along with Georgia Energy Company, a wholly owned subsidiary of Atlanta Gas Light Company, and Natural Gas Vehicles Development Company Southeast, Inc., formed a joint venture in 1992 to convert vehicles to natural gas. The conversion facility near Atlanta, Georgia, opened in February 1993. In addition to the conversion of vehicles, the venture plans to operate an EPA/FTP lab and emissions testing facility, which is currently under construction. During 1993 Ventures also entered into two joint ventures with local distribution companies in Alabama and Florida to construct, own, and operate natural gas vehicle refueling stations as well as finance the conversion of fleet vehicles. The first station in Alabama began operating in March of 1994. Ventures is currently pursuing opportunities to own and operate refueling centers elsewhere in the Southeast.
AES/Sonat Power, L.L.C. In June 1992 Sonat and The AES Corporation announced a 50-50 joint venture, AES/Sonat Power, that will construct, own, and operate natural gas-fueled independent power and cogeneration plants in the United States, Canada, and Mexico. In January 1994 Pacific Gas and Electric Company announced that it would sign a contract with AES Pacific, Inc., an affiliate of AES/Sonat Power, to purchase power from a 221-megawatt power plant to be constructed in San Francisco. Efforts to satisfy all contract-signing prerequisites are under way and, if successful, a subsidiary of The AES Corporation will construct and operate the plant and a subsidiary of Sonat will manage the gas supply and transportation requirements. The plant is scheduled to be completed by mid-1997 and would require an equity investment from Sonat in the range of approximately $15-20 million.
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Citrus Corp.
On June 30, 1986, Sonat acquired one-half of the stock of Citrus, which owns all of the stock of Florida Gas. Citrus also owns 100 percent of three natural gas marketing companies, Citrus Trading Corp., which began selling natural gas to Florida Power & Light Company during 1990 under a 15-year contract for up to 125 Bcf annually, and Citrus Marketing Company and Citrus Industrial Sales Company, Inc., both of which market gas to customers in Florida.
Florida Gas Transmission Company. Florida Gas, like Southern, is an interstate natural gas transmission company. It is operated by a subsidiary of Enron Corp., which through a subsidiary owns the other 50 percent of Citrus. Florida Gas' approximately 4,700-mile pipeline system extends from south Texas to a point near Miami, Florida, with a certificated daily delivery capacity of 925 million cubic feet per day. See the map on page I-17. Florida Gas is the primary pipeline transporter of natural gas in the state of Florida and the sole pipeline transporter to peninsular Florida.
In August 1990 Florida Gas commenced providing open-access gas transportation services under the provisions of FERC Order No. 500 and restructured its sales and transportation services. As a result, Florida Gas' throughput volumes, once primarily sales, became primarily transportation volumes. Effective November 1, 1993, Florida Gas, like Southern, restructured its services in compliance with FERC Order No. 636 and essentially became solely a transporter of natural gas.
Florida Gas has terminated its gas purchase contracts with a weighted average cost in excess of current spot-market prices and has been negotiating with its customers and the FERC to recover settlement payments made to terminate such contracts as a part of its Order No. 636 proceeding. On September 17, 1993, Florida Gas received approval of its restructuring settlement proposal (the "Restructuring Settlement") with regard to Order No. 636. The Restructuring Settlement includes a Transition Cost Recovery ("TCR") mechanism that allows Florida Gas, effective November 1, 1993, to recover from its customers 100 percent of payments above the $106 million level approved in a previous settlement, up to $160 million. Florida Gas will be allowed to recover 75 percent of any amounts greater than $160 million. Florida Gas has substantially completed the renegotiation and termination of these contracts for less than $160 million, however, and therefore expects to recover all of the amounts spent and not already expensed through its approved TCR mechanism.
In 1993 Florida Gas transported approximately 314 Bcf under transportation agreements and had sales of approximately 10 Bcf to resale customers and approximately 5 Bcf to direct sale customers, compared to transportation of approximately 298 Bcf, sales for resale of approximately 28 Bcf, and direct sales of approximately 16 Bcf in 1992. Transportation rates are regulated by the FERC. A large majority of the gas transported in 1993 by Florida Gas was sold by the Citrus marketing companies.
A significant 15-year gas supply contract ending in 2005 that Citrus Trading Corp. has with its principal customer has become unprofitable. This contract may be terminated by Citrus under certain circumstances relating to future prices for natural gas and competing fuel oil. Citrus is seeking to negotiate a restructuring of the pricing under the contract. No assurance can be given, however, that the contract will be terminated or that Citrus will be successful in negotiating a restructuring.
Florida Gas, with approval of the FERC, completed a project in late 1991 known as the Phase II expansion, which increased its system capacity by 100 million cubic feet of gas per day to its current total of 925 million cubic feet per day. Also, in response to continuing growth in demand for natural gas in Florida, primarily in the electric generation market, Florida Gas filed with the FERC in 1991 a proposal that would further increase its system capacity. This expansion, known as Phase III, will increase capacity to existing markets and also offer new service to the Tampa-St. Petersburg area. Florida Gas was granted final certificate authority by the FERC on September 15, 1993, for its Phase III expansion. This expansion will increase system capacity by 530 million cubic feet per day at a capital cost of approximately $900 million. As part of the expansion project, Florida Gas contracted for 100 million cubic feet per day of new firm transportation to be delivered from Southern's system. In connection with the Phase III expansion, Sonat expects to increase its equity investment in Citrus by $150 million by the end of the construction period. Additionally, Florida Gas is
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currently reviewing the prospects for further expansions of its pipeline system into the Florida market that could be in service in 1996 or 1997.
In connection with its Phase III expansion, Florida Gas entered into an agreement to acquire an interest in an existing pipeline in the Mobile Bay area that, pursuant to the agreement, will be expanded by over 300,000 Mcf per day and connected to Florida Gas' pipeline system.
At December 31, 1993, Citrus' gross pipeline and facilities cost was approximately $1,731,456,000. Sonat had an investment in Citrus, including its equity in undistributed earnings, of $103,822,000 at December 31, 1993. For additional information regarding Citrus, see Management's Discussion and Analysis of Financial Condition and Results of Operations contained in Part II of this report, and the Notes to Citrus' Consolidated Financial Statements contained in Part IV of this report.
Competition and Current Business Conditions
The natural gas transmission industry, although regulated, is very competitive. During the period from the mid-1980s until the Order No. 636 restructuring, customers had switched much of their volumes from a bundled merchant service to transportation service, reflecting an increased willingness to rely on gas supply under unregulated arrangements such as those provided by Sonat Marketing and Citrus Marketing. Southern competes with several pipelines for the transportation business of its customers and at times discounts its transportation rates in order to maintain market share. Southern continues to provide a limited merchant service with gas supply remaining under contract and, in this capacity, competes with other suppliers, pipelines, gas producers, marketers, and alternate fuels.
Natural gas is sold in competition principally with fuel oil, coal, liquefied petroleum gases, and electricity. An important consideration in Southern and Florida Gas' markets is the ability of natural gas to compete with alternate fuels. Residual fuel oil, the principal competitive alternate fuel in Southern and Florida Gas' market area, was at certain times in 1993, and currently is, priced at or below the comparable price of natural gas in industrial and electric generation markets. Some parts of Southern's market area are also served by one or more other pipeline systems that can provide transportation as well as sales service in competition with Southern. Southern's two largest customers are both able to obtain a portion of their natural gas requirements through transportation by other pipelines.
Competition in the gas marketing business is changing as Order No. 636 is implemented across the pipeline industry, but it is expected to remain intense due to the large number of industry participants.
Natural gas in the Florida market faces intense competition from residual fuel oil, which affects both the volumes of gas transported by Florida Gas and the volumes of gas sold by the Citrus marketing companies. In addition, certain pipeline competitors of Florida Gas are currently pursuing proposed pipelines that may be built to serve the Florida market later in the decade.
Orimulsion, a heavy crude oil product from Venezuela, has also recently emerged as a potential competitive fuel for the electric generation market in Florida. Orimulsion is a mixture of tar and water that is very high in sulfur. It can be burned as an alternative to coal or to fuel oil, but is cheaper than fuel oil and more easily transported than coal. Because of its high sulfur content, however, Orimulsion can only be burned in plants that have advanced environmental protection equipment.
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[SOUTHERN NATURAL PIPELINE MAP GOES HERE]
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INVESTMENT IN SONAT OFFSHORE DRILLING INC.
Sonat Offshore Drilling Inc. and its subsidiaries (collectively referred to as "Offshore" unless the context indicates otherwise) are engaged in contract drilling for oil and gas in offshore areas throughout the world. As a result of the initial public offering of Offshore's common stock on June 4, 1993, Sonat currently retains ownership of 39.9 percent of Offshore's outstanding shares. Offshore maintains offices, land bases, and other facilities at various locations throughout the world.
See "Governmental Regulation -- Contract Drilling" below for information concerning governmental regulation of contract drilling operations. See "Stock Sale by Subsidiary" below for information concerning the public offering.
Drilling Units and Equipment
As of March 15, 1994, Offshore wholly owns nineteen marine units and operates three others, two of which it partially owns and one of which it bareboat charters. All of Offshore's drilling equipment is suitable for both exploratory and development drilling, and Offshore is normally engaged in both types of drilling activity. At March 15, 1994, 17 of the 22 marine units were working or committed to work under contract.
The offshore contract drilling industry principally uses the following four types of rigs: (1) Semisubmersibles are floating vessels that can be submerged so that a substantial portion of the lower hull is below the water surface during drilling operations, which make them well suited for operations in rough water conditions. (2) Drillships are generally self-propelled and designed to drill in deep water. Shaped like a conventional ship, they are the most mobile of the major rig types. (3) Jack-up rigs stand on the ocean floor with their hull and drilling equipment elevated above the water on connected support legs. They are best suited for water depths of 350 feet or less. (4) Submersibles sit on the ocean floor with the drilling deck structure supported above the water by vertical trusses and columns. They are limited to shallow water applications.
The search for oil and gas has increasingly been moving into deeper and more demanding offshore environments, and Offshore's primary focus has been on the technically demanding deep water and harsh environment segments of the market. Offshore operates five of the world's thirteen "fourth-generation" semisubmersibles. "Fourth-generation" semisubmersibles are those built after 1984 that are larger than other semisubmersibles, are capable of working in harsh environments, and have other advanced features. With the acquisition of the outstanding interests in the Polar Pioneer described below, Offshore now wholly owns three of these five semisubmersibles, while the other two are owned by a company in which Offshore has a 25 percent interest and are managed by Offshore through 1995. As of March 15, 1994, four of these rigs were working in the North Sea under contracts of varying duration, expiring from April 1994 through October 1997, and one was working in a deep water area of the Gulf of Mexico under a contract expiring in November 1994.
Offshore also owns three older semisubmersibles. One of them was mobilized from the North Sea to the Gulf of Mexico during 1993. As of March 15, 1994, that rig was under contract through August 1994, one rig was enroute from the North Sea to the Gulf of Mexico, and the other one was idle in the North Sea.
Offshore owns two dynamically positioned drillships that, as of March 15, 1994, were under contracts expiring in May 1994 and December 1994. One is working in the U.S. Gulf of Mexico and the other is working offshore Brazil.
Offshore also operates eleven jack-ups and one submersible in selected shallow water markets. Ten of the jack-ups and the submersible are owned by Offshore, while one of the jack-ups is owned by unaffiliated companies and bareboat chartered to Offshore through completion of its current contract. Five jack-ups and the submersible are in the Gulf of Mexico. As of March 15, 1994, four of these jack-ups and the submersible were under short-term contracts of varying duration. Offshore has five jack-ups in Egypt, four of which, as of March 15, 1994, were under contracts of varying duration. The eleventh jack-up is currently idle in the United Arab Emirates.
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Upon the expiration of existing contracts, there can be no assurance that such contracts will be renewed or extended, that new contracts will be available, or if contracts are available, that they will provide revenues adequate to cover all fixed and variable costs associated with the units.
Offshore acquired ten offshore drilling rigs from Dixilyn-Field Drilling Company ("Dixilyn-Field"), a subsidiary of Panhandle Eastern Corporation, in 1987. Under the terms of the purchase agreement, the total consideration to be paid to Dixilyn-Field for the transfer of the rigs will be determined solely by the economic performance of the rigs during a period no longer than 13 years from the date of the acquisition. In 1993 the rigs had a negative cash flow position on a combined, cumulative basis and, therefore, Dixilyn-Field was not entitled to receive any additional compensation for the rigs for that year. Offshore has sold four of the rigs acquired from Dixilyn-Field, including one which was bareboat chartered by Offshore from the rig purchaser and is expected to be returned to the rig purchaser in April 1994.
In December 1993 Offshore entered into agreements with its partners in the Polar Frontier joint venture providing for the purchase of the remaining 52.5 percent interest in the Polar Pioneer by Offshore for approximately $44.6 million plus certain adjustments relating to rig upgrades and drydocking estimated at $2.5 million and limited future consideration (up to $3 million) contingent upon the future operations of the Polar Pioneer. The transaction closed on February 18, 1994. The acquisition was funded by Offshore through cash reserves and a private placement of $30 million of senior notes.
Drilling Contracts
Offshore's drilling contracts are individually negotiated, generally after competitive bidding, and vary in their terms and provisions. The contracts generally provide for a basic daily drilling rate ("dayrate") and for lower rates for periods of travel or when drilling operations are interrupted or restricted by equipment breakdowns, adverse weather conditions, or other circumstances beyond the control of Offshore. A drilling contract may be terminated by the customer in the event the drilling unit is destroyed or lost or if drilling operations are suspended for a specified period of time as a result of a breakdown of major equipment or, in some cases, due to other events beyond the control of either party. The duration of a dayrate drilling contract may be determined either by the time required to drill a specified number of wells or by the lapse of a stated term.
Offshore has also entered into "turnkey" contracts at fixed prices per well. Under turnkey contracts, Offshore agrees to drill a well to a specified depth for a fixed price. Turnkey contracts offer the possibility of gains or losses that are substantially greater than those that would ordinarily result under typical dayrate contracts, depending upon the performance of the drilling unit and other factors. Consequently, turnkey contracts generally provide an opportunity for greater profits than do conventional dayrate contracts, but entail more financial risk. In addition, revenues and operating costs from turnkey contracts are much higher than under dayrate contracts since Offshore provides substantially more of the material and services necessary to drill the wells.
In 1991 Offshore was awarded contracts to drill up to six turnkey wells in the Bay of Campeche, Mexico by Petroleos Mexicanos ("Pemex"), the national oil company of Mexico. The turnkey portions of all six of these wells have been completed. In 1992 Pemex awarded contracts to Offshore to drill up to an additional four turnkey wells in the Bay of Campeche, two of which had been completed as of March 15, 1994, and one of which Pemex had decided not to drill. Offshore continues to investigate additional turnkey opportunities as they arise, but there can be no assurance that Offshore will obtain additional contracts before the completion of its current projects.
During the past five years Offshore has engaged in contract drilling for many of the international oil companies (or their affiliates) in the world, as well as for many government-controlled and independent oil companies. During this period Offshore's principal customers included Royal Dutch/Shell, Conoco, British Petroleum, Pemex, Gulf of Suez Petroleum Company, Amoco, Petrobras, and Norsk Hydro. Offshore's two largest customers in 1993 were Pemex and Royal Dutch/Shell, which accounted for 35 percent and 26 percent, respectively, of Offshore's 1993 consolidated operating revenues.
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Sales of Marine Units
In December 1990 Offshore contributed one of its fourth-generation semisubmersibles, the Henry Goodrich, to Arcade Drilling as. ("Arcade Drilling"), a Norwegian corporation whose shares are traded on the Oslo Stock Exchange, for $70 million in cash and 21.75 percent of Arcade Drilling's common stock. Arcade Drilling also owns another fourth-generation semisubmersible, the Sonat Arcade Frontier, which was delivered from a Korean shipyard in 1990. Offshore has been engaged by Arcade Drilling to manage both of these rigs under five-year management contracts expiring in 1995. In August 1991 Reading & Bates Corporation ("R&B"), a competitor of Offshore, acquired effective control of Arcade Shipping as. ("Shipping"), a company that has a 46.25 percent interest in Arcade Drilling. R&B's control of Shipping, together with the shares of Arcade Drilling that it owns individually, gave R&B control of Arcade Drilling. Offshore has subsequently purchased additional shares of Arcade Drilling stock on the open market, increasing its interest in Arcade Drilling to approximately 25 percent.
Operational Hazards and Insurance
Offshore's operations are subject to the usual hazards inherent in the drilling of oil and gas wells, such as blowouts, reservoir damage, loss of production, loss of well control, cratering, or fires, which could result in the suspension of drilling operations, damage to or destruction of the equipment involved, and injury to rig personnel. In addition, offshore drilling operations are subject to perils peculiar to marine operations, including capsizing, grounding, collision, and loss or damage from severe weather or storms. Offshore maintains broad insurance coverage limiting financial loss resulting from these operating hazards, but present insurance coverage would not in all situations provide sufficient funds to protect Offshore from all liabilities that could result from its drilling operations or to replace the unit if a total loss occurred, including certain of its fourth-generation semisubmersibles and drillships. Also, insurance coverage in most cases does not protect against loss of revenues.
Offshore is subject to liability under various environmental laws and regulations. See "Governmental Regulations -- Contract Drilling" below. Damage to the environment could also result from Offshore's operations, particularly through oil spillage or extensive uncontrolled fires. Offshore has generally been able to obtain some degree of contractual indemnification pursuant to which Offshore's customer agrees to protect and indemnify Offshore from liability for pollution and environmental damages. There is no assurance, however, that Offshore can obtain such indemnities in all of its contracts or that, in the event of extensive pollution and environmental damages, the customer will have the financial capability to fulfill its contractual obligation to Offshore. Also, these indemnities may not be enforceable in all instances. No such indemnification is typically available for turnkey operations.
Competition and Current Business Conditions
Historically, the offshore contract drilling industry has been highly competitive and cyclical, with periods of high demand, short rig supply, and high dayrates followed by periods of low demand, excess rig supply, and low dayrates. The industry is characterized by high capital costs, long lead times for construction of new rigs, and numerous competitors. The offshore contract drilling business is influenced by many factors, including the current and anticipated prices of oil and gas (which affect the expenditures by oil companies for exploration and production) and the availability of drilling units.
For a number of years, depressed oil and gas prices and an oversupply of rigs have adversely affected the offshore drilling market. These forces have resulted in fewer contract drilling opportunities and substantial declines in dayrates for drilling services. In addition, Offshore has competition from many other offshore drilling contractors in all of the areas in which it operates. Offshore cannot predict the timing or extent of any improvement in the industry or the future level of demand for Offshore's drilling services.
The offshore drilling market in 1992 and 1993 generally experienced difficult conditions, although certain geographic areas have performed better than others. The North Sea market continues to be depressed in comparison with recent years, primarily due to the recent decline in oil prices and the effects of changes made in 1993 to the U.K. Petroleum Revenue Tax on exploratory drilling. Despite the recent awarding of additional
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licenses by the U.K. and Norwegian governments providing new drilling prospects and Offshore's belief that there has been a permanent reduction in the supply of rigs available for drilling in the North Sea as a result of U.K. safety regulations, Offshore expects the North Sea market to remain weak in 1994, especially in the first half of the year. A strong natural gas price environment continues to support the U.S. Gulf of Mexico drilling market. As a result of the improved market there, several drilling contractors, including Offshore, have recently moved rigs back to the Gulf of Mexico and additional mobilizations are expected through early 1994. The recent influx of rigs and decline in oil prices, however, have resulted in decreased dayrates and drilling opportunities over the past few months. Offshore believes the market will strengthen after the first quarter and will then remain strong for the remainder of 1994 as long as gas prices continue at or above the corresponding 1993 levels. Additional contractors have recently elected to focus on turnkey drilling, which has caused that market to become more competitive as compared to prior years.
Generally, Offshore has had a good degree of success in keeping its deep water and harsh environment drilling units utilized at acceptable dayrates. In spite of this success, however, there can be no assurance that as contracts for these units end new contracts offering similar returns can be found.
Foreign Operations
Offshore has derived a majority of its revenues from its foreign drilling operations in each of the past three years. Offshore cannot predict whether foreign drilling operations will account for a greater or lesser percentage of such revenues in future periods.
Risks inherent in foreign operations include loss of revenue and equipment from such hazards as expropriation, nationalization, war, insurrection, and other political risks. Offshore is protected to a substantial extent against capital loss (but typically not loss of revenues) from most of these hazards by insurance, indemnity provisions in its drilling contracts, or both, but usually not risk of expropriation or other political risks. Other risks inherent in foreign operations are the possibility of currency exchange losses where revenues are received in currencies other than U.S. dollars and losses resulting from an inability to collect U.S. dollar revenues because of a shortage of U.S. currency available to the foreign country. To date, Offshore's foreign operations have not been materially affected by these currency risks.
The ability of Offshore to compete in the international drilling market may be adversely affected by foreign governmental practices that favor or effectively require the awarding of drilling contracts to local contractors. Offshore expects to continue to structure certain of its operations through joint ventures or other appropriate means in order to remain competitive in the world market.
GOVERNMENTAL REGULATION
Exploration and Production
The federal government and the states in which Exploration has oil and gas production and owns interests in producing properties regulate production, the drilling and spacing of wells, conservation, and various other matters affecting Exploration's oil and gas production.
The operations of Exploration under federal oil and gas leases are subject to certain statutes and regulations of the U.S. Department of the Interior that currently impose liability upon lessees for the cost of clean-up of pollution resulting from their operations. Royalty obligations on all federal leases are regulated by the MMS, which has promulgated valuation guidelines for the payment of royalty by producers. To the extent the MMS finally determines valuation based on a method other than actual sales proceeds received, producers could be required to pay royalties at a rate higher than actual sales proceeds.
Other federal, state, and local laws and regulations relating to the protection of the environment may affect Exploration's oil and gas operations, both directly and indirectly, through their effect on the construction and operation of facilities, drilling operations, production, or the delay or prevention of future offshore lease sales. Sonat maintains substantial insurance on behalf of Exploration for oil pollution liability. Exploration is also subject to various governmental safety regulations in the jurisdictions in which it operates.
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Transmission, Sale, and Marketing of Natural Gas
Southern is subject to regulation by the FERC and by the Secretary of Energy under the Natural Gas Act, the NGPA, and the Department of Energy Organization Act of 1977 (the "DOE Act"). Southern's operating subsidiaries and Florida Gas are also subject to such regulation.
The Natural Gas Act, modified by the DOE Act, grants to the FERC authority to regulate the construction and operation of pipeline and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement, or abandonment of such facilities. Southern, its operating subsidiaries, and Florida Gas hold required certificates of public convenience and necessity issued by the FERC authorizing them to construct and operate all pipelines, facilities, and properties now in operation for which certificates are required, and to transport and sell natural gas in interstate commerce.
The FERC also has authority to regulate the transportation of natural gas in interstate commerce and the sale of natural gas in interstate commerce for resale. Although the FERC still retains jurisdiction over their resale rates, following the implementation of Order No. 636, Southern, Florida Gas, and other interstate pipeline companies are now permitted to charge market-based rates for gas sold in interstate commerce for resale. Gas sold by Marketing and other marketing companies is not regulated by the FERC. Transportation rates remain fully regulated. The price at which gas is sold to direct industrial customers is not subject to the FERC's jurisdiction. As necessary, Southern, its operating subsidiaries, and Florida Gas file with the FERC applications for changes in their transportation rates and charges designed to allow them to recover fully their costs of providing such service to their customers, including a reasonable rate of return. These rates are normally allowed to become effective, subject to refund, until such time as the FERC rules on the actual level of rates. See "Rate and Regulatory Proceedings" below.
The Natural Gas Wellhead Decontrol Act of 1989, enacted on July 26, 1989, phased in decontrol of the wellhead price of all gas then remaining subject to maximum lawful price limitations by January 1, 1993. Thus, the price of all gas sold at the wellhead is no longer regulated.
Regulation of the importation of natural gas is vested in the Secretary of Energy, who has delegated various aspects of this import jurisdiction to the FERC and the ERA.
Southern, its operating subsidiaries, and Florida Gas are subject to the Natural Gas Pipeline Safety Act of 1968, as amended, which regulates pipeline and LNG plant safety requirements, and to the National Environmental Policy Act and other environmental legislation. Southern, its operating subsidiaries, and Florida Gas have a continuing program of inspection designed to keep all of their facilities in compliance with pollution control and pipeline safety requirements and believe that they are in substantial compliance with applicable requirements. Southern's capital expenditures to comply with environmental and pipeline safety regulations were approximately $14 million in 1993. It is anticipated that such expenditures will be approximately $11 million in 1994 and approximately $10 million in 1995. For more information regarding environmental matters, see the discussion below.
Rate and Regulatory Proceedings. Various matters pending before the FERC, or before the courts on appeal from the FERC, relating to, or that could affect, Sonat or one or more of its subsidiaries are described in Part II of this report in Note 9 of the Notes to Consolidated Financial Statements and in Management's Discussion and Analysis of Financial Condition and Results of Operations, which are incorporated herein by reference. As described in Note 9, several general rate changes have been implemented by Southern and remain subject to refund.
Contract Drilling
Offshore's operations are affected from time to time in varying degrees by governmental laws and regulations. The drilling industry is dependent on demand for services from the oil and gas exploration industry and, accordingly, is affected by changing tax and other laws relating to the energy business generally.
Foreign contract drilling operations are subject to various other governmental laws and regulations in countries in which Offshore operates. Such laws and regulations govern various aspects of foreign operations,
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including the equipping and operation of drilling units, currency conversions and repatriation, oil exploration and development, taxation of foreign earnings and earnings of expatriate personnel, and use of local employees and suppliers by foreign contractors. Governments in some foreign countries have become increasingly active in regulating and controlling the ownership of concessions and companies holding concessions, the exportation of oil, and other aspects of the oil industries in their countries. In addition, government action, including initiatives by OPEC, may continue to cause oil price volatility. In some areas of the world this governmental activity has adversely affected the amount of foreign exploration and development work done by major oil companies and may continue to do so.
In the United States regulations applicable to Offshore's operations include certain regulations controlling the discharge of materials into the environment, requiring removal and cleanup of materials that may harm the environment, or otherwise relating to the protection of the environment. For example, as an operator of mobile offshore drilling units in navigable United States waters and certain offshore areas, Offshore may be liable for damages and costs incurred in connection with oil spills for which it is held responsible, subject to certain limitations. Laws and regulations protecting the environment have become more stringent in recent years and may in certain circumstances impose "strict liability," rendering a person liable for environmental damage without regard to negligence or fault on the part of such person. Such laws and regulations may expose Offshore to liability for the conduct of or conditions caused by others, or for acts of Offshore that were in compliance with all applicable laws at the time such acts were performed. The application of these requirements or the adoption of new requirements could have a material adverse effect on Offshore.
The Oil Pollution Act of 1990 ("OPA") and regulations promulgated pursuant thereto impose a variety of requirements on "responsible parties" related to the prevention of oil spills and liability for damages resulting from such spills. Few defenses exist to the liability imposed by the OPA, which could be substantial. A failure to comply with ongoing requirements or inadequate cooperation in a spill event could subject a responsible party to civil or criminal enforcement action.
In addition, the Outer Continental Shelf Lands Act authorized regulations relating to safety and environmental protection applicable to lessees and permittees operating on the Outer Continental Shelf. Specific design and operational standards may apply to Outer Continental Shelf vessels, rigs, platforms, vehicles, and structures. Violations of environmental-related lease conditions or regulations issued pursuant to the Outer Continental Shelf Lands Act can result in substantial civil and criminal penalties as well as potential court injunctions curtailing operations and the cancellation of leases. Such enforcement liabilities can result from either governmental or citizen prosecution.
Certain of the foreign countries in whose waters Offshore is presently operating or may operate in the future have regulations covering the discharge of oil and other contaminants in connection with drilling operations.
Offshore believes that it has conducted its operations in substantial compliance with applicable environmental laws and regulations governing its activities.
Although significant capital expenditures may be required to comply with such governmental laws and regulations, such compliance has not materially adversely affected the earnings or competitive position of Offshore. In 1992 regulations relating to offshore drilling rigs were issued in the U.K. that required a comprehensive review of the technical characteristics of and operating procedures for each rig in the U.K. sector of the North Sea. Offshore does not believe that any upgrade required on its rigs as a result of such technical review will be significant. Two rigs for which upgrades would be significant, however, the Sonat D-F 96 and the Sonat D-F 97, were moved from the North Sea because market conditions there did not justify the amount of capital expenditures required to upgrade these rigs. It is possible that such laws and regulations in the future may add to the cost of operating offshore drilling equipment or may significantly limit drilling activity.
The United Kingdom levies a petroleum revenue tax ("PRT") on revenue derived from the extraction of oil and natural gas from the U.K. sector of the North Sea. Prior to the changes discussed below, a company was permitted to reduce the amount of PRT it owed by taking as a credit against its revenues certain of its
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expenditures used to explore for oil and natural gas in the U.K. On March 16, 1993, the Chancellor of the Exchequer proposed certain changes in the PRT that were subsequently enacted. Among other things, these changes have (i) effective July 1, 1993, reduced the rate of PRT from 75 percent to 50 percent on revenues derived from existing fields; (ii) abolished the PRT for new fields, defined as those for which development consent is received after March 15, 1993; and (iii) eliminated the credit attributable to exploration costs. The changes in the PRT adversely affected exploratory drilling in the U.K. sector of the North Sea in 1993 and the first quarter of 1994. Offshore expects the impact on developmental drilling to be favorable, however, because the tax burden has been reduced on new field production. While Offshore expects these trends to become clearer in the future, Offshore cannot predict the long-term effect of changes in the PRT on demand for offshore drilling rigs in the U.K. Sector of the North Sea or on Offshore. The combination of low oil prices and the changes in the PRT, however, have resulted in a substantial reduction of drilling activities in the U.K. sector of the North Sea.
ENVIRONMENTAL MATTERS
Exploration and Southern and certain of their subsidiaries are subject to extensive federal, state, and local environmental laws and regulations that affect their operations. Governmental authorities may enforce these laws and regulations with a variety of civil and criminal enforcement measures, including monetary penalties, assessment and remediation requirements, and injunctions as to future activities. Exploration, Southern, and certain of their subsidiaries' use and disposal of hazardous materials and toxic substances are subject to the requirements of the federal Toxic Substances Control Act ("TSCA") and the federal Resource Conservation and Recovery Act ("RCRA"), among others, and comparable state and local statutes. The Comprehensive Environmental Response, Compensation and Liability Act ("CERCLA"), also known as "Superfund," imposes liability, without regard to fault or the legality of the original act, for release of a "hazardous substance" into the environment.
Exploration is named as a potentially responsible party ("PRP") at two Superfund sites, at one of which its status is that of a de minimis contributor. Exploration has reached tentative agreement with the Environmental Protection Agency ("EPA") for this latter site, which is projected to result in a total settlement of Exploration's involvement at the site for less than $20,000. Based on the information that it currently possesses, Exploration does not believe that any contribution will be sought from it with regard to the other site.
Southern is named as a PRP at three Superfund sites, at two of which it is a de minimis party. Based on the number of other financially responsible PRPs at each of the sites, the estimated relative volume of material contributed to the sites by Southern, the information that it currently possesses regarding the expected costs required to remediate the sites, and the amounts already contributed to remediation, Southern currently estimates that it should not ultimately be required to contribute in excess of $200,000 in the aggregate to the costs of remediation of all three sites.
In addition, Southern has been advised by a joint defense group of PRPs ("JDG") at another Superfund site that the JDG might seek to add it as a PRP, but Southern has received no notification from the EPA asserting that it is a PRP. A corporation in which a subsidiary of Exploration is a 50-percent shareholder has been named as a PRP at this site, however, and it has elected to join the JDG, which acting pursuant to an Administrative Order on Consent among the EPA and its members, has undertaken to stabilize the site by removing and disposing of all liquids and containers located thereon for a total cost believed to be less than $1.5 million, of which Exploration's share, through this 50-percent-owned corporation, is presently less than $50,000. Sonat has been informed by representatives of the JDG that no characterization of soil or groundwater contamination at this site has yet taken place and, therefore, the extent of such contamination, if any, is not currently known. Southern has thus far elected not to join the JDG, because it believes that it has significant potential defenses to liability for this site and that, in any event, it shipped de minimis amounts of material to this site. Based on the number of other financially responsible PRPs and other information that it currently possesses, Sonat currently estimates that neither Southern nor Exploration's subsidiary will incur liabilities related to this site in an amount material to Sonat.
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Liability under CERCLA (and applicable state law) can be joint and several with other PRPs. Although volumetric allocation is a factor in assessing liability, it is not necessarily determinative; thus, the ultimate liability at any of these sites could be substantially greater than the amounts described above. Neither Exploration nor Southern believes that its status as a PRP at any of these sites will have a material adverse effect on its financial condition or results of operations.
Southern has in the past used lubricating oils containing polychlorinated biphenyls ("PCBs") in conjunction with auxiliary compressed air systems at Southern's natural gas compressor stations. Although the use of such oils was discontinued in the early 1970's, Southern has discovered residual PCB contamination at certain of its gas compressor station sites. For some time, Southern has had an ongoing internal project to identify and deal with the presence of PCBs at these sites. A total of thirteen stations evidenced some level of on-site PCB contamination ranging from low to moderate. Southern has completed the characterization and clean-up of twelve of these sites based on the guidelines of the TSCA at a total cost of approximately $6 million. Southern has partially completed the characterization and clean-up of the remaining site and believes that it should be able to complete the remediation of this site for a total cost of less than $5 million.
In the operation of their natural gas pipeline systems, Southern and South Georgia have used, and continue to use at several locations, gas meters containing elemental mercury. Many of these meters have been removed from service. Southern and South Georgia plan to remove the remaining mercury meters during the course of regularly scheduled facilities upgrades, but until such time, the meters are handled pursuant to established procedures that protect employees and comply with Occupational Safety and Health Administration standards. It is generally believed in the natural gas pipeline industry that, in the course of normal maintenance and replacement operations, elemental mercury may have been released from mercury meters. Although at this time neither the EPA nor any state in which Southern or South Georgia operates has yet issued clean-up levels or guidelines with respect to contamination from past releases or spills of mercury, Sonat expects that guidelines will be forthcoming. Southern and South Georgia have nonetheless begun preliminary efforts to address this situation and plan to begin remediation if contamination is detected upon characterization of these sites. Because the number of sites involved and the extent of contamination at any site are not yet known, Sonat is unable at this time to estimate the cost of remediation. Based on its experience with other remediation projects, the industry experience to date with remediation of mercury, and its preliminary analysis of the possible extent of the contamination, however, Sonat believes that its remediation of any mercury contamination will not have a material adverse effect on its financial condition or results of operations.
Sonat generally considers environmental assessment and remediation costs and costs associated with compliance with environmental standards incurred by Southern and South Georgia to be recoverable through rates since they are prudent costs incurred in the ordinary course of business and, accordingly, will seek recovery of such costs through rate filings, although no assurance can be given with regard to their ultimate recovery.
Exploration, Southern, and their subsidiaries are subject to the federal Clean Air Act and the federal Clean Air Act Amendments of 1990 ("1990 Amendments"), which added significantly to the existing requirements established by the federal Clean Air Act. The 1990 Amendments require that the EPA issue new regulations, mainly related to mobile sources, air toxics, ozone non-attainment areas, acid rain, permitting, and enhanced monitoring. While it will not be possible to estimate the additional costs of compliance with these new requirements until the EPA and the states complete their regulations, Sonat expects that the regulations when issued may require significant capital spending to modify certain of its subsidiaries' facilities, particularly with regard to modifications that may be required for certain natural gas compressor stations of Southern to reduce their emissions of oxides of nitrogen.
In the opinion of Sonat's management, based on information currently possessed by Sonat, the probability is remote that Sonat or any of its subsidiaries will incur a liability as a result of the presently identified environmental contingencies described above in an amount material to Sonat. While the nature of environmental contingencies makes complete evaluation impractical, Sonat is currently aware of no other environmental matter that could reasonably be expected to have a material impact on its results of operations
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or financial condition. Sonat has an active and ongoing environmental program at all levels of its organization and believes responsible environmental management is integral to its business. Sonat believes that its subsidiaries have conducted their operations in substantial compliance with applicable environmental laws and regulations governing their activities.
For a discussion of the environmental matters affecting Offshore, see "Governmental Regulation -- Contract Drilling" above.
STOCK SALE BY SUBSIDIARY
On June 4, 1993, the initial public offering of Offshore's Common Stock at $22.00 per share was closed. Prior to the offering, Sonat owned 100 percent of Offshore. Offshore issued 15.5 million shares and Sonat sold 1.448 million of its shares resulting in a combined pretax gain of $155.8 million. Net proceeds from the combined transactions after underwriting commissions, expenses, and tax provisions totaled approximately $340 million. Sonat retained ownership of approximately 11.3 million or 39.9 percent of Offshore's outstanding shares and recognized an after-tax gain of $99.7 million or $1.15 per share from the combined transactions.
DISCONTINUED OPERATIONS
On April 23, 1992, Sonat completed the sale of Teleco Oilfield Services Inc., which had been acquired by Sonat in 1984, to Baker Hughes Incorporated ("Baker Hughes"). Sonat received $200 million in cash and four million shares of Baker Hughes convertible preferred stock. The convertible preferred stock has a liquidation preference of $200 million, a dividend rate of six percent per annum, and is convertible at $32.50 per share into Baker Hughes common stock. The cash proceeds were used to reduce Sonat's debt and the dividends paid on the convertible preferred stock had a positive impact on 1993 earnings.
ITEM 2.
ITEM 2. PROPERTIES
A description of Sonat's and its subsidiaries' properties is included under Item 1. Business above and is hereby incorporated by reference herein.
ITEM 3.
ITEM 3. LEGAL PROCEEDINGS
For information regarding certain proceedings pending before federal regulatory agencies, see Note 9 of the Notes to Consolidated Financial Statements in Part II of this report.
Arcadian Corporation v. Southern Natural Gas Company and Atlanta Gas Light Company was filed in January 1992 in the U.S. District Court for the Southern District of Georgia. In this lawsuit against Southern and Atlanta Gas Light Company for alleged violation of the antitrust laws in connection with Southern's refusal to provide direct service to the Plaintiff, Arcadian Corporation ("Arcadian"), Arcadian claims actual damages of at least $15 million, which could be trebled under the antitrust laws. Southern and Arcadian executed an agreement settling this lawsuit on November 30, 1993. The settlement provides that the lawsuit will be dismissed with prejudice upon final, nonappealable approval by the FERC of the direct connection and transportation service requested by Arcadian. Pending such approval, the lawsuit has been stayed. While management believes it has meritorious defenses and intends to defend the suit vigorously if the stay were to be lifted, given the inherently unpredictable nature of litigation and the relatively early state of discovery in the case, management is unable to predict the ultimate outcome of the proceeding if it were to go forward, but believes that it will not have a material adverse effect on Southern's financial position.
Exxon Corporation v. Southern Natural Gas Company was filed in February 1994 in the U.S. District Court for the Southern District of Texas. Exxon Corporation ("Exxon"), the plaintiff in this suit, asked the court to declare that Southern has no right to terminate a gas purchase contract with Exxon providing for the sale and purchase of gas produced from Mississippi Canyon and Ewing Bank Area Blocks, offshore Louisiana (the "Contract"), which Southern gave notice of termination effective March 1, 1994. In the alternative, Exxon alleged that Southern has repudiated and breached the Contract and asked for an unspecified amount
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of monetary damages. Management is unable to predict the outcome of this litigation and whether its position that it has the right to terminate this contract will be sustained.
Sonat and its subsidiaries are involved in a number of other lawsuits, all of which have arisen in the ordinary course of business. Sonat does not believe that any ultimate liability resulting from any of these other pending lawsuits will have a material adverse effect on the financial position or results of operations of Sonat.
ITEM 4.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
Sonat did not submit any matter to a vote of its security holders during the fourth quarter of 1993.
Executive Officers of the Registrant
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* Effective April 1, 1994.
There is no family relationship between any of the above-named executive officers.
The officers of Sonat are elected annually by the Board of Directors. The identification of an individual as an executive officer in this report does not constitute a determination by Sonat or its Board of Directors that such individual is an officer of Sonat for purposes of Section 16 of the Securities Exchange Act of 1934.
Ronald L. Kuehn, Jr. was elected Chairman of the Board of Sonat effective March 28, 1986. Mr. Kuehn has served as Director of Sonat since April 30, 1981, as President of Sonat since January 1, 1982, and as Chief Executive Officer of Sonat since June 1, 1984, and currently serves in those capacities. Mr. Kuehn also serves as Director of various Sonat subsidiaries. During the past five years Mr. Kuehn has served as a senior executive officer of Sonat.
Donald G. Russell was elected Executive Vice President of Sonat effective January 1, 1991, and currently serves in that capacity. Mr. Russell also serves as Chairman and Chief Executive Officer of Exploration. During the past five years Mr. Russell has served as an officer of Sonat and Exploration.
William A. Smith was elected Executive Vice President of Sonat effective March 1, 1991, and currently serves in that capacity. Mr. Smith also serves as Chairman and President of Southern and Chairman of Energy Services until April 1, 1994, when he will become Vice Chairman of Exploration. During the past five years, Mr. Smith has served as an officer of Sonat, Southern, and Energy Services.
Thomas W. Barker, Jr. was elected Vice President -- Finance of Sonat effective June 15, 1984, and Treasurer of Sonat effective January 1, 1990, and currently serves in those capacities. Mr. Barker also serves as Vice President -- Finance and Assistant Treasurer of Exploration and Treasurer of Southern and Energy Services. During the past five years Mr. Barker has served as an officer of Sonat, Southern, Exploration, and Energy Services.
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Beverley T. Krannich was elected Vice President-Human Resources of Sonat effective June 1, 1987, and Secretary of Sonat effective May 11, 1984, and currently serves in those capacities. Ms. Krannich also serves as Vice President-Human Resources of Exploration. During the past five years Ms. Krannich has served as an officer of Sonat and Exploration.
Ronald B. Pruet was elected Vice President and Controller of Sonat effective April 1, 1994, and will serve in that capacity beginning on such date. Mr. Pruet also serves as Senior Vice President and Treasurer of Exploration. During the past five years Mr. Pruet has served as an officer of Exploration.
James A. Rubright was elected Vice President and General Counsel of Sonat effective February 15, 1994, and currently serves in that capacity. Mr. Rubright also serves as Executive Vice President and General Counsel of Exploration, Southern, and Energy Services. During the past five years until his election as Vice President and General Counsel of Sonat, Mr. Rubright had been a member of the Atlanta, Georgia law firm of King & Spalding.
James E. Moylan, Jr. was elected Vice President and Controller of Sonat effective June 15, 1984, and will serve in that capacity until April 1, 1994, when he will become President of Southern. During the past five years Mr. Moylan has served as an officer of Sonat and Southern.
Richard B. Bates was elected President of Energy Services effective January 1, 1994, and currently serves in that capacity. Mr. Bates also serves as President of Marketing. During the past five years Mr. Bates has served as an officer of Exploration, Energy Services, and Marketing.
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PART II
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The financial data following on pages II-2 through II-37 is reproduced from, and the Table of Contents below is taken from, the Sonat Inc. Annual Report to Stockholders for 1993. An index to the financial statements and financial statement schedules may be found under Item 14. "EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K" in Part IV of this report.
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FINANCIAL INFORMATION CONTENTS
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
RESULTS OF OPERATIONS
OPERATING INCOME Sonat Inc. and its subsidiaries (the Company) operate in the energy industry through three business segments: Exploration and Production, Natural Gas Transmission and Marketing, and Offshore Drilling.
Segment Operating Income (Loss)
EXPLORATION AND PRODUCTION The Company participates in the exploration and production business in the United States through Sonat Exploration Company. Beginning in 1988, Sonat Exploration implemented a strategy to acquire gas properties with significant development potential. As a result of this strategy, Sonat Exploration has more than quintupled its proved reserves. At the end of 1993, the Company had proved reserves totaling more than 1.3 trillion cubic feet of natural gas equivalent, including a portion that qualifies for tax credits authorized by Congress in 1991 (Section 29 tax credits). The Section 29 tax credits were $19 million in 1993; however, production from wells that qualify for these credits will begin to decline in 1994 as these wells follow their normal decline pattern.
Sonat Exploration is continuing its strategy of aggressively acquiring domestic gas properties with significant development potential. During 1993 Sonat Exploration acquired oil and gas interests and properties totaling $266 million, which increased proved reserves by approximately 313 billion cubic feet of natural gas equivalent. The largest transaction was the third quarter acquisition of 34 producing wells on 21 lease blocks in the Gulf of Mexico from Mobil Exploration and Producing U.S., Inc. Sonat Exploration plans to drill eight wells on these properties in 1994 and up to 13 wells in 1995. During the fourth quarter, oil and gas properties in south Texas were acquired from Tri-C Resources, Inc. The properties include 87 producing wells located in 18 fields and approximately 40,000 gross acres. In December 1993, Sonat Exploration began a significant drilling program on the properties to hold lease acreage under the terms of a farmout agreement. As of February 1, 1994, Sonat Exploration had drilled 90 wells on these properties and plans to drill 46 additional wells during 1994. Another significant 1993 transaction was the acquisition of certain oil and gas properties belonging to Grace Petroleum Corporation located in eastern Texas and northwestern Louisiana.
Sonat Exploration has a substantial acreage position in the eastern extension of the Austin Chalk trend in Texas and Louisiana. During 1993 Sonat Exploration participated in the drilling of 15 wells, all of which were successful. As of December 31, 1993, Sonat Exploration has participated in the completion of 25 wells in the Austin Chalk trend, 24 of which are commercial.
On October 4, 1993, Sonat Exploration acquired the limited partnership interest of Prudential Insurance Company in Sonat/P Anadarko Limited Partnership (Sonat/P) for $11.5 million cash and the assumption of $4.1 million of debt pertaining to Prudential's interest in Sonat/P. As part of the transaction, the Company issued a total of $18.5 million of long-term debt to purchase all of Sonat/P's outstanding notes. Sonat Exploration was the general partner of Sonat/P, which acquired oil and gas reserves in the Anadarko Basin of Oklahoma from Louisiana Land and Exploration Company in the third quarter of 1992.
Total capital expenditures for Sonat Exploration (excluding its share of Sonat/P's capital expenditures) increased to $431 million in 1993 from $156 million in 1992. Low spot-market natural gas prices in early 1992 reduced cash flows from operations and resulted in lower capital expenditures in 1992. The opportunity to continue acquiring properties with value-enhancement potential by reinvesting proceeds from the Sonat Offshore Drilling Inc. initial public offering (IPO) and a stronger cash flow from oil and gas operations resulted in increased capital spending in 1993. Capital spending in 1994 is expected to approximate $390 million, which includes amounts for increased development drilling and additional producing property acquisitions.
Sonat Exploration's liquids and natural gas production is marketed in the spot market almost entirely by Sonat Marketing Company, a subsidiary of Sonat Energy Services Company operating in the Natural Gas Transmission and Marketing Segment. Due to the volatility of spot-market prices, part of Sonat Exploration's production is hedged from time to time through gas futures transactions and oil price swaps to reduce the effects of spot-market prices on operating results. Exploration and Production Operations
1993 Versus 1992. Operating results for 1993 were up significantly from 1992, reflecting a 16 percent increase in natural gas prices. Acquisition activity led to higher oil and gas volumes, which increased by 29 percent and 18 percent over 1992, respectively. Amortization expense also increased due to higher production volumes as well as higher amortization rates due to increased Austin Chalk production, which is predominantly oil, recent tight-sands gas drilling, along with acquisitions which included more proved producing reserves. General and administrative expense compared favorably to 1992 due to $4 million of restructuring charges included in 1992.
1992 Versus 1991. Spot-market gas prices for 1992 compared favorably to 1991, and gas volumes increased 9 percent over 1991. Much of the favorable gas revenue increase was offset by decreased oil and condensate production, which was down 21 percent due to the sale of oil properties in the second quarter of 1991 and to higher amortization costs. A significant decrease in operating expenses in 1992 due to lower production was partially offset by a $4 million increase in stock-based employee compensation.
NATURAL GAS TRANSMISSION AND MARKETING The Company participates in the natural gas transmission and marketing business through Southern Natural Gas Company, Citrus Corp. (a 50 percent-owned company), and Sonat Energy Services. Southern and Florida Gas Transmission Company (a subsidiary of Citrus), operating in the natural gas transmission industry, have historically provided customers of their natural gas pipelines both merchant and transportation services. Effective November 1, 1993, Southern separated its transportation, storage and merchant services to comply with Order No. 636. (See following discussion.) Florida Gas also restructured its services in compliance with Order No. 636 effective on November 1, 1993. As a result of Order No. 636, both Southern and Florida Gas have essentially become solely gas transporters, although Southern will continue to make limited sales until it has exhausted its gas supply remaining under contract. Sonat Energy Services, through its subsidiaries, manages Sonat's unregulated natural gas businesses including natural gas marketing and gathering and intrastate natural gas pipeline services. Natural gas marketing activities for Citrus, primarily to customers of Florida Gas, are provided by affiliates of Citrus.
The natural gas transmission industry, although regulated, is very competitive. Even before the Order No. 636 restructuring, customers switched much of their volumes from a bundled merchant service to transportation service, reflecting an increased willingness to rely on gas supply under unregulated arrangements such as those provided by Sonat Marketing and affiliates of Citrus. Southern competes with several pipelines for the transportation business of its customers and at times discounts its transportation rates in order to maintain market share. Although it is now predominantly a transporter of gas, Southern continues to provide a limited merchant service with gas supply remaining under contract and, in this capacity, competes with other suppliers, gas producers, marketers and alternate fuels.
Southern is pursuing growth opportunities to expand the level of services in its traditional market area and to connect new gas supplies. On May 13, 1993, approval was received from the Federal Energy Regulatory Commission (FERC) for expansion of South Georgia Natural Gas Company's pipeline system into northern Florida and southwestern Georgia that will increase firm daily capacity by 40 million cubic feet per day. Construction on this project is under way and should be completed by mid-1994. In May 1993, the Company announced a proposed intrastate natural gas pipeline to be built in Florida that would extend from the existing facilities of South Georgia near Tallahassee to the Tampa area. The size and timing of this project are uncertain, but projections indicate a substantial need for additional gas supply in this market later in this decade. Additionally, Southern has entered into an agreement in principle to expand its system to Chattanooga, Tennessee, and is meeting with major local distribution companies and other potential customers, primarily in eastern North Carolina, to discuss expansion opportunities in the rapidly growing North Carolina market.
Florida Gas, which has a current pipeline system capacity of 925 million cubic feet per day, was granted final certificate authority by the FERC on September 15, 1993, for the further expansion of its pipeline system. This expansion will increase system capacity by 530 million cubic feet per day at a capital cost of approximately $900 million. As part of the expansion project, Florida Gas contracted with Southern to deliver 100 million cubic feet per day of new firm transportation. In connection with this expansion, the Company will advance funds to Citrus and expects to have an equity investment in the project of $150 million by the end of the construction period. Additionally, Florida Gas is currently reviewing the prospects for further expansions of its pipeline system into the Florida market that could be in service in 1996 or 1997.
Sonat Marketing continues to expand its natural gas marketing business. Prior to 1993, Sonat Marketing's volumes were approximately 500 million cubic feet per day and were primarily on the Southern system. During the past year, Sonat Marketing assumed responsibility for marketing almost all of the natural gas and liquids production of Sonat Exploration, including execution of Sonat Exploration's risk management program. This has allowed Sonat Marketing to expand its presence in Gulf Coast, Midwest and Northeast markets and, in turn, provide attractive markets to unaffiliated producers. As a result of these efforts, Sonat Marketing's average daily sales volumes now exceed 1.1 billion cubic feet per day, making it one of the largest natural gas marketers in the country. Competition in the gas marketing business is changing as Order No. 636 is implemented across the pipeline industry and is expected to remain intense due to the large number of industry participants.
Sonat Ventures Inc. (a subsidiary of Sonat Energy Services) is focused primarily on the growing natural gas vehicle (NGV) market and opened an NGV conversion and emissions testing center in Atlanta in February 1993, along with Atlanta Gas Light Company and another partner. Separately, Sonat Ventures has established joint ventures in Alabama and Florida. These joint ventures, which are partnerships with local distribution companies that are customers of Southern, generally offer a complete range of services to facilitate the use of natural gas vehicles in those states. Sonat Ventures is also pursuing opportunities to own and operate refueling centers elsewhere in the Southeast.
In December 1993, AES/Sonat Power L.L.C. (a 50 percent-owned company), submitted a successful bid for a 221 megawatt power plant to be constructed near San Francisco. If a contract is signed, The AES Corporation will handle the construction and operation of the plant, while the Company will manage the gas supply requirements. The plant is scheduled to be completed by mid-1997 and would require an equity investment from the Company of approximately $15 million-$20 million.
Natural Gas Transmission & Marketing Operations
1993 Versus 1992. Southern's operating results for 1993 were down primarily due to a favorable settlement of $9.6 million in 1992 relating to Southern Energy Company's idle liquefied natural gas (LNG) facility. A settlement at Sea Robin Pipeline Company increased 1993 results by $4.5 million. General and administrative expenses were up in 1993 due to a $4 million increase in health insurance expense and an increase in stock-based employee compensation.
Gas sales revenue and gas cost increased at Southern due to the sale of $123 million of storage gas inventory pursuant to the implementation of Order No. 636 on November 1, 1993. Total market throughput increased 2 percent; however, Order No. 636 resulted in a shift in volumes from sales to market transportation. Supply transportation volumes decreased due to competition from other pipelines.
Sonat Marketing's sales volumes increased significantly over last year as a result of fully integrating the marketing of Sonat Exploration's production and expanding activities on non-affiliated pipelines through the purchase of additional third-party volumes.
Equity in earnings of Citrus increased $3 million over 1992. Operationally, high prices for natural gas relative to competing No. 6 fuel oil significantly reduced earnings in 1993. However, the decline was offset by gains from the sale of gas supply contracts at Citrus Marketing in 1993, decreased depreciation expense resulting from a change in the estimated useful life of the pipeline system and the recognition of natural gas settlement costs in 1992. Citrus' results (100 percent) were reduced by $10 million in 1993 by the recognition of the increase in the U.S. federal income tax rate.
1992 Versus 1991. Operating income for 1992 includes the effect of a favorable settlement of $9.6 million relating to Southern Energy's LNG facility, while 1991 was negatively affected by one-time charges totaling $11 million related to a cost-containment program and the cancellation of the Mobile Bay project. Excluding these items, operating income was lower primarily as a result of an $8 million increase for stock-based employee compensation.
Southern's total volumes increased 8 percent in 1992. Market throughput was higher because of colder weather and new markets, offsetting the loss of a competitive load to coal that was served in 1991 when gas prices were substantially lower and losses to other pipeline competition. The 18 percent increase in supply transportation is primarily the result of higher deliverability and an aggressive program of hooking up new gas supply to the Sea Robin system.
Sonat Marketing's sales volumes increased 6 billion cubic feet in 1992 due in part to its marketing of Sonat Exploration's production volumes. Net margins remained relatively flat.
Equity in earnings from Citrus in 1992 decreased from 1991 due primarily to the recognition of natural gas contract settlement costs and increased interest expense. Market throughput increased slightly over 1991, reflecting the increased capacity available to serve the Florida market. Throughput continued to reflect a shift from sales to market transportation.
ORDER NO. 636 In 1992 the FERC issued its Order No. 636 (the Order). As required by the Order, interstate natural gas pipeline companies have made significant changes in the way they operate. The Order required pipelines, among other things, to: (1) separate (unbundle) their sales, transportation and storage services; (2) provide a variety of transportation services, including a "no-notice" service pursuant to which the customer will be entitled to receive gas from the pipeline to meet fluctuating requirements without having previously scheduled delivery of that gas; (3) adopt a straight fixed variable (SFV) method for rate design (which assigns more costs to the demand component of the rates than do other rate design methodologies previously utilized by pipelines); and (4) implement a pipeline capacity release program under which firm customers will have the ability to "broker" the pipeline capacity for which they have contracted. The Order also authorized pipelines to offer unbundled sales services at market-based rates and allowed for pregranted abandonment of some services.
As discussed in Note 9 of the Notes to Consolidated Financial Statements, Southern is incurring certain transition costs as a result of implementing Order No. 636, and for Southern, those are primarily gas supply realignment (GSR) costs relating to existing gas purchase contracts. In its restructuring settlement discussions, Southern has advised its customers that the amount of GSR costs that it actually incurs will depend on a number of variables, including future natural gas and fuel oil prices, future deliverability under Southern's existing gas purchase contracts and Southern's ability to renegotiate certain of these contracts. While the level of GSR costs is impossible to predict with certainty because of these numerous variables, based on current spot-market prices, a range of estimates of future oil and gas prices, and recent contract renegotiations, the amount of GSR costs would be approximately $275 million-$325 million on a present value basis. This includes the $168 million of settlements discussed below. In requiring that Southern provide unbundled storage service, the Order resulted in a substantial reduction of Southern's working storage gas inventory and consequently a reduction in its rate base. The reduction in rate base was effective on November 1, 1993, when Southern restructured pursuant to the Order and sold $123 million of its storage gas inventory to its customers. The Order also resulted in rates that are less seasonal, thereby shifting revenues and earnings for Southern out of the winter months.
The FERC issued an order on September 3, 1993 (the September 3 order), that generally approved a compliance plan for Southern and directed it to implement restructured services on November 1, 1993. In accordance with the September 3 order, Southern solicited service elections from its customers in order to implement its restructured services on November 1, 1993. Southern's largest customer, Atlanta Gas Light Company and its subsidiary, Chattanooga Gas Company (collectively Atlanta), bid for firm transportation service on Southern at prices significantly below Southern's filed tariff rates. Southern rejected Atlanta's bids. Southern and Atlanta subsequently entered into an interim agreement under which Atlanta signed firm transportation service agreements with transportation demands of 582 million cubic feet per day for a minimum term of four months beginning November 1, 1993, and 118 million cubic feet per day for a term extending until April 30, 2007, at the maximum FERC-approved rates. This represented an aggregate reduction of 100 million cubic feet per day from Atlanta's level of services prior to November 1, 1993. In January 1994, Atlanta provided notice, subject to change, that it had elected to continue that level of firm service until October 31, 1994. Southern's other customers elected in aggregate to obtain an amount of firm transportation services that represented a slight increase from their previous level of firm sales and transportation services from Southern, at the maximum FERC-approved tariff rates, for terms ranging from one to 30 years.
Southern is unable to predict all of the elements of the ultimate outcome of its Order No. 636 restructuring proceeding, its settlement discussions with Atlanta and its other customers, and the limited rate filings to recover its transition costs.
NATURAL GAS SALES AND SUPPLY As a result of Order No. 636, Southern is attempting to terminate its remaining gas purchase contracts through which it had traditionally obtained its long-term gas supply. Some of these contracts contain clauses requiring Southern either to purchase minimum volumes of gas under the contract or to pay for it (take-or-pay clauses). Although Southern currently is incurring essentially no take-or-pay liabilities under these contracts, the annual weighted average cost of gas under these contracts is in excess of current spot-market prices. Pending the termination of these remaining supply contracts, Southern has agreed to sell a portion of its remaining gas supply to a number of its firm transportation customers for a one-year term which began November 1, 1993. The rest of Southern's remaining supply will be sold on a month-to-month basis. The difference between the cost associated with the gas supply contracts and the revenue from the sale agreements and month-to-month sales should be recoverable as a GSR cost pursuant to Order No. 636. In addition, any cost to terminate or reduce the price under Southern's remaining contracts should also be recoverable as a GSR cost pursuant to Order No. 636.
During 1993 Southern reached agreements to reduce significantly the price payable under a number of high-cost gas purchase contracts in exchange for payments with a present value of approximately $168 million.
Southern's purchase commitments under its remaining gas supply contracts for the years 1994 through 1998 are estimated as follows:
These estimates are subject to significant uncertainty due both to the number of assumptions inherent in these estimates and to the wide range of possible outcomes for each assumption. None of the three major factors which determine purchase commitments (underlying reserves, future deliverability and future price) is known today with certainty. As explained above, Southern expects to recover all of these costs, including its costs to terminate these purchase commitments, either through sale of the gas or as a GSR cost.
RATE MATTERS Several general rate changes have been implemented by Southern and remain subject to refund. See Note 9 of the Notes to Consolidated Financial Statements for a discussion of rate matters. CITRUS CORP. Citrus' historical losses are mainly due to a high level of depreciation and interest expense. However, since Citrus was acquired in mid-1986, cash generated by operations has been sufficient to fund normal capital expenditures and a portion of major expansion projects. Citrus' restructuring of its services in 1990 has helped to mitigate the effect of declines in the price of No. 6 fuel oil on its revenue and margins. However, the results of operations from Citrus have continued to be strongly influenced by the level of No. 6 fuel oil prices and the relationship of natural gas prices to fuel oil prices. Negotiations are under way to amend the gas supply services contract with its major customer.
Florida Gas has terminated its gas purchase contracts with a weighted average cost in excess of current spot-market prices and has been negotiating with its customers and the FERC to recover settlement payments made to terminate such contracts as a part of its Order No. 636 proceeding. On September 17, 1993, Florida Gas received approval of its restructuring settlement proposal (the Restructuring Settlement) with regard to the Order. The Restructuring Settlement includes a Transition Cost Recovery (TCR) mechanism that allows Florida Gas, effective November 1, 1993, to recover from its customers 100 percent of payments above the $106 million level approved in a previous settlement, up to $160 million. Florida Gas will be allowed to recover 75 percent of any amounts greater than $160 million. However, Florida Gas has substantially completed the renegotiation and termination of these contracts for less than $160 million and therefore expects to recover all of the amounts spent and not already expensed through its approved TCR mechanism.
Citrus has historically obtained its own financing independent of its parent companies. Debt financing by Citrus with outside parties is nonrecourse to its parent companies, and the Company has no contractual or legal requirement to maintain Citrus' liquidity. Citrus recently obtained a $300 million one-year financing that has support provisions from its parent companies. In connection with the construction of the Phase III expansion, the Company will advance Citrus funds and expects to have made an equity investment of approximately $150 million in 1994.
OFFSHORE DRILLING The Company participates in the offshore drilling business in markets around the world through its investment in Sonat Offshore. As a result of the IPO of Sonat Offshore's common stock on June 4, 1993, the Company currently retains ownership of approximately 40 percent of Sonat Offshore's outstanding shares.
The offshore drilling market in 1992 and 1993 generally experienced difficult conditions, although certain geographic areas have performed better than others. The North Sea market continues to be depressed in comparison with recent years, primarily due to the recent decline in oil prices and the effects of changes to the U.K. Petroleum Revenue Tax on exploratory drilling. Despite the recent awarding of additional licenses by the U.K. and Norwegian governments providing new drilling prospects and Sonat Offshore's belief that there has been a permanent reduction in the supply of rigs available to drill in the North Sea as a result of U.K. safety regulations, Sonat Offshore expects the North Sea market to remain weak in 1994, especially in the first half of the year. A strong natural gas price environment continues to support the U.S. Gulf of Mexico drilling market. As a result of the improved market, several drilling contractors, including Sonat Offshore, have recently moved rigs back to the Gulf of Mexico, and additional mobilizations are expected through early 1994. However, the recent influx of rigs and decline in oil prices have resulted in decreased dayrates over the past few months. Sonat Offshore believes the market will strengthen after the first quarter and will then remain strong for the remainder of 1994 as long as gas prices continue to remain at or above the corresponding 1993 levels.
In 1991 and 1992, Sonat Offshore was awarded three turnkey packages providing for the drilling of a total of 10 wells offshore Mexico. Two wells were completed under these three packages in 1992, six wells were completed in 1993 and one other well should be completed by mid-1994. In addition, one turnkey well was completed in 1993 in the U.S. sector of the Gulf of Mexico. Under a turnkey contract, Sonat Offshore is paid a fixed fee for drilling a well to a specified depth. Turnkey contracts generally provide an opportunity for greater profits than do conventional dayrate contracts, but entail more financial risk. Revenues and operating costs from turnkey contracts are much higher than under dayrate contracts since Sonat Offshore provides substantially more of the material and services necessary to drill the wells. Sonat Offshore continues to investigate additional turnkey opportunities as they arise, but there can be no assurance that Sonat Offshore will obtain additional contracts before the completion of its current projects.
In December 1993, Sonat Offshore entered into agreements with its partners in the Polar Frontier Drilling joint venture providing for the purchase of the remaining 52.5 percent interest in the semisubmersible rig, POLAR PIONEER, by Sonat Offshore for approximately $44.6 million plus certain adjustments relating to rig upgrades and drydocking estimated at $2.9 million and limited future consideration (up to $3 million) contingent upon the future operations of the POLAR PIONEER. The transaction closed on February 18, 1994.
As a result of management's reevaluation of the remaining useful lives of certain of its drilling units, effective January 1, 1993, Sonat Offshore adjusted the estimated working lives of these units from periods ranging 16-20 years to 25 years. This adjustment decreased Sonat Offshore's depreciation expense in 1993 by approximately $7 million. Offshore Drilling Operations
1993 Versus 1992. The pre-IPO amounts shown above reflect results of operations from January 1, 1993, through June 4, 1993, the completion date of the IPO. Amounts shown for 1992 and 1991 are for full years of operations. Hence, 1993 results are not comparable with the prior years due to the shorter period. The Company's share of Sonat Offshore's results for the period June 5, 1993, through December 31, 1993, is reflected in the above table as equity in earnings of Sonat Offshore.
On a 100 percent basis, Sonat Offshore's operating results for 1993 were favorable compared to 1992 due primarily to increased operating margins offshore Brazil, increased utilization of the Gulf of Mexico jack-up fleet and lower depreciation expense as mentioned above. General and administrative expense was also lower in 1993, primarily due to favorable adjustments relating to certain benefit plans. Operating results for 1993 also included favorable adjustments related to certain insurance accruals. These favorable results were partially offset by the recognition in 1992 of $7.7 million of deferred revenue relating to the termination of the DISCOVERER 534 contract.
1992 Versus 1991. In 1992 operating results for contract drilling operations were unfavorable primarily due to lower fleet utilization and lower operating margins per day. Margins from operations in the North Sea declined from 1991. Results in the Gulf of Mexico jack-up market, though not as significant to Sonat Offshore as its North Sea operations, showed significant improvement in the fourth quarter.
Turnkey operations in India contributed significantly to operating income in 1992. Operating income was otherwise negatively affected by higher operating expenses, higher depreciation expense and a $3 million increase in stock-based employee compensation.
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1993 Versus 1992. Other income in 1993 increased primarily due to the $155.8 million pretax gain on the Sonat Offshore IPO. In addition, dividends received on the Baker Hughes Incorporated preferred stock received in the sale of Teleco Oilfield Services Inc. in April 1992 contributed $12 million in 1993 and $7 million in 1992. 1992 included the recognition of a $9 million gain on the sale of oil and gas assets.
1992 Versus 1991. Other income in 1992 includes $9 million related to gains on the sale of oil and gas assets and $7 million from dividends received on the Baker Hughes preferred stock.
1993 Versus 1992. 1993 includes $31 million in net interest income related to a settlement of an examination of the Company's federal income tax returns for the years 1983-1985 and certain other tax issues. Interest expense was lower in 1993 due to decreased debt levels and lower interest rates, in part due to the refinancing of some higher interest rate debt during 1993.
1992 Versus 1991. Interest on debt decreased $7 million due to a decrease in average debt outstanding and lower average interest rates. The remainder is largely due to adjustments related to interest on income taxes.
1993 Versus 1992. Income taxes in 1993 increased due to higher pretax income including the gain on the Sonat Offshore IPO. The increase in taxes was partially offset by various tax adjustments, higher Section 29 tax credits and a settlement of an examination of the Company's federal income tax returns for the years 1983-1985.
1992 Versus 1991. Income taxes increased due to higher pretax earnings in 1992 and adjustments to overall tax provisions, partially offset by higher Section 29 tax credits.
1992 includes a $112.8 million gain on the sale of Teleco to Baker Hughes and a $.8 million loss on the disposal of the Company's insurance subsidiary.
In March 1993, the Company recognized a $4 million loss, net of taxes of $2 million, on the redemption of the Company's 7 1/4 Percent Zero Coupon, Subordinated Convertible Notes which were due September 6, 2005.
FINANCIAL CONDITION Cash Flows
1993 Versus 1992. Net cash provided by operating activities increased due to higher earnings at Sonat Exploration and a $62 million settlement of an examination of the Company's federal income tax returns for the years 1983-1985. Also contributing to the increase was the sale of storage gas inventory at Southern pursuant to Order No. 636 and lower cash outflows relating to gas imbalances. Partially offsetting the increase were GSR payments of approximately $128 million made by Southern in 1993.
1992 Versus 1991. Net cash provided by operating activities was higher due to improved operations and a tax refund at Sonat Exploration. Offsetting the increase was the inclusion of Teleco's operations for a full period in 1991.
1993 Versus 1992. Net cash used in investing activities increased $159 million in 1993. Capital expenditures of $516 million in 1993 were $290 million over the 1992 expenditures, primarily attributable to oil and gas acquisitions. A significant source of investing cash flows in 1993 was net cash proceeds of approximately $340 million from the sale of Sonat Offshore common stock. 1992 included cash proceeds of approximately $188 million from the sale of Teleco.
1992 Versus 1991. The net change in cash used in investing activities reflects the net cash proceeds from the sale of Teleco mentioned above as well as lower capital expenditures in 1992.
1993 Versus 1992. The net change in cash used in financing activities reflects a slight increase in debt repayments.
1992 Versus 1991. The change in net cash used in financing activities reflects the use of the proceeds from the sale of Teleco to pay down debt in 1992 as compared to an increase in borrowings in 1991. CAPITAL EXPENDITURES Capital expenditures for the Company's business segments (excluding unconsolidated affiliates) were as follows:
The Company's share of capital expenditures by its unconsolidated affiliates were as follows:
The Company's capital expenditures (including its $410 million share of unconsolidated affiliates' expenditures) for 1994 are expected to be $870 million and will include oil and gas acquisition, exploration and development, pipeline expansion and other projects. LIQUIDITY AND CAPITAL RESOURCES At December 31, 1993, the Company had lines of credit and a revolving credit agreement with a total capacity of $750 million. Of this, $546 million was unborrowed and available. The amount available under the lines of credit has been reduced by the amount of commercial paper outstanding of $60 million to reflect the Company's policy that credit line and commercial paper borrowings in the aggregate will not exceed the maximum amount available under its lines of credit. On July 26, 1993, Sonat filed a shelf registration with the Securities and Exchange Commission for up to $500 million in debt securities. The Company may use the proceeds from the sale of its registered debt securities to refinance the long-term debt redeemed in 1993.
As discussed in Note 3 of the Notes to Consolidated Financial Statements, the Company holds four million shares of Baker Hughes convertible preferred stock as well as 11.3 million shares of Sonat Offshore common stock. These resources, when combined with a strong cash flow and borrowings in the public or private markets, provide the Company with the means to invest for the future and continue earnings growth.
Capitalization Information
INFLATION AND THE EFFECT OF CHANGING ENERGY PRICES Although the rate of inflation in the United States has been moderate over the past several years, its potential impact should be considered when analyzing historical financial information. In past times of high general inflation, oil and gas prices have increased at comparable, and at times, higher rates. The changing regulatory environment in which the natural gas business operates, along with other competitive factors, would currently make it difficult to increase prices enough to recover significantly higher costs of operations. The results of operations in the Company's two major business segments will be affected by future changes in domestic and international oil and gas prices, the interrelationship between oil, gas and other energy prices and the ability of the Company's natural gas business to purchase gas at competitive prices. ENVIRONMENTAL ISSUES The Company's subsidiaries are involved in various environmental compliance and cleanup activities, and certain of these subsidiaries have been notified that they are one of many potentially responsible parties at certain federal Superfund sites. The Company does not expect costs relating to these activities, including any responsibility for cleanup of such sites, to be material, taken either separately or in the aggregate, with respect to the financial position or results of operations of the Company.
In addition, Southern has taken steps to test for the presence of polychlorinated biphenyls (PCB) at its natural gas compressor stations. A total of 13 stations evidenced some level of on-site PCB contamination ranging from low to moderate. Southern has completed the characterization and cleanup of 12 of these sites at a cost of approximately $6 million. Southern has partially completed the characterization and cleanup of the 13th site and believes that it should be able to complete the remediation of this site for a total cost of less than $5 million, approximately half of which had been incurred at December 31, 1993.
Sonat generally considers environmental assessment and remediation costs and costs associated with compliance with environmental standards for its regulated companies to be recoverable through rates since they are prudent costs incurred in the ordinary course of business, and accordingly, will seek recovery of such costs through rate filings, although no assurance can be given with regard to their ultimate recovery.
The Company has an active and ongoing environmental program at all levels of its organization and believes responsible environmental management is integral to its business. REPORT OF MANAGEMENT The management of the Company is responsible for the preparation and integrity of all financial data included in this annual report. The Consolidated Financial Statements have been prepared in conformity with generally accepted accounting principles and necessarily include amounts based on estimates and judgments of management.
The Company maintains a system of internal accounting controls designed to provide reasonable assurance that assets are safeguarded against loss or unauthorized use and that the financial records are adequate and reliable for preparation of financial statements and other financial data. The concept of reasonable assurance is based on the recognition that the cost of a system of internal accounting control must not exceed the related benefits. The systems of internal accounting control are complemented by the selection, training and development of qualified accounting and internal audit personnel.
The Company engages the firm of Ernst & Young as independent auditors to audit the Company's financial statements and express their opinion thereon. Their audits are conducted in accordance with generally accepted auditing standards and include a review and evaluation of the Company's internal accounting control systems and tests of transactions as they consider appropriate. The Report of Ernst & Young, Independent Auditors, appears on the facing page. Internal audit activities are coordinated with the independent auditors to maximize audit effectiveness.
The Audit Committee of the Board of Directors is composed solely of directors who are not active or retired officers or employees of the Company. It recommends a firm to serve as independent auditors of the Company, subject to nomination by the Board of Directors and election by the stockholders, authorizes all audit and other professional services rendered by the independent auditors and regularly reviews their independence. The Audit Committee reviews and reports on significant accounting decisions and transactions and the scope and results of audits by the Company's internal auditing staff and the independent auditors. It reviews with management and the independent auditors compliance with the Company's business ethics and conflict of interest policies and reviews with independent auditors the adequacy of the Company's system of internal controls. The internal auditors and the independent auditors have free access to the Audit Committee, without management's presence, to discuss the Company's internal controls and the results of their audits.
/s/ James E. Moylan, Jr. - ------------------------- JAMES E. MOYLAN, JR. Vice President and Controller February 24, 1994 REPORT OF ERNST & YOUNG, Independent Auditors The Board of Directors and Stockholders Sonat Inc.
We have audited the accompanying consolidated balance sheets of Sonat Inc. and Subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of income, changes in stockholders' equity and cash flows for each of the three years in the period ended December 31, 1993. These financial statements are the responsibility of the Company'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 consolidated financial position of Sonat Inc. and Subsidiaries at December 31, 1993 and 1992, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles.
/s/ Ernst & Young
Birmingham, Alabama January 20, 1994 CONSOLIDATED FINANCIAL STATEMENTS
CONSOLIDATED BALANCE SHEETS
See accompanying notes. CONSOLIDATED BALANCE SHEETS
See accompanying notes. CONSOLIDATED STATEMENTS OF INCOME
See accompanying notes. CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
See accompanying notes. CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes. NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. SIGNIFICANT ACCOUNTING POLICIES Principles of Consolidation-The Consolidated Financial Statements include the accounts of Sonat Inc. and its subsidiaries (the Company). Intercompany transactions and accounts have been eliminated in consolidation. The equity method of accounting is used for investments in affiliates owned 50 percent or less.
Certain amounts in the 1992 and 1991 Consolidated Financial Statements have been reclassified to conform with the 1993 presentation.
Cash Equivalents-Cash equivalents are typically money-market investments in the form of treasury bills, certificates of deposit and time deposits with original maturities of three months or less. These investments are accounted for at cost, which approximates market value.
Inventories-At December 31, 1993, inventories consist primarily of materials and supplies and are carried at cost.
Gas Imbalance Receivables and Payables-Gas imbalances represent the difference between gas receipts from and gas deliveries to the Company's transportation and storage customers. Gas imbalances arise when these customers deliver more or less gas into the pipeline than they take out. Under the provisions of Order No. 636, these amounts are settled monthly.
Plant, Property and Equipment and Depreciation-Plant, property and equipment is carried at cost. The Company provides for depreciation on a composite or straight-line basis, except for oil and gas properties. (See Notes 6 and 13.)
Revenue Recognition-Revenue is recognized in the Exploration and Production segment when deliveries of oil and natural gas are made. The Company's Natural Gas Transmission and Marketing segment recognizes revenue from both natural gas sales and transportation in the period the service is provided. Reserves are provided on revenues collected subject to refund when appropriate. Revenues included in the Consolidated Statements of Income for the Offshore Drilling segment were recognized as earned through June 4, 1993, based on contractual daily drilling rates, or on a per-well basis. (See Note 3.)
Foreign Currency Translation-For periods in which the Company had foreign operations, the U.S. dollar was the functional currency. The effect of foreign currency exchange transactions included in "Other Income" for those periods was not material. (See Note 3.) Income Taxes-The Company follows an asset and liability approach in accounting for income taxes. Deferred tax assets and liabilities are determined using the tax rate for the period in which those amounts are expected to be received or paid.
Futures-The Company engages in the gas futures market to lock in natural gas prices in its exploration and production business and in its gas marketing business to decrease volatility related to fluctuations in spot-market prices. Gains or losses resulting from changes in the market value of these transactions entered into as hedges are deferred until the hedged commodity transaction occurs. Neither net futures positions nor the unrecognized gain at December 31, 1993, was material.
Swaps-The Company engages in oil and gas price swap agreements with certain counterparties to effectively manage a portion of the market risk associated with fluctuations in the prices of natural gas and crude oil and to provide risk management services to its customers. The agreements call for the Company to make payments to (or receive payments from) other parties based upon the differential between a fixed and a variable price as specified by the contract. At December 31, 1993, the Company had a price swap agreement having a notional contract amount of 4,105,000 MMBtu of natural gas equivalent. This agreement runs for a period of three years.
Issuance of Stock by Subsidiary-The Company follows an accounting policy of income statement recognition for issuances of stock by a subsidiary. Other than the initial public offering (IPO) by Sonat Offshore Drilling Inc. (see Note 3) there have been no issuances of subsidiary stock during the periods presented in these financial statements.
Earnings Per Share-Earnings per share amounts are computed on the basis of the weighted average number of common shares outstanding during the periods. (See Note 10.)
2. FINANCIAL INSTRUMENTS The carrying amounts and fair values of the Company's financial instruments are as follows:
The following methods and assumptions were used by the Company in estimating its fair value disclosures for financial instruments:
Cash and cash equivalents, gas supply realignment costs, natural gas purchase contract settlement costs and unsecured notes payable: The carrying amount reported in the balance sheet approximates its fair value.
Investment securities: The fair value for equity securities is estimated using values obtained from an independent appraisal. The fair values for marketable debt securities are based on quoted market prices.
Long-term debt: The fair values of the Company's long-term debt are based on quoted market values or estimated using discounted cash flow analyses, based on the Company's current incremental borrowing rates for similar types of borrowing arrangements.
3. CHANGES IN OPERATIONS Stock Sale by Subsidiary-On June 4, 1993, the IPO of Sonat Offshore's common stock at $22.00 per share was closed. Prior to the offering, the Company owned 100 percent of Sonat Offshore. Sonat Offshore issued 15.5 million shares, and the Company sold 1.448 million of its shares resulting in a combined pretax gain of $155.8 million. Net cash proceeds from the combined transactions after underwriting commissions, expenses and tax provisions totaled approximately $340 million. The Company retained ownership of approximately 40 percent of Sonat Offshore's outstanding shares and recognized an after-tax gain of $99.7 million, or $1.15 per share, from the combined transactions. At December 31, 1993, the Company held 11.3 million shares of Sonat Offshore common stock at a market value of $180.0 million. Discontinued Operations-On April 23, 1992, the Company completed the sale of Teleco Oilfield Services Inc. to Baker Hughes Incorporated. The Company received $200 million in cash and four million shares of Baker Hughes convertible preferred stock. The convertible preferred stock has a face amount of $200 million, a dividend rate of 6 percent per annum, and is convertible at $32.50 per share into Baker Hughes common stock. The Company attributed a value of $180 million to the noncash portion of the transaction which is included in "Other Investments" on the Consolidated Balance Sheets.
Summary operating results of discontinued operations are as follows:
4. INVENTORIES The table below shows the values of various categories of the Company's inventories by business segment.
Gas stored underground decreased due to the sale of $123 million of storage gas inventory by Southern pursuant to the implementation of Order No. 636 on November 1, 1993. (See Note 9.)
5. UNCONSOLIDATED AFFILIATES At December 31, 1993, the Company's investments in unconsolidated affiliates totaled $295.2 million, and the Company's share of underlying equity in net assets of the investees was $363.1 million. The difference is primarily due to the excess over cost of the Company's share of the underlying equity in net assets of Citrus Corp., which is being amortized over the depreciable life of Citrus' assets. Through December 31, 1993, the Company's cumulative equity in earnings of these unconsolidated affiliates was $177.8 million and cumulative dividends received from them totaled $134.0 million. The following table presents the components of equity in earnings of unconsolidated affiliates.
Exploration and Production Affiliate-Sonat Exploration Company had an initial 49 percent interest in Sonat/P Anadarko Limited Partnership (Sonat/P) which acquired oil and gas reserves in the Anadarko Basin of Oklahoma from Louisiana Land and Exploration Company in the third quarter of 1992. On October 4, 1993, Sonat Exploration acquired the limited partnership interest of Prudential Insurance Company in Sonat/P. (See Notes 7 and 13.) For the 1993 period prior to acquisition, Sonat/P had revenues of $16.3 million and reported earnings of $6.6 million. The Company's investment in Sonat/P at December 31, 1992, was $19.7 million. Sonat/P had revenues of $6.1 million and reported earnings of $2.5 million in 1992.
Natural Gas Transmission and Marketing Affiliates- Sonat owns 50 percent of Citrus, the parent of Florida Gas Transmission Company. Southern Natural Gas Company owns 50 percent of Bear Creek Storage Company, an underground gas storage company.
The following is summarized financial information for Citrus:
On December 23, 1993, Citrus entered into a $300 million, 364-day revolving credit agreement with a group of banks. Advances under the credit agreement may be used for general corporate purposes, including the interim construction costs for Florida Gas' Phase III expansion project. The Company is providing indirect credit support to the extent of up to 50 percent of the outstanding advances in the form of a standby note purchase agreement for up to $150 million principal amount plus accrued interest and/or fees if any. At December 31, 1993, $275 million was outstanding under the credit agreement at a rate of 3.63 percent.
In connection with the expansion project, the Company expects to make an equity investment of $150 million in 1994.
The following is summarized financial information for Bear Creek. No provision for income taxes has been included since its income taxes are paid directly by the joint-venture participants.
Offshore Drilling Affiliate-The Company's investment in Sonat Offshore has been accounted for on the equity method since June 5, 1993 (see Note 3). The following is summarized financial information for Sonat Offshore:
6. PLANT, PROPERTY AND EQUIPMENT AND DEPRECIATION Plant, property and equipment, by business segment, is shown in the following table (see Note 3).
Plant, property and equipment includes construction work in progress of $56.0 million and $49.0 million at December 31, 1993 and 1992, respectively.
The accumulated depreciation, depletion and amortization amounts, by business segment, are as follows:
The annual depreciation rates or useful productive lives, by business segment, are as follows:
The successful efforts method of accounting results in the cost of proved oil and gas properties and development dry holes being capitalized and amortized on a unit-of-production basis over the life of remaining proved reserves. Also included in amortization on a unit-of-production basis are the estimated future dismantlement and abandonment costs.
7. LONG-TERM DEBT AND LINES OF CREDIT Long-Term Debt-Long-term debt consisted of:
Annual maturities of long-term debt at December 31, 1993, are as follows:
On March 15, 1993, Sonat redeemed all of its outstanding 7 1/4 Percent Zero Coupon, Subordinated Convertible Notes due September 6, 2005, at a cost of approximately $272 million. The funds utilized for the redemption consisted of $52 million of cash on hand and a $220 million borrowing under Sonat's $500 million revolving credit agreement. The Company recognized an extraordinary noncash loss after income taxes of $3.8 million, or $.04 per share, on the redemption.
On June 1, 1993, Sonat redeemed all of its outstanding 9 7/8 Percent Notes due June 1, 1996, at par value plus accrued interest, totaling approximately $210 million. The funds utilized for the redemption were provided from cash on hand.
On October 4, 1993, in connection with Sonat Exploration's purchase of Prudential's interest in Sonat/P, Sonat issued to Prudential $18.5 million of 8.24 Percent Senior Notes dated September 30, 1993, to mature December 31, 2000. Proceeds from the notes were utilized by Sonat to purchase all of Sonat/P's outstanding notes to Prudential.
On November 23, 1993, in connection with the acquisition of certain oil and gas properties by Sonat Exploration, Sonat issued a promissory note for $43.8 million payable in full on January 3, 1994.
Lines of Credit and Credit Agreement-At December 31, 1993, the Company had available $546 million under short-term lines of credit and a revolving credit agreement. The amount available under the lines of credit has been reduced by the amount of commercial paper outstanding to reflect the Company's policy that credit line and commercial paper borrowings in the aggregate will not exceed the maximum amount available under its lines of credit. On May 31, 1993, Sonat and Southern renewed their short-term lines of credit of $200 million and $50 million, respectively, for a period of 364 days. Borrowings are in the form of unsecured promissory notes and bear interest at rates based on the banks' prevailing prime, international or money-market lending rates. On December 15, 1993, Sonat renegotiated and extended its revolving credit agreement with a group of banks. The revolving credit agreement will provide for periodic borrowings and repayments of up to $500 million through December 15, 1998. Borrowings are supported by unsecured promissory notes that at the option of the Company, will bear interest at the banks' prevailing prime or international lending rate, or such rates as the banks may competitively bid. At December 31, 1993, $9 million was outstanding under the lines of credit at a rate of 3.38 percent, $135 million was outstanding under the revolving credit agreement at a rate of 3.75 percent, and $60 million in commercial paper was outstanding at an average rate of 3.64 percent.
8. INCOME TAXES An analysis of the Company's income tax expense (benefit) on continuing operations is as follows:
Net deferred tax liabilities are comprised of the following:
The Company has not provided a valuation allowance to offset deferred tax assets because, based on the weight of available evidence, it is more likely than not that all deferred tax assets will be realized.
Consolidated income tax expense relating to continuing operations is different from the amount computed by applying the U.S. federal income tax rate to income from continuing operations before income tax. The reasons for this difference are as follows:
The effect of the deferred tax rate increase to 35 percent due to the Omnibus Budget Reconciliation Act of 1993 has been reduced by the effect of the Company's regulated subsidiaries' reduction of liabilities established for excess deferred income taxes expected to be returned over future periods to customers.
The domestic and foreign components of income (loss) from continuing operations before income taxes are as follows:
9. COMMITMENTS AND CONTINGENCIES Leases-The Company has operating lease commitments expiring at various dates, principally for office space and equipment. The Company has no significant capital leases.
Rental expense for all operating leases from continuing operations is summarized below:
At December 31, 1993, future minimum payments for non-cancelable operating leases for the years 1994 through 1998 are less than $7 million per year.
Rate Matters-Periodically, Southern and its subsidiaries file general rate filings with the FERC to provide for the recovery of cost of service and a return on equity. The FERC normally allows the filed rates to become effective, subject to refund, until it rules on the approved level of rates. Southern and its subsidiaries provide reserves relating to such amounts collected subject to refund, as appropriate, and make refunds upon establishment of the final rates.
On September 1, 1989, Southern implemented new rates, subject to refund, reflecting a general rate decrease of $6 million. In January 1991, Southern implemented new rates, subject to refund, that restructured its rates consistent with a FERC policy statement on rate design and increased its sales and transportation rates by approximately $65 million annually. These two proceedings have been consolidated for hearing. On October 7, 1993, the presiding administrative law judge certified to the FERC a contested offer of settlement pertaining to the consolidated rate cases which (1) resolved all outstanding issues in the rate decrease proceeding, (2) resolved the cost of service, throughput, billing determinant and transportation discount issues in the rate increase proceeding, and (3) provided a method to resolve all other issues in the latter proceeding, including the appropriate rate design. On December 16, 1993, the FERC issued an order (December 16 Order) approving the settlement, but with modifications. On December 22, 1993, Southern filed a letter with the FERC that outlined certain objections with respect to the FERC's modifications to the terms and conditions of the settlement. Southern advised the FERC that the December 16 Order undercut the economic compromise achieved in the settlement. Southern also filed a request for rehearing of the December 16 Order but is unable to determine at this time if or to what extent rehearing will be granted by the FERC.
On September 1, 1992, Southern implemented another general rate change. The rates reflected the continuing shift in the mix of throughput volumes away from sales and toward transportation and a $5 million reduction in annual revenues. On April 30, 1993, Southern submitted a proposed settlement in the proceeding which, if approved by the FERC, would resolve the throughput and certain cost of service issues. On June 4, 1993, the presiding administrative law judge certified the settlement to the FERC. In another order issued on December 16, 1993, the FERC also approved this settlement, but with modifications. Southern objects to these modifications and has also requested rehearing of this order, but is unable to determine at this time if rehearing will be granted by the FERC.
In 1992 Southern placed in service certain facilities constructed to connect to its pipeline system gas reserves produced from certain Mississippi Canyon and Ewing Bank Area Blocks, offshore Louisiana. By order dated May 15, 1991, the FERC had authorized Southern, subject to certain conditions affecting Southern's ability to include the cost of the facilities in its rates, to construct and operate the pipeline, compression, and related facilities necessary to connect these reserves. Southern sought rehearing of the unacceptable certificate conditions, but in an order issued on January 13, 1993, the FERC left intact the conditions contained in its 1991 order. It deferred the specific application of the conditions to Southern's pending rate case implemented September 1, 1992. The certificate order itself is now on appeal. The Company is unable to predict the ultimate rate treatment of the $45 million cost of these facilities, but does not expect such treatment to have a material adverse effect on its financial position.
On May 1, 1993, Southern implemented a general rate change, subject to refund, which increased its sales and transportation rates by approximately $57 million annually. The filing is designed to recover increased operating costs and to reflect the impact of competition on both Southern's level and mix of services. A hearing regarding various cost allocation and rate design issues in this proceeding is set for June 14, 1994.
Sea Robin Pipeline Company has previously filed under the provisions of Order No. 500 to recover $83.1 million in gas purchase contract settlement payments from its former pipeline sales customers, Koch Gateway Pipeline Company, successor to United Gas Pipe Line Company (United), and Southern. Those filings remain subject to refund pending the outcome of any prudence challenges in the proceedings. Although the eligibility issues have been resolved, one party has reserved its rights to challenge prudence until such time as certain take-or-pay allocation issues are resolved with respect to the flow-through of costs billed to United.
Southern is authorized to flow through to its jurisdictional customers $38.1 million of the costs allocated to it by Sea Robin as well as the $32.7 million in Order No. 500 costs allocated to it by United. Southern's flow-through of United and Sea Robin's costs remains subject to refund pending the outcome of any challenges to the costs or allocation of the costs in those pipelines' Order No. 500 proceedings. The Company does not believe that the outcome of any such challenges will have a material adverse effect on its financial position.
On July 2, 1993, the FERC issued an order reaffirming its approval of the non-take-or-pay aspects of a settlement filed by United in 1988, which included Southern's phased abandonment of its contract demand with United. The order rejected the take-or-pay aspects of the settlement, including United's proposed Order No. 528 allocation methodology. As a consequence, various parties that had originally supported the settlement are now contesting it. United has evidenced its intention to honor the non-take-or-pay aspects of the 1988 settlement and has induced several of the parties to withdraw their judicial appeals of the July 2 order. The Company does not believe that the final resolution of this matter will have a material adverse effect on its financial position.
Gas Purchase Contracts-Gas purchase contract settlement payments (other than the gas supply realignment payments discussed below) made by Southern and not previously recovered or expensed are included on the Consolidated Balance Sheet at December 31, 1993, in "Current Assets." Pursuant to a final and nonappealable FERC order, Southern is entitled to collect these amounts from its customers over the remainder of a five-year period which commenced May 1, 1989. Southern currently is incurring essentially no take-or-pay liabilities under its gas purchase contracts. Southern regularly evaluates its position relative to gas purchase contract matters, including the likelihood of loss from asserted or unasserted take-or-pay claims or above-market prices. When a loss is probable and the amount can be reasonably estimated, it is accrued.
Order No. 636-In 1992 the FERC issued its Order No. 636 (the Order). The Order requires significant changes in interstate natural gas pipeline services. Interstate pipeline companies, including Southern, are incurring certain costs (transition costs) as a result of the Order, the principal one being costs related to amendment or termination of existing gas purchase contracts, which are referred to as gas supply realignment (GSR) costs. The Order provides for the recovery of 100 percent of the GSR costs and other transition costs arising out of the implementation of the Order to the extent that the pipeline can prove that they were prudently incurred. Numerous parties have appealed the Order to the Circuit Courts of Appeal.
On September 3, 1993, the FERC generally approved a compliance plan for Southern and directed Southern to implement its restructured services pursuant to the Order on November 1, 1993 (the September 3 order). Pursuant to Southern's compliance plan, GSR costs that are eligible for recovery include payments to reform or terminate gas purchase contracts or, for contracts where Southern can show that it can minimize transition costs by continuing to purchase gas under the contract (i.e., it is more economic to continue to perform), the difference between the contract price and the higher of (a) the sales price for gas purchased under the contract, or (b) a price established by an objective index of spot-market prices. Recovery of these latter costs is permitted for an initial period of two years.
Southern's compliance plan contains two mechanisms pursuant to which Southern is permitted to recover 100 percent of its GSR costs. The first mechanism is a monthly fixed charge designed to recover 90 percent of the GSR costs from Southern's firm transportation customers. The second mechanism is a volumetric surcharge designed to collect the remaining 10 percent of such costs from Southern's interruptible transportation customers. This funding will continue until the GSR costs are fully recovered or funded. The FERC also permitted Southern to file to recover any GSR costs not recovered through the volumetric surcharge after a period of two years. In addition, Southern's compliance plan provides for the recovery of other transition costs as they are incurred and any remaining transition costs may be recovered through a regular rate filing.
The September 3 order rejected the argument of certain customers that a 1988 take-or-pay recovery settlement bars Southern from recovering GSR costs under gas purchase contracts executed before March 31, 1989. Those customers have filed motions urging the FERC to reverse its ruling on that issue. On December 16, 1993, the FERC affirmed its September 3 ruling with respect to the 1988 take-or-pay recovery settlement. The December 16 Order generally approved Southern's restructuring tariff submitted pursuant to the September 3 order. Various parties have filed motions urging the FERC to modify the December 16 Order and have sought judicial review of the September 3 order. Southern and its customers engaged in settlement discussions regarding Southern's restructuring filing prior to the September 3 order, but the parties were unable to reach a settlement. Those discussions are continuing.
During 1993 Southern reached agreements to reduce significantly the price payable under a number of high cost gas purchase contracts in exchange for payments of approximately $114 million. On December 1, 1993, Southern filed to recover such costs and approximately $3 million of prefiling interest. On December 30, 1993, the FERC accepted such filing to become effective January 1, 1994, subject to refund, and subject to a determination that such costs were prudently incurred and eligible under Order No. 636. The December 30 order rejected arguments of various parties that a pipeline's payments to affiliates, which represented approximately $34 million of the December 1, 1993 filing, may not be recovered under Order No. 636.
In December 1993, Southern reached agreement to reduce the price under another contract in exchange for payments having a present value of approximately $52 million which is included in "Deferred Credits and Other" in the Consolidated Balance Sheet. Payments will be made in equal monthly installments over an eight-year period ending December 31, 2001. Southern expects to make a limited rate filing by mid-February 1994 to recover such costs beginning April 1, 1994. Southern has also incurred approximately $11 million of costs during November and December 1993 from continuing to purchase gas under contracts that are in excess of current market prices. Southern will make additional rate filings to recover these costs quarterly. The total costs of $180 million accrued through December 31, 1993, are included in current and long-term gas supply realignment costs in the Consolidated Balance Sheet.
Southern is unable to predict all of the elements of the ultimate outcome of its Order No. 636 restructuring proceeding, its settlement discussions with its customers, and the limited rate filings to recover its transition costs.
10. CAPITAL STOCK On July 22, 1993, the Company's Board of Directors approved a two-for-one stock split which became effective September 14, 1993, to stockholders of record on August 31, 1993. All share, per share and dividend amounts reported in the Consolidated Financial Statements have been restated to reflect the two-for-one stock split.
Per share prices of the Company's common stock, based on the New York Stock Exchange listing of composite transactions, and dividends paid per common share for the last two years are summarized below. Price Range and Dividends Paid Per Common Share (Unaudited)
The Company had no restrictions on the payment of dividends at December 31, 1993.
The Company has a Stockholder Rights Plan designed to protect the interest of stockholders in the event of a hostile attempt to take over the Company and to make it more difficult for a person to gain control of the Company in a manner or on terms not approved by the Board of Directors. The rights under the Plan are redeemable at any time by the Company before the end of their 10-year term, February 3, 1996, so long as an entity has not acquired 20 percent or more of the Company. As of December 31, 1993, 92,675,535 shares of common stock were reserved for issuance under this Plan.
The Company has a Restricted Stock Plan for non-employee members of the Board of Directors of Sonat Inc. Full rights vest over a maximum of five years. The Company issued 21,200 shares during 1993. At December 31, 1993, 13,860 of the 35,060 cumulative shares granted have vested.
Executive Award Plan-The Company has an Executive Award Plan that provides awards to certain key employees in the form of stock options, restricted stock, and stock appreciation rights (SARs) in tandem with any or all stock options. In years prior to 1991, tax offset payments were generally provided in conjunction with these awards. SARs permit the holder of an exercisable option to surrender that option for an amount equal to the excess of the market price of the common stock on the date of exercise over the option price (appreciation). The appreciation is payable in cash, common stock, or a combination of both. SARs are subject to the same terms and conditions as the options to which they are related. No SARs have been issued since 1990. At December 31, 1993, 392,134 SARs were outstanding. The Company issued 62,400 shares of restricted stock to employees during 1993. The shares generally vest 10 years from the date of grant, unless the closing price of the Company's common stock achieves certain specified levels. At December 31, 1993, 33,316 of the 246,300 cumulative restricted shares issued have vested.
The following table summarizes option activities in the Plan:
Stock-based employee compensation decreased pretax income by $12.6 million in 1993, decreased pretax income by $9.3 million in 1992 and increased pretax income by $12.3 million in 1991.
At December 31, 1993 and 1992, there were 10,000,000 shares of Preference Stock authorized, with none issued.
11. RETIREMENT PLANS AND OTHER POST EMPLOYMENT BENEFITS Retirement Plans-Sonat Inc. has a trusteed, non-contributory, tax qualified defined benefit retirement plan (the Retirement Plan) covering substantially all domestic employees of the Company. A supplemental benefit plan (the Supplemental Plan) that provides retirement benefits in excess of those allowed under the Company's tax qualified retirement plan is also in effect for the Company. Benefits under the plans are based on a combination of years of service and a percentage of compensation. Benefits are vested over five years.
In connection with the Sonat Offshore divestiture, the qualified retirement plan assets and liabilities related to Sonat Offshore employees were transferred to a new, separate qualified retirement plan to be maintained by Sonat Offshore. As a result of splitting the plans, Sonat recorded a $4 million prepaid pension asset. For the Supplemental Plan, Sonat has retained the obligation to pay the supplemental benefit accrued through the date of the IPO for all of Sonat Offshore's current and retired employees. An additional $2.7 million liability was recorded by Sonat for this obligation. Sonat Offshore retains responsibility for the obligation to its employees' supplemental benefits subsequent to the date of the IPO.
The Company determines the amount of funding to the Retirement Plan on a year-to-year basis, with amounts consistent with minimum and maximum funding requirements established by various governmental bodies. The trust established to provide benefits under the Supplemental Plan is being funded; however, this trust is not subject to any funding requirements. At December 31, 1993, this trust had assets with a fair market value of $33.5 million to pay benefits under the Supplemental Plan.
The Company's net periodic pension cost included in continuing operations consists of the following components:
For a limited period during 1993 and 1991, special early retirement programs were offered to certain employees. The total cost of the programs was $5.5 million and $12.2 million, respectively. All of the 1993 costs related to regulated operations and are deferred to be collected in future rates.
The following table sets forth the assets and liabilities of the plans and the amount of the net pension liability recognized in the Company's Consolidated Balance Sheets.
(1) The Retirement Plan. (2) The Supplemental Plan. (3) Plan assets consist of equity securities, commingled funds and debt securities. (4) Amortization periods for unrecognized net (asset) or obligation are 16.5 years for the Retirement Plan and 15 years for the Supplemental Plan. (5) Amortization periods for early retirement termination benefits are 10 years for the Retirement Plan and five years for the Supplemental Plan.
Until July 1993, the Company set aside assets in fixed income securities such that values of those assets equal or exceed the present value of the Company's benefit obligations to current retirees (immunized obligations). After that date, a separate immunized portfolio has not been maintained. The assumed rates used to measure the projected benefit obligations and the expected earnings of plan assets are:
Other Post Employment Benefits-The Company has plans that provide for postretirement health care and life insurance benefits to substantially all of its domestic employees when they retire. The Company adopted Statement of Financial Accounting Standards (SFAS) No. 106, "Employers' Accounting for Postretirement Benefits Other Than Pensions," for all plans as of January 1, 1993. SFAS No. 106 requires companies to accrue the cost of postretirement health care and life insurance benefits within the employees' active service periods. The Company has elected to amortize the transition obligation over a 20-year period. The Company previously expensed the cost of its retiree medical benefits as they were paid. Expense for retiree life insurance benefits was recognized as the Company funded its Retiree Life Insurance Plan.
With respect to the Sonat Offshore IPO, Sonat Offshore will maintain responsibility for its retired employees for both health care and life insurance benefits. The portion of assets held by Sonat in a Continued Life Insurance Reserve fund that related to Sonat Offshore employees, $1.2 million, was transferred to Sonat Offshore during 1993.
The annual net periodic cost for postretirement health care and life insurance benefits for the year ended December 31, 1993, includes the following components:
Prior to the adoption of SFAS No. 106, the cost of providing health care and life insurance benefits was $5.1 million and $5.2 million in 1992 and 1991, respectively.
Southern implemented rates effective May 1, 1993, which provide for the recovery of its $9.7 million share of the 1993 expense. Costs incurred in 1993 prior to that date, amounting to $2.6 million, were deferred to be amortized over a three-year period commencing when Southern's next rate case becomes effective.
The Company funds its Retiree Life Insurance Plan with the amount of funding determined on a year-to-year basis with the objective of having assets equal plan liabilities. In addition, during 1993 the Company initiated funding of postretirement health care benefits for employees of its regulated subsidiaries in an amount generally equal to the subsidiaries' SFAS No. 106 expense. The following table sets forth the funded status at December 31, 1993, and at the date of SFAS No. 106 adoption, January 1, 1993, for the Company's postretirement health care and life insurance plans:
(1) Plan assets are held in a life insurance reserve account and consist primarily of fixed income securities.
The assumed rates used to measure the projected benefit obligation and the expected earnings of plan assets are:
The rate of increase in the per capita costs of covered health care benefits is assumed to be 12.3 percent in 1994, decreasing gradually to 6 percent by the year 2002. Increasing the assumed health care cost trend rate by 1 percentage point would increase the accumulated postretirement benefit obligation as of December 31, 1993, by approximately $8.9 million and increase the service cost and interest cost components of the net periodic postretirement benefit cost by approximately $.7 million.
12. BUSINESS SEGMENT AND GEOGRAPHIC AREA ANALYSIS The Company's financial statements reflect operations in three segments: Exploration and Production, Natural Gas Transmission and Marketing, and Offshore Drilling. The Exploration and Production segment is involved in exploration, development and production of domestic oil and natural gas. The principal activity of the Natural Gas Transmission and Marketing segment is the interstate transmission and sale of natural gas. The Offshore Drilling segment provides contract drilling services in offshore areas. The Sonat Offshore IPO closed on June 4, 1993; therefore, the offshore drilling information shown for 1993 reflects results from January 1, 1993, through June 4, 1993. The Company's share of Sonat Offshore's results for the period June 5, 1993, through December 31, 1993, is shown as equity in earnings of Sonat Offshore. Intersegment sales are primarily gas sales by the Exploration and Production segment and are generally priced at rates determined by market forces.
Operating profit is revenues less operating expenses. In determining operating profit, none of the following items have been included: unallocated general corporate revenues and expenses, interest, dividend and other income, interest expense, income taxes and equity in earnings of unconsolidated affiliates. Business Segment Analysis
Financial instruments, which potentially subject the Company to concentration of credit risks, consist principally of accounts receivables. Customers of the Exploration and Production segment include primarily oil and gas marketing companies and also pipeline companies. Revenues and accounts receivable of the Natural Gas Transmission and Marketing segment relate to business conducted with gas distribution companies, municipalities, gas districts, industrial customers and other interstate pipeline companies in the Southeast.
The Company performs ongoing credit evaluations of its customers' financial condition and, in some circumstances, requires collateral from its customers.
Revenues from the Major Unaffiliated Customers of the Natural Gas Transmission & Marketing Segment
Capital expenditures for unconsolidated affiliates are accounted for on the books of the unconsolidated affiliates and therefore are not reflected in the totals appearing in the Company's consolidated financial statements. Capital Expenditures by Business Segment
Identifiable assets by business and geographic area are those assets that are used in the Company's operations in each business and location. Corporate assets are typically investments, cash and equipment.
Assets by Business Segment
Revenues and operating profit from continuing operations of domestic and foreign operations have been computed consistent with the methods previously discussed. Foreign operations were conducted by the Company's offshore drilling subsidiary. The following table summarizes by domestic and foreign areas revenues, operating profit and equity in earnings of unconsolidated affiliates by year and identifiable assets and investments in unconsolidated affiliates by domestic and foreign areas at the end of each year.
Geographic Area Analysis
Foreign cash equivalents amounted to $18.4 million and $9.7 million at December 31, 1992 and 1991, respectively.
13. OIL AND GAS OPERATIONS (Unaudited) At December 31, 1993, the Company had interests in oil and gas properties that are located primarily in Texas, Louisiana, Arkansas, Oklahoma, Alabama, and offshore Louisiana and Texas, in the Gulf of Mexico. The Company does not own or lease any oil and gas properties outside the United States.
In October 1993, the Company purchased Prudential Insurance Company's interest in Sonat/P, whereby the partnership was subsequently dissolved. (See Note 5.) Capitalized costs relating to oil and gas producing activities and related accumulated depreciation, depletion and amortization were as follows:
Capitalized Costs
Costs incurred in oil and gas producing activities were as follows:
Net quantities of proved developed and undeveloped reserves of natural gas and crude oil, including condensate and natural gas liquids, and changes in such quantities were as follows:
Reserve Data
The significant changes to reserves, other than acquisitions, dispositions or production, are due to reservoir performance in existing fields, drilling of additional wells in existing fields and development of new fields. No major discovery or other event, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves, has occurred since December 31, 1993.
Results of operations from producing activities by fiscal year were as follows:
Results of Operations
The standardized measure of discounted future net cash flows relating to proved oil and gas reserves follows:
Standardized Measure of Discounted Future Net Cash Flows
For the calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using average year-end oil and gas prices. The following are the principal sources of change in the standardized measure of discounted future net cash flows:
Changes in Standardized Measure of Discounted Future Net Cash Flows
14. QUARTERLY RESULTS (Unaudited) Shown below are selected unaudited quarterly data.
(1) Net income for the second quarter of 1993 includes a gain of $99.7 million, or $1.15 per share, from the closing of the initial public offering of Sonat Offshore Drilling Inc. common stock. Net income also includes a net gain of $21 million, or $.24 per share, related to the settlement of an examination of the Company's federal income tax returns from 1983 through 1985 and other tax issues. The third quarter of 1993 includes a loss of $12 million, or $.14 per share, due to the Omnibus Budget Reconciliation Act of 1993 which increased corporate and personal income tax rates. Net income also included favorable income tax adjustments of $4 million, or $.05 per share. Net income for the fourth quarter of 1993 includes favorable income tax adjustments of $3 million, or $.03 per share.
(2) Income from discontinued operations for the second quarter of 1992 includes the gain on the sale of Teleco Oilfield Services Inc. of $112.8 million or $1.30 per share. Also, net income includes a loss of $3 million, or $.03 per share, relating to restructuring charges. Net income for the third quarter of 1992 includes favorable adjustments of $6 million related to a settlement regarding Southern Energy Company's idle liquefied natural gas facilities and a loss for the Company's share of Citrus Corp.'s recognition of natural gas purchase contract settlement costs of $3.4 million, for a total favorable impact of $.04 per share. Net income for the fourth quarter of 1992 includes a loss for the Company's share of Citrus Corp.'s recognition of natural gas purchase contract settlement costs of $1.3 million or $.01 per share. SELECTED CONSOLIDATED FINANCIAL DATA (1)
Notes: (1) All earnings per share amounts and dividend amounts reflect a two-for-one stock split effective September 14, 1993. (2) Discontinued operations include the measurement-while-drilling businesses as of 1991, the marine transportation and underwater services businesses as of 1986, and the forest products business as of 1984. (3) In March 1993, the Company recognized a loss on the redemption of the Company's 7 1/4 Percent Zero Coupon, Subordinated Convertible Notes which were due September 6, 2005.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
Sonat has not had a change in accountants within twenty-four months prior to the date of its most recent financial statements or in any period subsequent to such date.
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PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT
The information regarding the Directors and nominees for Director of Sonat required by Item 401 of Regulation S-K is presented under the heading "Election of Directors" in the Proxy Statement of Sonat Inc. dated as of March 16, 1994 (the "Proxy Statement"), which information is hereby incorporated by reference herein. A copy of the Proxy Statement is filed as an exhibit to this report on Form 10-K. Information regarding the executive officers of Sonat is presented following Item 4 of this report, as permitted by General Instruction G(3) to Form 10-K and Instruction 3 to Item 401(b) of Regulation S-K.
ITEM 11. EXECUTIVE COMPENSATION
The information required by Item 402 of Regulation S-K regarding executive compensation is presented under the headings "Compensation of Outside Directors" and "Compensation of Executive Officers" in the Proxy Statement, which information is hereby incorporated by reference herein. Notwithstanding the foregoing, the information provided under the headings "Report of the Executive Compensation Committee" and "Performance Graph" in the Proxy Statement are not incorporated by reference herein. A copy of the Proxy Statement is filed as an exhibit to this report on Form 10-K.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
The information regarding the security ownership of certain beneficial owners and management required by Item 403 of Regulation S-K is presented under the headings "Ownership of Common Stock by Directors and Executive Officers" and "Institutional Ownership of Common Stock" in the Proxy Statement, which information is hereby incorporated by reference herein. A copy of the Proxy Statement is filed as an exhibit to this report on Form 10-K.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
The information regarding certain relationships and related transactions required by Item 404 of Regulation S-K is presented under the heading "Certain Business Relationships and Transactions" in the Proxy Statement, which information is hereby incorporated by reference herein. A copy of the Proxy Statement is filed as an exhibit to this report on Form 10-K.
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PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K
(a) Index to Financial Statements, Financial Statement Schedules, and Exhibits
1. FINANCIAL STATEMENTS
2. FINANCIAL STATEMENT SCHEDULES
All other schedules have been omitted as the subject matter is either not present or is not present in amounts sufficient to require submission of the schedule, in accordance with the instructions contained in Regulation S-X, or the required information is included in the financial statements or notes thereto.
Financial statements of 50-percent or less owned companies and joint ventures, other than Citrus Corp., are not presented herein because such companies and joint ventures do not meet the significance test.
3. EXHIBITS (1)
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(1) Sonat will furnish to requesting security holders any exhibit on this list upon the payment of a fee of 10 cents per page up to a maximum of $5.00 per exhibit. Requests must be made in writing and should be addressed to Beverley T. Krannich, Secretary, Sonat Inc., P.O. Box 2563, Birmingham, Alabama 35202.
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Exhibits listed above which have heretofore been filed with the Securities and Exchange Commission, which were physically filed as noted above, are hereby incorporated herein by reference pursuant to Rule 12b-32 under the Securities Exchange Act of 1934 and made a part hereof with the same effect as if filed herewith.
Certain instruments relating to long-term debt of Sonat and its subsidiaries have not been filed as exhibits since the total amount of securities authorized under any such instrument does not exceed 10 percent of the total assets of Sonat and its subsidiaries on a consolidated basis. Sonat agrees to furnish a copy of each such instrument to the Commission upon request.
(b) Reports on Form 8-K
There were no reports on Form 8-K filed during the quarter ended December 31, 1993.
(c) Exhibits
Exhibits required by Item 601 of Regulation S-K and filed with this report on Form 10-K accompany this report in a separate exhibit volume.
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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.
SONAT INC.
By /s/ RONALD L. KUEHN, JR. ----------------------------- RONALD L. KUEHN, JR. CHAIRMAN OF THE BOARD, PRESIDENT AND CHIEF EXECUTIVE OFFICER
Dated: March 25, 1994
PURSUANT TO THE REQUIREMENTS OF THE SECURITIES EXCHANGE ACT OF 1934, THIS REPORT HAS BEEN SIGNED BELOW BY THE FOLLOWING PERSONS ON BEHALF OF THE REGISTRANT AND IN THE CAPACITIES AND ON THE DATES INDICATED.
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REPORT OF INDEPENDENT AUDITORS
We have audited the accompanying consolidated financial statements of Sonat Inc. and Subsidiaries as of December 31, 1993 and 1992, and for each of the three years in the period ended December 31, 1993, and have issued our report thereon dated January 20, 1994 (included elsewhere in this Annual Report). Our audits also included the financial statement schedules listed in Item 14(a)2 of this Annual Report. These schedules are the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits.
In our opinion, the financial statement schedules referred to above, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
/s/ Ernst & Young
ERNST & YOUNG
Birmingham, Alabama January 20, 1994 SONAT INC. AND SUBSIDIARIES SCHEDULE V - PLANT, PROPERTY AND EQUIPMENT YEAR ENDED DECEMBER 31, 1993
(a) Additions include $4,516,000 of funds capitalized. (b) Reflects the removal of fixed assets due to the Initial Public Offering of Sonat Offshore Drilling Inc. common stock. (See Note 3 of the Notes to Consolidated Financial Statements located in Item 8.
Item 8. (b) Reflects the removal of depreciation, depletion and amortization balances due to the Initial Public Offering of Sonat Offshore Drilling Inc. common stock. (See Note 3 of the Notes to Consolidated Financial Statements located in Item 8.) (c) Other changes are either transfers or amounts received as reimbursement for alterations of facilities. SONAT INC. AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PLANT, PROPERTY AND EQUIPMENT (a) - (CONTINUED) YEAR ENDED DECEMBER 31, 1992
(a) Depreciation, depletion and amortization is provided as described in Note 1 and Note 6 of the Notes to Consolidated Financial Statements located in Item 8. (b) Includes an adjustment of $9.6 million for a settlement relating to Southern Energy Company's idle liquefield natural gas facilities. (c) Reflects the sale of Teleco Oilfield Services Inc. (See Note 3 of the Notes to Consolidated Financial Statements located in Item 8.) (d) Other changes are either transfers or amounts received as reimbursement for alterations of facilities. SONAT INC. AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION OF PLANT, PROPERTY AND EQUIPMENT (a) - (CONTINUED) YEAR ENDED DECEMBER 31, 1991
(a) Depreciation, depletion and amortization is provided as described in Note 1 and Note 6 of the Notes to Consolidated Financial Statements located in Item 8. (b) Other changes are either transfers or amounts received as reimbursement for alterations of facilities. SONAT INC. AND SUBSIDIARIES SCHEDULE IX - SHORT-TERM BORROWINGS FOR YEARS ENDED DECEMBER 31, 1993, 1992 and 1991 (In Thousands)
(1) Total interest paid divided by weighted average daily balance. SONAT INC. AND SUBSIDIARIES SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION YEARS ENDED DECEMBER 31, 1993, 1992 and 1991
Other information required to be disclosed has been omitted because amounts are less than 1% of consolidated revenues or the information required has been included elsewhere herein.
CITRUS CORP.
(AN INCORPORATED JOINT VENTURE)
INDEX TO FINANCIAL STATEMENTS AND FINANCIAL STATEMENT SCHEDULES COVERED BY REPORT OF INDEPENDENT AUDITORS (Item 14(a)2)
Report of Independent Auditors
Consolidated Balance Sheets at December 31, 1993 and 1992
Consolidated Statements of Operations and Retained Earnings for the years ended December 31, 1993, 1992 and 1991
Consolidated Statements of Cash Flows for the years ended December 31, 1993, 1992 and 1991
Notes to Consolidated Financial Statements
Schedules for the years ended December 31, 1993, 1992 and 1991:
V - Property, Plant and Equipment
VI - Accumulated Depreciation of Property, Plant and Equipment
IX - Short-Term Borrowings
All other schedules are omitted since the required information is not present or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the financial statements including the notes thereto. Report of Ernst & Young, Independent Auditors
Board of Directors Citrus Corp. and Subsidiaries
We have audited the accompanying consolidated balance sheets of Citrus Corp. and Subsidiaries as of December 31, 1993 and 1992, and the related consolidated statements of operations and retained earnings and cash flows for each of the three years in the period ended December 31, 1993. Our audits also included the financial statement schedules listed in the Index at Item 14(a)2. These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Citrus Corp. and Subsidiaries at December 31, 1993 and 1992, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1993, in conformity with generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
/s/ Ernst & Young
ERNST & YOUNG
Birmingham, Alabama February 25, 1994 CITRUS CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements. CITRUS CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements. CITRUS CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
The accompanying notes are an integral part of these consolidated financial statements. CITRUS CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements. CITRUS CORP. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) REPORTING ENTITY
Citrus Corp. (the Company), a holding company formed during 1986, owns 100% of the stock of Florida Gas Transmission Company (Transmission), Citrus Trading Corp. (Trading), Citrus Industrial Sales Company, Inc. (Industrial) and Citrus Marketing, Inc. (Marketing). The stock of the Company is owned 50% by Sonat Inc. (Sonat) and 50% by Houston Pipe Line Company, a subsidiary of Enron Corp. (Enron).
Transmission, an interstate gas pipeline, is engaged in the interstate transmission and sale of natural gas, and is subject to the jurisdiction of the Federal Energy Regulatory Commission (FERC).
Trading is engaged in the sale of natural gas primarily to Florida Power and Light, a large electric utility in the state of Florida.
Industrial is engaged in the sale of natural gas to local distribution customers and end users.
Marketing specializes in supply acquisition, nontraditional gas sales and purchases, and gas related financial instrument transactions (see Note 7).
(2) SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements include the accounts of the Company and its subsidiaries. All significant intercompany transactions and accounts have been eliminated in consolidation.
CASH AND CASH EQUIVALENTS - The Company considers as cash equivalents all highly liquid short-term investments with original maturities of three months or less. These investments are accounted for at cost, which approximates estimated fair value.
MATERIALS AND SUPPLIES - Materials and supplies are valued at actual cost. Materials transferred out of warehouses are priced out at average cost.
OVERRECOVERED PURCHASED GAS COSTS - For the portion of gas costs that are applicable to regulated revenues, the FERC requires Transmission to defer the overrecovery or underrecovery of gas costs. Pursuant to Transmission's Order No. 636 settlement, Transmission will flowthrough the overrecovery or underrecovery of gas costs on or before November 1, 1995. (2) SIGNIFICANT ACCOUNTING POLICIES (continued)
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES - To manage the risks of price fluctuations, Marketing follows the practice of entering into swap agreements in certain energy products. All related gains and losses are recognized currently in income as adjustments to costs and expenses.
DEPRECIATION, AMORTIZATION AND MAINTENANCE POLICIES - The Company amortizes that portion of its investment in Transmission and other subsidiaries which is in excess of historical cost (acquisition adjustment) on a straight-line basis at an annual rate of 1.9% based upon the estimated remaining useful life of the pipeline system.
During the third quarter of 1993, the Company changed its depreciation rate applicable to the acquisition adjustment to better reflect its remaining useful life. The effect of the change was a reduction in depreciation and amortization expense of $5.6 million in 1993.
Transmission has provided for depreciation of assets on a straight-line basis at an annual composite rate of 3.06%, 3.16% and 2.45% for 1993, 1992 and 1991, respectively. Depreciation rates are based on the estimated useful lives of the individual assets and are subject to approval by the FERC.
The Company charges to maintenance the costs of repairs and renewal of items determined to be less than units of property. Costs of replacements and renewals of units of property are capitalized. The original costs of units of property retired are charged to the depreciation reserves, net of salvage and removal costs.
INCOME TAXES - The Company and its subsidiaries file a consolidated federal income tax return. Pursuant to a tax allocation agreement between the Company and its subsidiaries, the Company will pay to each subsidiary an amount equal to the tax benefits realized in the consolidated federal income tax return resulting from the utilization of the subsidiary's net operating losses and tax credits. Conversely, each subsidiary will pay to the Company an amount equal to the federal income tax computed on its separate company taxable income, less the tax benefits associated with the net operating losses and tax credits generated by the subsidiary which are utilized in the consolidated federal income tax return.
The Company adopted the provisions of Statement of Financial Accounting Standards (SFAS) No. 109 - "Accounting for Income Taxes" effective January 1, 1993, and applied the provisions of the statement retroactively. The Company previously accounted for income taxes under the provisions of SFAS No. 96 which was superseded by SFAS No. 109. Both SFAS No. 96 and SFAS No. 109
(2) SIGNIFICANT ACCOUNTING POLICIES (continued)
utilize the 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. The adoption of SFAS No. 109 did not have a material impact on the Company's results of operations or financial position.
RECLASSIFICATIONS - Certain items on the Consolidated Statements of Operations and Retained Earnings have been reclassified in 1992 and 1991 to conform with the 1993 presentation.
(3) LONG-TERM DEBT
Long-term debt outstanding as of December 31, 1993 and 1992 was as follows (in thousands):
Citrus Corp. 1993 1992 ------------ --------- --------- 9.70% Notes due 1994-1996 $ 90,000 $120,000 11.10% Notes due 1999-2006 175,000 175,000 -------- -------- 265,000 295,000 -------- -------- Transmission ------------ 9.30% Notes due 1998 25,000 25,000 9.75% Notes due 1999-2008 65,000 65,000 10.11% Notes due 2009-2013 70,000 70,000 -------- -------- 160,000 160,000 -------- --------
Total Long-Term Debt 425,000 455,000
Less Current Maturities 30,000 30,000 -------- -------- Total Long-Term Debt, Net of Current Maturities $395,000 $425,000 ======== ========
Annual maturities and sinking fund requirements on long-term debt outstanding as of December 31, 1993 were as follows (in thousands):
Year Amount ---- ------ 1994 $ 30,000 1995 30,000 1996 30,000 1997 - 1998 44,250 Thereafter 290,750 -------- $425,000 ========
The Company has a note agreement that contains certain restrictions which, among other things, limits the incurrence of additional debt, the sale of assets and the payment of dividends. The agreements relating to Transmission's promissory notes include, among other things, restrictions as to the payment of dividends. As of December 31, 1993, the Company is restricted in its ability to
(3) LONG-TERM DEBT (continued)
incur any additional long-term debt other than for the addition, expansion or modification of the gas transmission system or to extend, renew or refund its outstanding debt.
The Company has committed lines of credit of $300.0 million with $275.0 million outstanding at December 31, 1993. Transmission has committed lines of credit of $175.0 million which was all available at December 31, 1993. Transmission also has uncommitted bid note facilities for up to $45.0 million. At December 31, 1993, there were no amounts outstanding under these facilities.
(4) INCOME TAXES
In August 1993, the 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 in the period of enactment.
The principal components of the Company's net deferred income tax liability at December 31, 1993 and 1992 are as follows (in thousands):
Total income tax expense (benefit) for the years ended December 31, 1993, 1992 and 1991 is summarized as follows (in thousands):
(4) INCOME TAXES (continued)
The differences between income taxes computed at the U.S. federal statutory rate and the Company's effective tax rate for the years ended December 31, 1993, 1992 and 1991 are as follows (in thousands):
The Company has a consolidated net operating loss carryforward for tax purposes of approximately $62 million. This loss carryforward will be available until 2006, at which time it will begin to expire. For financial statement purposes, the Company has recognized the benefit of this loss carryforward as a reduction of deferred tax liabilities.
(5) EMPLOYEE BENEFIT PLANS
Employees of the Company participate in a defined benefit pension plan maintained by Enron. Employees with five years or more of service are entitled to retirement benefits based upon a formula that uses a percentage of final average pay and years of service. It is Enron's policy to fund pension costs to the minimum legal amount required by federal tax regulations. Pension expenses charged by Enron were $.4 million, $.3 million and $.5 million for 1993, 1992 and 1991, respectively.
During 1986, Enron formed a new employee stock ownership plan (ESOP). Concurrent with the establishment of the ESOP, Enron amended its retirement plan to provide that the value of stock allocated to an employee's account in the ESOP will be utilized to partially fund the employee's retirement benefits accrued subsequent to the date of the amendment.
As of September 30, 1993, the most recent valuation date, the actuarial present value of projected plan benefit obligations for the Enron Corp. Retirement Plan in which the employees of the Company participate was less than the plan net assets by approximately $25.3 million. The assumed discount rate and rate of return on plan assets used in determining the actuarial present value of projected plan benefits were 7.0% and 10.5%. The assumed rate of increase in wages was 4.0%. (5) EMPLOYEE BENEFIT PLANS (continued)
In addition to providing pension benefits, Enron also provides certain health care and life insurance benefits to eligible employees (and their eligible surviving spouses) who retire under the Enron Corp. Retirement Plan. Benefits are provided under the provisions of a contributory defined dollar benefit plan.
Effective January 1, 1993, the Company adopted the provisions of SFAS No. 106 "Employers Accounting for Postretirement Benefits Other Than Pensions" (SFAS 106). SFAS 106 requires that employers providing postretirement benefits accrue those costs over the service lives of the employees expected to be eligible to receive such benefits. The Company has elected the prospective transition approach and is amortizing the transition obligation which existed at January 1, 1993, over a period of approximately 19 years. The Company's net periodic postretirement benefit cost for 1993 totaled approximately $.8 million, substantially all of which relates to Transmission and is expected to be recovered through rates, while the accumulated postretirement benefit obligation exceeded plan assets by $6.1 million as of December 31, 1993.
(6) MAJOR CUSTOMERS
Revenues from individual customers exceeding 10% of total revenues for the years ended December 31, 1993, 1992 and 1991 were approximately as follows (in thousands):
At December 31, 1993, the Company's subsidiaries had receivables of approximately $14.7 and $4.0 million from Florida Power and Light and Peoples Gas System, Inc., respectively.
(7) RELATED PARTY TRANSACTIONS
The Company incurred corporate administrative expenses including employee benefit costs from Enron and its affiliates. The Company was charged approximately $14.8, $12.1 and $15.9 million for these expenses for the years ended December 31, 1993, 1992 and 1991, respectively.
The Company's subsidiaries provide natural gas sales and transport services to Enron and Sonat affiliates at rates equal to rates charged to non-affiliated customers in the same class of service. Revenues related to these services amounted to approximately $13.0, $4.3 and $13.1 million for the years ended December 31, 1993, 1992 and 1991, respectively. The Company's subsidiaries purchased gas from affiliates of Sonat of approximately $10.8, $8,8 and $11.9.
RELATED PARTY TRANSACTIONS (continued)
million for the years ended December 31, 1993, 1992 and 1991, respectively. The Company's subsidiaries also purchased gas from affiliates of Enron of approximately $31.1, $41.4 and $53.7 million for the years ended December 31, 1993, 1992 and 1991, respectively.
In 1993 Marketing sold certain gas purchase and sales contracts to Enron Gas Marketing, Inc. The combined proceeds of the sales, $24.6 million, are included in other revenues.
On November 1, 1993, the Company, Marketing, Trading and Industrial (collectively the Citrus Marketing Group) entered into an Operating and Marketing Agreement (Agreement) with Enron Gas Services Corp. (EGS). Under the terms of the Agreement, EGS provides certain marketing and operating services to the Citrus Marketing Group, including administration of existing and new contracts. EGS also performs marketing functions on behalf of the Citrus Marketing Group for its customers taking natural gas deliveries in Florida on Transmission's pipeline.
(8) RATE MATTERS AND CONTINGENCIES
On January 15, 1993, the FERC approved Transmission's rate case settlement which resolved all issues of cost of service, volumes and rates pending in the July 1991 rate case filing. Transmission made refunds by April 30, 1993, and with the acceptance of Transmission's refund report by the FERC all matters related to the rate case are closed.
Transmission has been authorized by the FERC to recover certain take-or-pay costs billed to Transmission by Southern Natural Gas Company through a flowthrough billing mechanism similar to, but separate from, the PGA mechanism. The FERC authorization requires a cap be placed on the liability of customers based on some measure of historical purchases. Deferred settlement charges in the balance sheets at December 31, 1993 and 1992 include approximately $3.4 and $10.5 million, respectively, related to this matter.
In April 1992, the FERC issued Order No. 636 (Order 636). Among other features, Order 636 requires pipelines to eliminate their bundled city-gate sales service by separating (or unbundling) their sales services from their transportation services, requires an expanded capacity relinquishment program and adopts a straight fixed variable rate design methodology. Order 636 also provides for the recovery of transition costs. In a series of orders issued in 1993, the FERC approved most aspects of Transmission's June 16, 1993 settlement of all Order 636 issues including the recovery of transition payments.
(8) RATE MATTERS AND CONTINGENCIES (continued)
Transmission has been authorized by the FERC to recover certain transition costs incurred through the reformation of gas supply contracts related to Transmission's jurisdictional sales services. On November 1, 1993, Transmission's Order 636 restructuring settlement went into effect. In addition to the existing recovery mechanism, the settlement allows Transmission to recover 100% of any transition payments from $106 million up to $160 million and 75% of payments after the $160 million level.
Transmission has certain gas purchase contracts which provide for take-or-pay obligations. Certain suppliers have made claims for payment under the take-or-pay provision of these contracts. Thus far, Transmission has made payments totaling $129.6 million as consideration for modifying claims or other gas purchase contract terms.
As Transmission completes the transition to a transportation only function and terminates all of its remaining gas purchase contracts, it is possible that additional payments to suppliers may be made to resolve contract issues. To the extent additional payments are made, Management believes that these costs will be 100% recoverable through existing tariff mechanisms.
Transmission has received authority for an expansion of its pipeline system (Phase III Expansion) with an estimated cost of approximately $908 million. On August 25, 1992, Transmission filed a settlement (Phase III Settlement) that covers the expansion facilities needed to provide an additional firm transportation service that will average approximately 530,000 MMBtu per day. This settlement amended Transmission's previous filings for an expansion of its facilities for approximately 825,000 MMBtu per day and was agreed to by all customers. Service on Phase III Expansion facilities is to be provided under a new firm transportation rate schedule which calls for payment of incremental rates based upon a levelized rate methodology.
On September 15, 1993, the FERC issued Transmission a certificate of public convenience and necessity approving the Phase III settlement and authorizing Transmission to construct and operate the Phase III Expansion facilities. Transmission accepted the certificate on October 14, 1993. On February 2, 1994, the FERC denied rehearing on an environmental issue but granted Transmission's request for clarification on a rate issue. (9) COMMITMENTS AND CONTINGENCIES
In August 1990, Marketing entered into a price swap agreement to effectively manage a portion of the market risk caused by fluctuations in the price of natural gas and residual fuel oil. The agreement provides a hedge on 41,000 MMBtu of natural gas and 5,000 barrels of residual fuel oil per day. The agreement requires Marketing to make payments to (or receive payments from) the other party based upon the differential between a fixed and a floating price for natural gas and residual fuel oil as specified in the agreement. The current swap agreement is effective for a period of five years beginning August 1, 1990. The Company's after-tax results of operations for the years ended December 31, 1993 and 1992, included net gains of $4.6 and $1.1 million, respectively, and a net loss for the year ended December 31, 1991 of $1.6 million, related to this agreement.
(10) CONCENTRATIONS OF CREDIT RISK AND OTHER FINANCIAL INSTRUMENTS
The Company and its subsidiaries have a concentration of customers in the electric and gas utility industries. These concentrations of customers may impact the Company'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. Credit losses incurred on receivables in these industries compare favorably to losses experienced in the Company's receivable portfolio as a whole. The Company and its subsidiaries also have a concentration of customers located in the southeastern United States, primarily within the state of Florida. Receivables are generally not collateralized. The Company's management believes that the portfolio of receivables, which includes local distribution companies and municipalities, is well diversified and that such diversification minimizes any potential credit risk.
The carrying amounts and fair value of the Company's financial instruments at December 31, 1993 and 1992, are as follows (in thousands):
The carrying amount of contract reformation costs and notes payable reasonably approximate their fair value. The fair value of long-term debt is based upon market quotations of similar debt at interest rates currently available.
CITRUS CORP. AND SUBSIDIARIES SCHEDULE V PROPERTY, PLANT AND EQUIPMENT
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS)
(1) Additions in 1993 primarily relate to expansion of transmission plant commonly referred to as Phase III. (2) Additions in 1992 and 1991 primarily relate to Phase II expansion. (3) Acquisition adjustment includes the effect of Statement of Financial Accounting Standards No.96. "Accounting for Income Taxes". Reference is made to Note 2 to the financial statements. CITRUS CORP. AND SUBSIDIARIES SCHEDULE VI - ACCUMULATED DEPRECIATION OF PROPERTY, PLANT AND EQUIPMENT
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS)
CITRUS CORP. AND SUBSIDIARIES SCHEDULE IX -- SHORT-TERM BORROWINGS
YEARS ENDED DECEMBER 31, 1993, 1992 AND 1991 (IN THOUSANDS)
(1) Computations based on daily outstanding balances and applicable rates during the period.
APPENDIX TO ANNUAL REPORT ON FORM 10-K
OF SONAT INC. FOR THE YEAR ENDED DECEMBER 31, 1993
In compliance with Section 304 of Regulation S-T, the following information describes pictorial and/or graphic materials contained herein: