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 and through Southern Natural Gas Company ("Southern"), Citrus Corp. ("Citrus"), and Sonat Energy Services Company ("Energy Services") in the transmission, storage, and marketing of natural gas.
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 38 percent of Sonat's consolidated operating profit for 1994.
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' largest subsidiary, Sonat Marketing Company ("Marketing"), sells natural gas throughout much of the United States. In 1993 Marketing assumed responsibility for the sale of most of Exploration's natural gas production and at year-end 1994 was one of the twenty largest natural gas marketers in the United States. Natural gas operations, excluding Citrus, contributed approximately 60 percent of Sonat's consolidated operating profit for 1994. Sonat's share of Citrus' earnings are reflected in Equity in Earnings of Unconsolidated Affiliates.
Sonat owns approximately 11.3 million or 39.7 percent of the outstanding shares of Sonat Offshore Drilling Inc. ("Offshore"), which is in the offshore contract drilling business. Prior to the initial public offering of Offshore's common stock, which closed on June 4, 1993, Offshore had been a wholly owned subsidiary of Sonat. Sonat also owns four million shares of convertible preferred stock of Baker Hughes Incorporated ("Baker Hughes"), which provides products and services to the petroleum and continuous process industries. 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.
Sonat was incorporated under the laws of Delaware in 1973 in connection with a reorganization of Southern. At March 1, 1995, Sonat and its subsidiaries employed approximately 1,910 people.
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 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.
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 and Oklahoma City, Oklahoma.
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, 1994, Exploration had operations or properties in 14 states. Exploration had working interests in
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approximately 2.2 million gross acres or 1.5 million net acres onshore as of December 31, 1994. Of this onshore acreage, approximately 1.2 million gross or 654,986 net acres were producing oil or gas. In addition, as of such date, Exploration had a working interest in 70 federal offshore blocks in the Gulf of Mexico and one state offshore block, totaling 308,344 gross acres or 160,932 net acres. Of these blocks, 58 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 at spot-market prices under a long-term contract.
Beginning in 1988 Exploration implemented a strategy to acquire gas properties with significant development potential. As a result of this strategy, Exploration has increased its total proved reserves since that time to approximately 1.6 trillion cubic feet of natural gas equivalent at the end of 1994, which represents more than a six-fold increase. Approximately 88 percent of Exploration's proved reserves are natural gas.
In 1994 Exploration continued its strategy of acquiring producing oil and gas properties with potential for additional reserves and production development. Exploration's acquisition strategy is to make investments in areas where it currently operates in order to take advantage of operating efficiencies and to expand the geographic scope of its operations in select regions where opportunities make it attractive to do so.
During 1994 Exploration acquired approximately 278 billion cubic feet ("Bcf") of proved natural gas equivalent reserves in 37 separate transactions totaling $163 million, for an average acquisition cost of $.59 per thousand cubic feet equivalent. Through these acquisitions, Exploration extended its operations to the Permian Basin of west Texas and increased its position in south Texas.
In January 1995 Exploration announced two significant acquisitions of oil and gas producing properties, one in north Louisiana and the other in the Texas Panhandle area. When fully completed, these transactions, which total $158.3 million, will add proved reserves of 188 Bcf of natural gas and 11.2 million barrels of oil and condensate, yielding a unit acquisition cost on a natural gas equivalent basis of $.62 per thousand cubic feet.
In north Louisiana, Exploration will acquire, for $135.7 million, interests of Cobra Oil and Gas, Inc. and its partners in the north Shongaloo-Red Rock Field. Proved reserves are estimated at 162 Bcf of natural gas and 10 million barrels of condensate and gas liquids, with only 21 percent of the reserves presently developed and producing. An aggressive drilling program to bring the undeveloped reserves to producing status is planned.
In the other transaction, Exploration will acquire from Horizon Oil and Gas Company and partners, for $22.6 million, producing interests in the northern Texas Panhandle producing area. Proved reserves are estimated at 26 Bcf of natural gas and 1.2 million barrels of oil and condensate, of which 41 percent are developed and producing.
In 1994 Exploration continued its aggressive drilling program, participating in the drilling of 343 development wells, of which approximately 85 percent were successful, increasing proved reserves by approximately 137 Bcf of natural gas equivalent. Exploration also participated in the drilling of 15 exploratory wells in 1994, none of which were successful. Of these 15 exploratory wells, however, 13 were drilled as part of a shallow-well drilling program in south Texas done in order to acquire additional lease acreage. Of the total of 358 wells in which Exploration participated in drilling in 1994, it operated 250.
Exploration is also continuing to develop its substantial acreage position in the eastern extension of the Austin Chalk trend in Texas and Louisiana. As a part of its drilling program, Exploration participated in the drilling of 26 horizontal wells in this trend during 1994, all of which were successful.
As of December 31, 1994, Exploration's net proved reserves totaled 32 million barrels of crude oil, condensate, and natural gas liquids and 1,367 Bcf of natural gas. As of December 31, 1993, Exploration's net proved reserves amounted to 27 million barrels of crude oil, condensate, and natural gas liquids and 1,187 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.
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Exploration's total exploration and production capital expenditures in 1994 were $390 million compared with $441 million in 1993, which includes its share of the capital expenditures of Sonat/P Anadarko Limited Partnership in 1993 (see Note 5 of the Notes to Consolidated Financial Statements in Part II of this report). Exploration will continue to emphasize producing property acquisitions and development drilling in 1995, when capital spending is expected to be approximately $410 million. While maintaining an active program, Exploration has also continued its cost control and productivity improvement efforts.
In order to focus its exploration and production efforts and to minimize administrative and other costs, Exploration disposed of certain non-strategic oil and gas interests in 1994 in the states of Louisiana, Texas, Oklahoma, and Arkansas. These properties were sold for a total of approximately $6 million and included approximately 10,106 net developed acres of oil and gas leases with interests in approximately 54 gross productive wells, representing net proved reserves of approximately seven Bcf natural gas equivalent. Exploration expects that it will continue to dispose of non-strategic oil and gas interests in the future and anticipates that the number and size of properties sold in 1995 will be greater than in 1994.
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 by acquisition or through a competitive bidding process from the federal or state governments. Exploration has, and may in the future, bid with other companies for leases on prospective offshore acreage. 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. Drilling for Exploration is conducted by independent drilling contractors.
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 Federal Energy Regulatory Commission (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 (the "MMS"). 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'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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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, 1994. 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 working interest below 9,500 feet in West Cameron 290, which is one of the 15 producing blocks. In one of the producing blocks, West Cameron 421, Exploration only has an overriding interest. (2) In one of the producing blocks, Eugene Island 10, Exploration only has an overriding interest. (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
[MAP TO COME]
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Consolidated Net Production
Exploration had interests in production from 3,545 producing wells onshore and 157 producing wells offshore as of December 31, 1994. 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 1992 to 1994 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 1994, $.38 in 1993, and $.38 in 1992. 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. Sales of natural gas by Exploration to affiliates accounted for approximately 65 percent of Exploration's revenues in 1994 and 44 percent in 1993.
During 1993 Marketing assumed responsibility for marketing all of Exploration's natural gas production that is not sold under pre-existing term dedications. Marketing purchases most of this production directly from Exploration and markets the balance pursuant to an agency agreement. Marketing, on behalf of Exploration, uses derivative transactions, including natural gas futures contracts, options on natural gas futures contracts, and oil and gas price swap agreements, as hedges for Exploration's production to reduce the risks associated with spot-market price volatility. See Note 2 of the Notes to Consolidated Financial Statements contained in Part II of this report.
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, 1994.
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(1) One of these wells is a multiple completion. (2) 148 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 1992 through 1994.
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
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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.
Natural gas prices were down significantly in 1994, with Exploration's realized gas prices averaging $1.83 per thousand cubic feet compared with $1.99 in 1993. Oil prices were also significantly lower, averaging $15.91 per barrel in 1994 versus $17.42 per barrel in 1993. Thus far in 1995 natural gas prices are lower than prices for the same months in 1994. Exploration is unable to predict price levels for oil or natural gas in 1995 or beyond, but if the trend of lower natural gas prices continues for the entire year of 1995, Exploration's earnings and cash flow will be lower than 1994 results.
TRANSMISSION, STORAGE, AND MARKETING OF NATURAL GAS
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 9,320 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-18.
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 sought to have 21 Bcf of the certificated working storage capacity of Muldon reclassified to cushion gas, resulting in a certificated working storage capacity of 31 Bcf of gas. The FERC approved Southern's reclassification application on a limited-term basis for a one-year period ending November 1, 1994, subject to a further review of engineering and geophysical data supporting the reclassification and Muldon's operations during the 1993-94 winter period. On December 30, 1994, Southern filed a comprehensive study with the FERC containing the data it had requested, which is pending FERC review. Southern believes the results of the study support the reclassification of working storage gas to cushion gas requested by Southern. Southern's limited-term authorization has been extended until the FERC completes its review of the study.
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., and their customers. The Bear Creek Storage Field has a total certificated working storage capacity of approximately 65 Bcf of gas, half of which is committed to Southern. At December 31, 1994, Bear Creek's gross facilities cost was approximately $246,902,000, its net facilities cost was approximately $164,257,000, and its participants' equity was $93,815,000. Southern had an investment in Bear Creek, including its equity in undistributed earnings, of $46,907,000 at December 31, 1994.
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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 is now used for such services.
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 (the "NGA"), and various pipeline safety and environmental laws. See "Governmental Regulation -- Transmission, Storage, and Marketing of Natural Gas" 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.
Order No. 636 Restructuring. In 1992 the FERC issued its Order No. 636 (the "Order"), which required 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, to make 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 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 authorized pipelines to offer unbundled sales services at market-based rates and allowed for pregranted abandonment of some services.
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 new storage customers. The Order also resulted in rates that are less seasonal, thereby shifting revenues and earnings for Southern out of the winter months.
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, or purchasing gas at above-market prices under, existing gas purchase contracts, which are referred to as gas supply realignment ("GSR") costs. The Order provided 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. The prudence review will extend both to the prudence of the underlying gas purchase contracts, based on the circumstances that existed at the time the contracts were executed, and to the prudence of the amendments or terminations of the contracts. 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 to 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 "price differential" 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
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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 based on both eligibility and prudence grounds. 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 FERC's finding that the 1988 settlement is not a bar in general to the recovery as GSR costs of payments made to amend or to terminate these contracts does not prevent an eligibility challenge to specific payments, however, on the theory that they are actually take-or-pay costs that would have been unavoidable regardless of the Order. The December 16 order generally approved Southern's restructuring tariff submitted pursuant to the September 3 order. Various parties have sought judicial review of the September 3 and December 16 orders.
As of December 31, 1994, Southern had either paid or accrued $134 million in GSR costs (including $4 million in interest) either to reduce significantly the price payable under or to terminate a number of gas supply contracts providing for payment of above-market prices. In addition, on February 17, 1995, Southern reached an agreement to resolve its remaining high-cost supply contracts with Exxon Corporation ("Exxon") by paying an additional $45 million in GSR costs and foregoing a claim against $19 million in price differential costs that have been paid to Exxon under an interim agreement entered into between the parties pending resolution of litigation contesting Southern's termination on March 1, 1994, of a gas purchase contract with Exxon. This agreement is conditioned upon the Customer Settlement (described below) becoming effective. Southern also has an agreement under which another high-cost contract price is reduced in exchange for monthly payments having a present value of approximately $44 million. Southern has received permission from the FERC to purchase an annuity in order to monetize this obligation.
In addition to its GSR costs relating to termination or amendment of its remaining gas supply contracts, Southern has incurred and expects to continue to incur certain price differential GSR costs resulting from Southern's continued purchase of gas under its remaining supply contracts that provide for prices in excess of current market prices. As of December 31, 1994, Southern had incurred $69 million in price differential costs.
Beginning in December 1993 Southern has made a number of filings with the FERC seeking to recover GSR costs paid through various periods prior to the filings. In each instance, the FERC has accepted Southern's filing subject to refund, and subject to a determination through a hearing before an administrative law judge regarding whether such costs were prudently incurred and are eligible for recovery under the Order. Southern's customers are opposing its recovery of its GSR costs in these proceedings based on both eligibility and prudence grounds. These proceedings, which have all been consolidated, are in the early stages of discovery and Southern cannot predict their outcome at this time.
Customer Settlement. Southern filed with the FERC on March 15, 1995, a Stipulation and Agreement that would settle all of Southern's pending rate and GSR cost recovery proceedings ("Customer Settlement"). As of that date, Southern had been advised that customers representing more than 90 percent of the firm transportation capacity on its pipeline system intend to support the Customer Settlement. Pursuant to the Customer Settlement, which must be approved by the FERC, all issues in Southern's current and prior rate cases would be settled and Southern would credit against GSR costs incurred by Southern the full amount of Southern's rate reserves as of February 28, 1995, which were approximately $155 million. Such amount, less certain amounts withheld for potential rate refunds to parties, if any, that contest the Customer Settlement, will be credited in the aggregate to reduce the GSR costs borne by Southern's customers. Southern has filed
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with the FERC to implement reduced settlement rates for parties that support the Customer Settlement on an interim basis effective as of March 1, 1995, subject to reinstatement, pending FERC consideration and approval of the Customer Settlement. The Customer Settlement provides that, except in certain limited circumstances, Southern will not file a general rate case to be effective prior to March 1, 1998. In the fourth quarter of 1994 Sonat recognized a $29 million charge associated with the Customer Settlement, which includes anticipated amounts for GSR costs that Southern would not recover from its customers, and a $28 million provision relating to regulatory assets that will not be recovered as a result of the Customer Settlement, including amounts for a corporate restructuring undertaken in 1994.
Southern's Customer Settlement would settle as to supporting parties all of the proceedings pursuant to which Southern is seeking recovery of its GSR costs as well as all of its other outstanding rate proceedings. If the Customer Settlement is ultimately approved by the FERC, all challenges to the recovery of Southern's GSR costs would be resolved as to those customers supporting the Customer Settlement, including all issues related to eligibility and prudence. Additionally, Southern would absorb an agreed-upon portion of its total GSR costs, which was reflected in the provision for the Customer Settlement noted above.
It is possible that the Customer Settlement will be contested by certain of Southern's customers, in which case the Customer Settlement, if approved by the FERC, will become effective only as to supporting parties and Southern's rates and GSR costs applicable to contesting parties would be determined by the outcome of Southern's pending rate and GSR proceedings, where Southern anticipates that those contesting customers will continue to challenge both the eligibility and prudence of such costs. It is also possible that the Customer Settlement might not be approved by the FERC or, if approved, might be modified in a way unacceptable to Southern or its customers.
In its Customer 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, recent contract renegotiations, and price differential costs actually incurred, the total amount of GSR costs is estimated to be approximately $328 million on a present-value basis. This amount includes the payments made or accrued through December 31, 1994, to amend or to terminate gas purchase contracts, price differential costs through December 31, 1994, and the $64 million cost that will be incurred under the settlement of existing contracts with Exxon, which will become effective if the Customer Settlement becomes effective. These costs collectively total $288 million. Thus, Southern currently estimates it will ultimately pay an additional $40 million in GSR costs. These amounts do not include an additional $87 million in GSR costs that would be incurred if the settlement with Exxon does not become effective and Exxon prevails in its lawsuit regarding Southern's March 1, 1994, termination of a contract relating to Exxon's reserves in its Mississippi Canyon blocks. See "Administrative Law Judge Ruling Concerning Recoverability of Investment in Offshore Gas Supply Facilities; Settlement with Exxon Corporation" below.
Until the Customer Settlement is approved, Southern plans to make additional rate filings quarterly to recover its price differential costs and any other GSR costs. Additionally, Southern will continue to make monthly filings designed to adjust the billing determinants and associated surcharges for its firm transportation customers to reflect changes in the level of systemwide contract demands and effective carrying charges that occur from time to time.
If the Customer Settlement is not approved, Southern cannot predict the ultimate outcome of its Order No. 636 restructuring proceedings, its rate filings to recover its GSR costs, or its other outstanding rate proceedings.
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
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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 113 municipalities and gas districts, and to eight connecting interstate pipeline companies. Southern also transported gas directly to 56 industrial end-users in 1994. Southern principally transports gas to resale and industrial customers and to other pipelines and, as indicated, continues to sell some limited volumes of gas at wholesale for distribution. 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 1994 for Southern and all of its subsidiaries were 886 Bcf, which was all of Southern's throughput in 1994, compared with transportation volumes in 1993 of 763 Bcf, which was 91 percent of Southern's total 1993 throughput of 836 Bcf. Sales to resale distribution customers, including municipalities and gas districts, accounted for virtually all of 1994 sales of 103 Bcf and 1993 sales of 73 Bcf (excluding the sale of storage inventory). The volumes associated with the 1994 sales are included in transportation volumes because, as required by Order No. 636, all sales are now made at the receipt points where the gas enters Southern's pipeline system. Likewise, Southern had sales of 19 Bcf during November and December 1993 (following implementation of its Order No. 636 restructuring) that were made at the receipt points where the gas entered its pipeline system; consequently, those volumes are included within the 763 Bcf of transportation volumes for 1993.
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.
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 Gas Light Company, and its subsidiary, Chattanooga Gas Company (collectively "Atlanta"), signed firm transportation service agreements with transportation demands of 582 million cubic feet per day for a one-year term that ended October 31, 1994, and 118 million cubic feet per day for a term extending until April 30, 2007. This represented an aggregate reduction of 100 million cubic feet per day from Atlanta's level of service prior to November 1, 1993. 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 for terms ranging from one to ten or more years. Alabama Gas Corporation ("Alagasco"), Southern's second largest customer, executed firm transportation contracts for 393 million cubic feet per day under terms extending through October 31, 2008.
Atlanta elected to renew its firm transportation service agreements with transportation demands of 582 million cubic feet per day, which expired October 31, 1994, for a one-year term beginning November 1, 1994. In September and October of 1994 Atlanta Gas Light Company and South Carolina Pipeline Corporation ("SCPL") executed three-year firm service agreements with transportation demands of an additional 100 million cubic feet per day and 28 million cubic feet per day, respectively. With these additional subscriptions, substantially all of Southern's firm market-area capacity currently available became fully subscribed.
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If the Customer Settlement becomes effective, Atlanta will amend its firm transportation contracts for an aggregate of 682 million cubic feet per day to extend their primary terms for a period of three years beginning March 1, 1995. An additional 118 million cubic feet per day would remain under its current term to April 30, 2007. If the Customer Settlement becomes effective, SCPL will amend its firm transportation contract for 28 million cubic feet per day to extend its primary term for a period of three years beginning March 1, 1995. Such extension will be in addition to the remaining 160 million cubic feet per day of SCPL's firm transportation services that remain in effect under terms extending from 1997 through 2003.
Sales by Southern of natural gas 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 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 sold 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. A portion of these sales agreements were extended for an additional one-year term, while the sales agreements with Atlanta were extended through March 31, 1995. Certain customers, including Atlanta, have advised Southern that if the Customer Settlement becomes effective, they will extend their sales agreements through November 1997. The remainder of Southern's gas supply will continue to be sold on a month-to-month basis. Subject to the cost-sharing mechanism in the Customer Settlement, pursuant to which Southern will absorb an agreed-upon portion of its total GSR costs, Southern will recover in accordance with the Customer Settlement or, pending approval of the Customer Settlement, 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 as well as any cost previously incurred or to be incurred as a result of Order No. 636 to terminate or to reduce the price under Southern's remaining gas supply contracts.
Transportation and sales by Southern, combined with sales by Marketing, to two unaffiliated distribution customers, Atlanta and Alagasco, accounted for approximately 16 percent and ten percent, respectively, of Sonat's 1994 consolidated revenues. Atlanta and Alagasco were the only two customers that accounted for ten percent or more of Sonat's consolidated revenues for 1994.
Southern continues to pursue growth opportunities to expand the level of services in its traditional market area and to connect new gas supplies. On May 1, 1994, Southern completed its second pipeline expansion into northern Florida and southwestern Georgia, which increased firm daily capacity by 40 million cubic feet per day. On July 22, 1994, Southern filed an application with the FERC for authorization to construct a 21-mile pipeline extension to a delivery point near Chattanooga that will deliver natural gas to a group of new customers that have signed ten-year contracts for firm transportation volumes totaling approximately 11 million cubic feet per day.
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.
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Gas Supplies. During 1994 Southern reduced the number of its existing long-term gas supply contracts from 60 at the end of 1993 to 31 at the end of 1994. The following table contains information as to Southern's gas supply and the general sources from which that supply was purchased during the years 1992 through 1994.
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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 supply agreements in 1994, 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, except for the two contracts entered into with Exxon as part of the settlement described below, which, if the Exxon settlement becomes effective, will replace six above-market-priced contracts with longer terms. 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.
Administrative Law Judge Ruling Concerning Recoverability of Investment in Offshore Gas Supply Facilities; Settlement with Exxon Corporation. In an initial decision issued on May 2, 1994, which Southern has appealed, an administrative law judge ruled, in a rate case Southern had filed before the FERC, that Southern could not include in its rates the approximately $45 million cost of certain pipeline facilities placed in service by Southern in 1992 to connect to its interstate pipeline system extensive new gas reserves being developed by Exxon in the Mississippi Canyon and Ewing Bank Area Blocks, offshore Louisiana (the "Mississippi Canyon Facilities").The judge ruled that Southern's recovery of these costs was precluded by the 1988 settlement with Southern's customers that limits the amount of take-or-pay payments Southern may recover in its rates. The judge found that the cost of the facilities constitutes non-cash consideration to Exxon for a 1989 take-or-pay settlement and is therefore subject to the dollar "cap" on these payments contained in the 1988 settlement. Southern has previously recovered the maximum amount permitted by the 1988 settlement in its rates. Southern has appealed the administrative law judge's decision to the FERC, but cannot predict the outcome of this appeal.
The Customer Settlement provides that, as to customers supporting the settlement, the costs of the Mississippi Canyon Facilities will be recovered by Southern on a rolled-in basis and the 1988 take-or-pay settlement cap will not preclude Southern's recovery of such costs. On February 17, 1995, Southern reached a settlement with Exxon pursuant to which, in return for an additional cash payment by Southern of $45 million, plus allowing Exxon to retain $19 million in price differential costs already paid to Exxon, all existing gas purchase contracts would be terminated, two new gas purchase contracts would be entered into having three-year terms and providing for market-based index prices, and a lawsuit regarding Southern's termination of the gas purchase contract covering gas reserves connected by the Mississippi Canyon Facilities (the "Mississippi Canyon Contract") would be dismissed. The settlement with Exxon is contingent on FERC approval of the Customer Settlement.
If this settlement with Exxon does not become effective, total GSR costs under the Mississippi Canyon Contract through the scheduled renegotiation of its pricing provisions in 1997 are estimated to be approximately $125 million on a present-value basis, although such estimate is subject to significant uncertainty since the assumptions inherent in the estimate (including underlying reserves, future deliverability, and a range of estimated future gas market prices) are not known today with certainty and there is a wide range of possible outcomes for each assumption. In addition, Southern has given notice to Exxon that effective March 1, 1994,
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it has terminated the Mississippi Canyon Contract pursuant to certain provisions of the contract. Such termination, if effective, would reduce GSR costs associated with such contract to $14 million. Exxon has filed suit against Southern seeking a declaratory judgment that Southern does not have the right to terminate the contract or alternatively for damages of an unspecified amount arising out of the alleged repudiation or breach of the contract by Southern. The court entered a summary judgment order upholding Southern's termination of this contract, which Exxon has appealed to the Fifth Circuit Court of Appeals. Southern's customers are challenging the recovery of GSR costs attributable to such contract on eligibility and prudence grounds and on the basis that such costs also constitute non-cash consideration for the 1989 take-or-pay settlement with Exxon and thus are not recoverable due to the 1988 take-or-pay cost cap. If the settlement with Exxon does not become effective, Southern cannot predict the outcome of pending or future proceedings for the recovery of GSR costs related to the gas supplies connected by the Mississippi Canyon Facilities or its pending litigation with Exxon regarding Southern's notice of termination of the Mississippi Canyon Contract.
Potential Royalty Claims. In connection with certain of its settlements of take-or-pay claims made by producers during the 1980s, Southern indemnified the producers against various potential claims related to the settlement that might be made by royalty owners. Southern has thus far been notified by ten producers of 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 MMS with respect to federal offshore and Indian leases. Southern has spent approximately $1.2 million to date in settlement of claims of this type. Under the terms of a 1988 take-or-pay recovery settlement with Southern's customers, Southern is entitled to seek recovery of such costs related to federal offshore or Indian leases under the FERC's Order No. 500 cost-sharing procedures. The customers are entitled, however, to challenge any effort by Southern to recover those costs. Southern 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 or of Southern's efforts to recover from its customers any amounts it may pay, but believes that these claims will not have a material adverse effect on Southern's financial condition or results of operations.
Sea Robin Pipeline Company. Sea Robin Pipeline Company ("Sea Robin"), a wholly owned subsidiary of Southern, owns and operates a 438-mile pipeline system located in the Gulf of Mexico through which it gathers natural gas and condensate for others and delivers those products to shore for condensate removal and gas processing and redelivery to five downstream transmission pipelines. See the system map on page I-18. Sea Robin is a transportation-only pipeline that has restructured in compliance with FERC Order No. 636. During 1994 Sea Robin connected three new offshore gas fields to its system at a cost of $9 million. Sea Robin has also executed contracts to connect a new deepwater offshore production area to its system during 1995 at an expected cost of $1.1 million. Sea Robin transported approximately 282 Bcf of natural gas in 1994 compared to 287 Bcf in 1993. These Sea Robin volumes are included within the Southern transportation volumes discussed earlier.
During the past year the FERC has issued a series of orders in which it has found that certain facilities operated by interstate natural gas transmission companies and, in some instances, facilities previously certificated under the NGA, are exempt from its jurisdiction pursuant to Section 1(b) of the NGA because they qualify as gathering facilities. Sea Robin began discussions during the fourth quarter of 1994 with the shippers on its pipeline system regarding the terms under which it would gather gas supplies for its existing shippers as a gathering company not subject to the jurisdiction of the FERC. As of March 1, 1995, Sea Robin has executed new gathering contracts with shippers representing approximately 53 percent of its annual deliveries in 1994. Discussions are continuing with the remaining shippers. Sea Robin's general proposal to all of its shippers includes maintenance of Sea Robin's existing rates for five years, following which the gathering rates will be adjusted on an annual basis by application of an inflation index. Sea Robin has negotiated gathering contracts with each shipper on an individual basis, however, and the specific terms and conditions of each contract may vary.
On January 20, 1995, Sea Robin filed a petition requesting the FERC to declare that Sea Robin's facilities are exempt from the jurisdiction of the FERC under Section 1(b) of the NGA. Shippers representing approximately 21 percent of Sea Robin's annual deliveries in 1994 have filed in opposition to Sea
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Robin's petition at the FERC. The new gathering contracts described above are contingent on the FERC granting Sea Robin's request. If Sea Robin's petition is approved by the FERC, Sea Robin expects that the FERC will require it to tender to those shippers with which it has been unable to reach agreement a "default contract" that will provide for gathering services under Sea Robin's existing rates, as adjusted for inflation, for a two-year term. In addition to their protests in the gathering proceeding, on February 16, 1995, several of Sea Robin's shippers filed with the FERC a complaint against Sea Robin under Section 5 of the NGA claiming that Sea Robin's rates are unjust and unreasonable. Any reduction in Sea Robin's rates as a result of this complaint, however, could be implemented only on a prospective basis. Sea Robin is unable to predict the outcome of either of these proceedings.
Sonat Intrastate-Alabama Inc. Sonat Intrastate-Alabama Inc. ("SIA"), a wholly owned subsidiary of Southern, owns and operates 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. See the system map on page I-18. SIA's throughput in 1994 was approximately 38 Bcf compared to 36 Bcf in 1993.
Sonat Ventures Inc. Sonat Ventures Inc. ("Ventures"), a wholly owned subsidiary of Southern, 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. ("Sonat NGV"), a wholly owned subsidiary of Ventures, was created in July 1992. Sonat 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. In 1994 this joint venture was reorganized into a Georgia limited liability company, NGV Southeast Technologies Center, L.L.C. ("NGV Southeast"). The conversion facility near Atlanta, Georgia, opened in February 1993. In addition to the conversion of vehicles, NGV Southeast has constructed a mobile source emissions testing laboratory, which is scheduled for completion during the second quarter of 1995. NGV Southeast intends to seek certification by the U. S. Environmental Protection Agency to perform vehicular emissions tests. During 1993 Ventures also entered into two joint ventures with affiliates of 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 and the first station in Florida is expected to begin operating in the second quarter of 1995. A Florida limited partnership, in which Ventures is a 50-percent general partner and an affiliate of a Florida local distribution company is a 50-percent general partner, entered into a joint venture in January 1995 with Amoco Oil Company to develop a public fueling infrastructure for vehicular natural gas in Dade, Broward, and Palm Beach Counties, Florida.
South Georgia Natural Gas Company. South Georgia, a wholly owned subsidiary of Southern, owns and operates a 909-mile interstate natural gas transmission system located in eastern Alabama, southern Georgia, and the Florida Panhandle. See the system map on page I-18. As described above, South Georgia has restructured pursuant to Order No. 636 and is a transportation-only pipeline. South Georgia transported approximately 34 Bcf of natural gas in 1994 compared to 32 Bcf in 1993. These South Georgia volumes are included within the Southern transportation volumes discussed earlier.
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 and preserved an option for customers of Southern Energy to obtain LNG through this facility at least through the year 1999.
Sonat Energy Services Company
Energy Services, which is a wholly owned subsidiary of Sonat, acts as a holding company for two of Sonat's largely non-FERC-regulated companies engaged in natural gas marketing and power generation.
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Sonat Marketing Company. Marketing, which is a wholly owned subsidiary of Energy Services and 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 1994 Marketing sold 482 Bcf of natural gas purchased from approximately 275 natural gas producers compared to 1993 sales of 285 Bcf of natural gas purchased from approximately 250 natural gas producers.
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 all of the natural gas production of Exploration that is not sold under pre-existing term dedications and for executing 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 1.6 billion cubic feet of natural gas per day at the end of 1994 versus 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. During 1994 Marketing also added a variety of new risk-management, transportation, and storage services for its customers.
Sonat Power Inc. Sonat Power Inc. is a wholly owned subsidiary of Energy Services. In June 1992 Sonat and The AES Corporation formed a 50-50 joint venture, AES/Sonat Power, L.L.C., 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 natural gas-fueled power plant to be constructed in San Francisco. If this project goes forward, a subsidiary of The AES Corporation would construct and operate the plant. Energy Services is assisting in the negotiation of the gas supply and transportation contracts needed in connection with the project. The plant is currently planned to be completed by mid-1997 and would require an equity investment from Sonat in the range of approximately $15-20 million.
Citrus Corp.
Sonat owns one-half of the stock of Citrus, which owns all of the stock of Florida Gas and Citrus Trading Corp., a natural gas marketing company that began selling natural gas to Florida Power & Light Company during 1990 under a 15-year contract for up to 125 Bcf annually. During 1994 Citrus successfully negotiated a restructuring of the pricing terms under this contract.
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 owns the other 50 percent of Citrus. Florida Gas' approximately 4,500-mile pipeline system extends from south Texas to a point near Miami, Florida, with a certificated daily delivery capacity of 1,455 million cubic feet per day. See the map on page I-18. Florida Gas is the primary pipeline transporter of natural gas in the state of Florida and the sole pipeline transporter to peninsular Florida. In 1994 Florida Gas transported 325 Bcf of natural gas.
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 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 for aggregate costs that are less than the $160 million maximum amount that it is entitled to recover from its customers pursuant to its 1993 restructuring settlement under Order No. 636.
Florida Gas, with approval of the FERC, completed a project in the first quarter of 1995 known as the Phase III expansion, which increased its system capacity by 530 million cubic feet of gas per day to its current total of 1,455 million cubic feet per day. The project is fully subscribed by 31 customers under long-term service agreements, with over 60 percent of the capacity dedicated to the growing electric generation market in
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Florida. As part of Phase III, Florida Gas contracted for 100 million cubic feet per day of new firm transportation to be delivered from Southern's system. Also in connection with the expansion, Florida Gas acquired a 20-percent interest in an existing pipeline in the Mobile Bay area that has been expanded by over 300,000 Mcf per day and connected to Florida Gas' pipeline system.
Primarily as a result of the delays and increased construction costs associated with weather and environmental problems, the $1 billion cost of the Phase III expansion project is more than originally estimated. While Florida Gas believes that all of the costs of the Phase III expansion have been prudently incurred, Florida Gas' customers have the right under general rate-making principles to challenge any of these costs as imprudently incurred. As of December 31, 1994, Sonat has increased its equity investment in Citrus by $159 million in order to fund Phase III.
Florida Gas is currently reviewing the prospects for further expansions of its pipeline system into the Florida market.
At December 31, 1994, Citrus' gross pipeline and facilities cost was approximately $2,593,563,000 and its net cost was approximately $2,235,167,000. Sonat had an investment in Citrus, including its equity in undistributed earnings, of $291,700,000 at December 31, 1994. 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. Since the mid-1980s customers have switched their volumes from a bundled merchant service to transportation service, acquiring gas supply under unregulated arrangements such as those provided by Marketing and Citrus Trading Corp. 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, electricity, and heavy crude oil. 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 1994, and may be at times in the future, 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. 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.
FERC's Order No. 636 mandates a rate design, known as straight fixed-variable ("SFV"), that is designed to allow pipelines to recover substantially all fixed costs, a return on equity, and income taxes in the capacity reservation component of their rates. The firm transportation customers of Southern and Florida Gas (with the exception of certain small customers) must pay these reservation charges regardless of the volumes shipped. Accordingly, the SFV rate design should result in greater stability in the earnings and cash flows of interstate pipelines, including Southern and Florida Gas. This is particularly true at Florida Gas, which faces intense competition in the Florida market from residual fuel oil that affects the volumes of gas it transports.
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.
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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 39.7 percent of Offshore's outstanding shares. Offshore maintains offices, land bases, and other facilities at various locations throughout the world.
As of March 1, 1995, Offshore wholly owns 19 marine units and operates two others that are owned by a company in which Offshore has a 24.9 percent ownership interest. At March 1, 1995, 16 of the 21 marine units were working or committed to work under contract.
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 13 "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. Offshore now wholly owns three of these five semisubmersibles, while the other two are owned by a company in which Offshore has a 24.9 percent interest and are managed by Offshore through most of 1995. At March 1, 1995, Reading & Bates Corporation, a competitor of Offshore, owned 73.1 percent of the company that owns these two rigs. Offshore also owns and operates three other semisubmersibles, two dynamically positioned, deep-water drillships, ten jackups, and one submersible. All of Offshore's drilling equipment is suitable for both exploration and development drilling, and Offshore is normally engaged in both types of drilling activity.
Offshore's contracts to provide offshore drilling services are individually negotiated and vary in their terms and provisions. Offshore obtains most of its contracts through competitive bidding against other contractors. It is not unusual, however, for Offshore to be awarded drilling contracts for its deep-water and harsh-environment units on a negotiated basis without competitive bidding. Drilling contracts generally provide for a basic drilling rate on a dayrate basis and for lower rates for periods of travel or when drilling operations are interrupted or restricted by equipment breakdowns, adverse environmental conditions, or other conditions beyond the control of Offshore. Offshore also performs drilling services under turnkey contracts, which provide for payment of a fixed price per well. Under turnkey contracts, Offshore agrees to drill a well to a specified depth for a fixed price. In general, no payment is received unless the well is drilled to the specified depth. Turnkey contracts offer the possibility of financial gains or losses that are substantially greater than those that would ordinarily result under conventional dayrate contracts. Revenues from dayrate contracts have historically accounted for substantially more of Offshore's revenues than turnkey contracts.
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.
The offshore drilling market in 1993 and 1994 generally experienced difficult conditions, although certain geographic areas and market segments have performed better than others. Throughout most of 1994 the North Sea market was depressed in comparison with recent years, primarily due to the decline in oil prices and the effects of changes made in 1993 to the U.K. Petroleum Revenue Tax on exploratory drilling. Beginning in late 1994 and continuing into 1995, however, the market for drilling services in the U.K. sector of the North Sea improved significantly because of a combination of factors, including the exodus of rigs from the area, the commencement of both major and marginal field development programs, and major new discoveries in the area. Offshore expects nearly full utilization of semisubmersibles in the North Sea market in 1995. The U.S. Gulf of Mexico shallow-water market is largely dependent on U.S. natural gas prices. The steady decline of these prices in 1994, together with the influx of rigs into the Gulf beginning in late 1993, resulted in declines in
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demand and dayrates in the second half of 1994. Given the uncertainties of natural gas prices, Offshore cannot predict the extent or duration of the current weakness in this market. The deep-water market has continued to evidence increased demand, however, which started in early 1994. Additional contractors have elected to focus on turnkey drilling, a factor that 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 are completed, new contracts offering similar returns can be found.
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.
Transmission, Storage, and Marketing of Natural Gas
Southern is subject to regulation by the FERC and by the Secretary of Energy under the NGA, the NGPA, and the Department of Energy Organization Act of 1977 (the "DOE Act"). Southern's interstate transmission subsidiaries and Florida Gas are also subject to such regulation.
The NGA, 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 interstate transmission 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. As necessary, Southern, its interstate transmission 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.
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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 natural gas transmission 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 natural gas transmission 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 $13 million in 1994 compared to $14 million in 1993. It is anticipated that such expenditures will be approximately $20 million in 1995.
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 under the caption "Rate Matters," 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 and Southern filed with the FERC on March 15, 1995, a Customer Settlement (described above) that, if it is approved by the FERC and becomes effective, would resolve all outstanding rates and GSR cost recovery proceedings as to supporting customers.
ENVIRONMENTAL MATTERS
Various environmental matters relating to, or that could affect, Sonat or one or more of its subsidiaries are described in Part II of this report in Management's Discussion and Analysis of Financial Condition and Results of Operations under the caption "Environmental Issues," which is incorporated herein by reference.
CORPORATE RESTRUCTURING
In late 1994 and early 1995 Sonat completed a reduction in staffing levels that is described in Part II of this report in Management's Discussion and Analysis of Financial Condition and Results of Operations under the caption "Corporate Restructuring," which is incorporated herein by reference.
ITEM 2.
ITEM 2. PROPERTIES
A description of Sonat's and its subsidiaries' properties is included under Item 1. Business above and is 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. For information regarding various environmental matters relating to, or that could affect, Sonat or one or more of its subsidiaries, see Management's Discussion and Analysis of Financial Condition and Results of Operations in Part II of this report under the caption "Environmental Issues."
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. This lawsuit was filed against Southern and Atlanta Gas Light Company ("Atlanta") 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. On May 12, 1994, the FERC issued an order granting such approval. Atlanta and
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others sought rehearing on the May 12 order. Atlanta also filed a petition for review of such order in the Court of Appeals. The FERC has not acted upon the rehearing requests other than to give itself more time to consider the rehearing petition. 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.
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 of monetary damages. Southern's customers are challenging the recovery of GSR costs attributable to the Contract. See the discussion above in Item 1 under the caption "Administrative Law Judge Ruling Concerning Recoverability of Investment in Offshore Gas Supply Facilities; Settlement with Exxon Corporation." The U.S. District Court for the Southern District of Texas entered a summary judgment order on August 29, 1994, upholding Southern's termination of the Contract. On September 6, 1994, Exxon filed an appeal of the summary judgment order with the U.S. Court of Appeals for the Fifth Circuit, which remains pending. On February 17, 1995, Southern reached a settlement with Exxon pursuant to which this lawsuit would be dismissed. The settlement with Exxon, however, will not become effective until the Customer Settlement (described above in Item 1) is effective. Pending the settlement becoming effective, therefore, Exxon's appeal has been stayed. If it were to go forward, management is unable to predict the outcome of this litigation or whether its position that it has the right to terminate the Contract would be sustained.
Southern Natural Gas Company v. ARCO Oil and Gas Company, d/b/a Vastar Resources, Inc., was filed in January 1994 in Civil District Court for the Parish of Orleans, Louisiana, and Vastar Resources, Inc. v. Southern Natural Gas Company was filed in April 1994 in the 125th Judicial Court of Harris County, Texas. Vastar Resources, Inc. ("Vastar") and Southern filed separate actions to petition these respective state courts to determine the price of gas under a 1949 contract between Vastar and Southern, providing for the purchase and sale of gas from the Logansport and Joaquin Fields located in Louisiana and Texas. Southern maintains that a provision of the contract provides for a market price, while Vastar maintains that the contract price is based upon the last regulated price in effect, adjusted for escalation. The parties have deferred the matter to arbitration and the two lawsuits have been stayed pending the outcome of that proceeding, which is scheduled to begin April 3, 1995, in New Orleans, Louisiana. Southern has recorded its reasonably estimable losses in connection with these proceedings,but will seek to recover as a GSR cost any amounts for gas purchases at prices above spot-market that may ultimately be determined it owes to Vastar as a result of these proceedings.
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 it.
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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 1994.
Executive Officers of the Registrant
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 a Director of Sonat effective September 22, 1994, and currently serves in those capacities. 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 Vice Chairman of Exploration. During the past five years Mr. Smith has served as an officer of Sonat, Exploration, Southern, and Energy Services.
James A. Rubright was elected Senior Vice President and General Counsel of Sonat effective April 1, 1995, and will serve in that capacity beginning on that date. Mr. Rubright currently serves as Vice President and General Counsel of Sonat and 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 effective February 15, 1994, Mr. Rubright had been a member of the Atlanta, Georgia law firm of King & Spalding.
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, Exploration, Southern, 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 and Southern. During the past five years Ms. Krannich has served as an officer of Sonat, Exploration, and Southern.
Ronald B. Pruet was elected Vice President and Controller of Sonat effective April 1, 1994, and currently serves in that capacity. 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 Sonat and Exploration.
James E. Moylan, Jr. was elected President of Southern effective April 1, 1994, and currently serves in that capacity. 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-41 is reproduced from, and the Table of Contents below is taken from, the Sonat Inc. Annual Report to Stockholders for 1994. 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
II-1
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 its Exploration and Production and Natural Gas Transmission and Marketing segments.
Segment Operating Income
EXPLORATION AND PRODUCTION
The Company is engaged in the exploration for and the acquisition, development, and production of oil and natural gas in the United States through Sonat Exploration Company. Sonat Exploration's strategy is to acquire gas properties with significant development potential. Since implementing this strategy in 1988, Sonat Exploration's proved reserves have grown to approximately 1.6 trillion cubic feet of natural gas equivalent at December 31, 1994, more than a six-fold increase. Sonat Exploration intends to continue aggressively to acquire domestic gas properties with significant development potential. During 1994 Sonat Exploration acquired oil and gas interests and properties for a total of $163 million, with proved reserves of approximately 278 billion cubic feet of natural gas equivalent. Through these acquisitions, Sonat Exploration extended its operations to the Permian Basin of west Texas and increased its position in south Texas. In early 1995, Sonat Exploration announced two significant acquisitions of oil and gas producing properties, one in north Louisiana and the other in the Texas Panhandle area. These transactions, which total $158.3 million, will add proved reserves of 188 billion cubic feet of natural gas and 11.2 million barrels of oil and condensate, yielding a unit acquisition cost on a natural gas equivalent basis of $.62 per thousand cubic feet. Total capital expenditures for Sonat Exploration are expected to approximate $410 million in 1995, which would be up slightly from 1994. Capital spending planned for 1995 includes approximately $250 million for producing property acquisitions. Sonat Exploration's developmental drilling programs continue to be very successful. During 1994 Sonat Exploration participated in the drilling of 343 development wells. These drilling programs added proved reserves of approximately 136.5 billion cubic feet of natural gas equivalent. Sonat Exploration's natural gas production is marketed primarily in the spot-market by Sonat Marketing Company, a subsidiary of the Company operating in the Natural Gas Transmission and Marketing segment. The decline in natural gas prices since mid-year reduced earnings for 1994, particularly in the fourth quarter. These low prices are continuing into 1995 and, if the trend of lower prices continues for the entire year of 1995, Sonat Exploration's earnings and cash flow will be lower than 1994 results. Sonat Exploration, through Sonat Marketing, uses derivative financial instruments as hedges to reduce the risks associated with price volatility for its production (see Commodity Price Risk Management and Note 2 of the Notes to Consolidated Financial Statements).
Exploration and Production Operations
II-2
Sonat Inc. and Subsidiaries
1994 Versus 1993. Operating income for 1994 declined 26 percent when compared to 1993 primarily due to lower natural gas prices and higher amortization. Revenues for 1994 were up by $60 million over 1993 due primarily to a 21 percent increase in natural gas production and a 36 percent increase for oil and condensate production resulting from the continuing acquisition and development program. Natural gas liquids production increased 69 percent over last year, primarily as a result of increased production from the Austin Chalk trend. On average, 1994 oil and gas prices were 9 percent and 8 percent lower, respectively, than in 1993. The hedging program's effect on revenue was a favorable $10 million in 1994 and an unfavorable $5 million in 1993. The most significant price fluctuation occurred in the fourth quarter of 1994 as average gas prices declined to $1.59 per Mcf compared to $2.06 for the fourth quarter of 1993, a 23 percent decrease. Amortization expense increased 39 percent when compared with 1993, primarily due to increased production volumes. The 1994 amortization rate also increased from the 1993 rate due in large part to a higher proportion of Austin Chalk (predominantly oil, condensate and natural gas liquids) production in 1994. Expanding operations and acquisitions were primarily responsible for increases in other operating expenses, including general and administrative expenses. The reduction in equity in earnings of unconsolidated affiliates reflects Sonat Exploration's acquisition of the remaining interest in Sonat/P Anadarko Limited Partnership (Sonat/P) in late 1993. Sonat/P was established in the third quarter of 1992. 1993 Versus 1992. Operating income for 1993 was up significantly from 1992, reflecting in part 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. The higher amortization rates resulted from increased Austin Chalk production, tight-sands gas drilling, and acquisitions that included more proved, producing reserves. General and administrative expense compared favorably to 1992 due to $4 million of restructuring charges included in 1992.
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 Marketing. Southern and Florida Gas Transmission Company, a subsidiary of Citrus, operating in the natural gas transmission industry, have historically provided their customers with 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, both Southern and Florida Gas have essentially become solely gas transporters, although Southern continues to make limited sales pending the expiration, termination, or assignment of its remaining gas supply contracts. Citrus also provides natural gas marketing activities through affiliates, primarily to customers of Florida Gas. The natural gas transmission industry, although regulated, is very competitive. Since the mid-1980s customers have switched their volumes from a bundled merchant service to transportation service, acquiring 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. Southern continues to pursue growth opportunities to expand the level of services in its traditional market area and to connect new gas supplies. On May 1, 1994, Southern completed its second pipeline expansion into northern Florida and southwestern Georgia, which increased firm daily capacity by 40 million cubic feet per day. On July 22, 1994, Southern filed an application with the Federal Energy Regulatory Commission (FERC) for authorization to construct a 21-mile pipeline extension to a delivery point near Chattanooga, Tennessee, that will deliver natural gas to a group of new customers who have signed 10-year contracts for firm transportation volumes totaling approximately 11 million cubic feet per day. Florida Gas, which has a pipeline system capacity of 925 million cubic feet per day, will place its Phase III expansion into service on March 1, 1995, increasing its system capacity by 530 million cubic feet per day. As part of Phase III, Florida Gas will contract for 100 million cubic feet per day of new firm transportation to be delivered from Southern's system. Also in connection with this expansion, Florida Gas will acquire a 20 percent interest in an existing pipeline in the Mobile Bay area that was expanded by over 300 million cubic feet per day and connected to Florida Gas' pipeline system. Primarily as a result of the delays and increased construction costs associated with weather and environmental problems, the $1 billion cost of the Phase III expansion project is more than originally estimated. While Florida Gas believes that all of the costs of the Phase III expansion have been
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
prudently incurred, Florida Gas' customers have the right under general rate-making principles to challenge any of these costs as imprudently incurred. As of December 31, 1994, the Company had increased its equity investment in Citrus by $159 million in order to fund Phase III. Additionally, Florida Gas is currently reviewing the prospects for further expansions of its pipeline system into the Florida market. Sonat Marketing continued to expand its natural gas marketing business during 1994. It now markets the majority of the natural gas production of Sonat Exploration, and has responsibility for the execution of Sonat Exploration's risk management program. Adding the Sonat Exploration volumes has enabled Sonat Marketing to expand its presence in Gulf Coast, Midwest, and Northeast markets and to begin building a significant base of sales in these markets to enhance its marketing of natural gas volumes acquired from unaffiliated producers. As a result of these efforts and due to increased purchasing from third parties, Sonat Marketing's average daily sales volumes at year-end 1994 were 1.6 billion cubic feet per day, versus 1.1 billion cubic feet per day at the end of 1993. Sonat Marketing uses derivative financial instruments to offer fixed price contracts to its suppliers and customers. (See Commodity Price Risk Management and Note 2 of the Notes to Consolidated Financial Statements.)
Natural Gas Transmission and Marketing
Southern Natural Gas Company
(1) Southern's transportation revenues and depreciation expense in 1994 include a $16 million decrease reflecting a retroactive reduction in certain depreciation rates. (2) Southern's other revenue and operating and maintenance expense in 1994 include a $38 million adjustment related to the recognition of fuel revenue and expense.
Citrus Corp.
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Sonat Inc. and Subsidiaries Sonat Marketing Company
1994 Versus 1993. Operating income for the Natural Gas Transmission and Marketing segment increased 9 percent excluding the effect of significant unusual items recognized by Southern in the fourth quarter of 1994. The increase was due to operations of both Southern and Sonat Marketing. The significant unusual items in 1994 included in operating and maintenance expense consisted of a $29 million charge associated with a comprehensive customer rate settlement that will be filed by Southern with the FERC in March 1995 (the Customer Settlement) and a $28 million provision relating to regulatory assets that will not be recovered as a result of the Customer Settlement, including amounts for a corporate restructuring undertaken in 1994. See Rate Matters for a discussion of the Customer Settlement. Southern Natural Gas-Excluding the unusual items discussed above, Southern's operating income for 1994 increased slightly when compared with 1993 as a result of higher transportation revenue resulting from the sale of unsubscribed firm transportation capacity and lower general and administrative costs. Southern's gas sales revenues and gas costs were down significantly in 1994 as a result of implementing Order No. 636 and primarily represent recognition of gas sales made from supply remaining under contract after the implementation of Order No. 636 (see Order No. 636 discussion below). The volumes associated with these sales are included in transportation volumes because, as required by Order No. 636, all sales are now made at the wellhead. Another factor in the decrease in revenues was the recovery of $42 million of Order No. 500 costs in 1993 revenues. Higher transportation revenues and volumes are a result of the shift from sales to transportation due to the implementation of Order No. 636. Other revenue also increased in 1994 due to the recovery of transition costs of $108 million related to the implementation of Order No. 636. General and administrative costs decreased primarily due to lower employee costs, including stock-based compensation expenses. Citrus-Equity in earnings of Citrus increased to $29 million from a loss of $6 million in 1993 due to the capitalization of financing costs (AFUDC) in 1994 related to the Phase III expansion project, lower depreciation due to an increase in the estimated useful life of the existing pipeline system, and higher margins on a gas supply contract with one of its major customers, which was restructured during 1994. This was partially offset by the favorable effect in 1993 of the sale of gas supply contracts at Citrus Marketing. Sonat Marketing-Operating income for Sonat Marketing was $11 million in 1994 as compared with $2 million in 1993. Sonat Marketing's sales volumes increased significantly over 1993 levels as a result of marketing Sonat Exploration's production for the entire period and increasing sales on interstate pipelines that serve the Midwest and Northeast markets through the purchase of additional third-party volumes. In addition, average margins per MMBtu have increased from $.03 in 1993 to $.05 in 1994 due to greater concentration on value-added services. 1993 Versus 1992. Operating results for the Natural Gas Transmission and Marketing segment were up slightly in 1993 excluding the effect of a $9.6 million settlement in 1992 relating to Southern Energy Company's (a subsidiary of Southern) idle liquefied natural gas facility. Southern Natural Gas-Excluding the unusual item discussed above, Southern's operating results were up 4 percent in 1993. Gas sales revenue and gas costs were abnormally high 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. 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. Citrus-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. The decline was offset, however, 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
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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. Sonat Marketing-Operating income for Sonat Marketing was $2 million in both 1993 and 1992. Sonat Marketing's sales revenues and volumes increased significantly over 1992 as a result of integrating the marketing of Sonat Exploration's production, which was completed in late 1993, and expanding activities on nonaffiliated pipelines through the purchase of additional third-party volumes. Increased expenses related to expanding operations offset the benefit of the revenue growth.
ORDER NO. 636
In 1992 the FERC issued its Order No. 636 (the Order), which required interstate natural gas pipeline companies to make significant changes in the way they operate, including 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 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 (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 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. 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. 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. Southern's largest customer, Atlanta Gas Light Company and its subsidiary, Chattanooga Gas Company (collectively Atlanta), signed firm transportation service agreements with transportation demands of 582 million cubic feet per day for a one-year term ending October 31, 1994, and 118 million cubic feet per day for a term extending until April 30, 2007. This represented an aggregate reduction of 100 million cubic feet per day from Atlanta's level of service prior to November 1, 1993. 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 for terms ranging from one to 10 or more years. Alabama Gas Corporation, Southern's second largest customer, executed firm transportation contracts for 393 million cubic feet per day under terms extending through October 31, 2008. Atlanta elected to renew its firm transportation service agreements with transportation demands of 582 million cubic feet per day, which expired October 31, 1994, for a one-year term beginning November 1, 1994. In September and October of 1994, Atlanta and South Carolina Pipeline Corporation (SCPL) executed three-year firm service agreements with transportation demands of an additional 100 million cubic feet per day and 28 million cubic feet per day, respectively. With these additional subscriptions, substantially all of Southern's firm market-area capacity currently available became fully subscribed. If the Customer Settlement (described in Note 9 of the Notes to Consolidated Financial Statements) becomes effective, Atlanta will amend its firm transportation contracts for an aggregate of 682 million cubic feet per day to extend the primary term for a period of three years beginning as of the date an interim rate reduction becomes effective, which will occur as of March 1, 1995. (See Note 9 of the Notes to Consolidated Financial Statements.) An additional 118 million cubic feet per day would remain under its current term to April 30, 2007.
NATURAL GAS SALES AND SUPPLY
Sales by Southern of natural gas are anticipated to continue until Southern's remaining gas supply contracts expire, are terminated, or are assigned. Southern is attempting to terminate its remaining gas supply 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 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
II-6
Sonat Inc. and Subsidiaries
remaining gas supply contracts, Southern sold 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. A portion of these sales agreements were extended for an additional one-year term, while the sales agreements with Atlanta were extended through March 31, 1995. Certain customers, including Atlanta, have advised Southern that if the Customer Settlement becomes effective, they will extend their sales agree- ments through November 30, 1997. The remainder of Southern's gas supply will continue to be sold on a month-to-month basis. As discussed in Note 9 of the Notes to Consolidated Financial Statements, Southern is incurring certain transition costs under the Order, primarily gas supply realignment (GSR) costs relating to existing gas purchase contracts. Southern's customers are contesting Southern's proceedings to recover its GSR costs on eligibility and prudence grounds and on the basis that Southern is precluded from recovering certain of such costs under a 1988 take-or-pay settlement that limited the amount of such costs that Southern could recover. In its Customer 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, recent contract renegotiations, and price differential costs actually incurred, the total amount of GSR costs are estimated to be approximately $328 million on a present-value basis. This amount includes the payments made or accrued through December 31, 1994, to amend or to terminate gas purchase contracts and price differential costs, and the $64 million cost that will be incurred under a settlement of existing contracts with Exxon Corporation (Exxon), which will become effective if the Customer Settlement becomes effective. These costs collectively total $288 million. Thus, Southern currently estimates it will ultimately pay an additional $40 million in GSR costs. These amounts do not include an additional $87 million in GSR costs that would be incurred if the settlement with Exxon does not become effective and Exxon prevails on its lawsuit regarding Southern's March 1, 1994, termination of a contract relating to Exxon's reserves in its Mississippi Canyon blocks. Subject to the cost-sharing mechanism in the Customer Settlement, pursuant to which Southern will absorb an agreed-upon portion of its total GSR costs, Southern will recover in accordance with the Customer Settlement or, pending approval of the Customer Settlement, 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 sales agreements and month-to-month sales as well as any cost previously incurred or to be incurred as a result of Order No. 636 to terminate or reduce the price under Southern's remaining contracts. If the Customer Settlement is not approved, Southern cannot predict the ultimate outcome of its Order No. 636 restructuring proceedings and its limited rate filings to recover its GSR costs. (See Rate Matters and Note 9 of the Notes to Consolidated Financial Statements.) Southern's purchase commitments under its remaining gas supply contracts for the years 1995 through 1999 are estimated as follows:
Estimated Purchase Commitments
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 that determine purchase commitments (underlying reserves, future deliverability, and future price) is known today with certainty. These estimates also exclude estimated purchase commitments under certain contracts with Exxon that will be terminated if the Customer Settlement becomes effective. If the Customer Settlement does not become effective and Southern were therefore required to perform these contracts, and further assuming that Exxon were to prevail on its appeal of a summary judgment upholding the Company's termination of the Mississippi Canyon Contract, which is currently the subject of litigation between Exxon and Southern as described in Note 9 of the Notes to Consolidated Financial Statements, these estimates would increase by $170 million in 1995, $144 million in 1996, $57 million in 1997, $5 million in 1998, and $2 million in 1999. Of these amounts, $126 million in 1995 and 1996 and $49 million in 1997 is attributable to the Mississippi Canyon Contract. In addition, as part of its settlement with Exxon, which as noted is contingent on the effectiveness of the Customer Settlement, Southern and Exxon have agreed to terminate all their existing gas purchase contracts and to enter into two new gas purchase contracts having three-year terms and providing for market-based index prices (which would not constitute GSR costs). Therefore, if the Customer Settlement becomes effective,
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MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
these estimates could increase by $108 million in 1995, $94 million in 1996, and $35 million in 1997 to include these two new contracts with Exxon.
RATE MATTERS
Several general rate changes have been implemented by Southern and remain subject to refund. If the Customer Settlement is approved by the FERC and becomes effective, all outstanding rate and Order No. 636 transition cost recovery proceedings would be resolved. The settlement would result in reducing Southern's filed rates to more competitive levels, would reduce somewhat reported revenues, and would reduce depreciation expense to approximately $40 million in 1995. Although Southern has been advised by customers representing more than 80% of its firm capacity that they intend to support the settlement, there is no assurance that the settlement will be approved by the FERC. (See Note 9 of the Notes to Consolidated Financial Statements for a discussion of the Customer Settlement and other rate matters.)
CITRUS CORP.
During 1994 Citrus had net income of $55 million compared with a loss of $16 million in 1993. This increase primarily resulted from AFUDC recognized on the Phase III expansion project, decreased depreciation due to an increase in the estimated useful life of the existing pipeline, and improved earnings on a gas supply contract with one of its major customers. These events, combined with Florida Gas' Order No. 636 restructuring and resultant conversion to an SFV rate methodology, are expected to result in stable revenues, earnings, and cash flow at Citrus, although at somewhat lower levels than in 1994 due to the completion of the Phase III expansion project and the resulting end of AFUDC recognition on the project combined with the use of levelized rates on the Phase III portion of the pipeline. Florida Gas has terminated its gas purchase contracts with a weighted average cost in excess of current spot-market prices and has negotiated a settlement with its customers and the FERC to recover 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. 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. Citrus obtains its own financing independent of its parent companies. Debt financing by Citrus with outside parties generally is nonrecourse to its parent companies. (See Note 5 of the Notes to Consolidated Financial Statements for a discussion of a Florida Gas financing.) In connection with the construction of the Phase III expansion, the Company made capital contributions to Citrus totaling $159 million. See Capital Expenditures below.
Equity in earnings of unconsolidated affiliates in the Exploration and Production and Natural Gas Transmission and Marketing segments were discussed earlier. 1994 Versus 1993. Results reported for Sonat Offshore Drilling Inc. in the above table for 1993 are for the last seven months of the year, which is the period after the date of the initial public offering (IPO) of 60 percent of its common stock. Sonat Offshore's results on a 100 percent basis were $13 million and $17 million in 1994 and 1993, respectively. 1994 was lower primarily due to the inclusion in 1993 of $24 million ($16 million after-tax) of interest income relating to an IRS tax settlement for the years 1983 through 1985 and lower operating income from turnkey operations and dayrate operations in Brazil and the North Sea. These unfavorable items were partially offset by improved operating results in the U.S. Gulf of Mexico and Egypt and the acquisition of the remaining 52.5 percent of the Polar Pioneer in 1994. 1993 Versus 1992. On a 100 percent basis, Sonat Offshore's results were $17 million in 1993 compared with $84,000 in 1992. 1993 was higher due to the 1993 $24 million
II-8
Sonat Inc. and Subsidiaries
tax settlement mentioned above and to higher results in the Gulf of Mexico, Brazil and from turnkey operations for 1993.
1994 Versus 1993. Other income is down due to the $156 million pretax gain on the sale of 60 percent interest in Sonat Offshore in 1993. Exclusive of that gain, 1994 Other Income is higher due to the recognition of $4 million in gains on the disposal of assets compared with $1 million in 1993. 1993 Versus 1992. Other income increased in 1993 due to the $156 million pretax gain on the Sonat Offshore IPO. In addition, dividends on the Baker Hughes Incorporated preferred stock received in the sale of Teleco Oilfield Services Inc. (Teleco) in April 1992 contributed $12 million in 1993 versus $7 million in 1992. Also included in 1992 was a $9 million gain on the sale of oil and gas assets.
1994 Versus 1993. Net interest expense for 1994 included $10 million of favorable adjustments related to the settlement of the Company's federal income tax returns for the years 1986-1988. Net interest expense in 1993 included $31 million of favorable adjustments related to the settlement of the Company's 1983-1985 federal income tax returns and certain other tax issues. Excluding these adjustments, net interest expense increased from 1993 due to higher debt levels. 1993 Versus 1992. Net interest expense in 1993 included the $31 million in net interest income mentioned above. Otherwise, the decrease in interest expense in 1993 was due to lower debt levels and interest rates. Some higher rate debt was refinanced during 1993.
1994 Versus 1993. Income tax expense in 1994 decreased as compared to 1993 due to lower pretax income (see 1993 explanation below). Both periods included favorable settlements relating to the examination of the Company's federal income tax returns which reduced reported income tax expense. Tax preference items were higher in 1994 compared to 1993 primarily due to higher dividend exclusions on unconsolidated equity investees partially offset by lower nonconventional fuel tax credits. 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 primarily includes a $113 million gain on the sale of Teleco to Baker Hughes.
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.
LIQUIDITY AND CAPITAL RESOURCES
CASH FLOWS
1994 Versus 1993. Net cash flows from operating activities were $57 million higher in 1994. The increase was primarily attributable to the $147 million change in gas supply realignment costs as a result of net recoveries of $19 million received in 1994 compared with net payments of $128 million in 1993. The $38 million increase in the change in accounts receivable in 1994 reflects the effect on 1993 accounts receivable of Sonat Offshore's turnkey operations in Mexico. The $47 million decrease in the change in inventories reflects the sale of storage gas inventory at Southern in 1993 pursuant to Order No. 636. The $52 million decrease in accrued interest and income taxes reflects recognition of the settlement of an examination of the Company's federal income tax returns and a prepayment of state taxes and related interest. In 1994 the Company completed
II-9
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
recovery of its take-or-pay costs, resulting in the $33 million decrease in the change in take-or-pay recoveries when compared with 1993. The amount in Other in 1994 includes a $57 million provision for the Customer Settlement discussed in Note 9 of the Notes to Consolidated Financial Statements, while the amount in Other in 1993 reflects $52 million in accruals for GSR settlements. 1993 Versus 1992. Net cash provided by operating activities increased due to higher earnings at Sonat Exploration and receipt of $62 million for the settlement of an examination of the Company's federal income tax returns for the years 1983-1985. The $48 million increase in the change in inventories reflects the sale of storage gas inventory at Southern pursuant to Order No. 636. The $36 million net change in other current assets and liabilities reflects lower cash outflows in 1993 relating to gas imbalances. The $24 million decrease in the change in accounts receivable reflects the growth in 1993 of Sonat Offshore's receivables for turnkey operations in Mexico. The $51 million decrease in the change in accrued interest and income taxes reflects the effect of the disposition of Teleco.
1994 Versus 1993. The change in net cash used in investing activities reflects the equity investment in Citrus of $159 million made in 1994 and the approximately $340 million in net cash proceeds from the sale of Sonat Offshore common stock received in 1993. Slightly offsetting the increase is a $68 million reduction in capital expenditures for 1994. 1993 Versus 1992. Net cash used in investing activities increased $159 million in 1993. Capital expenditures of $516 million in 1993 were $291 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. Cash proceeds in 1992 included approximately $188 million from the sale of Teleco.
1994 Versus 1993. The change in cash flows from financing activities reflects increased borrowings in 1994 under Sonat's floating rate facilities compared with debt repayments in 1993. Borrowings in 1994 were primarily used for advances to Citrus and repayment of Southern's $100 million 9 5/8 Percent Notes. In 1993 the Company redeemed its 7 1/4 Percent Zero Coupon, Subordinated Convertible Notes and used cash from the Sonat Offshore IPO temporarily to repay borrowings under its credit agreements. 1993 Versus 1992. The net change in cash used in financing activities reflects a slight increase in debt repayments.
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 $70 million share of unconsolidated affiliates' expenditures) for 1995 are expected to be approximately $550 million.
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Sonat Inc. and Subsidiaries
CAPITAL RESOURCES
At December 31, 1994, the Company had lines of credit and revolving credit agreements with a total capacity of $1.05 billion. Of this amount, $475 million was available for borrowing. The amount available has been reduced by the $100 million of commercial paper outstanding to reflect the Company's policy that bank and commercial paper borrowings in the aggregate will not exceed the maximum amount available under its lines of credit and revolving credit agreements. On July 26, 1993, Sonat filed a shelf registration with the Securities and Exchange Commission (SEC) for up to $500 million in debt securities. The net proceeds from the sale of these debt securities are expected to be used for general corporate purposes, which may include refinancing of indebtedness, working capital increases, capital expenditures, possible future acquisitions, and redemption of securities. Southern also has a shelf registration with the SEC for up to $200 million in debt securities of which $100 million has been issued. On August 1, 1994, Sonat entered into a new 364-day revolving credit agreement with a group of banks. The revolving credit agreement provides for borrowings of up to $300 million through July 31, 1995. The Company expects to continue to use cash from operations and borrowings in the public or private markets or loans from affiliates to finance its capital and other corporate expenditures. In April 1994 the Board of Directors of the Company authorized the repurchase of up to two million shares of the Company's common stock. Purchases are being made from time-to-time in the open market or in privately negotiated transactions. Shares purchased under the authorization are expected to be reissued in connection with employee stock option and restricted stock programs. At December 31, 1994, 940,000 shares of common stock had been purchased under this program. Strong cash flow and borrowings in the public or private markets provide the Company with the means to fund operations and currently planned investment and capital expenditures. As discussed in Note 3 of the Notes to Consolidated Financial Statements, the Company holds four million shares of Baker Hughes preferred stock, as well as 11.3 million shares of Sonat Offshore common stock, both of which could be monetized.
Capitalization Information
COMMODITY PRICE RISK MANAGEMENT
Sonat Exploration and Sonat Marketing use natural gas futures contracts and options on gas futures and oil and gas price swap agreements to hedge the effects of spot-market price volatility on operating results. The Company's use of these instruments is implemented under a set of policies approved by the Board of Directors. These policies prohibit speculation, determine approval levels for each transaction, and set limits regarding volume relative to budgeted production or sales levels. All swap counterparties are approved by the Board, and volume limits are set for any single counterparty. Reports detailing each transaction and showing the Company's aggregate hedge position are prepared daily and distributed to management. In addition, all hedge activities are internally reviewed to ensure compliance with all policies. (See Note 2 of the Notes to Consolidated Financial Statements.)
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 pending customer settlement which will be filed by Southern in March 1995, if approved, would prohibit Southern from recovering higher costs of operations prior to March 1, 1998 (see Note 9 of the Notes to Consolidated Financial Statements). 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 and the interrelationship between oil, gas, and other energy prices.
II-11
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
CORPORATE RESTRUCTURING
In late 1994 and early 1995 the Company completed a reduction in staffing levels through a combination of special early retirement options (SERO) and involuntary terminations. The SEROs and terminations, which involved 340 employees, or approximately 15 percent of the Company's work force, occurred primarily in field locations, but also included significant reductions in office employees. The total cost of the program amounted to $21 million. The majority of the charge represented accelerated retirement costs, with the remainder being primarily cash severance payments. The Company anticipates the savings in 1995 from this program will approximate $12 million.
ENVIRONMENTAL ISSUES
Sonat Exploration, Southern, and 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. The use and disposal by Sonat Exploration, Southern, and their subsidiaries 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. The Environmental Protection Agency (EPA) has notified Sonat Exploration that it could become a potentially responsible party (PRP) at the D. L. Mud Superfund Site in Abbeyville Parish, Louisiana. Based on the information that it currently possesses, Sonat Exploration does not believe that any contribution will be sought from it with regard to this site and believes that, if it were named as a PRP, its status would be that of a de minimis contributor. Sonat Exploration has settled its potential liability at two other Superfund sites at which it had been named as a PRP in exchange for payments not material to it and, barring unexpected events, does not expect to have any further liability with regard to those sites. Southern was named by the EPA in October 1994 as a PRP at a Superfund site in Mississippi known as the Pike County Drum Site. In response to a request from the EPA, Southern provided the EPA with information concerning materials shipped to the site. The EPA advised Southern and the other PRPs in January 1995 that the cost to date of the response actions related to this site through EPA funding was approximately $330,000, and the EPA made demand on Southern and the other PRPs for payment of such amount plus applicable interest. In accordance with the procedures prescribed by the EPA, Southern has indicated to the EPA Southern's intent to participate in settlement negotiations relating to the allocation of such cost among all of the PRPs. Southern believes that, based on the nature and volume of materials that it shipped to this site and the information currently available to it, Southern should be a de minimis contributor to any settlement of such cost. In connection with the Superfund site in Alabama known as the Fuels and Chemicals Site, both Southern and a company in which a subsidiary of Sonat Exploration is a 50-percent shareholder, which were both named among the PRPs at this site, have signed an Administrative Order on Consent for Removal Action (AOC) with the EPA for removal actions at the site. To satisfy their obligations under the AOC, all of the signatory PRPs to the AOC have entered into an Indemnification, Reopener and Settlement Bank Fund Agreement (Indemnification Agreement) with one of the largest PRPs, who has agreed to undertake to perform all remedial actions required by the AOC and any additional response obligation required by the EPA or the Alabama Department of Environmental Management. In return for payments not material to Southern or Sonat Exploration, this PRP has agreed to indemnify the two Sonat entities against any further liability related to the AOC and a prior AOC dated July 20, 1993, (Phase I AOC) unless costs of complying with the AOC and the Phase I AOC exceed a specified amount. Based on the information that it currently possesses, Sonat does not expect the specified amount to be exceeded, unless tests that are being conducted indicate the presence of groundwater contamination at this site.
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Sonat Inc. and Subsidiaries
Southern has settled its potential liability at three other Superfund sites, at two of which it had been named as a PRP, in exchange for payments not material to it and, barring unexpected events, does not expect to have any further liability with regard to any of the three sites. Liability for PRPs under CERCLA (and applicable state law) is joint and several among all 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. In the operation of their natural gas pipeline systems, Southern and its wholly owned subsidiary, South Georgia Natural Gas Company (South Georgia), have used, and continue to use at several locations, gas meters containing elemental mercury. Southern and South Georgia plan to remove all remaining mercury meters during the course of regularly scheduled facilities upgrades. Mercury and mercury meters are handled pursuant to procedures that are designed to 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. Southern believes that its mercury meters may in the past have been the sources of small releases of elemental mercury. Southern intends to commence site characterization and, as appropriate, remediation of mercury-contaminated soil located in Louisiana during the first quarter of 1995. Southern expects to undertake the characterization and remediation of mercury-contaminated soil in its other states of operation beginning in 1996, subject to completion of work in Louisiana. Southern is unable to estimate with precision the cost of the characterization and remediation of mercury-contaminated soil at this time, because costs will vary based on a number of factors particular to each site and because regulatory standards for elemental mercury cleanup are uncertain at this time. Neither the EPA nor any state in which Southern operates has issued standards with respect to cleanup of mercury-contaminated soil; however, Southern has received informal guidance from the State of Louisiana with respect to cleanup standards in that state. Southern has budgeted the amount of $500,000 in 1995 for the characterization and remediation of mercury-contaminated soil in Louisiana and, based on the information that it currently possesses, believes that this amount may be sufficient to complete such characterization and remediation, subject to the actual extent of contamination discovered at any site. During the course of retirement and removal of certain field compressors, Southern discovered soil and groundwater contamination in the Logansport and Joaquin Fields, respectively, in the states of Louisiana and Texas. Although no link between Southern's operations and the groundwater contamination has been established, Southern notified the Louisiana Department of Environmental Quality (LDEQ) of this discovery because of a possibility that the groundwater contamination may be associated to some extent with Southern's past operations in the area. In November 1994 Southern received a request from the LDEQ for an Assessment Work Plan (the Plan) designed to determine the extent, source, and magnitude of soil and groundwater contamination discovered under Southern's field compressor locations, including evaluation procedures used to determine recommendations for remediation of soil and groundwater. Southern filed the Plan in December 1994. Southern expects that work under the Plan will commence during the first quarter of 1995, subject to review and approval of the Plan by the LDEQ. Southern believes that the cost to clean up any soil contamination at its field compressors will not be material. To date, Southern does not have in its possession sufficient information reasonably to estimate the cost, if any, that it may be required to bear for any cleanup of groundwater contamination. No reporting was required in Texas.
II-13
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (CONTINUED)
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, generally will seek recovery of such costs through rate filings, although no assurance can be given with regard to their ultimate recovery. As described in Note 9 of the Notes to Consolidated Financial Statements, however, Southern's proposed Customer Settlement, if approved, would prevent Southern from filing a general rate case to be effective prior to March 1, 1998. Sonat Exploration, Southern, and their subsidiaries are subject to the federal Clean Air Act (Clean Air Act), the federal Clean Air Act Amendments of 1990 (1990 Amendments), which added significantly to the existing requirements established by the Clean Air Act, and the state regulations and requirements promulgated thereunder (together the Clean Air Rules). The 1990 Amendments require that the EPA issue new regulations, mainly related to mobile sources, air toxicants, ozone non-attainment areas, acid rain, permitting, and enhanced monitoring. Southern operates three compressor stations in areas that do not meet the National Ambient Air Quality Standards (NAAQS) established under the Clean Air Act for ozone. Two of these stations are located in Louisiana and one is located in Alabama. The Clean Air Rules require Southern to submit an emissions control plan for nitrogen oxides (NOX) that may require the addition of emissions control technology at each of these stations. The LDEQ had previously instructed Southern to suspend the implementation of its Louisiana emissions control plans for NOX until September 1, 1994, because of the possibility that the emissions of NOX are not the cause of the area's failure to meet NAAQS. In a subsequent letter dated November 22, 1994, the LDEQ instructed Southern to suspend such implementation indefinitely pending the resolution of the LDEQ's request of the EPA for an exemption from the NOX Reasonably Available Control Technology (NOX RACT) requirements. The letter further advised that, upon receipt of such exemption, LDEQ intends to rescind the NOX RACT rules for this area entirely, in which case Southern would no longer be required to add emissions control technology for NOX for the affected facilities. Alabama regulators have not yet published specific emissions control requirements for NOX. Further, Alabama regulators have undertaken to have the area in which Southern's station is located recharacterized as meeting the NAAQS for NOX. Based on these actions, Southern does not currently know whether it will be required to implement emissions control plans for these stations. Based on Southern's projected cost of implementing its emissions control plans in Louisiana, its estimate of the possible cost of implementing a similar emissions control plan in Alabama, and its projected cost of complying with other applicable provisions of the Clean Air Rules, Southern currently estimates that the capital costs that it may incur to implement such plans and to comply with the Clean Air Rules could approximate $15 million. Based on information currently available, management believes that it is not reasonably likely that Sonat or any of its subsidiaries will incur liabilities as a result of the presently identified environmental contingencies in excess of the amounts specifically identified above in amounts 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 be material. 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.
II-14 REPORT OF MANAGEMENT Sonat Inc. and Subsidiaries
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 LLP as independent auditors to audit the Company's consolidated financial statements and express their opinion thereon. Their audit is conducted in accordance with generally accepted auditing standards and includes 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 LLP, Independent Auditors, appears below. 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 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.
Ronald B. Pruet, Jr. - ----------------------------- Ronald B. Pruet, Jr. Vice President and Controller February 23, 1995
REPORT OF ERNST & YOUNG LLP, 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, 1994 and 1993, 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, 1994. 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, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
Ernst & Young LLP
Birmingham, Alabama January 19, 1995
II-15 CONSOLIDATED FINANCIAL STATEMENTS Sonat Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
See accompanying notes.
II-16
CONSOLIDATED FINANCIAL STATEMENTS Sonat Inc. and Subsidiaries
CONSOLIDATED BALANCE SHEETS
See accompanying notes.
II-17 CONSOLIDATED FINANCIAL STATEMENTS Sonat Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF INCOME
See accompanying notes.
II-18 CONSOLIDATED FINANCIAL STATEMENTS Sonat Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CHANGES IN STOCKHOLDERS' EQUITY
See accompanying notes.
II-19 CONSOLIDATED FINANCIAL STATEMENTS Sonat Inc. and Subsidiaries
CONSOLIDATED STATEMENTS OF CASH FLOWS
See accompanying notes.
II-20 Notes to Consolidated Financial Statements Sonat Inc. and Subsidiaries
1. BUSINESS DESCRIPTION AND SIGNIFICANT ACCOUNTING POLICIES
Business Description-The Consolidated Financial Statements of Sonat Inc. and its subsidiaries (the Company) reflect operations in the Exploration and Production and Natural Gas Transmission and Marketing segments. 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. For further description of business segments, see Note 12. For a description of financial instruments, credit risk and contingencies, see Notes 2 and 9. Principles of Consolidation-The Consolidated Financial Statements include the accounts of Sonat Inc. and its subsidiaries. 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 1993 and 1992 Consolidated Financial Statements have been reclassified to conform with the 1994 presentation. Cash Equivalents-Cash equivalents are typically money-market investments in the form of repurchase agreements, 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, 1994, inventories consist primarily of materials and supplies that 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. Imbalances incurred prior to implementation of Order No. 636 are settled through exchange of gas. Imbalances incurred after implementation of Order No. 636 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 product is delivered or the service is provided. Reserves are provided on revenues collected subject to refund when appropriate. Revenues included in the Consolidated Statements of Income relating to the period when Sonat Offshore Drilling's operations were consolidated were recognized as earned based on contractual daily drilling rates, or on a per-well basis. (See Note 3.) Environmental Expenditures-The Company accrues for environmental liabilities when environmental assessments and/or remediation are probable and such costs to the Company can be reasonably estimated. Income Taxes-The Company follows a liability and asset approach in accounting for income taxes. Deferred tax liabilities and assets are determined using the tax rate for the period in which those amounts are expected to be paid or received. 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 Consolidated 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. The dilutive effect of stock options is less than 3 percent and is therefore excluded from the computation. Derivative Financial Instruments-The Company follows hedge accounting for changes in the market value of derivative financial instruments. (See Note 2.) Gains and losses are included in deferred assets or liabilities, respectively, until they are recognized in revenue when the hedged transaction is recorded.
2. FINANCIAL INSTRUMENTS
DERIVATIVE FINANCIAL INSTRUMENTS The Company through its subsidiaries (Sonat Exploration Company and Sonat Marketing Company) uses natural gas futures contracts, options on natural gas futures contracts, and oil and gas price swap agreements to reduce the effects of spot-market price volatility on operating results. All derivative transactions are identified with specific cash transactions or positions. Speculation in derivatives is prohibited by company policy. Futures-Natural gas futures contracts are traded on the New York Mercantile Exchange (NYMEX). Contracts are for fixed units of 10,000 MMBtu and #are available for up to 18 months in the future. Options on natural gas futures contracts are traded on the NYMEX. Brokers require both parties (buyers and sellers) to futures contracts to# deposit cash or other assets with a broker (the margin) at the time the contract is initiated.
II-21
2. FINANCIAL INSTRUMENTS (Continued)
Brokers mark open positions to market daily and require additional assets to be maintained on deposit when unrealized losses are experienced. Conversely, customers' accounts are credited when unrealized gains are experienced. This daily adjustment generally must be settled in cash or acceptable collateral, which serves to reduce credit risk. Maintenance of the deposit account can result in fluctuating cash requirements for both parties. At December 31, 1994, Sonat Marketing had $2.2 million on deposit with brokers for margin calls. Sonat Exploration uses futures contracts to lock in the price of a portion of its expected future natural gas and/or oil production when it believes that prices are at acceptable levels. Generally, contracts have been sold no more than six months into the future and by company policy cannot exceed 50 percent of budgeted monthly gas or oil production. At December 31, 1994, Sonat Exploration had no futures contracts open. Sonat Marketing buys and resells natural gas as part of its normal business operations. In situations where natural gas is not bought and sold simultaneously, Sonat Marketing will use futures contracts to reduce the risk of price changes. For example, Sonat Marketing may purchase certain natural gas volumes before a customer has been identified, then sell an equivalent volume in natural gas futures contracts or options on futures contracts to match the cash transaction. Futures transactions or options are generally one year or less in duration; however, two option agreements extend four and five years. Company policy limits futures contracts to 1,000 net contracts per month. At December 31, 1994, Sonat Marketing had a total of 282 net contracts open (2,270 long and 1,988 short futures contracts) and a marked-to-market loss of $2.6 million, $1.0 million of which will be realized in January 1995, the remainder representing unrealized losses on contracts that will mature in 1995. To date, option activity has not been significant. Swaps-Price swap agreements call for one party to make monthly payments to (or receive payments from) another party based upon the differential between a fixed and a variable price or two variable prices for a notional volume specified by the contract. Sonat Exploration and Sonat Marketing had a total of 16 price swap agreements at December 31, 1994, to exchange payments based on a total notional volume of 25,755,000 MMBtu of natural gas over periods ranging from one month to five years. The average price the Company paid was $1.56 per MMBtu and the average price the Company received was $1.63 per MMBtu for the 1994 period. The Company's credit exposure on swaps is limited to the value of swaps that are in a favorable position to the Company. At December 31, 1994, the market value of the Company's favorable swaps was $2.1 million. The net position of all swaps, both favorable and unfavorable, was $1.8 million favorable. The Company is exposed to credit loss in the event of nonperformance by counterparties on swap contracts. Company policy regarding derivative trading activity limits swap agreements to counterparties with appropriate credit standings that have been approved by the Board of Directors.
OTHER FINANCIAL INSTRUMENTS
The carrying amounts and fair values of the Company's financial instruments other than derivatives are as follows:
The following methods and assumptions were used by the Company in estimating its fair value disclosures for balance sheet financial instruments: Cash and cash equivalents, gas supply realignment (GSR) costs, natural gas purchase contract settlement costs and unsecured notes payable: The carrying amount reported in the Consolidated Balance Sheet approximates its fair value. Investment securities: The fair value for equity securities is based upon an estimate received from an independent valuation consultant. 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
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Sonat Inc. and Subsidiaries
current incremental borrowing rates for similar types of borrowing arrangements. All of the Company's financial instruments are held for purposes other than trading. The Company's financial instruments that are exposed to concentrations of credit risk consist primarily of cash equivalents, investments, accounts receivableand GSR costs which the Company expects to recover from its customers. The Company's cash equivalents and short-term investments represent high-quality securities placed with various high investment grade institutions. This investment practice limits the Company's exposure to concentrations of credit risk. Accounts receivable of the Exploration and Production segment are primarily from joint-interest partners, oil and gas marketing companies and pipeline companies. Accounts receivable of the Natural Gas Transmission and Marketing segment relate to business conducted with gas distribution companies, municipalities, gas districts, industrial customers, and 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.
3. Changes in Operations
Stock Sale by Subsidiary-On June 4, 1993, the IPO of approximately 60 percent 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 recognized an after-tax gain of $99.7 million, or $1.15 per share, from the combined transactions. At December 31, 1994, the Company held 11.3 million shares of Sonat Offshore common stock with a market value of $199.7 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 segment.
5. Unconsolidated Affiliates
At December 31, 1994, the Company's investments in unconsolidated affiliates totaled $486.3 million, and the Company's share of underlying equity in net assets of the investees was $552.7 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, 1994, the Company's cumulative equity in earnings of these unconsolidated affiliates was $222.1 million and cumulative dividends received from them totaled $146.2 million.
II-23 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
5. UNCONSOLIDATED AFFILIATES (CONTINUED)
The following table presents the components of equity in earnings of unconsolidated affiliates.
Exploration and Production Affiliate-Sonat Exploration 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 remaining interest in Sonat/P not owned by it from Prudential Insurance Company (see Note 13). For the 1993 period prior to acquisition, Sonat/P had revenues of $16.3 million and reported earnings of $6.6 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 company 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.
The significant increase in allowance for funds used during construction relates to Florida Gas' Phase III expansion, a$1 billion expansion of its pipeline facilities that will increase the system throughput capacity by 57 percent. On November 7, 1994, Florida Gas issued $700 million of Senior Notes of various maturities ranging from three years to 30 years, with an average life of approximately 10 years. Proceeds from the Notes were primarily used to refund construction financing and funds advanced by Citrus' parent companies for construction of the Phase III expansion. The Notes are senior, unsecured obligations of Florida Gas, but Sonat provided indirect credit support in the form of a standby note purchase agreement to the extent of 50 percent of the outstanding Notes plus accrued interest in the event Florida Gas' largest customer exercises its right to terminate
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Sonat Inc. and Subsidiaries
its Phase III service contracts as a result of the Phase III facilities not being in service by January 14, 1996. In addition, Sonat has agreed to provide funds required by Florida Gas for any interest payments due on the debt (to the extent of 50 percent of any such required amounts) prior to the attainment of the in-service date for the Phase III facilities. Once the in-service date of the Phase III facilities is attained, Sonat will be released from all obligations under the standby note purchase agreement and the Notes will be non-recourse except to Florida Gas. Phase III will go into service on March 1, 1995. In connection with the construction of the Phase III expansion, the Company made equity contributions to Citrus of $159 million during 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.
Contract Drilling Affiliate-Since June 4, 1993, the Company has owned approximately 40 percent of Sonat Offshore, which provides offshore drilling services (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.
II-25 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
6. PLANT, PROPERTY AND EQUIPMENT AND DEPRECIATION (CONTINUED)
Plant, property and equipment includes construction work in progress of $37.5 million and $56.0 million at December 31, 1994 and 1993, 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 used for oil and gas properties in the Exploration and Production segment 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. In the third quarter of 1994, Southern Natural Gas Company adjusted its transportation revenue reserve and depreciation expense by $16 million reflecting a retroactive reduction in certain depreciation rates. The entry had no effect on net income.
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, 1994, are as follows:
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Sonat Inc. and Subsidiaries
During 1994, Sonat borrowed $4.4 billion and repaid $4.2 billion under its long-term revolving credit agreement, which provides for periodic borrowings and repayments of up to $500 million through December 15, 1998. At December 31, 1994, $375 million was outstanding at a rate of 6.30 percent. On June 15, 1994, Southern's $100 million 9 5/8 Percent Notes matured and were redeemed. Funds were obtained by increased borrowings under Sonat's floating rate facilities. Lines of Credit and Credit Agreement-At December 31, 1994, the Company had available $475 million under its lines of credit and revolving credit agreements. The amount available has been reduced by the $100 million of commercial paper outstanding to reflect the Company's policy that bank and commercial paper borrowings in the aggregate will not exceed the maximum amount available under its lines of credit and revolving credit agreements. Loans outstanding under all short-term credit facilities are for a duration of less than three months. Short-Term Credit Facilities-On May 30, 1994, Sonat and Southern renewed their short-term lines of credit with several banks to provide for borrowings of $200 million and $50 million, respectively. Borrowings are available through May 29, 1995, in the form of unsecured promissory notes and bear interest at rates based on the banks' prevailing prime, international, or money-market lending rates. At December 31, 1994, no amounts were outstanding under either agreement. At December 31, 1993, $9 million was outstanding under the Sonat agreement at a rate of 3.38 percent, and no amounts were outstanding under the Southern agreement. On August 1, 1994, Sonat entered into a new 364-day revolving credit agreement with a group of banks. The revolving credit agreement provides for periodic borrowings of up to $300 million through July 31, 1995. 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, 1994, $100 million was outstanding at a rate of 6.33 percent under this agreement. Sonat had $100 million and $60 million in commercial paper outstanding at average rates of 6.30 percent and 3.64 percent at December 31, 1994 and 1993, respectively. Extraordinary Item-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 $200 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.
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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
8. INCOME TAXES (Continued)
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 domestic and foreign components of income from continuing operations before income taxes are as follows:
9. COMMITMENTS AND CONTINGENCIES
Rate Matters-Periodically, Southern and its subsidiaries make general rate filings with the Federal Energy Regulatory Commission (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 that (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. Under the settlement, the FERC will decide the cost classification, cost allocation, and rate design issues based on written submissions of the parties and the existing record in the proceeding. By orders issued on December 16, 1993, and May 5, 1994, the FERC approved the settlement. One party has sought judicial review of these FERC orders. Southern cannot predict the outcome of this appeal. 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 that, if approved by the FERC, would resolve the throughput and certain cost of service issues. The cost allocation and rate design issues were consolidated with similar issues in Southern's rate proceeding filed May 1, 1993, which is described below, and will be resolved in that proceeding. This settlement was also approved by FERC orders issued on December 16, 1993, and May 5, 1994. One party has sought judicial review of these FERC orders as well. Southern also cannot predict the outcome of this appeal. On May 1, 1993, Southern implemented a general rate change, subject to refund, that 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 January 9, 1995, Southern filed a trial stipulation that resolved certain cost of service issues with the FERC staff in this proceeding. A hearing regarding all other outstanding issues concluded in February 1995. Southern cannot predict the outcome of this hearing. Southern will file with the FERC in March 1995 a Stipulation and Agreement that would settle all of Southern's pending rate (described above) and GSR cost recovery proceedings as described below (Customer Settlement). Southern has been advised that customers representing more than 80 percent of the pipeline's firm capacity intend to support the Customer Settlement. Pursuant to the Customer
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Sonat Inc. and Subsidiaries
Settlement, which must be approved by the FERC, all issues in Southern's current and prior rate cases would be settled and Southern would credit against GSR costs incurred by Southern the full amount of Southern's rate reserves at February 28, 1995, which, as of December 31, 1994, were approximately $148 million. Such amount, less certain amounts withheld for potential rate refunds to parties, if any, that contest the Customer Settlement and certain amounts related to one specific contesting customer, will be credited in the aggregate to reduce the GSR costs borne by Southern's customers. Southern will implement the settlement rates for supporting parties on an interim basis, subject to reinstatement, which will become effective March 1, 1995, pending FERC consideration and approval of the Customer Settlement. The Customer Settlement provides that, except in certain limited circumstances, Southern will not file a general rate case to be effective prior to March 1, 1998. Southern's GSR costs are discussed below (see Order No. 636). The Company recognized a $29 million charge associated with the anticipated customer rate settlement, which includes anticipated amounts for GSR costs that Southern would not recover from its customers, and a $28 million provision relating to regulatory assets that will not be recovered as a result of the Customer Settlement, including amounts for a corporate restructuring undertaken in 1994. These charges resulted in the increase in "Other" in the Deferred Credits and Other section of the 1994 Consolidated Balance Sheet. It is possible that the Customer Settlement will be contested by certain of Southern's customers, in which case the Customer Settlement, if approved by the FERC, will become effective only as to supporting parties and Southern's rates and GSR costs applicable to the contesting parties would be determined by the outcome of Southern's pending rate and GSR proceedings. It is also possible that the Customer Settlement might not be approved by the FERC or, if approved, might be modified in a way unacceptable to Southern or its customers. Gas Purchase Contracts-Pursuant to a final and nonappealable FERC order, Southern has collected substantially all of its gas purchase contract settlement payments from its customers over a five-year period that ended on April 30, 1994. Southern currently is incurring 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 required 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 transition cost is related to amendment or termination of existing gas purchase contracts, which are referred to as gas supply realignment costs. The Order provided 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. The prudence review will extend both to the prudence of the underlying gas purchase contracts, based on the circumstances that existed at the time the contracts were executed, and to the prudence of the amendments or terminations of the contracts. 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. 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 "price differential" 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 charge designed to collect the remaining 10 percent of such costs from Southern's interruptible transportation customers. These funding mechanismswill 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 charge after a period of two years. In addition, Southern's complianceplan 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 Southern's GSR costs based on both eligibility and prudence
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
9. COMMITMENTS AND CONTINGENCIES (CONTINUED)
grounds. 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 FERC's finding that the 1988 settlement is not a bar in general to the recovery as GSR costs of payments made to amend or to terminate these contracts does not prevent an eligibility challenge to specific payments, however, on the theory that they are actually take-or-pay costs that would have been unavoidable regardless of the Order. The December 16 order generally approved Southern's restructuring tariff submitted pursuant to the September 3 order. Various parties have sought judicial review of the September 3 and December 16 orders. As of December 31, 1994, Southern had either paid or accrued $134 million in GSR costs (including $4 million in interest) either to reduce significantly the price payable under or to terminate a number of gas supply contracts providing for payment of above-market prices. In addition, on February 17, 1995, Southern reached an agreement to incur $64 million in GSR costs to resolve its remaining high-cost supply contracts with Exxon Corporation (Exxon) that is conditioned upon the effectiveness of the Customer Settlement described above. Southern also has an agreement under which another high-cost contract price is reduced in exchange for monthly payments having a present value of approximately $44 million. Southern has received permission from the FERC to purchase an annuity in order to monetize this obligation. In addition to its GSR costs relating to termination or amendment of its remaining gas supply contracts, Southern has incurred and expects to continue to incur certain "price differential" GSR costs resulting from Southern's continued purchase of gas under its remaining supply contracts that provide for prices in excess of current market prices. As of December 31, 1994, Southern had incurred $69 million in price differential costs. Beginning in December 1993, Southern has made a number of filings with the FERC seeking to recover GSR costs paid through various periods prior to the filings. In each instance, the FERC has accepted Southern's filing subject to refund, and subject to a determination through a hearing before an administrative law judge regarding whether such costs were prudently incurred and are eligible for recovery under the Order. Southern's customers are opposing its recovery of its GSR costs in these proceedings based on both eligibility and prudence grounds. These proceedings, which have all been consolidated, are in the early stages of discovery and Southern cannot predict their outcome at this time. As described above, Southern's Customer Settlement would settle all of the proceedings pursuant to which Southern is seeking recovery of its GSR costs as well as all of its other outstanding rate proceedings. If the Customer Settlement is ultimately approved by the FERC, all challenges to the recovery of Southern's GSR costs would be resolved as to those customers supporting the Customer Settlement, including all issues related to eligibility and prudence. Additionally, Southern would absorb an agreed-upon portion of its total GSR costs, which was reflected in the provision for the Customer Settlement. As indicated above, it is possible that the Customer Settlement will be contested by certain of the customers on Southern's system and the possibility exists that the FERC may not approve the Customer Settlement or may modify it in a way unacceptable to Southern or its customers. In addition, Southern's GSR costs allocated to those customers who contest the Customer Settlement will remain subject to Southern's pending GSR cost recovery proceedings, where Southern anticipates that those customers will continue to challenge both the eligibility and prudence of such costs. In its Customer 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, recent contract renegotiations, and price differential costs actually incurred, the amount of GSR costs are estimated to be approximately $328 million. This amount includes the payments already made or accrued to amend or to terminate gas purchase contracts and price differential costs, and the $64 million cost that will be incurred under a settlement of existing contracts with Exxon, which will become effective if the Customer Settlement becomes effective. These costs collectively total $288 million. Thus, Southern currently estimates it will ultimately pay an additional $40 million in GSR costs. Until the Customer Settlement is approved, Southern plans to make additional rate filings quarterly to recover its price differential costs and any other GSR costs. Additionally,
II-30 Sonat Inc. and Subsidiaries
Southern will continue to make monthly filings designed to adjust the billing determinants and associated surcharges for its firm transportation customers to reflect changes in the level of systemwide contract demands and effective carrying charges that occur from time to time. Administrative Law Judge Ruling Concerning Recoverability of Investment in Offshore Gas Supply Facilities; Settlement with Exxon Corporation-In an initial decision issued on May 2, 1994, which Southern has appealed, an administrative law judge ruled, in a rate case Southern had filed before the FERC, that Southern could not include in its rates the approximately $45 million cost of certain pipeline facilities placed in service by Southern in 1992 to connect to its interstate pipeline system extensive new gas reserves being developed by Exxon in the Mississippi Canyon and Ewing Bank Area Blocks, offshore Louisiana (the Mississippi Canyon Facilities). The judge ruled that Southern's recovery of these costs was precluded by the 1988 settlement with Southern's customers that limits the amount of take-or-pay payments Southern may recover in its rates. The judge found that the cost of the facilities constitutes non-cash consideration to Exxon for a 1989 take-or-pay settlement and is therefore subject to the dollar "cap" on these payments contained in the 1988 settlement. Southern has previously recovered the maximum amount permitted by the 1988 settlement in its rates. Southern has appealed the administrative law judge's decision to the FERC but cannot predict the outcome of this appeal. The Customer Settlement provides that as to customers supporting the settlement, the costs of the Mississippi Canyon Facilities will be recovered by Southern on a rolled-in basis and the 1988 take-or-pay settlement cap will not preclude Southern's recovery of such costs. On February 17, 1995, Southern reached a settlement with Exxon pursuant to which, in return for an additional cash payment by Southern of $45 million, plus allowing Exxon to retain $19 million in price differential costs already paid to Exxon, all existing gas purchase contracts would be terminated, two new gas purchase contracts would be entered into having three-year terms and providing for market-based index prices, and a lawsuit regarding Southern's termination of the gas purchase contract covering gas reserves connected by the Mississippi Canyon Facilities (Mississippi Canyon Contract) would be dismissed. The settlement with Exxon is contingent on FERC approval of the Customer Settlement. If this settlement with Exxon does not become effective, total GSR costs under the Mississippi Canyon Contract through the scheduled renegotiation of its pricing provisions in 1997 are estimated to be approximately $125 million on a present-value basis, although such estimate is subject to significant uncertainty since the assumptions inherent in the estimate (including underlying reserves, future deliverability, and a range of estimated future gas market prices) are not known today with certainty and there is a wide range of possible outcomes for each assumption. In addition, Southern has given notice to Exxon that effective March 1, 1994, it has terminated the Mississippi Canyon Contract pursuant to certain provisions of the contract. Such termination, if effective, would reduce GSR costs associated with such contract to $14 million. Exxon has filed suit against Southern seeking a declaratory judgment that Southern does not have the right to terminate the contract or alternatively for damages of an unspecified amount arising out of the alleged repudiation or breach of the contract by Southern. The court entered a summary judgment order upholding Southern's termination of this contract, which Exxon has appealed to the Fifth Circuit Court of Appeals. Southern's customers are challenging the recovery of GSR costs attributable to such contract on eligibility and prudence grounds and on the basis that such costs also constitute non-cash consideration for the 1989 take-or-pay settlement with Exxon and thus are not recoverable due to the 1988 take-or-pay cost cap. If the settlement with Exxon does not become effective, Southern cannot predict the outcome of pending or future proceedings for the recovery of GSR costs related to the gas supplies connected by the Mississippi Canyon Facilities or its pending litigation with Exxon regarding Southern's notice of termination of the Mississippi Canyon Contract. 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.
RENTAL EXPENSE
At December 31, 1994, future minimum payments for non-cancelable operating leases for the years 1995 through 1999 are $9 million or less per year.
II-31 NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
10. CAPITAL STOCK
On April 28, 1994, the shareholders of the Company approved an increase in the common stock shares authorized from 200 million to 400 million. 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, 1994. 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 this plan are redeemable at any time by the Company before February 3, 1996, the end of their 10-year term, so long as an entity has not acquired 20 percent or more of the Company. As of December 31, 1994, 92,556,554 shares of common stock were reserved for issuance under this plan. 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, 1994, 389,634 SARs were outstanding. The Company issued 72,700 shares of restricted stock to employees during 1994. 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, 1994, 51,998 of the 319,000 cumulative restricted shares issued have vested. The following table summarizes option activities in the Plan:
NUMBER OF SHARES UNDER OPTION
Stock-based employee compensation increased pretax income by $1.2 million in 1994 and decreased pretax income by $12.6 million and $9.3 million in 1993 and 1992, respectively. At December 31, 1994 and 1993, there were 10,000,000 shares of $1.00 par value Serial Preference Stock authorized, with none issued. Directors Restricted Stock 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 1,433 shares during 1994. At December 31, 1994, 18,660 of the 36,493 cumulative shares granted have vested. Treasury Stock-In April 1994 the Board of Directors of the Company authorized the repurchase of up to two million shares of the Company's common stock. Purchases are being made from time to time in the open market or in privately negotiated transactions. Shares purchased under the authorization are expected to be reissued in connection with employee stock option and restricted stock programs. At December 31, 1994, 940,000 shares of common stock had been purchased and 69,000 shares had been reissued under this program.
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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 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 vest after a period of 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. For the Supplemental Plan, Sonat retained the obligation to pay the benefit accrued through the date of the IPO for all of Sonat Offshore's current and retired employees. 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, 1994, this trust had assets with a fair market value of $32.9 million available to pay benefits. The Company's net periodic pension (income) cost included in continuing operations consists of the following components:
The change in the discount rate assumption in 1994 to 8.5 percent from 7.0 percent was the primary reason for the change in net periodic pension cost.
The following table sets forth the assets and liabilities of the plans and the amount of the net pension asset or liability recognized in the Company's Consolidated Balance Sheets.
(1) The Retirement Plan. (2) The Supplemental Plan. (3) Plan assets consist primarily of debt and equity securities, and investments in equity index and foreign index funds. (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.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
11. RETIREMENT PLANS AND OTHER POST EMPLOYMENT BENEFITS (CONTINUED)
Until July 1993, the Company set aside assets in fixed income securities such that values of those assets equaled or exceeded 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 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 has 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 consists of 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 in 1992. 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' annual SFAS No. 106 expense. Southern implemented rates effective May 1, 1993, which provide for the recovery of its share of the postretirement expense. The following table sets forth the funded status at December 31, 1994 and 1993, for the Company's postretirement health care and life insurance plans:
(1) Plan assets are held in a life insurance reserve account which consists primarily of fixed income securities, and in equity securities, municipal tax exempt bonds, and short-term investment funds.
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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 11.6 percent in 1995, decreasing gradually to 6 percent by the year 2003. Increasing the assumed health care cost trend rate by 1 percentage point would increase the accumulated postretirement benefit obligation as of December 31, 1994, by approximately $4.9 million and increase the service cost and interest cost components of the net periodic postretirement benefit cost by approximately $.5 million. The Company sponsors a postemployment benefit plan that provides disability benefits to former or inactive employees, their beneficiaries, and covered dependents after employment but before retirement. The Company adopted SFAS No. 112, "Employers' Accounting for Postemployment Benefits" as of January 1, 1994. SFAS No. 112 requires companies to accrue a liability for employees' compensation for future absences if certain conditions are met. For the year ended December 31, 1994, $1.3 million of expense was recognized for this employee benefit plan. Corporate Restructuring-In late 1994 and early 1995 the Company completed a reduction in staffing levels in the office and field locations through a combination of special early retirement options (SERO) and involuntary terminations involving 340 employees. The total cost of the program amounted to $21.3 million, which included $3.1 million related to the qualified retirement plan, $10.8 million related to the postretirement plans, and $6.0 million of cash severance payments. Included in the cash severance amount was $2.0 million paid during 1994. All of the terminations, voluntary and involuntary, were completed by the end of January 1995.
12. BUSINESS SEGMENT AND GEOGRAPHIC AREA ANALYSIS
The Company's operations, capital expenditures, and assets by business segment and geographic location are shown in the following tables. On June 4, 1993, the Company's ownership of Sonat Offshore, which provides offshore drilling services, was reduced from 100 percent to approximately 40 percent. (See Note 3.) Sonat Offshore's results prior to June 4, 1993, are reported in the Other Business segment. The Company's share of Sonat Offshore's results since June 4, 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
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
12. BUSINESS SEGMENT AND GEOGRAPHIC AREA ANALYSIS (Continued)
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.
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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 at December 31, 1992. There were no foreign cash equivalents at December 31, 1994 and 1993.
13. OIL AND GAS OPERATIONS (Unaudited)
At December 31, 1994, 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 acquired the remaining interest in Sonat/P not owned by it from Prudential InsuranceCompany 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:
Costs Incurred
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:
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
13. OIL AND GAS OPERATIONS (Unaudited) (Continued)
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. In early 1995, Sonat Exploration announced two significant acquisitions of oil and gas producing properties, one in north Louisiana and the other in the Texas Panhandle area. These transactions of $158.3 million, which are not reflected in the above data, will add proved reserves of 188 billion cubic feet of natural gas and 11.2 million barrels of oil and condensate. There were no other events or major discoveries, favorable or adverse, that may be considered to have caused a significant change in the estimated proved reserves since December 31, 1994. 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
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Sonat Inc. and Subsidiaries
For the calculations in the preceding table, estimated future cash inflows from estimated future production of proved reserves were computed using realized oil and gas prices for each December. 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 fourth quarter of 1994 includes a gain of $20.3 million, or $.23 per share, related to the settlement of an examination of the Company's federal income tax returns for the years 1986 through 1988; a charge for Southern Natural's Rate Settlement of $17.9 million, or $.21 per share; and charges for a reduction in work force and other matters amounting to $22.0 million, or $.25 per share. (2) 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.
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Selected Consolidated Financial Data
Notes: (1) 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. (2) 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.
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ITEM 9.
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.
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 15, 1995 (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.
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.
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 heading "Ownership of Common Stock by Directors and Executive Officers" 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.
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.
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
Financial Statement Schedules have been omitted because they are not applicable or because 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)
- ---------------
(1) Sonat will furnish to requesting security holders any exhibit on this list upon the payment of a fee of 10c 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 that have heretofore been filed with the Securities and Exchange Commission, which were physically filed as noted above, are 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 ten 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, 1994.
(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 28, 1995
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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CITRUS CORP. AND SUBSIDIARIES
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Report of Ernst & Young LLP, Independent Auditors
Board of Directors Citrus Corp.
We have audited the accompanying consolidated balance sheets of Citrus Corp. and Subsidiaries as of December 31, 1994 and 1993, 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, 1994. 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 consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of Citrus Corp. and Subsidiaries at December 31, 1994 and 1993, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 1994, in conformity with generally accepted accounting principles.
Ernst & Young LLP
Birmingham, Alabama February 24, 1995
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CITRUS CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
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CITRUS CORP. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS
The accompanying notes are an integral part of these consolidated financial statements.
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CITRUS CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF OPERATIONS AND RETAINED EARNINGS
The accompanying notes are an integral part of these consolidated financial statements.
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CITRUS CORP. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS
The accompanying notes are an integral part of these consolidated financial statements.
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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) and Citrus Trading Corp. (Trading). 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 & Light Co., a large electric utility in the state of Florida, to local distribution customers, and to end users.
(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.
ACCOUNTING FOR PRICE RISK MANAGEMENT ACTIVITIES - To manage the risks of price fluctuations, Trading 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. Trading uses the settlement method of accounting for its commodity swaps and the Company uses the deferral method for its interest-rate swaps. Commodity swaps are settled monthly and gains and losses are recognized immediately. The effects of commodity swaps are recorded as an adjustment to natural gas purchased. The current year interest-rate swaps have been closed and the termination gain has been deferred in other deferred credits in the consolidated balance sheet at December 31, 1994, to be amortized against interest expense over the portion of the debt agreement associated with the swaps. Fees associated with these transactions have been expensed as incurred.
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. Transmission has provided for depreciation of assets on a straight-line basis at an annual composite rate of .75%, 3.06% and 3.16% for 1994, 1993 and 1992, respectively. Depreciation rates are based on the estimated useful lives of the individual assets.
In 1994, Transmission changed its depreciation rate applicable to its mainline transportation assets to better reflect its remaining useful life. The effect of the change was a reduction in depreciation and amortization expense of $13.3 million in 1994. 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.
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(2) SIGNIFICANT ACCOUNTING POLICIES (continued)
In 1994, Trading entered into an agreement with a major customer which provides significant future benefits over previous gas sales contracts. The agreement requires Trading to make approximately $55 million in deposits on the customers behalf over sixteen months ending in August 1995. Trading is amortizing the total amounts paid on a volumetric basis over the term of the new agreement. Amortization of these payments is included in depreciation and amortization expense.
Transmission amortizes contract reformation costs based on volume deliveries and FERC-approved recovery rates. Such amortization is included in depreciation and amortization expense.
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 accounts for income taxes under the provisions of Statement of Financial Accounting Standards (SFAS) No. 109. SFAS No. 109 provides for an asset and liability approach for accounting for income taxes. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax bases.
RECLASSIFICATIONS - Certain items on the consolidated financial statements have been reclassified in 1993 and 1992 to conform with the 1994 presentation.
(3) LONG-TERM DEBT AND OTHER FINANCING ARRANGEMENTS
Long-term debt outstanding at December 31, 1994 and 1993 was as follows (in thousands):
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(3) LONG-TERM DEBT AND OTHER FINANCING ARRANGEMENTS (continued)
Annual maturities and sinking fund requirements on long-term debt outstanding as of December 31, 1994 were as follows (in thousands):
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.
The Company had no committed lines of credit at December 31, 1994. Transmission has a committed line of credit of $70.0 million and uncommitted bid note facilities for up to $45.0 million, all of which were available at December 31, 1994.
In April 1994, Transmission entered into an agreement in which it transferred the rights to future cash flows from collections of certain transportation surcharge receivables relating to the recovery of contract reformation costs. Transmission received $86.3 million relating to the transfer of rights to future cash flows. The Company's TCR deferred revenues on the consolidated balance sheet at December 31, 1994 are collateralized by transportation surcharge receivables included in contract reformation costs.
(4) INCOME TAXES
The principal components of the Company's net deferred income tax liabilities at December 31, 1994 and 1993 are as follows (in thousands):
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(4) INCOME TAXES (continued)
Total income tax expense (benefit) for the years ended December 31, 1994, 1993 and 1992 is summarized as follows (in thousands):
The differences between taxes computed at the U.S. federal statutory rate and the Company's effective tax rate for the years ended December 31, 1994, 1993 and 1992 are as follows (in thousands):
The Company has a consolidated net operating loss carryforward for tax purposes of approximately $13 million. This loss carryforward will be available until 2008, at which time it will begin to expire. For financial statement purposes, the Company has recognized the benefit of this loss carryforward by a reduction of deferred tax liabilities.
(5) EMPLOYEE BENEFIT PLANS
Enron maintains a retirement plan (the Enron Plan) which is a noncontributory defined benefit plan covering substantially all employees in the United States and certain employees in foreign countries. Through December 31, 1994, participants in the Enron Plan with five years or more of service are entitled to retirement benefits based on a formula that uses a percentage of final average pay and years of service. Pension expenses charged to the Company by Enron were $.2, $.4 and $.3 million for 1994, 1993 and 1992, respectively.
Enron amended the Enron Plan providing, among other things, that all employees become fully vested in retirement benefits earned through December 31, 1994, and effective January 1, 1995, temporarily suspended accruals under the Enron Plan in connection with Enron's decision to change the benefits formula effective January 1, 1996.
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(5) EMPLOYEE BENEFIT PLANS (continued)
Enron maintains a noncontributory employee stock ownership plan (ESOP) which covers all eligible employees. Allocations to individual employees' retirement accounts within the ESOP offset a portion of benefits earned under the Enron Plan. To the extent allocations to the individual employees' retirement account within the ESOP exceed accrued benefits under the Enron Plan at the date of retirement, the individual employees receive the additional shares.
As of September 30, 1994, the most recent valuation date, the actuarial present value of projected plan benefit obligations for the Enron Plan in which the employees of the Company participate was less than the plan net assets by approximately $18.9 million. The assumed discount rate and rate of return on plan assets used in determining the actuarial present value of projected plan benefits were 8.0% and 10.5%, respectively. The assumed rate of increase in wages was 4.0%.
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 Plan. Benefits are provided under the provisions of a contributory defined dollar benefit plan.
Effective January 1, 1993, Enron adopted the provisions of SFAS No. 106 "Employers Accounting for Postretirement Benefits Other Than Pensions". SFAS No. 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. Enron 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 charged by Enron were $.8 and $.7 million for 1994 and 1993, respectively, substantially all of which relates to Transmission and is expected to be recovered through rates. The measurement of the accumulated postretirement benefit obligation (APBO) assumes a 8% discount rate and a health care cost trend rate of 12.3% in 1994 decreasing to 5% by the year 2006 and beyond. The APBO exceeded plan assets by $103.6 million as of its most recent valuation date of December 31, 1994.
(6) MAJOR CUSTOMERS
Revenues from individual customers exceeding 10% of total revenues for the years ended December 31, 1994, 1993 and 1992 were approximately as follows (in thousands):
At December 31, 1994, the Company's subsidiaries had receivables of approximately $19.6 and $3.0 million from Florida Power & Light Co. 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 $17.4, $14.8 and $12.1 million for these expenses for the years ended December 31, 1994, 1993 and 1992, respectively.
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(7) RELATED PARTY TRANSACTIONS (continued)
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 $9.1, $13.0 and $4.3 million for the years ended December 31, 1994, 1993 and 1992, respectively. The Company's subsidiaries purchased gas from affiliates of Sonat of approximately $22.0, $10.8 and $8.8 million for the years ended December 31, 1994, 1993 and 1992, respectively. The Company's subsidiaries also purchased gas from affiliates of Enron of approximately $139.4, $31.1 and $41.4 million for the years ended December 31, 1994, 1993 and 1992, respectively.
The Company has an agreement with an affiliate of Enron in which the affiliate manages the operations of Trading in exchange for a $1.2 million annual fee.
(8) RATE MATTERS
Transmission was authorized by the FERC in April 1989, to recover via a volumetric surcharge certain take-or-pay buy-out and buy-down costs billed by Southern Natural Gas Company (Southern Fixed Charges) and paid by Transmission. On May 31, 1994, the Southern Fixed Charges billed to Transmission ceased. Transmission's recovery mechanism was suspended effective June 1, 1994, pending a determination of the status of actual collections and remaining balances to be refunded to or collected from Transmission's customers. On September 12, 1994, Transmission filed tariff sheets to reinstate its flow-through billing mechanism effective November 1, 1994. The September 12 filing included schedules detailing the outstanding Southern Fixed Charge account balances owed Transmission at May 31, 1994, by customer, totaling approximately $7.2 million. In an order issued October 28, 1994, the FERC accepted the tariff sheets, subject to refund and conditions, and directed Transmission to provide additional information and documentation. Supplemental filings were made November 14, 1994, to comply with the October 28 order and to correct certain minor errors contained in the September 12 filing. Several parties have requested rehearing of the October 28 order. These requests are currently pending before the FERC.
Transmission has been authorized by the FERC to recover certain transition costs incurred through the reformation of gas supply contracts related to Transmission's former sales services. The Order No. 636 restructuring settlement, effective November 1, 1993, allows Transmission to recover 100% of any such transition costs between $106 million and $160 million and 75% of payments exceeding $160 million. Transmission has made payments totaling $134 million through December 31, 1994. It is possible that additional payments to suppliers may be made to resolve gas purchase contract issues. However, to the extent additional payments are made, management believes that these costs will be 100% recoverable through Transmission's existing tariff mechanisms.
By orders issued January 15, 1993, April 21, 1993 and September 15, 1993, the FERC approved the Stipulation and Agreement filed in Docket Nos. CP92-182, et al. on August 25, 1992 and authorized Transmission to construct and operate a major expansion of its system (Phase III Expansion). These orders also authorized Transmission to provide firm transportation service through the expanded capacity pursuant to a new firm transportation rate schedule, FTS-2. Construction was completed and service under FTS-2 commenced March 1, 1995.
On December 30, 1994, Transmission made a Section 4 rate filing proposing an increase in its annual revenues, exclusive of the Phase III Expansion, of approximately $9.7 million. In an order issued January 31, 1995, the FERC accepted and suspended the filing to be effective July 1, 1995, subject to refund and certain conditions.
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(9) COMMITMENTS AND CONTINGENCIES
In late 1994, the FERC's Division of Audits completed a compliance review of Transmission's books and records for the time periods January 1, 1991 through December 31, 1993. Among other things, the FERC auditors questioned certain aspects of Transmission's procedures for accounting for the costs of financing Transmission's Phase III expansion facilities. The Company's management does not believe ultimate resolution of these compliance issues will have a material effect on the Company's results of operations or financial position.
(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 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, 1994 and 1993, are as follows (in thousands):
The carrying amount of contract reformation costs, notes payable to banks and TCR deferred revenues 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.
(11) PRICE RISK MANAGEMENT
In August 1990, Trading entered into a price swap agreement to effectively manage approximately 10% 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 Trading 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.
Additionally, in May 1994, the Company entered into an offsetting swap agreement with an affiliate of Enron, the term of which coincides with the remaining life of the previously referenced swap.
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(11) PRICE RISK MANAGEMENT (continued)
The Company's after-tax results of operations for the years ended December 31, 1994, 1993 and 1992 included net gains of $5.5 ($2.4 million of this amount is from an affiliate of Enron), $4.6 and $1.1 million, respectively, related to these agreements. Under the swap agreements, Trading effectively pays a fixed price of $13.75 per barrel and receives a fixed price of $20.135 per barrel for residual fuel, and pays a fixed price of $2.381 per mcf and receives a fixed price of $2.042 mcf for natural gas.
The Company entered into two off-balance-sheet transactions involving interest-rate swaps in 1994. The Company's objective in managing interest rate exposure was to control interest rate risk associated with its then anticipated $700 million private debt placement for construction of Phase III facilities. Management's strategy with regards to interest-rate swaps was to limit the impact of changes in interest rates on this specific private debt placement only.
The Company's interest-rate swaps modified the interest characteristics of the then anticipated private debt placement from an unknown to a fixed-basis interest rate. These agreements involved the placement of a fixed rate on anticipated tranches of the principal amount of the debt without an exchange of the underlying principal amount. The approximately $36 million differential paid to the Company was received in November 1994, when the Company effected the placement of the debt and closed out the swaps.
The Company is exposed to credit loss in the event of nonperformance by counterparties on interest-rate and commodity swaps. The counterparty involved in the interest-rate swap has already performed and the Company does not anticipate nonperformance by other counterparties. The amount of such exposure is generally the unrealized gain on such contracts.
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APPENDIX TO ANNUAL REPORT ON FORM 10-K
OF SONAT INC. FOR THE YEAR ENDED DECEMBER 31, 1994
In compliance with Section 304 of Regulation S-T, the following information describes pictorial and/or graphic materials contained herein: