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SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
(Mark One)
/x/ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [FEE REQUIRED]
For the fiscal year ended DECEMBER 31, 1993 or
/ / TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934 [NO FEE REQUIRED]
For the transition period from ____________________ to _____________________
Commission file number 1-7176
THE COASTAL CORPORATION
(EXACT NAME OF REGISTRANT AS SPECIFIED IN ITS CHARTER)
DELAWARE 74-1734212
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
COASTAL TOWER
NINE GREENWAY PLAZA
HOUSTON, TEXAS 77046-0995
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (713) 877-1400
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
Name of each exchange
Title of each class on which registered
------------------- -----------------------
Common Stock ($.33 1/3 par value) )
$1.19 Cumulative Convertible Preferred Stock, Series A ($.33 1/3 par value) )
$1.83 Cumulative Convertible Preferred Stock, Series B ($.33 1/3 par value) )
$2.125 Cumulative Preferred Stock, Series H ($.33 1/3 par value) )
11-3/4% Senior Debentures 10% Senior Notes ) New York Stock Exchange
11-1/8% Senior Subordinated Notes 9-3/4% Senior Debentures )
10-1/4% Senior Debentures 8-3/4% Senior Notes )
10-3/8% Senior Notes 9-5/8% Senior Debentures )
10-3/4% Senior Debentures 8-1/8% Senior Notes )
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT:
Class A Common Stock ($.33-1/3 par value)
---------------------------
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months, and (2) has been subject to such filing
requirements for the past 90 days. Yes _____/x/ No _____
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405
of Regulation S-K is not contained herein, and will not be contained, to the
best of Registrant's knowledge, in definitive proxy or information statements
incorporated by reference in Part III of this Form 10-K or any amendment to this
Form 10-K. /x/
As of March 16, 1994, there were outstanding 104,218,335 shares of common
stock, 427,408 shares of Class A common stock, 64,403 shares of $1.19 Cumulative
Convertible Preferred Stock, Series A, 87,398 shares of $1.83 Cumulative
Convertible Preferred Stock, Series B, 35,252 shares of $5.00 Cumulative
Convertible Preferred Stock, Series C and 8,000,000 shares of $2.125 Cumulative
Preferred Stock Series H, of the Registrant. The aggregate market value on such
date of the voting stock of the Registrant held by non-affiliates was an
estimated $2.9 billion, based on the closing prices in the daily composite list
for transactions on the New York Stock Exchange and other markets.
DOCUMENTS INCORPORATED BY REFERENCE:
Portions of the Registrant's Proxy Statement for the 1994 Annual Meeting of
Stockholders, filed pursuant to Regulation 14A under the Securities Exchange Act
of 1934, referred to in Part III hereof.
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TABLE OF CONTENTS
ITEM NO. PAGE
- -------- ----
Glossary.................................................................. (ii)
PART I
1. Business.................................................................. 1
Introduction........................................................... 1
Natural Gas Systems.................................................... 1
Operations........................................................... 1
General.............................................................. 1
Competition.......................................................... 2
ANR Pipeline......................................................... 3
Colorado............................................................. 5
ANR Storage.......................................................... 6
Gas System Reserves and Availability................................. 6
Reconciliation with FERC Form 15 Report.............................. 7
Wyoming Interstate Company, Ltd. .................................... 7
Great Lakes Gas Transmission Limited Partnership..................... 7
Coastal Gas Services Company......................................... 7
Regulations Affecting Gas Systems.................................... 8
Other Developments................................................... 10
Refining, Marketing and Distribution................................... 12
Exploration and Production............................................. 14
Coal................................................................... 17
Chemicals.............................................................. 18
Independent Power Production........................................... 19
Trucking Operations.................................................... 19
Competition............................................................ 20
Environmental.......................................................... 20
2. Properties................................................................ 21
3. Legal Proceedings......................................................... 21
4. Submission of Matters to a Vote of Security Holders....................... 22
PART II
5. Market for the Registrant's Common Equity and Related Stockholder
Matters................................................................. 23
6. Selected Financial Data................................................... 24
7. Management's Discussion and Analysis of Financial Condition and Results
of Operations........................................................... 24
8. Financial Statements and Supplementary Data............................... 24
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure.............................................................. 24
PART III
10. Directors and Executive Officers of the Registrant........................ 25
11. Executive Compensation.................................................... 26
12. Security Ownership of Certain Beneficial Owners and Management............ 26
13. Certain Relationships and Related Transactions............................ 26
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.......... 27
(i)
GLOSSARY
"ANR Pipeline" means ANR Pipeline Company
"ANR Storage" means ANR Storage Company
"Bcf" means billion cubic feet
"BTU" means British thermal unit
"CGMC" means Coastal Gas Marketing Company
"CGS" means Coastal Gas Services Company
"CIG" or "Colorado" means Colorado Interstate Gas Company
"Coastal" or "Company" means The Coastal Corporation and its subsidiaries
"Empire" means Empire State Pipeline
"EPA" means Environmental Protection Agency
"FAS" means Statement of Financial Accounting Standards
"FASB" means Financial Accounting Standards Board
"FERC" means Federal Energy Regulatory Commission
"Great Lakes" means Great Lakes Gas Transmission Limited Partnership
"HIOS" means High Island Offshore System
"Interim Settlement" means ANR Pipeline's Stipulation and Agreement submitted to
the FERC which is more fully described in Item 1, Business, Regulations
Affecting Gas Systems - Rate Matters
"Huddleston" means Huddleston & Co., Inc., Houston, Texas
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"NEB" means Canadian National Energy Board
"NGA" means Natural Gas Act of 1938, as amended
"NGPA" means Natural Gas Policy Act of 1978
"NGWDA" means Natural Gas Wellhead Decontrol Act of 1989
"OFE" means Office of Fossil Energy of the Department of Energy
"Order 636" means the FERC Order No. 636 series of orders which is more fully
described in Item 1, Business, Regulations Affecting Gas Systems - General
"TransCanada" means TransCanada PipeLines Limited
"UTOS" means U-T Offshore System
"WIC" means Wyoming Interstate Company, Ltd.
NOTES:
The terms "Coastal" and "Company" are used in this Annual Report for purposes of
convenience and are intended to refer to The Coastal Corporation and/or its
subsidiaries either individually or collectively, as the context may require.
These references are not intended to suggest that the various Coastal companies
referred to are not independent corporate entities having their separate
corporate identities and managements.
All natural gas volumes presented in this Annual Report are stated at a pressure
base of 14.73 pounds per square inch absolute and 60 degrees Fahrenheit.
(ii)
PART I
ITEM 1. BUSINESS.
INTRODUCTION
Coastal, acting through its subsidiaries, is a diversified energy holding
company with subsidiary operations in natural gas marketing, processing, storage
and transmission; petroleum refining, marketing and distribution; gas and oil
exploration and production; coal mining; chemicals; independent power
production; and trucking. The Company was incorporated under the laws of
Delaware in 1972 to become the successor parent, through a corporate
restructuring, of a corporate enterprise founded in 1955. The Company employed
approximately 16,000 persons as of December 31, 1993.
Annual Reports on Form 10-K for the year ended December 31, 1993, are also
filed by Coastal's subsidiaries, ANR Pipeline and Colorado, and by each of the
six limited partnership oil and gas drilling programs, of which Coastal's
subsidiary, Coastal Limited Ventures, Inc., is the managing general partner.
Such reports contain additional details concerning the reporting organizations.
The operating revenues and operating profit of the Company by industry
segment for the years ended December 31, 1993, 1992 and 1991, and the related
identifiable assets as of December 31, 1993, 1992 and 1991, are set forth in
Note 10 of the Notes to Consolidated Financial Statements included herein.
Information concerning inventories is set forth in Note 2 of the Notes to
Consolidated Financial Statements included herein.
NATURAL GAS SYSTEMS
OPERATIONS
GENERAL
Natural gas operations involve the production, purchase, gathering,
processing, transportation, balancing, storage and sale of natural gas to and
for utilities, industrial customers, distributors, other pipeline companies and
end-users.
ANR Pipeline is involved in the storage, transportation and balancing of
natural gas. ANR Pipeline provides these services for various customers through
its facilities located in Arkansas, Illinois, Indiana, Iowa, Kansas, Kentucky,
Louisiana, Michigan, Mississippi, Missouri, Nebraska, New Jersey, Ohio,
Oklahoma, Tennessee, Texas, Wisconsin, Wyoming and offshore in federal waters.
Prior to November 1, 1993, ANR Pipeline was also engaged in the sale for resale
of natural gas. With ANR Pipeline's implementation of Order 636 effective
November 1, 1993, ANR Pipeline no longer provides a merchant service. However,
former gas sales customers of ANR Pipeline have largely retained their firm
storage and transportation service levels previously included in their "bundled"
gas sales services. ANR Pipeline will auction gas on the open market as part of
its gas restructuring program designed to handle the continuation of certain gas
purchase contracts pending renegotiation or expiration of such contracts. ANR
Pipeline's gas sales for resale customers previously included 51 local
distributors in Michigan, Wisconsin, Illinois, Indiana, Iowa, Kansas, Missouri,
Ohio and Tennessee. ANR Pipeline operates two major offshore gas pipeline
systems in the Gulf of Mexico which are owned by HIOS and UTOS, general
partnerships composed of ANR Pipeline subsidiaries and subsidiaries of other
pipeline companies. ANR Pipeline also operates Empire, a 156-mile pipeline
extending from Niagara Falls to Syracuse, New York, in which an affiliate of ANR
Pipeline has a 45% interest.
During 1993, approximately 62% of ANR Pipeline's gas supply was purchased
from gas producers and marketers in Illinois, Indiana, Kansas, Louisiana,
Michigan, Mississippi, Oklahoma, Texas, Wisconsin, Wyoming and the Texas and
Louisiana offshore areas; approximately 32% was obtained from three Canadian
suppliers; and approximately 6% was purchased from the Dakota Gasification
Company in North Dakota.
1
ANR Pipeline's two interconnected large-diameter multiple pipeline systems
transport gas to the Midwest from (a) the Hugoton Field and other fields in the
Anadarko Basin in Texas and Oklahoma and (b) the Louisiana onshore and Louisiana
and Texas offshore areas. Gas from Wyoming and Canada is obtained by ANR
Pipeline through transportation and exchange agreements with other companies.
ANR Pipeline's principal pipeline facilities at December 31, 1993 consisted
of 12,657 miles of pipeline and 97 compressor stations with 1,069,788 installed
horsepower. At December 31, 1993, the design peak day delivery capacity of the
transmission system, considering supply sources, storage, markets and
transportation for others, was approximately 5.6 Bcf per day.
Colorado is involved in all phases of the production, gathering, processing,
transportation, storage and sale of natural gas. Colorado purchases and produces
natural gas and makes sales of such gas principally to local gas distribution
companies for resale. Separately, Colorado contracts to gather, process,
transport and store natural gas owned by third parties.
Colorado's gas transmission system extends from gas production areas in the
Texas Panhandle, western Oklahoma and western Kansas, northwesterly through
eastern Colorado to the Denver area, and from production areas in Montana,
Wyoming and Utah, southeasterly to the Denver area. Colorado's gas gathering and
processing facilities are located throughout the production areas adjacent to
its transmission system. Most of Colorado's gathering facilities connect
directly to its transmission system, but some gathering systems are connected to
other pipelines. Colorado also has certain gathering facilities located in New
Mexico. Colorado owns four underground gas storage fields; three located in
Colorado, and one in Kansas.
Colorado's principal pipeline facilities at December 31, 1993 consisted of
6,347 miles of pipeline and 65 compressor stations with approximately 346,000
installed horsepower. At December 31, 1993, the design peak day delivery
capacity of the transmission system was approximately 2.0 Bcf per day. The
underground storage facilities have a working capacity of approximately 29 Bcf
per year and a peak day delivery capacity of approximately 769 MMcf.
The Company formed CGS as a wholly-owned subsidiary in early 1993 to
consolidate its unregulated natural gas businesses. CGS and its subsidiaries
operate certain of Coastal's natural gas gathering and processing, gas supply
and marketing, price risk management and producer financing activities.
COMPETITION
ANR Pipeline and Colorado have historically competed with interstate and
intrastate pipeline companies in the sale, storage and transportation of gas and
with independent producers, brokers, marketers and other pipelines in the
gathering, processing and sale of gas within their service areas. On October 1,
1993 and November 1, 1993, Colorado and ANR Pipeline, respectively, implemented
Order 636 on their systems. As a consequence, ANR Pipeline is no longer a seller
of natural gas to resale customers. Order 636 also mandated implementation of
capacity release and secondary delivery point options allowing a pipeline's firm
transportation customers to compete with the pipeline for interruptible
transportation, which may result in reduced interruptible transportation revenue
of pipelines. Additional information on this subject is included under
"Regulations Affecting Gas Systems" included herein.
Natural gas competes with other forms of energy available to customers,
primarily on the basis of price. These competitive forms of energy include
electricity, coal, propane and fuel oils. Changes in the availability or price
of natural gas or other forms of energy, as well as changes in business
conditions, conservation, legislation or governmental regulations, capability to
convert to alternate fuels, changes in rate structure, taxes and other factors
may affect the demand for natural gas in the areas served by ANR Pipeline and
Colorado.
ANR Pipeline's storage, transportation and balancing services are influenced
by its customers' access to alternative providers of such services. ANR Pipeline
competes directly with Panhandle Eastern Pipe Line Company, Trunkline Gas
Company, Northern Natural Gas Company, Natural Gas Pipeline Company of America,
Michigan
2
Consolidated Gas Company and CMS Energy Company in its principal market areas of
Michigan and Wisconsin for its storage, transportation and balancing business.
ANR PIPELINE
GAS SALES FOR RESALE AND TRANSPORTATION
ANR Pipeline transports gas to markets on its system and other markets under
transportation and exchange arrangements with other companies, including
distributors, intrastate and interstate pipelines, producers, brokers, marketers
and end-users. Typically, these arrangements call for ANR Pipeline to transport
such gas to points of interconnection with local distribution companies or other
interstate pipelines. Transportation service revenues provided by ANR Pipeline
amounted to $533 million for 1993 compared to $463 million for 1992 and $382
million for 1991.
During the period January through October of 1993, ANR Pipeline sold 228 Bcf
of gas, of which approximately 71% was sold to its three largest customers:
Michigan Consolidated Gas Company, Wisconsin Gas Company and Wisconsin Natural
Gas Company. Michigan Consolidated Gas Company serves the City of Detroit and
certain surrounding areas, the industrial cities of Grand Rapids and Muskegon,
the communities of Ann Arbor and Ypsilanti and numerous other communities in
Michigan. Wisconsin Gas Company serves the Milwaukee metropolitan area and
numerous other communities in Wisconsin. Wisconsin Natural Gas Company serves
the industrial cities of Racine, Kenosha, Appleton and their surrounding areas
in Wisconsin. In 1993, ANR Pipeline provided 71% and 33% of the total gas
requirements for Wisconsin and Michigan, respectively. Gas sales for resale by
ANR Pipeline amounted to $604 million for 1993, compared to $635 million for
1992 and $641 million for 1991.
ANR Pipeline's deliveries for the years 1993, 1992 and 1991 are as follows:
Total System Daily Average
Year Deliveries System Deliveries
- ---------------- -------------- -----------------
(Bcf) (MMcf)
1993 1,336 3,660
1992 1,335 3,648
1991 1,324 3,627
On November 1, 1992, as part of its Interim Settlement, ANR Pipeline
implemented a restructuring of its traditional sales service by replacing
existing services with a combination of competitive service alternatives. This
restructuring provided a number of options for pipeline customers and was
designed to enhance competition in ANR Pipeline's service areas. Under this
restructuring, the sales service was "unbundled" on an interim basis into firm
sales, transportation, flexible storage and flexible delivery services. Prior to
the restructuring, the cost of providing transportation services for sales
customers was recovered as part of ANR Pipeline's total resale rate and
therefore, was classified as part of gas sales revenue. Under the restructuring,
these costs were recovered through a separate rate and were included in
transportation revenue. Additional information concerning the restructuring is
set forth in "Regulations Affecting Gas Systems - Rate Matters" included herein.
Effective November 1, 1993, ANR Pipeline implemented Order 636. This Order
required significant changes in the services provided by ANR Pipeline, and
resulted in the elimination of ANR Pipeline's merchant service. ANR Pipeline now
offers an array of "unbundled" storage, transportation and balancing service
options. Additional information concerning Order 636, including transportation
and storage, is set forth in "Regulations Affecting Gas Systems - General"
included herein.
3
GAS PURCHASES
Effective November 1, 1993, as a result of the elimination of ANR Pipeline's
merchant service, as mentioned above, ANR Pipeline's gas purchases decreased
substantially. However, ANR Pipeline still purchases gas under a number of gas
purchase contracts. ANR Pipeline's Order 636 restructured tariff provides
mechanisms for the purpose of recovering from or refunding to its customers any
pricing differential between costs incurred to purchase this gas and the amount
ANR Pipeline recovers through auctioning of gas on the open market.
Of ANR Pipeline's gas purchases in 1993, approximately 62% was obtained
directly from producers, including 17% from affiliates. In addition, ANR
Pipeline received approximately 32% of its gas supply from Canadian suppliers
and 6% from a producer of synthetic fuels. The border price of gas originating
in Canada has been based on policies, established in 1984 by the NEB and the
OFE, allowing exporters and importers to negotiate market-responsive prices.
Gas purchase contracts with producers generally provide for minimum purchase
obligations based on estimated reserves under the well, the well's ability to
produce or allowable gas takes set by state regulatory agencies. The prices paid
depend upon, among other things, contractual requirements, market conditions,
and the quality, condition of delivery and location of the gas. Under the NGWDA,
effective July 26, 1989, all gas which would otherwise continue to be subject to
price controls under the NGPA was deregulated over a three-year period and
complete deregulation became effective January 1, 1993.
Some of ANR Pipeline's remaining gas purchase contracts with independent
producers contain provisions which require taking minimum volumes and/or making
prepayments for volumes not taken if purchases fall below specified levels
during the contract year ("take-or-pay"). Additional information on take-or-pay
matters is set forth in Note 3 of the Notes to Consolidated Financial Statements
included herein.
GAS STORAGE
ANR Pipeline owns seven and leases eight underground storage facilities in
Michigan. The total working storage capacity of the system is approximately 193
Bcf, with a maximum day delivery capacity of 2 Bcf as late as the end of
February. However, of the 193 Bcf, ANR Pipeline has proposed to the FERC to
reclassify 62.1 Bcf of working gas to recoverable base gas. ANR Pipeline also
has the contract rights for 42 Bcf of storage capacity provided by Blue Lake Gas
Storage Company, 30 Bcf of storage capacity provided by ANR Storage and 10 Bcf
of storage capacity provided by Michigan Consolidated Gas Company. The contract
with Michigan Consolidated Gas Company expires in March 1994. Underground
storage services of up to 166 Bcf of gas are provided by ANR Pipeline to
customers on a firm basis. ANR Pipeline also provides interruptible storage
services for customers on a short-term basis.
Coastal's independent engineers, Huddleston, have estimated that ANR
Pipeline's gas storage reserves as of December 31, 1993, 1992 and 1991 were
106.5 Bcf, 128 Bcf and 134 Bcf, respectively. The 1993 gas storage reserves are
comprised of 19.4 Bcf of natural gas, maintained under ANR Pipeline's own
account as working gas for system balancing and no-notice storage services; 25
Bcf of recoverable base gas reserves in seven owned storage fields; and 62.1 Bcf
of working gas which ANR Pipeline has proposed to the FERC to reclassify as
recoverable base gas. The decrease in the gas storage reserves between 1993 and
1992 reflects ANR Pipeline's elimination of its merchant service. Effective
November 1, 1993, ANR Pipeline storage reserves are solely used to facilitate
the overall operations of the system.
4
COLORADO
GAS SALES, STORAGE AND TRANSPORTATION
Beginning in October 1993, Colorado implemented Order 636 on its system and
as required by the Order, Colorado's gas sales are now made at "upstream"
locations (typically the wellhead). Colorado's gas sales contracts extend
through September 30, 1996, but provide for reduced customer purchases to be
made each year. Under Order 636, Colorado's certificate to sell gas for resale
allows sales to be made at negotiated prices and not at prices established by
FERC. Colorado is also authorized to abandon all sales for resale at such time
as the contracts expire and without prior FERC approval.
Effective October 1, 1993, Colorado formed an unincorporated Merchant
Division to conduct most of Colorado's sales activity in the Order 636
environment. The gas sales volumes reported include those sales which continue
to be made by Colorado together with those of its Merchant Division.
Effective on October 1, 1993, Colorado assigned an undivided interest in a
portion of its company-owned leases (representing approximately 20% of
Colorado's owned reserves) to a new subsidiary. The subsidiary has entered into
a contract to sell the production to Colorado's Merchant Division, which
utilizes the gas primarily for its sales to Colorado's traditional customers.
The reserve volumes reported represent those interests retained by Colorado
together with those assigned to the new subsidiary.
Gas sales revenues were $223 million in 1993, compared to $261 million in
1992. This decrease is due largely to the fact that prior to the mandated
restructuring under Order 636 the costs of providing gathering, storage and
transportation services for sales customers were recovered as part of the total
resale rate and were classified as part of gas sales revenue. Subsequent to
restructuring, these costs are now recovered under separate rates for each
service.
Colorado has engaged in "open access" transportation and storage of gas owned
by third parties for several years. In addition, prior to October 1, 1993,
Colorado provided storage and transportation services as part of its "bundled"
sales service. As a result of Order 636, the Company has "unbundled" these
services from its sales services and will continue to provide these services to
third parties under individual contracts. Such services will be at negotiated
rates that are within minimum and maximum levels established by the FERC. Also,
pursuant to Order 636, Colorado, on September 30, 1993, sold all of its working
gas except for 3.8 Bcf which it retained for operational needs.
Colorado's deliveries for the years 1993, 1992 and 1991 are as follows:
Total System Daily Average
Year Deliveries System Deliveries
- ------------------------ -------------- -----------------
(Bcf) (MMcf)
1993 453 1,241
1992 428 1,169
1991 408 1,119
GAS GATHERING AND PROCESSING
Prior to Order 636, Colorado gathered and processed gas incident to its
"bundled" sales service (which also included storage and transportation
activities). However, in compliance with the FERC mandated restructuring,
Colorado now provides gathering and processing services on an "unbundled" or
stand-alone basis. Colorado contracts for these services under terms which are
negotiated. With respect to gathering, Colorado is limited to charging rates
which are between minimum and maximum levels approved by the FERC. Processing
terms are not subject to FERC approval, but Colorado is required to provide
"open access" to its processing facilities.
5
Colorado has 2,994 miles of gathering lines and 110,500 horsepower of
compression in its gathering operations. Colorado owns and operates six gas
processing plants which recovered approximately 86 million gallons of liquid
hydrocarbons in 1993, compared to 77 million gallons in 1992 and 61 million
gallons in 1991, and 4,400 long tons of sulfur in 1993 and 3,600 long tons in
both 1992 and 1991. Additionally, in 1993, Colorado processed approximately 12
million gallons of liquid hydrocarbons owned by others compared to 10 million in
1992 and 11 million in 1991. These plants, with a total operating capacity of
approximately 697 MMcf daily, recover mainly propane, butanes, natural gasoline,
sulfur and other by-products, which are sold to refineries, chemical plants and
other customers.
ANR STORAGE
ANR Storage develops and operates gas storage reservoirs to store gas for
customers under firm long-term contracts. ANR Storage owns four underground
storage fields and related facilities in northern Michigan, the working storage
capacity of which is approximately 53 Bcf, including 30 Bcf contracted to ANR
Pipeline. ANR Storage also owns a 50% equity interest in 3 joint venture storage
facilities located in Michigan and New York with a total working storage
capacity of approximately 60 Bcf, including 42 Bcf contracted to ANR Pipeline.
GAS SYSTEM RESERVES AND AVAILABILITY
ANR PIPELINE
With the termination of its merchant service, ANR Pipeline no longer reports
on gas system reserves and availability and, therefore, this report has been
replaced by a general discussion set forth in "Supply Area Deliverability",
presented below.
SUPPLY AREA DELIVERABILITY
Shippers on ANR Pipeline have direct access to the two most prolific gas
supply areas in the United States, the Gulf Coast and Midcontinent. Statistics
published by the Energy Information Agency, Office of Oil and Gas, U.S.
Department of Energy, indicate that approximately 82% of all natural gas in the
lower 48 states is produced from these two supply areas. Interconnecting
pipelines provide shippers with access to all other major gas supply areas in
the United States and Canada.
Gas deliverability available to shippers on ANR Pipeline's system from the
Midcontinent and Gulf Coast supply areas through direct connections and
interconnecting pipelines and gatherers is approximately 3,800 MMcf per day. An
additional 275 MMcf per day of deliverability is accessible to shippers on ANR
Pipeline owned, or partially owned, pipeline segments not directly connected to
an ANR Pipeline mainline.
ANR Pipeline remains active in locating and connecting new gas supply sources
to facilitate transportation arrangements made by third party shippers. During
1993, field development, newly connected supply sources and pipeline
interconnections contributed 515 MMcf per day to total deliverability accessible
to shippers on ANR Pipeline.
COLORADO
Colorado has reported in its Form 10-K for the year ended December 31, 1993
the current and future availability of Colorado's gas system reserves based on
information prepared by Huddleston, the Company's independent engineers.
Colorado, even with the restructuring under Order 636, continues to dedicate
certain of its reserves pursuant to contract. Additional information is set
forth in "Reserves Dedicated to a Particular Customer," presented below.
6
RESERVES DEDICATED TO A PARTICULAR CUSTOMER
Colorado is committed to provide gas to Mesa Operating Company, formerly Mesa
Operating Limited Partnership ("Mesa"), a customer, from specific owned gas
reserves in the West Panhandle Field of Texas. Production from this area
contributed approximately 46% of Colorado's total supply in 1993. Approximately
68% of those volumes were delivered to Mesa. Under an agreement which was
effective January 1, 1991, as amended, Colorado has the right to take a
cumulative 23% of the total net production from such reserves for its customers
other than Mesa.
RECONCILIATION WITH FERC FORM 15 REPORT
The FERC Form 15 Annual Report of Gas Supplies is no longer required pursuant
to FERC Order No. 554 issued July 13, 1993.
WYOMING INTERSTATE COMPANY, LTD.
WIC, a limited partnership owned by two wholly-owned Coastal subsidiaries,
owns a 269-mile, 36-inch diameter pipeline across southern Wyoming. It has a
throughput capacity of approximately 500 MMcf of gas daily. The WIC pipeline
connects with an 88-mile western segment in which a Coastal subsidiary has a 10%
interest and is the center section of the 800-mile Trailblazer pipeline system
built by a group of companies to move gas from the Overthrust Belt and other
Rocky Mountain areas to supply midwestern and eastern markets. Colorado and
three other pipeline companies for which the WIC line transports gas have
entered into long-term contracts having demand volumes totaling 500 MMcf daily.
In 1993, the WIC line transported an average of 228 MMcf daily, compared to 261
MMcf daily in 1992. On January 1, 1992, WIC became an unrestricted open access
transporter.
GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Coastal and TransCanada, a non-affiliated company, each own 50% of Great
Lakes which owns a 1,985-mile, 36-inch diameter gas pipeline system from the
Manitoba-Minnesota border to an interconnection on the Michigan-Ontario border
at St. Clair, Michigan. Great Lakes transported 854 Bcf in 1993 as compared to
789 Bcf in 1992. Great Lakes has contract commitments to transport a total of
1.3 Bcf per day for TransCanada. It also transports up to 800 MMcf per day
primarily for United States markets, including 77 MMcf per day to ANR Pipeline.
Great Lakes exchanges gas with ANR Pipeline by delivering gas in the upper
peninsula of Michigan and receiving an equal amount of gas in the lower
peninsula of Michigan. This arrangement reduces the distance that gas must be
transported by Great Lakes and ANR Pipeline.
COASTAL GAS SERVICES COMPANY
The Company formed CGS, a wholly-owned subsidiary, in early 1993 to
consolidate its unregulated natural gas businesses. CGS and its subsidiaries
operate certain of Coastal's natural gas gathering and processing, gas supply
and marketing, price risk management and producer financing activities. CGS'
subsidiary, ANR Gas Supply Company, was formed to provide merchant services to
former ANR Pipeline customers contracting for such service. ANR Gas Supply
Company has executed 25 contracts with former ANR Pipeline customers with an
aggregate service commitment of 85 MMcf per day. CGMC is the largest of CGS's
subsidiaries and continues to be one of the most successful natural gas
marketing companies in North America. CGMC managed the sale and delivery of 828
Bcf of natural gas in 1993 as compared to 788 Bcf in 1992. CGMC conducts
business on over 60 pipelines and has over 1,000 producer and market customers
in North America, including imports and exports with Canada and Mexico.
7
REGULATIONS AFFECTING GAS SYSTEMS
GENERAL
Under the NGA, the FERC has jurisdiction over ANR Pipeline, Colorado, WIC,
ANR Storage and Great Lakes as to sales, transportation, balancing of gas, rates
and charges, the construction of new facilities, extension or abandonment of
service and facilities, accounts and records, depreciation and amortization
policies and certain other matters. Under Order 636, the FERC has determined
that it will not regulate sales rates by pipelines including these companies.
Additionally FERC has asserted rate-regulation (but not certificate regulation)
over gathering. Colorado is challenging the FERC's assertion of rate
jurisdiction over gathering, but has agreed in a settlement that for three years
beginning October 1, 1993 Colorado will post in its tariff the minimum and
maximum gathering rates which will be established by FERC. ANR Pipeline,
Colorado, WIC, ANR Storage and Great Lakes, where required, hold certificates of
public convenience and necessity issued by the FERC covering their
jurisdictional facilities, activities and services.
ANR Pipeline, Colorado, WIC, ANR Storage and Great Lakes are also subject to
regulation with respect to safety requirements in the design, construction,
operation and maintenance of their interstate gas transmission and storage
facilities by the Department of Transportation. Operations on United States
government land are regulated by the Department of the Interior.
On November 1, 1990, the FERC issued Order No. 528 in which it sets forth
guidelines for an acceptable allocation method for a fixed direct charge to
collect take-or-pay settlement costs. Pursuant to Order No. 528, ANR Pipeline
has filed for and received approval to recover 75% of expenditures associated
with resolving producer claims and renegotiating gas purchase contracts. The
approved filings provide for recovery of 25% of such expenditures via a direct
bill to ANR Pipeline's former sales for resale customers and 50% via a surcharge
on all transportation volumes. Contract reformation and take-or-pay costs
incurred as a result of the mandated Order 636 restructuring will be recovered
under the transition costs mechanisms of Order 636 as well as through negotiated
agreements with ANR Pipeline's customers.
FERC Order Nos. 500 and 528 allowed regulated pipelines, including Colorado,
to recover, through a fixed charge, from 25% to 50% of the cost of payments made
to producers to extinguish outstanding claims under existing gas purchase
contracts or to secure reformation of existing contracts. Fixed charges are paid
by pipeline customers without regard to volumes of gas purchased. Under this
election, however, an amount equivalent to the amount included in the fixed
charge must be borne by the pipeline. Colorado has incurred costs related to
contract reformation and settlements of take-or-pay claims, a portion of which
have been recovered under Order Nos. 500 and 528.
On April 8, 1992, the FERC issued Order Nos. 636, 636-A and 636-B
(collectively "Order 636"), which required significant changes in the services
provided by interstate natural gas pipelines. Subsidiaries of the Company and
numerous other parties have sought judicial review of aspects of Order 636.
Notwithstanding those appeals, ANR Pipeline, Colorado, WIC, ANR Storage and
Great Lakes have successfully complied with the requirements of Order 636.
On July 2, 1993, Colorado submitted to the FERC an unanimous offer of
settlement which resolved all the Order 636 restructuring issues which had been
raised in its restructuring proceedings. That settlement was ultimately approved
(except for minor issues), and Colorado's restructured services became effective
October 1, 1993. Under that settlement, Colorado has "unbundled" its gas sales
from its other services. Separate gathering, transportation, storage, no notice
transportation and storage and other services are available on a "stand alone"
basis to any customers desiring them. Colorado's Order 636 transition costs are
not expected to be material and are expected to be recovered through Colorado's
rates.
ANR Pipeline placed its restructured services under Order 636 into effect on
November 1, 1993. ANR Pipeline now offers a wide range of "unbundled"
transportation, storage and balancing services. Several persons, including
8
ANR Pipeline, have sought judicial review of aspects of the FERC's orders
approving ANR Pipeline's restructuring filings. Order 636 also provides
mechanisms for recovery of transition costs associated with compliance with that
Order. These transition costs include gas supply realignment costs, the cost of
stranded pipeline investment and the cost of new facilities required to
implement Order 636. ANR Pipeline expects that it will incur transition costs of
approximately $150 million. As a result of the recovery mechanisms provided
under Order 636, ANR Pipeline anticipates that these transition costs will not
have a material adverse effect on ANR Pipeline's consolidated financial position
or its results of operations.
RATE MATTERS
ANR PIPELINE. All of ANR Pipeline's 1993 service options were subject to
rate regulation by the FERC. Under the NGA, ANR Pipeline must file with the FERC
to establish or adjust its service rates. The FERC may also initiate proceedings
to determine whether ANR Pipeline rates are "just and reasonable."
On March 10, 1992, ANR Pipeline submitted to the FERC a comprehensive Interim
Settlement designed to resolve all outstanding issues resulting from its 1989
rate case and its 1990 proposed service restructuring proceeding. The Interim
Settlement involved, inter alia, an array of new sales, delivery, transportation
and storage service alternatives and the implementation of a gas inventory
charge, designed to compensate ANR Pipeline for the costs of standing ready to
serve its sales customers. The Interim Settlement reflected a decrease in cost
of service of approximately $45 million, which was largely attributable to a
reduction in depreciation rates from 3.4% to 1.82%. Also included was a
provision which allowed ANR Pipeline to direct bill its customers for its
remaining unrecovered purchased gas costs. The Interim Settlement became
effective November 1, 1992 and expired with ANR Pipeline's implementation of
Order 636 on November 1, 1993. Specific provisions of the Interim Settlement
relating to the deferral and future recovery of certain costs remain in effect.
On December 17, 1992, the FERC issued a policy statement that outlined
changes on how pipelines may recover the costs of employees' postretirement
benefits other than pensions. The FERC's policy will be to recognize, as a
component of jurisdictional cost-based rates, allowances for FAS No. 106 costs
of company employees when determined on an accrual basis, provided certain
conditions are met.
On November 1, 1993, ANR Pipeline filed a general rate increase with the
FERC. The proposed rates reflect a $121 million increase in ANR Pipeline's cost
of service from that approved in the Interim Settlement and a $218 million
increase over ANR Pipeline's approved rates for its restructured services. The
increase represents higher plant investment, Order 636 restructuring costs, rate
of return and tax rate changes and increased costs related to the required
adoption of recent accounting rule changes, i.e., FAS Nos. 106 and 112. (See
Note 11 of the Notes to Consolidated Financial Statements for a discussion of
FAS Nos. 106 and 112.) The FERC has permitted ANR Pipeline to place its new
rates into effect on May 1, 1994, subject to refund and subject to certain
required compliance changes and the outcome of an evidentiary hearing on all
remaining issues.
COLORADO. Under the NGA, Colorado continues to be required to file with the
FERC to establish or adjust certain of its service rates. The FERC may also
initiate proceedings to determine whether Colorado's rates are "just and
reasonable".
On March 31, 1993, Colorado filed at FERC to increase its rates by
approximately $26.5 million annually. Such rates (adjusted to reflect Colorado's
Order 636 program) became effective subject to refund on October 1, 1993.
WIC. WIC settled a rate case with the FERC, as principal payments and
associated interest of $68.1 million were paid to WIC's shippers on October 8,
1991, exclusive of amounts which are being held until the resolution of pending
bankruptcy proceedings involving its customer, Columbia Gas Transmission
Corporation, which is currently pending before the U.S. Bankruptcy Court for the
District of Delaware. Should such refunds be required, there would be no effect
on the results of operations as accruals have been previously established.
9
In 1993 the FERC initiated proceedings under Section 5 of the NGA to
determine if WIC's rates approved in 1991 had become excessive. Administrative
hearings were held in December of 1993, but no decision has been issued. Any
decrease in rates that the FERC may ultimately require will only take effect
prospectively following the issuance of a final order by the FERC that is no
longer subject to rehearing by the agency.
Certain regulatory issues remain unresolved among ANR Pipeline, Colorado, WIC
and ANR Storage, their customers, their suppliers, and the FERC. ANR Pipeline,
Colorado, WIC and ANR Storage have made provisions which represent management's
assessment of the ultimate resolution of these issues. While these companies
estimate the provisions to be adequate to cover potential adverse rulings on
these and other issues, they cannot estimate when each of these issues will be
resolved.
OTHER DEVELOPMENTS
The Empire State Pipeline Project, in which an affiliate of ANR Pipeline has
a 45% interest and ANR Pipeline is the operator, was placed in service on
November 1, 1993. The 156-mile pipeline system, extending from Niagara Falls to
Syracuse, New York, will carry up to 570 MMcf per day to western and central New
York and provide ANR Pipeline access to markets in the Northeastern United
States.
In August 1993, ANR Pipeline and Arkla, Inc. ("Arkla") announced execution of
a restructured agreement under which ANR Pipeline will purchase an ownership
interest in 250 MMcf per day of capacity in existing natural gas transmission
facilities from Arkla. The restructured agreement resolved certain conditions
imposed by the FERC in its October 1, 1992 authorization of the original
purchase and sale agreement. As restructured, ANR Pipeline will own capacity
interests in facilities valued at approximately $90 million, subject to receipt
of all required regulatory approvals. The reduction in value of the facilities
from the original purchase and sale agreement is the result of negotiations
between ANR Pipeline and Arkla in light of the FERC's orders.
ANR Pipeline and a subsidiary of CGS are partners in the SunShine Pipeline
Project which is designed to capture a share of the growing Florida power
generation market, as well as markets located in Mississippi, Alabama and the
Florida Panhandle. SunShine Interstate Transmission Company ("SITCO"), the
interstate pipeline segments of this project, will extend 170 miles from
Pascagoula, Mississippi to Okaloosa, Florida where it will connect with Sunshine
Pipeline Company, ("SunShine") the intrastate segment of this project. SunShine
will be a 545-mile pipeline starting in Okaloosa and extending down Florida's
west coast to the Tampa area. ANR Pipeline, through a wholly-owned subsidiary,
will have a 40% interest in SITCO and a subsidiary of CGS will have a 40%
interest in SunShine. Florida Power Corporation and TransCanada will both hold a
30% equity interest in each of the two projects. SITCO will have an initial
capacity of 329.5 MMcf per day and SunShine will have an initial capacity of
249.5 MMcf per day. Both SITCO and SunShine have signed precedent agreements for
a portion of their initial pipeline capacity. SITCO, which will be subject to
FERC jurisdiction, has filed with the FERC to obtain a Certificate of Public
Convenience and Necessity. FERC approval is expected in March, 1995. SunShine,
which will be subject to the jurisdiction of the Florida Public Service
Commission ("FPSC"), has received approval of its request for a Determination of
Need from the FPSC. SunShine also expects environmental approval, in early 1995,
under the procedures set forth in Florida's Natural Gas Transmission Pipeline
Siting Act. Both projects are targeted to be placed into service in December
1995. The SunShine pipeline is expected to cost approximately $462 million and
the SITCO pipeline is expected to cost approximately $188 million.
A subsidiary of ANR Pipeline will have a 25% equity interest in the proposed
Liberty Pipeline project, a 38-mile pipeline extending from New Jersey across
New York Harbor to Long Island with a potential capacity of 500 MMcf per day.
The pipeline is expected to serve local distribution company participants and
independent power producers. A filing to obtain a Certificate of Public
Convenience and Necessity has been made and is currently pending before the
FERC. Subject to receiving applicable governmental approvals, an in-service date
of late 1995 is possible, at an estimated cost of $160 million.
ANR Pipeline (20% equity interest) and Interprovincial Pipe Line System Inc.
plan to participate in the construction of the InterCoastal Pipe Line, a project
designed to serve incremental markets in southern Ontario and
10
potentially Quebec and the Northeastern United States. The project will involve
converting approximately 130 miles of existing oil pipeline to natural gas
service, originating in Sarnia, Ontario and extending to Toronto, and the
construction of approximately 25 miles of new pipeline. In connection with the
project, facilities in Michigan will be constructed by ANR Pipeline to deliver
gas from domestic sources. The project, which will have a maximum capacity of
175 MMcf per day, is projected to cost $37.6 million. The InterCoastal Pipe Line
is subject to regulatory approval in Canada, and the ANR Pipeline facilities are
subject to regulatory approvals in the United States. Filings seeking necessary
authorizations from the NEB were made in the second quarter of 1993, and with
the FERC on July 19, 1993. The project could be in service as early as November
1, 1994.
A subsidiary of ANR Pipeline and affiliates of TransCanada and Brooklyn Union
Gas Company have entered into a partnership agreement for the construction of
the Mayflower Pipeline, which is expected to expand natural gas sales and
storage services to markets in the Northeastern United States. ANR Pipeline will
have a 45% interest in this project. The proposed 240-mile pipeline will extend
east from the Iroquois Gas Transmission System at Canajoharie, New York to a
location near Boston, Massachusetts and have an initial design capacity of 350
MMcf per day. The total project cost is expected to be $540 million. The
pipeline is expected to be in service in late 1997. Construction of the project
is subject to receipt of all federal regulatory approvals.
Colorado owns approximately 20% of Natural Fuels Corporation ("NFC") which is
headquartered in Denver, Colorado. NFC's business is to develop compressed
natural gas ("CNG") as an alternative vehicular fuel. Major services provided by
NFC include vehicle conversions to CNG, fuel sales, CNG equipment sales,
maintenance services, and training. Besides operating a full service conversion
center which converts vehicles to CNG, NFC has installed 44 stations in
Colorado, 26 of which are open to the public. NFC, in joint partnership with
Total Petroleum, installs natural gas refueling facilities at selected Total
Petroleum stores along the Colorado Front Range. This project is one of the
largest public fueling station development commitments in the United States. As
of January 1994, seven stations were operational and one was under construction.
Also, Colorado is a co-sponsor in the testing of two Colorado Springs buses that
are powered by dual-fueled engines modified to run on up to 90% natural gas.
On July 8, 1993, Young Gas Storage Company, Ltd. ("Young"), a limited
partnership, filed an application with the FERC for a Certificate of Public
Convenience and Necessity authorizing, in part, the development, construction
and operation of an underground natural gas storage field. The $44.4 million
storage field project, to be located in Morgan County, Colorado, will be capable
of storing 5.3 Bcf of working gas with a withdrawal rate of 200 MMcf per day
when fully developed in 1998. The total capacity is under long-term contracts.
On March 3, 1994, the FERC issued an Order Granting Preliminary Determination
which approved the non-environmental aspects of the project. The Company is
reviewing this Order and intends to seek rehearing with respect to some aspects
of this Order. CIG Gas Storage Company and Young Gas Storage Company, the two
general partners in the Young Partnership, are affiliates of Coastal. The
limited partner is the City of Colorado Springs, a municipal corporation of the
State of Colorado.
CGS has established a producer and market services division to provide
financing services to producers. This division will arrange funding for
acquisitions and development of oil and gas reserves and other producer capital
requirements. As a result of these activities, CGS will obtain access to long-
term oil and gas supplies enhancing CGS' marketing capabilities.
Coastal States Gas Transmission Company, a subsidiary of the Company, is
building a natural gas intrastate pipeline from the Bob West Field in South
Texas to run initially 26 miles north to the Midcon Texas Pipeline System at a
cost of approximately $8 million. This new pipeline is expected to be completed
prior to June 1994 and will transport up to 200 MMcf per day of natural gas
without compression and up to 350 MMcf per day with compression.
Funding for certain pending and proposed natural gas pipeline projects is
anticipated to be provided through non-recourse financings in which the
projects' assets and contracts will be pledged as collateral. This type of
financing typically requires the participants to make equity investments
totaling approximately 20% to 30% of the cost of the project, with the remainder
financed on a long-term basis.
11
REFINING, MARKETING AND DISTRIBUTION
The Company has subsidiary operations involved in refining, marketing and
distribution of petroleum products. The petroleum industry is highly competitive
in the United States and throughout most of the world. This industry also
competes with other industries in supplying the energy needs of various types of
consumers.
REFINING
Subsidiaries of the Company operated their wholly-owned refineries at 87% of
year 1993 average combined capacity compared to 82% in 1992. The aggregate sales
volumes (millions of barrels) of Coastal's wholly-owned refineries for the three
years ended December 31, 1993, were 134.9 (1993), 136.7 (1992) and 141.2 (1991).
A joint venture, Pacific Refining Company, had sales of 19.9 million barrels in
1993, 21.3 million barrels in 1992 and 27.4 million barrels in 1991 which were
excluded from Coastal's 1993, 1992 and 1991 sales. Of the total refinery sales
in 1993, 30% was gasoline, 46% was middle distillates, such as jet fuel, diesel
fuel and home heating oil, and 24% was heavy industrial fuels and other
products.
The average daily processing capacity of crude oil at December 31, 1993,
average daily throughput and storage capacity at the Company's wholly-owned
operating refineries are set forth below:
Refinery Location
- ---------------- ---------------------- Average Daily
Daily Throughput (Barrels) Storage
Capacity ----------------------- Capacity
(Barrels) 1993 1992 (Barrels)
-------------- --------- -------- ---------
Aruba Aruba 175,000 136,400 123,800 8,000,000
Corpus Christi Corpus Christi, Texas 95,000 79,300 78,600 7,500,000
Eagle Point Westville, New Jersey 125,000 109,300 101,500 10,400,000
Mobile Mobile, Alabama 17,500 13,500 12,400 600,000
------- ------- ------- ----------
Total Operating 412,500 338,500 316,300 26,500,000
The Company has curtailed refining operations at its three Kansas refinery
locations as part of an overall restructuring plan for refining and marketing
undertaken in 1992. Two of these locations, Wichita and El Dorado, are still
operating as refined products terminals. Refinery units have been mothballed and
are being evaluated for utilization either by the company or by third parties.
Pacific Refining at Hercules, California has a refining capacity of 55,000
barrels per day at December 31, 1993. Since January 1989, the China National
Chemicals Import & Export Corporation has held a 50% interest in Coastal's west
coast refining and marketing properties, including Pacific Refining Company. The
Hercules refinery was operated during 1993 and processed 46,200 barrels per day
of crude oil and other feedstocks. Present plans are to continue operation of
the refinery through 1994 and most likely through 1995, consistent with
resolution of regulatory issues and attainment of earnings objectives. The
Company is evaluating several future options for the facility. These include
expansion of asphalt facilities and installation of Clean Air Act of 1990 and
California Air Resources Board regulations compliance upgrades and conversion of
the Hercules site to alternative uses.
In addition, Coastal's international operations include a minority interest,
through a foreign subsidiary, in a refinery located in Hamburg, Germany which
has a refining capacity of 100,000 barrels per day and a storage capacity of
1,800,000 barrels for crude oil and 5,200,000 barrels for products.
The Company's refineries produce a full range of petroleum products ranging
from transportation fuels to paving asphalt. The refineries are operated to
produce the particular products required by customers within each refinery's
geographic area. In 1993, the products emphasized included premium gasolines and
products for specialty markets such as petrochemical feedstocks, aviation fuels
and asphalt.
12
MARKETING AND DISTRIBUTION
REFINED PRODUCTS MARKETING. Sales volumes for distribution activities of
Coastal subsidiaries, including products from Company refineries and purchases
from other suppliers, for the three years ended December 31, 1993, are set forth
below (thousands of barrels):
Type of Sale 1993 1992 1991
- ---------------------------------------- ------- ------- -------
Company Produced Refined Products....... 134,925 136,664 141,224
Refined Products Purchased from Others.. 140,635 162,280 128,146
Natural Gas Liquids..................... 18,155 17,038 13,914
------- ------- -------
Total.................... 293,715 315,982 283,284
======= ======= =======
Subsidiaries of the Company market refined products and liquefied petroleum
gas at wholesale in 36 states through 322 terminals. Coastal Refining &
Marketing, Inc. serves customers in the Midwest, Mississippi Valley and the
Southwest through 221 product and liquified petroleum gas terminals in 27
states. On the Gulf and East Coasts, Coastal Fuels Marketing, Inc., Coastal Oil
New York, Inc. and Coastal Oil New England, Inc. serve home, industry, utility,
defense and marine energy needs. In 1993, these subsidiaries' sales volumes were
132 million barrels, which accounted for approximately 45% of the total
marketing and distribution sales. Effective January 1, 1994, the refined
products marketing operations of these subsidiaries were consolidated into
Coastal Refining & Marketing, Inc. International subsidiaries that acquire
feedstocks for the refineries and products for the distribution system are
located in Aruba, Bahrain, Bermuda, London, Madrid and Singapore.
In March 1993, Coastal Petroleum N.V., a subsidiary of Coastal, and The Subic
Bay Metropolitan Authority signed a long-term lease for petroleum storage
facilities located at the former U.S. naval base at Subic Bay in the
Philippines. Coastal is leasing 304 acres of land, with 68 individual storage
tanks totalling 2.4 million barrels of storage, most of which are underground,
and 40 miles of pipeline connecting the terminal with other facilities within
the Subic Bay Freeport Zone. Additionally, in late 1993, another subsidiary of
Coastal signed a joint venture agreement with a subsidiary of the Malaysian
national oil company, Petronas, for use of the entire capacity of this storage
facility for independent marketing efforts throughout the region and for joint
marketing in the Subic Bay Freeport Zone.
The Company, through Coastal Mart, Inc. and branded marketers, conducts
retail marketing, using the C-MART(R) and/or COASTAL(R) trademarks, in 36 states
through approximately 1,532 Coastal branded outlets, with 578 of those outlets
operated by the Company. Fleet fueling operations include 17 outlets in Texas
and 7 in Florida.
Coastal Unilube, Inc., based in West Memphis, Arkansas, blends, packages and
distributes lubricants and automotive products under the UNILUBE(R), DUPLEX(R),
CUI(R) and UNIPRO(R) brand names. Coastal Unilube, Inc. distributes lubricants
and automotive products through 14 warehouses servicing customers in 36 states.
TRANSPORTATION. The Company's transportation facilities include petroleum
liquids pipelines, tank cars, tankers, tank trucks and barges. Coastal has
approximately 3,900 miles of pipeline for gathering and transporting an average
of 334,000 barrels daily of crude oil, condensate, natural gas liquids and
refined products. These lines are located principally in Texas and Kansas and
include 358 miles of crude oil pipelines, 784 miles of refined products
pipelines and 671 miles of natural gas liquids pipelines, all 100% owned and
operated by Coastal subsidiaries, and 1,997 miles of 50% owned crude oil
pipelines and 80 miles of jointly-owned products pipelines with less than a 50%
interest. In 1993, throughput of crude oil pipelines averaged 148,199 barrels
per day, compared to 155,386 barrels per day in 1992. In 1993, throughput of
refined products and natural gas liquid pipelines averaged 186,430 barrels per
day, compared to 162,696 barrels per day in 1992.
Other transportation facilities for marketing operations of Coastal
subsidiaries include a regional tank truck fleet which distributes refined and
liquefied petroleum gas products to customers in parts of Florida, New England
and
13
New York, and another fleet of trucks, which transport petroleum products and
liquefied petroleum gas products for Coastal marketing subsidiaries serving the
Texas area.
The marine transportation total fleet at December 31, 1993 consisted of 17
tug boats, 24 oil barges, 6 owned tankers used for the transportation of refined
petroleum products and crude oil and 3 time-chartered tankers.
EXPLORATION AND PRODUCTION
GAS AND OIL PROPERTIES
Coastal subsidiaries are engaged in gas and oil exploration, development and
production operations in the United States and Argentina. Argentine operations
are discussed in Supplemental Information on Oil & Gas Producing Activities
(Unaudited), as set forth in Item 14(a)1 hereof. United States operations are
principally in Alabama, Arkansas, California, Colorado, Kansas, Louisiana,
Michigan, Mississippi, Montana, New Mexico, North Dakota, Oklahoma, Texas, Utah,
West Virginia, Wyoming and offshore in the Gulf of Mexico.
In 1993, the Company's domestic operations sold approximately 53% of all the
gas it produced to its natural gas system affiliates and a gas brokerage
affiliate. The Company's domestic operations make short-term gas sales directly
to industrial users and distribution companies to increase utilization of its
excess current gas production capacity. Oil is sold primarily under short-term
contracts at field prices posted by the principal purchasers of oil in the areas
in which the producing properties are located.
Acreage held under gas and oil mineral leases as of December 31, 1993 is
summarized as follows:
UNDEVELOPED DEVELOPED
----------- ---------
AREA GROSS NET GROSS NET
- ------------------------------------- ----- ----------- --------- ---
(Thousands of Acres)
Domestic........................... 1,093 798 1,792 962
Federal Offshore (Gulf of Mexico).. 66 32 54 20
----- --- ----- ---
TOTAL.......................... 1,159 830 1,846 982
===== === ===== ===
The domestic net acreage held for production is concentrated principally in
Texas (37%), Utah (20%), Oklahoma (10%), West Virginia (7%), Kansas (6%) and
Wyoming (6%). Approximately 21%, 22% and 23% of the Company's total undeveloped
net acreage is under leases that have minimum remaining primary terms expiring
in 1994, 1995 and 1996, respectively.
Productive wells as of December 31, 1993 are as follows (domestic):
TYPE OF WELL GROSS NET
- -------------------------- ----- -----
Oil..................... 3,860 1,016
Gas..................... 2,574 1,372
----- -----
TOTAL............... 6,434 2,388
===== =====
14
EXPLORATION AND DRILLING
During 1993, Coastal's domestic exploration and production units participated
in drilling 158 gross wells, 75.5 net wells, to the Company's interest.
Coastal's participation in wells drilled in the three years ended December 31,
1993, is summarized as follows:
1993 1992 1991
----------- ----------- ----------
EXPLORATORY WELLS GROSS NET GROSS NET GROSS NET
- ---------------------------------- ----- ---- ----- ----- ----- ----
Oil........................... 1 0.5 6 1.8 7 4.6
Gas........................... - - 3 1.7 7 5.3
Dry Holes..................... 7 4.1 16 9.1 9 6.5
---- ----- ---- ----- ---- ----
8 4.6 25 12.6 23 16.4
==== ===== ==== ===== ==== ====
DEVELOPMENT WELLS
- ---------------------------------
Oil.......................... 44 18.6 47 18.4 24 5.3
Gas.......................... 104 51.2 141 108.5 89 62.0
Dry Holes.................... 2 1.1 11 8.3 7 3.2
--- ---- ---- ----- ---- ----
150 70.9 199 135.2 120 70.5
=== ==== ==== ===== ==== ====
Wells in progress as of December 31, 1993 are as follows (domestic):
TYPE OF WELL GROSS NET
------------ ----- ---
Exploratory............................. 3 1.2
Development............................. 9 2.2
--- ---
Total.................................. 12 3.4
=== ===
During the course of 1992 and 1991 development drilling focused on natural
gas wells which qualified under a federal tax incentive program providing for
future tax credits on wells producing from tight sands gas formations. To
qualify, wells must have been spudded before January 1, 1993. During 1993,
development drilling focused on replacing and increasing production capacity as
natural gas prices stabilized at acceptable levels.
Coastal Limited Ventures, Inc., a domestic subsidiary of Coastal, is the
general partner in six limited partnership drilling programs which have been
offered to Coastal's employees and shareholders. Information pertaining thereto
can be located in the Annual Report on Form 10-K filed by each limited
partnership and available from the Company.
GAS AND OIL PRODUCTION
Natural gas production during 1993 averaged 334 MMcf daily, compared to 277
MMcf daily in 1992. Production from non-pipeline-owned wells averaged 207 MMcf
daily in 1993, compared to 147 MMcf daily in 1992. Crude oil, condensate and
natural gas liquids production averaged 13,534 barrels daily in 1993, compared
to 13,002 barrels daily in 1992.
15
The following table shows gas, oil, condensate and natural gas liquids
production volumes attributable to Coastal's domestic interest in gas and oil
properties for the three years ended December 31, 1993:
NATURAL GAS
OIL CONDENSATE LIQUIDS
GAS (THOUSANDS (THOUSANDS (THOUSANDS
YEAR (MMCF) OF BARRELS) OF BARRELS) OF BARRELS)
- --------------------- ---------- ---------- ---------- ----------
1993 122,011 3,908 440 592
1992 101,502 3,823 496 440
1991 89,346 3,398 512 179
Many of Coastal's domestic gas wells are situated in areas near, and are
connected to, its gas systems. In other areas, gas production is sold to
pipeline companies and other purchasers.
Generally, Coastal's domestic production of crude oil, condensate and natural
gas liquids is purchased at the lease by its marketing and refinery affiliates.
Some quantities are delivered via Coastal's gathering and transportation lines
to its refineries, but most quantities are redelivered to Coastal through
various exchange agreements.
The following table summarizes sales price (net of production taxes) and
production cost information for domestic exploration and production operations
during the three years ended December 31, 1993:
1993 1992 1991
----- ----- -----
Average sales price (net of production taxes):
Gas - per Mcf..................................... $ 1.93 $ 1.76 $ 1.67
Oil - per barrel.................................. 16.21 18.21 19.15
Condensate - per barrel........................... 15.55 17.40 18.67
Natural Gas Liquids - per barrel.................. 8.75 9.62 13.36
Average production cost per unit (equivalent Mcf).. 0.67 0.79 0.97
NATURAL GAS PROCESSING
ANR Production Company and Coastal Oil & Gas Corporation, domestic
subsidiaries of the Company, are also engaged in the processing of natural gas
for the extraction and sale of natural gas liquids. In 1993, total revenues of
$36.7 million were generated from the extraction and sale of 136 million gallons
of ethane, propane, iso-butane, normal butane and natural gasoline from natural
gas processing plants. Sales prices of natural gas liquids fluctuate widely as a
result of market conditions and changes in the prices of other fuels and
chemical feedstocks.
COMPANY-OWNED RESERVES
Coastal's domestic proved reserves of crude oil, condensate and natural gas
liquids at December 31, 1993, as estimated by Huddleston, its independent
engineers, were 28.8 million barrels, compared to 33.1 million barrels at the
end of 1992. Proved gas reserves as of December 31, 1993, net to Coastal's
interest, were estimated by the engineers to be 925.5 Bcf compared to 974.8 Bcf
as of December 31, 1992.
For information as to Company-owned reserves of oil and gas, see
"Supplemental Information On Oil and Gas Producing Activities" as set forth in
Item 14(a)1 hereof.
16
COMPETITION
In the United States, the Company competes with major integrated oil
companies and independent oil and gas companies for suitable prospects for oil
and gas drilling operations. The availability of a ready market for gas
discovered and produced depends on numerous factors frequently beyond the
Company's control. These factors include the extent of gas discovery and
production by other producers, crude oil imports, the marketing of competitive
fuels, and the proximity, availability and capacity of gas pipelines and other
facilities for the transportation and marketing of gas. The production and sale
of oil and gas is subject to a variety of federal and state regulations,
including regulation of production levels.
REGULATION
In all states in the United States in which Coastal engages in oil and gas
exploration and production, its activities are subject to regulation. Such
regulations may extend to requiring drilling permits, the spacing of wells, the
prevention of waste and pollution, the conservation of natural gas and oil, and
various other matters. Such regulations may impose restrictions on the
production of natural gas and crude oil by reducing the rate of flow from
individual wells below their actual capacity to produce. Likewise, oil and gas
operations on all federal lands are subject to regulation by the Department of
the Interior and other federal agencies.
COAL
The Company, through ANR Coal Company and its subsidiaries ("ANR Coal") in
the eastern United States and through Coastal States Energy Company and its
subsidiaries ("Coastal States Energy") in the west, produces and markets high
quality bituminous coal from its reserves in Kentucky, Virginia, West Virginia
and Utah. In addition, subsidiaries of ANR Coal lease interests in their
reserves to unaffiliated producers and market third-party coal through brokerage
sales operations.
At December 31, 1993, coal properties consisted of the following:
Coal Holdings (Acres)
---------------------------------------------------- Clean,
Owned Leased Recoverable
---------------------------- Exchanged Total Tons
Fee Mineral Surface (Net) Acres (Millions)(1)
------ ----------- ------- ----------- --------- -------------
Kentucky............... 11,351 65,107 2,271 25,746 104,475 222
Virginia............... 23,765 37,531 2,021 22,724 86,041 168
West Virginia.......... 2,165 36,772 4,156 124,352 167,445 230
Utah................... - 2,480 - 32,077 34,557 251
------ ------- ----- ------- ------- ---
TOTAL................ 37,281 141,890 8,448 204,899 392,518 871
====== ======= ===== ======= ======= ===
- ------------------------
(1) Based on a 65% recovery rate.
In September 1993, a subsidiary of the Company acquired Soldier Creek Coal
Company and its parent, Sage Point Coal Company. This acquisition added
approximately 86 million tons of new recoverable coal reserves to Coastal's
reserve base. Substantially all of the acquired reserves satisfy the sulfur
emissions requirements of the Clean Air Act of 1990.
17
At December 31, 1993, the Company controlled approximately 871 million
recoverable tons of bituminous coal reserves. Production in 1993 from the
Company's reserves totalled 23.6 million tons of which 18.4 million tons were
produced from captive operations and 5.2 million tons were produced by lessees
under royalty agreements. In its eastern captive operations, ANR Coal contracts
with independent mine operators to mine and deliver coal to Company owned and
operated processing and loading facilities. Captive production and processing
from ANR Coal and Coastal States Energy in 1993 totalled 9.2 and 9.2 million
tons, respectively.
Captive sales from ANR Coal and Coastal States Energy were 7.2 million and
8.9 million tons, respectively, in 1993. Brokerage sales in which the Company
receives a commission on coal sold for third parties totalled 1.3 million tons
for the same period.
In 1993, approximately 70% of sales were to domestic utilities, 12% of sales
were to domestic industrial customers and 18% of sales were to export markets
primarily in Asia and Canada. Of the total 1993 tonnage sold, 12.1 million tons
(75%) were sold under long-term contracts. At December 31, 1993, the weighted
average remaining life of these contracts was 63 months.
The Company had approximately 21.2 million tons of annual production capacity
at December 31, 1993. In the eastern United States, the Company owns and
operates five coal preparation plants and nine loading facilities with a
combined annual capacity of 10.6 million tons. Coastal States Energy's mines in
Utah employ three longwall mining systems, diesel shuttle cars and have a
combined annual capacity of 10.6 million tons.
In addition to its bituminous coal operations, the Company controls
overriding royalty interests in approximately 484 million tons of lignite
reserves in North Dakota. Production from these reserves in 1993 totalled 16.1
million tons.
The Company, through its captive operations, leasing programs and brokerage
activities, participates in all aspects of the national bituminous coal industry
and is a significant competitor in international coal markets. A significant
portion of its eastern reserves and all of its Utah reserves are low-sulfur,
compliance coal which will allow the Company to remain a major supplier of steam
coal to domestic utilities under the Clean Air Act of 1990.
The Company competes with a large number of coal producers and land holding
companies across the United States. The principal factors affecting the
Company's coal sales are price, quality (BTU, sulfur and ash content), royalty
rates, employee productivity and rail freight rates.
CHEMICALS
Coastal Chem, Inc. ("Coastal Chem"), a Coastal subsidiary, operates a plant
near Cheyenne, Wyoming, which produces anhydrous ammonia, ammonium nitrate,
nitric acid, food grade liquid carbon dioxide and urea for use as agricultural
fertilizers, livestock feed supplements, blasting agents and various other
industrial applications. This plant has the capacity to produce 500 tons per day
of anhydrous ammonia, 750 tons per day of ammonium nitrate, 275 tons per day of
urea, 700 tons per day of nitric acid and 400 tons per day of food grade liquid
carbon dioxide. Coastal Chem also owns a plant at Table Rock, Wyoming, which has
a production capacity of 150 tons of liquid fertilizer per day. In addition,
Coastal Chem operates a low density ammonium nitrate ("LoDAN/(R)/") facility in
Battle Mountain, Nevada. The LoDAN/(R)/ is used primarily as a blasting agent in
surface mining. This facility produces 400 tons per day of LoDAN/(R)/.
Coastal Chem completed a urea expansion project in 1992 with full production
commencing in mid 1993. This expanded facility increased the previous capacity
of 175 tons per day to 275 tons per day. During the last six months, the
facility has operated at its designed capacity.
18
Coastal Chem commenced production from its integrated methyl tertiary butyl
ether ("MTBE") plant in 1993. MTBE is a gasoline additive which adds oxygen and
boosts octane of the blended mixture. The plant has a production capacity of
4,000 barrels per day.
Sales volumes for the three years ended December 31, 1993, are set forth
below (thousands of tons):
1993 1992 1991
---- ---- ----
Agricultural Sales....................... 222 214 238
Industrial Sales......................... 410 407 365
MTBE..................................... 119 - -
---- ---- ----
TOTAL.................................. 751 621 603
==== ==== ====
INDEPENDENT POWER PRODUCTION
Coastal Power Production Company ("Coastal Power") and certain of its
affiliates develop, operate and are equity participants in cogeneration plants
which produce and sell electricity and thermal products, including steam and
chilled water. Affiliates of Coastal Power currently own interests in four
operating cogeneration facilities in the United States.
Capitol District Energy Center Cogeneration Associates ("CDECCA") owns a
cogeneration facility with an approximate 56 megawatt capacity. An affiliate of
Coastal Power owns a 50% interest in CDECCA and is the project manager and
Coastal Technology, Inc. ("CTI"), a Coastal subsidiary, is the operator of the
plant. Electricity from the facility is sold to the local utility under a long-
term contract. Steam and chilled water produced from the plant help to serve the
thermal requirements of the City of Hartford and the plant's co-owner.
An affiliate of Coastal Power is the managing partner and 50% owner of a
combined cycle cogeneration plant at Coastal's Eagle Point, New Jersey refinery.
The plant has a permitted nameplate rating of approximately 260 megawatts and
currently operates at approximately 225 megawatts. Power from the plant is sold
to a local utility and Coastal's refinery under long-term contracts. Steam from
the plant is also sold to the refinery under long-term contract. Gas supply and
transmission is provided to the cogeneration plant by other Coastal affiliates.
CTI is the operator of the cogeneration plant.
Coastal Power and an affiliate own a gas-fired cogeneration facility in
Fulton, New York with an approximate 47 megawatt capacity. Electricity from this
project is sold under a long-term contract to a New York utility. Steam is sold
to a neighboring plant owned by a major candy manufacturer. Approximately half
of the gas supply requirements for the cogeneration plant are supplied by an
affiliate of Coastal Power. CTI is the plant operator.
Coastal, through a wholly-owned subsidiary, has a 10.9% equity interest in
the Midland Cogeneration Venture Limited Partnership, the largest gas-fired
cogeneration plant in the United States. Coastal subsidiaries supply and
transport a portion of the gas to this facility.
TRUCKING OPERATIONS
ANR Freight System, Inc. ("ANR Freight") is a regional common and contract
carrier by motor vehicle, conducting operations in both interstate and
intrastate commerce.
During 1993, ANR Freight transported approximately 1.4 million tons of
freight, consisting of both truckload shipments (10,000 pounds or more) and less
than truckload (LTL) shipments (less than 10,000 pounds) versus
19
1.3 million tons in 1992. LTL shipments comprised approximately 42% of total
tonnage hauled by ANR Freight and generated approximately 82% of its operating
revenues. As of December 31, 1993, ANR Freight operated 40 terminals and almost
4,000 trucks, tractors and trailers.
Regulatory actions by the Interstate Commerce Commission ("ICC") allowing
relatively easy entry into and expansion of the motor freight business have
tended to increase competition among motor carriers and also between motor
carriers and other modes of transportation. ANR Freight competes primarily with
other regular route motor carriers of general freight and, to a lesser extent,
with irregular route motor carriers, individual truckers and private carriers
(for truckload general freight) and with surface freight forwarders, railroads,
airlines and air freight forwarders. The extent of competition between various
modes of transportation is largely determined by their rate structures and by
the service requirements of the shippers. Over-capacity in the motor carrier
industry has increased competition for freight, and discounting programs, which
effectively reduce the rates filed with the ICC, have been adopted by many
carriers. ANR Freight continues to participate, on a limited basis, in
collective rate making within the regional rate bureaus as authorized by the
Interstate Commerce Act. ANR Freight also carries freight under contract and
under general and individually published tariff arrangements.
ANR Freight is subject to regulation by the ICC with regard to accounting.
The carriers are regulated as to rates and routes of travel by the ICC for
freight transported in interstate commerce and by state regulatory agencies for
freight transported in intrastate commerce. The Department of Transportation
regulates certain aspects of carrier operations such as the transportation of
hazardous materials, motor vehicle maintenance, motor vehicle safety devices and
appliances and driver qualifications. Various states regulate the gross weight
and length of vehicles which travel over the highways of such states.
COMPETITION
Coastal and its subsidiaries are subject to competition. In all the Company's
business segments, competition is based primarily on price with factors such as
reliability of supply, service and quality being considered.
The coal, chemicals, independent power production and trucking subsidiaries
of Coastal are engaged in highly competitive businesses against competitors,
some of which have significantly larger facilities and market share. See the
discussion of competition under "Natural Gas Systems," "Refining, Marketing and
Distribution" and "Exploration and Production" herein.
ENVIRONMENTAL
The Company's operations are subject to extensive federal, state and local
environmental laws and regulations. The Company anticipates annual capital
expenditures of $20 to $40 million over the next several years aimed at
compliance with such laws and regulations. Additionally, appropriate
governmental authorities may enforce the laws and regulations with a variety of
civil and criminal enforcement measures, including monetary penalties and
remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." Certain subsidiaries of the Company have been named as a potentially
responsible party ("PRP") in several "Superfund" waste disposal sites. At the 15
sites for which the EPA has developed sufficient information to estimate total
clean-up costs of approximately $350 million, the Company estimates its pro-rata
exposure to be paid over a period of several years is approximately $5 million
and has made appropriate provisions. At 3 other sites, the EPA is currently
unable to provide the Company with an estimate of total clean-up costs and,
accordingly, the Company is unable to calculate its share of those costs.
Finally, at 5 other sites, the Company has
20
paid amounts to other PRPs as its proportional share of associated clean-up
costs. As to these latter sites, the Company believes that its activities were
de minimis.
The following administrative proceedings and suits involve subsidiaries of
the Company:
1. In October 1993, the Bay Area Air Quality Management District brought an
administrative action against Pacific Refining Company, in which Coastal has an
indirect 50% interest. In March 1994, the parties agreed upon a structured
settlement amount of $300,000 regarding certain compliance issues relating to
the installation of a sulfur recovery unit at Pacific Refining Company's
refinery.
2. In January 1993, the State of Texas filed suit against the Corpus Christi,
Texas refinery of Coastal Refining & Marketing, Inc., a subsidiary of Coastal,
alleging failure to comply in 1992 with certain administrative orders relating
to groundwater contamination and seeking penalties in unspecified amounts. The
Company believes that this suit could result in monetary sanctions which, while
not material to the Company and its subsidiaries, could exceed $100,000.
3. In February 1993, the State of Texas filed suit against Coastal Refining &
Marketing, Inc., seeking civil penalties in unspecified amounts for alleged
public nuisance odor violations occurring in 1991 and 1992 at the Corpus Christi
refinery. In July 1993, the proceeding was amended to include a claim for excess
benzene emissions and to seek civil penalties. The Company believes that this
suit could result in monetary sanctions which, while not material to the Company
and its subsidiaries, could exceed $100,000.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. Future information and developments will require
the Company to continually reassess the expected impact of these environmental
matters. However, the Company has evaluated its total environmental exposure
based on currently available data, including its potential joint and several
liability, and believes that compliance with all applicable laws and regulations
will not have a material adverse impact on the Company's liquidity or financial
position.
ITEM 2. PROPERTIES.
Information on properties of Coastal is included in Item 1, "Business" and
certain encumbrances on its properties are described in Note 5 of the Notes to
Consolidated Financial Statements included herein.
The real property owned by the Company with regard to its subsidiary
pipelines is owned in fee and consists principally of sites for compressor and
metering stations and microwave and terminal facilities. With respect to the
subsidiary owned storage fields, the Company holds title to gas storage rights
representing ownership of, or has long-term leases on, various subsurface strata
and surface rights and also holds certain additional mineral rights. Under the
NGA, the Company and its pipeline subsidiaries may acquire by the exercise of
the right of eminent domain, through proceedings in United States District
Courts or in state courts, necessary rights-of-way to construct, operate and
maintain pipelines and necessary land or other property for compressor and other
stations and equipment necessary to the operation of pipelines. All of the
principal properties of ANR Pipeline are subject to the lien of its Mortgage and
Deed of Trust dated as of September 1, 1948, securing its First Mortgage Pipe
Line Bonds, and some of such properties are subject to "permitted liens" as
defined in such Mortgage and Deed of Trust. The First Mortgage Pipe Line Bonds
were retired in 1993 and ANR Pipeline is in the process of terminating the
associated Mortgage and Deed of Trust.
ITEM 3. LEGAL PROCEEDINGS.
In December 1992, certain of Colorado's natural gas lessors in the West
Panhandle Field filed a complaint in the U.S. District Court for the Northern
District of Texas, claiming underpayment, breach of fiduciary duty, fraud and
negligent misrepresentation. Management believes that Colorado has numerous
defenses to the lessors' claims, including (i) that the royalties were properly
paid, (ii) that the majority of the claims were released by written agreement,
and (iii) that the majority of the claims are barred by the statute of
limitations.
21
A subsidiary of Coastal has initiated a suit against TransAmerican Natural
Gas Corporation ("TransAmerican") in the District Court of Webb County, Texas,
for breach of two gas purchase agreements. In February 1993, TransAmerican filed
a Third Party Complaint and a Counterclaim in this action against Coastal and
certain subsidiaries. TransAmerican alleges breach of contract, fraud,
conspiracy, duress, tortious interference and violations of the Texas Free
Enterprises and Anti-trust Act arising out of the gas purchase agreements.
TransAmerican seeks compensatory damages, exemplary damages and attorney fees.
The trial began on March 14, 1994.
Numerous other lawsuits and other proceedings which have arisen in the
ordinary course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at this
time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position.
Additional information regarding legal proceedings is set forth in Notes 3 and
14 of the Notes to Consolidated Financial Statements included herein.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
None.
22
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
MATTERS.
The principal market on which Coastal Common Stock is traded is the New York
Stock Exchange; Coastal Common Stock is also listed on The Stock Exchange in
London, the Stock Exchanges of Dusseldorf, Frankfurt, Hamburg and Munich in
Germany and on the Amsterdam Stock Exchange. The Class A Common Stock of Coastal
is non-transferable; however, such stock is convertible share-for-share into
Coastal Common Stock. As of March 16, 1994, the approximate number of holders of
record of Common Stock was 12,550 and of the Class A Common Stock was 3,900.
The following table presents the high and low sales prices for Coastal common
shares based on the daily composite listing of transactions for New York Stock
Exchange stocks.
1993 1992
------------------------ -------------------------
Quarters High Low Dividends High Low Dividends
- ---------------- ------ ------ --------- ------ ------ ---------
First Quarter $27.38 $23.50 .10 $26.25 $22.00 .10
Second Quarter 28.50 25.63 .10 29.00 22.13 .10
Third Quarter 31.38 25.63 .10 30.00 24.00 .10
Fourth Quarter 29.50 26.13 .10 30.00 23.13 .10
Coastal expects to continue paying dividends in the future. Dividends of $.09
per share were paid on the Class A Common Stock for each quarterly period in
1993 and 1992. At December 31, 1993, under the most restrictive of its financing
agreements, the Company was prohibited from paying dividends and distributions
on its Common Stock, Class A Common Stock and preferred stocks in excess of
approximately $409.9 million.
23
ITEM 6. SELECTED FINANCIAL DATA.
The following selected financial data (in millions of dollars except per
share amounts) is derived from the Consolidated Financial Statements included
herein and Item 6 of the Company's Annual Report on Form 10-K for the fiscal
year ended December 31, 1992. The Notes to Consolidated Financial Statements
included herein contain other information relating to this data.
Year Ended December 31,
---------------------------------------------------
1993 1992 1991 1990 1989
--------- ---------- -------- -------- --------
Operating revenues $10,136.1 $10,062.9 $ 9,554.8 $ 9,613.8 $8,747.5
Earnings (loss) before extraordinary item 118.3 (126.8) 8.7 264.2 218.9
Net earnings (loss) 115.8 (126.8) 8.7 264.2 218.9
Earnings (loss) per common and common
equivalent share before extraordinary
item 1.02 (1.23) .08 2.52 2.33
Net earnings (loss) per common and
common equivalent share 1.00 (1.23) .08 2.52 2.33
Cash dividends per common share* .40 .40 .40 .40 .30
Total assets 10,227.1 10,579.8 10,520.3 10,399.8 9,938.0
Debt, excluding current maturities 3,812.5 4,306.1 3,865.6 3,438.8 3,250.9
Mandatory redemption preferred stock,
excluding current maturities 26.6 36.7 49.2 65.1 78.6
* In addition, cash dividends of $.36, $.36, $.36 and $.18, respectively, were
paid on the Company's Class A Common Stock in 1993, 1992, 1991 and 1990.
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS.
The Management's Discussion and Analysis of Financial Condition and Results
of Operations is presented on pages F-1 through F-7 hereof.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
The Financial Statements and Supplementary Data required hereunder are
included in this Annual Report as set forth in Item 14(a) hereof.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
24
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT.
The information called for by this Item with respect to the directors is
set forth under "Election of Directors" and "Information Regarding Directors" in
the Coastal Proxy Statement for the May 5, 1994 Annual Meeting of Stockholders
filed pursuant to Regulation 14A under the Securities Exchange Act of
1934, and is incorporated herein by reference.
The executive officers of the Registrant as of March 16, 1994, were as
follows:
NAME (AGE), YEAR FIRST
ELECTED AN OFFICER POSITIONS AND OFFICES WITH THE REGISTRANT
---------------------- -----------------------------------------
O. S. Wyatt, Jr. (69), 1955 Chairman of the Board of Directors and Chief
Executive Officer
David A. Arledge (49), 1982 President, Chief Operating Officer, Chief
Financial Officer and Director
Harold Burrow (79), 1974 Vice Chairman of the Board of Directors,
Chairman of the Board of Directors of Colorado
James F. Cordes (53), 1985 Executive Vice President and Director
James A. King (54), 1992 Executive Vice President
Sam F. Willson, Jr. (64), 1974 Executive Vice President
Jerry D. Bullock (64), 1992 Senior Vice President
Jeffrey A. Connelly (47), 1988 Senior Vice President and Treasurer
Carl A. Corrallo (50), 1993 Senior Vice President and General Counsel
Donald H. Gullquist (50), 1994 Senior Vice President
Coby C. Hesse (46), 1986 Senior Vice President and Controller
Dan J. Hill (53), 1978 Senior Vice President
Jose J. Iglesias (48), 1992 Senior Vice President
Kenneth O. Johnson (73), 1978 Senior Vice President and Director
Austin M. O'Toole (58), 1974 Senior Vice President and Secretary
Jack C. Pester (59), 1987 Senior Vice President
James L. Van Lanen (49), 1985 Senior Vice President
M. Truman Arnold (65), 1993 Vice President
Daniel F. Collins (52), 1989 Vice President
Robert C. Hart (49), 1994 Vice President
Robert G. Holsclaw (59), 1983 Vice President
Charles M. Oglesby (41), 1991 Vice President
M. Frank Powell (43), 1993 Vice President
E. C. Simpson (58), 1990 Vice President
The above named persons bear no family relationship to each other. Their
respective terms of office expire coincident with the officer elections at the
Annual Board of Directors' meeting which follows Coastal's Annual Meeting of
Stockholders. Each of the officers named above have been officers of Coastal,
ANR Pipeline and/or Colorado for five years or more with the following
exceptions:
Mr. Arnold was elected Vice President of Coastal in August 1993. He has been
a Vice President of Coastal States Management Corporation, a subsidiary of
Coastal, since 1977.
Mr. Bullock was elected Senior Vice President of Coastal in August 1992. From
1987 to 1990, he was an Executive Vice President of British Petroleum's BP
Exploration Company and a director and a member of the
25
management committee of BP Exploration USA. From 1990 to 1992, he was an
independent petroleum consultant for several major exploration companies.
Mr. Corrallo was elected Senior Vice President and General Counsel of Coastal
in March 1993. He has served as a Senior Vice President of Coastal States
Management Corporation, a subsidiary of Coastal, since August 1991 and prior
thereto as Vice President since December 1986.
Mr. Gullquist was elected Senior Vice President of Coastal in March 1994.
From 1988 to 1989 he served as Vice President, Finance at Enron Corporation;
from 1989 to 1990 he served as president of Enron Finance Corporation.
Mr. Hart was elected Vice President of Coastal in March 1994. From 1989
through 1994, he was president of Hart Associates, Inc., an energy development
firm.
Mr. Iglesias was elected a Senior Vice President of Coastal in January 1992.
He was president of Mobile Bay Refining Company from 1982 to 1987 and of Mo-Bel
Corporation from 1987 to 1990.
Mr. King was elected Executive Vice President of Coastal in May 1992. From
1987 to 1990, he was Senior Vice President of refining, supply and
transportation for Crown Central Petroleum Corporation.
Mr. Oglesby was elected a Vice President of Coastal in August 1991. He served
as an Executive Vice President of Colorado and ANR Pipeline from January 1988 to
May 1993. He was Senior Vice President for Marketing and Transportation of
Valero Transmission Company from 1985 to 1987.
Mr. Powell was elected Vice President of Coastal and Senior Vice President of
Coastal States Management Corporation in August 1993. From 1984 to 1993 he was
in private law practice with the law firms of Powell, Popp & Ikard and Powell &
Associates representing Coastal and other corporations. Prior thereto he was
employed at Coastal since 1978.
Mr. Simpson was elected a Vice President of Coastal in April 1990 and of
Colorado in May 1990. He has been a Vice President of Coastal States Management
Corporation, a subsidiary of Coastal, for the past ten years.
ITEM 11. EXECUTIVE COMPENSATION.
The information called for by this item is set forth under "Executive
Compensation" in the Coastal Proxy Statement for the May 5, 1994 Annual Meeting
of Stockholders filed pursuant to Regulation 14A under the Securities Exchange
Act of 1934, and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information called for by this item is set forth under "Stock Ownership,"
"Election of Directors" and "Information Regarding Directors" in the Coastal
Proxy Statement for the May 5, 1994 Annual Meeting of Stockholders filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, and is
incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
The information called for by this item is set forth under "Election of
Directors," "Transactions with Management and Others" and "Certain Business
Relationships" in the Coastal Proxy Statement for the May 5, 1994 Annual Meeting
of Stockholders filed pursuant to Regulation 14A under the Securities Exchange
Act of 1934, and is incorporated herein by reference.
26
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K.
(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:
1. Financial Statements and Supplemental Information.
The following Consolidated Financial Statements of Coastal and
Subsidiaries and Supplemental Information are included in response to Item
8 hereof on the attached pages as indicated:
Page
----
Independent Auditors' Report.................... F-8
Statement of Consolidated Operations for
the years ended December 31, 1993, 1992
and 1991....................................... F-9
Consolidated Balance Sheet at December 31, 1993
and 1992 ...................................... F-10
Statement of Consolidated Cash Flows for the
years ended December 31, 1993, 1992 and 1991 F-12
Statement of Consolidated Common Stock and .....
Other Stockholders' Equity for the years ended
December 31, 1993, 1992 and 1991............... F-13
Notes to Consolidated Financial Statements...... F-14
Supplemental Information on Oil & Gas
Producing Activities (Unaudited)............... F-32
Supplemental Statistics for Coal Mining
Operations (Unaudited) ........................ F-36
2. Financial Statement Schedules.
The following schedules of Coastal and Subsidiaries are included on the
attached pages as indicated:
Page
----
Schedule III Condensed Financial Information of the Registrant.......... S-1
Schedule V Property, Plant and Equipment.............................. S-6
Schedule VI Accumulated Depreciation, Depletion and Amortization of
Property, Plant and Equipment............................ S-8
Schedule VIII Valuation and Qualifying Accounts.......................... S-9
Schedule IX Short-Term Borrowings...................................... S-10
Schedule X Supplementary Income Statement Information................. S-11
Schedules other than those referred to above are omitted as not applicable or
not required, or the required information is shown in the Consolidated Financial
Statements or Notes thereto.
3. Exhibits.
3.1+ Restated Certificate of Incorporation of Coastal, as restated on
March 22, 1994. (Filed as Module TCC-Artl-Incorp on March 28, 1994).
3.2+ By-Laws of Coastal, as amended on January 16, 1990 (Exhibit 3.4 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1989).
4 (With respect to instruments defining the rights of holders of long-
term debt, the Registrant will furnish to the Commission, on request,
any such documents).
10.1+ The Coastal Corporation Stock Option Plan (Exhibit 10.1 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1980).
27
10.2+ Employment Agreement between Coastal States Gas Corporation and Sam
F. Willson, Jr., dated December 1, 1979 (Exhibit 10.41 to Coastal's
Annual Report on Form 10-K for the fiscal year ended December 31,
1980).
10.3+ First Amendment of The Coastal Corporation Stock Option Plan, dated
September 3, 1981 (Exhibit 10.11 to Coastal's Annual Report on Form
10-K for the fiscal year ended December 31, 1982).
10.4+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement for
the 1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.5+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement for
the 1986 Annual Meeting of Stockholders, dated March 27, 1986).
10.6+ The Coastal Corporation Performance Unit Plan effective as of
January 1, 1987 (Exhibit 10.5 to Coastal's Annual Report on Form 10-K
for the fiscal year ended December 31, 1987).
10.7+ The Coastal Corporation Replacement Pension Plan effective as of
November 1, 1987 (Exhibit 10.6 to Coastal's Annual Report on Form 10-K
for the fiscal year ended December 31, 1987).
10.8+ Description of Coastal's Key Employees Bonus Plan (Exhibit 10.7 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1987).
10.9+ The Coastal Corporation Stock Purchase Plan, as restated on January
1, 1994 (Appendix B to Coastal's Proxy Statement for the 1994 Annual
Meeting of Stockholders dated March 29, 1994).
10.10+ The Coastal Corporation Stock Grant Plan, effective December 1,
1988 (Exhibit 10.12 to Coastal's Annual Report on Form 10-K for the
fiscal year ended December 31, 1988).
10.11+ The Coastal Corporation Deferred Compensation Plan for Directors
(Exhibit 10.13 to Coastal's Annual Report on Form 10-K for the fiscal
year ended December 31, 1988).
10.12+ The Coastal Corporation 1990 Stock Option Plan (Exhibit 10.13 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1989).
10.13+ Employment Agreement between The Coastal Corporation and James F.
Cordes dated April 12, 1990 (Exhibit 10.13 to Coastal's Annual Report
on Form 10-K for the fiscal year ended December 31, 1990).
10.14* The Coastal Corporation Deferred Compensation Plan.
10.15+ The Coastal Corporation 1994 Incentive Stock Plan (Appendix A to
Coastal's Proxy Statement for the 1994 Annual Meeting of Stockholders
dated March 29, 1994).
10.16* Pension Plan for Employees of The Coastal Corporation as of January 1,
1993, includes Plan as Restated as of January 1, 1989 and First
Amendment dated July 27, 1992, Second Amendment dated December 9, 1992,
Third Amendment dated October 29, 1993.
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23.1* Consent of Deloitte & Touche.
24* Powers of Attorney (included on signature pages herein).
28
99+ Indemnity Agreement revised and updated as of April, 1988 (Exhibit 28
to Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1990).
_________________________
Note:
+ Indicates documents incorporated by reference from the prior filing
indicated.
* Indicates documents filed herewith.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the quarter ended December 31, 1993.
29
POWERS OF ATTORNEY
Each person whose signature appears below hereby appoints David A. Arledge,
Coby C. Hesse and Austin M. O'Toole and each of them, any one of whom may act
without the joinder of the others, as his attorney-in-fact to sign on his behalf
and in the capacity stated below and to file all amendments to this Annual
Report on Form 10-K, which amendment or amendments may make such changes and
additions thereto as such attorney-in-fact may deem necessary or appropriate.
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.
THE COASTAL CORPORATION
(Registrant)
By: DAVID A ARLEDGE
--------------------
David A. Arledge
President
March 29, 1994
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
By: O. S. WYATT, JR.
---------------------
O. S. Wyatt, Jr.
Chairman of the Board and Chief Executive Officer
March 29, 1994
By: DAVID A. ARLEDGE
----------------------
David A. Arledge
Principal Financial Officer and Director
March 29, 1994
By: COBY C. HESSE
---------------------
Coby C. Hesse
Principal Accounting Officer
March 29, 1994
By: JOHN M. BISSELL
---------------------
John M. Bissell
Director
March 29, 1994
* * *
30
By: GEORGE L. BRUNDRETT, JR. By: KENNETH O. JOHNSON
---------------------------- ---------------------------
George L. Brundrett, Jr. Kenneth O. Johnson
Director Director
March 29, 1994 March 29, 1994
By: ERVIN O. BUCK By: JEROME S. KATZIN
---------------------------- ---------------------------
Ervin O. Buck Jerome S. Katzin
Director Director
March 29, 1994 March 29, 1994
By: HAROLD BURROW By: THOMAS R. McDADE
---------------------------- ---------------------------
Harold Burrow Thomas R. McDade
Director Director
March 29, 1994 March 29, 1994
By: ROY D. CHAPIN, JR. By: J. HOWARD MARSHALL, II
---------------------------- ---------------------------
Roy D. Chapin, Jr. J. Howard Marshall, II
Director Director
March 29, 1994 March 29, 1994
By: JAMES F. CORDES By: L. D. WOODDY, JR.
---------------------------- ---------------------------
James F. Cordes L. D. Wooddy, Jr.
Director Director
March 29, 1994 March 29, 1994
By: ROY L. GATES
----------------------------
Roy L. Gates
Director
March 29, 1994
31
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
The Notes to Consolidated Financial Statements contain information that is
pertinent to the following analysis.
LIQUIDITY AND CAPITAL RESOURCES
The Company uses the following consolidated ratios to measure liquidity and
ability to meet future funding needs and debt service requirements.
1993 1992 1991
----- ------ -----
Net return on average common stockholders' equity...... 5.2% (6.0%) .4%
Cash flow from operating activities to long-term debt.. 21.2% 10.1% 12.8%
Total debt to total capitalization..................... 64.3% 69.3% 66.6%
Times interest earned (before tax)..................... 1.4 .6 1.0
The changes in the ratio of net return on average common stockholders' equity
can be attributed primarily to changes in earnings, as earnings increased in
1993 and decreased in 1992. The 1993 increase in the cash flow from operating
activities to long-term debt ratio resulted from increased cash flow from
operations and reduced long-term debt, while the 1992 decrease can be attributed
to decreased cash flow from operations and increased long-term debt. The total
debt to total capitalization ratio improved in 1993 as debt was paid down while
equity was increased through retained earnings and stock issuances. The 1992
increase was due to increased debt and reduced equity. The 1993 increase in the
times interest earned ratio resulted from increased earnings and reduced
interest expense; while the 1992 decrease resulted from decreased earnings and
increased interest expense.
Cash flows provided from operating activities were $809.8 million in 1993 and
$434.2 million in 1992. The 1993 increase can be attributed to increased
earnings and a reduction in inventories and other working capital requirements.
Capital expenditures amounted to $392.7 million in 1993 and $573.5 million in
1992. The Company, which had emphasized its capital expansion program in 1992
and 1991 in order to expand its earnings base, returned to a lower level of
capital spending in 1993, as it emphasized debt reduction. Prepayments for gas
supply and payments for settlement of natural gas contract disputes required
investments of $11.4 million and $43.8 million in 1993 and 1992, respectively.
The Company was able to reduce total debt by $471.3 million in 1993 primarily
by the use of internally generated funds and $193.5 million of proceeds
resulting from the issuance of preferred stock in April 1993. Dividend payments
increased by $11.0 million as a result of the new preferred stock issue.
Capital expenditures for 1994, including the Company's equity investments in
partnerships and joint ventures, are currently budgeted at approximately $500.0
million. These expenditures are primarily for completion of projects in process,
operational necessities, environmental requirements, expansion projects and
increased efficiency. Other expansion opportunities will continue to be
evaluated.
Financing for budgeted expenditures and mandatory debt retirements in 1994
will be accomplished by the use of internally generated funds, existing credit
lines and new financings.
Funding for certain proposed natural gas pipeline projects is anticipated to
be provided through non-recourse project financings in which the projects'
assets and contracts will be pledged as collateral. Equity participation by
other entities will also be considered. To the extent required, cash for equity
contributions to projects will be from general corporate funds.
F-1
On September 23, 1993, ANR Pipeline filed a shelf registration statement with
the Securities and Exchange Commission for the public offering of up to $200
million in senior unsecured debt securities which became effective October 5,
1993. In February 1994, ANR Pipeline completed an offering of $125.0 million of
7-3/8% Debentures due in 2024. The net proceeds from the sale will be used for
capital expenditures and for other general corporate purposes.
Unused lines of credit at December 31, 1993, were as follows (millions of
dollars):
Short-term............................ $413.0
Long-term............................. 544.6
------
$957.6
======
Credit agreements of certain subsidiaries contain covenants which limit the
making of advances to affiliates and payment of dividends. Where applicable,
restrictions are generally in the form of computed capacities with respect to
advances and the payment of dividends. At December 31, 1993, net assets of
consolidated subsidiaries amounted to approximately $5.1 billion, of which
approximately $1.7 billion was restricted. These provisions have not and are not
expected to have any meaningful impact on the ability of the Company to meet its
cash obligations.
In 1994, the Company adopted Statement of Financial Accounting Standards
("FAS") No. 112, "Employer's Accounting for Postemployment Benefits." This
standard covers the accounting for estimated costs of benefits provided to
former or inactive employees before their retirement. The implementation of this
new standard is not expected to have a significant effect on the Company's
results of operations or financial position.
In 1993, the Company adopted changes in accounting for post-retirement
benefits as required by FAS No. 106, "Employer's Accounting for Postretirement
Benefits Other Than Pensions." See Note 11 in the Notes to Consolidated
Financial Statements.
The Company's operations are subject to extensive federal, state and local
environmental laws and regulations. The Company anticipates annual capital
expenditures of $20 to $40 million over the next several years aimed at
compliance with such laws and regulations. Additionally, appropriate
governmental authorities may enforce the laws and regulations with a variety of
civil and criminal enforcement measures, including monetary penalties and
remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." Certain subsidiaries of the Company have been named as a potentially
responsible party ("PRP") in several "Superfund" waste disposal sites. At the 15
sites for which the Environmental Protection Agency ("EPA") has developed
sufficient information to estimate total clean-up costs of approximately $350
million, the Company estimates its pro-rata exposure to be paid over a period of
several years is approximately $5 million, and has made appropriate provisions.
At three other sites, EPA is currently unable to provide the Company with an
estimate of total clean-up costs and, accordingly, the Company is unable to
calculate its share of those costs. Finally, at five other sites, the Company
has paid amounts to other PRPs as its proportional share of associated clean-up
costs. As to these latter sites, the Company believes that its activities were
de minimis.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. Future information and developments will require
the Company to continually reassess the expected impact of these environmental
matters. However, the Company has evaluated its total environmental exposure
based on currently available data, including its potential joint and several
liability, and believes that compliance with all applicable laws and regulations
will not have a material adverse impact on the Company's liquidity or financial
position.
RESULTS OF OPERATIONS
The Company operates principally in the following lines of business: natural
gas, refining and marketing, exploration and production, and coal.
F-2
NATURAL GAS. Natural gas operations involve the production, purchase,
gathering, storage, transportation and sale of natural gas, principally to
utilities, industrial customers and other pipelines, and include the operations
of natural gas liquids extraction plants.
In the fourth quarter of 1993, ANR Pipeline Company and Colorado Interstate
Gas Company ("CIG") placed their Order 636 (See Note 14 in the Notes to
Consolidated Financial Statements) service structures into effect and now offer
an array of unbundled transportation, storage and balancing service options.
Under Order 636, the interstate pipeline companies will no longer offer sales
for resale services, with the exception of certain gas sales services provided
by CIG, which are being phased out over a three-year period. Former gas sales
customers of the interstate pipelines have largely retained their firm storage
and transportation services levels. These services were previously contracted as
part of bundled sales services. Consequently, while operating revenues will be
reduced as a result of the implementation of Order 636, purchases and other
related costs will be reduced by a similar amount.
Millions of Dollars
---------------------------------------
1993 1992 1991
--------------- -------- --------
Operating revenues........................ $3,247.9 $2,746.8 $2,405.5
Depreciation, depletion and amortization.. 145.4 187.1 177.0
Operating profit.......................... 405.2 403.1 402.2
Total throughput volume (Bcf)............. 1,908 1,885 1,878
1993 Versus 1992. The increase in operating revenues of $501 million can be
attributed to increased sales volumes for the interstate pipelines and gas
marketing companies, higher prices for the gas marketing companies, and
increased storage and transportation revenues. Decreased gas sales prices for
the interstate pipelines partially offset the increase. Total throughput volumes
for the interstate pipelines increased by approximately 1%, while the volume for
the gas marketing companies increased by 10%.
Purchases increased $529 million over 1992, primarily due to volume increases
for the interstate pipelines and gas marketing companies and cost of gas
increases for the gas marketing companies, resulting in a reduction in the gross
profit of $28 million.
The operating profit increase of $2 million results from increased sales
volumes of $7 million; higher storage and transportation revenues of $137
million; and reduced depreciation, depletion and amortization of $41 million
offset by lower margins of $166 million, increased operating expenses of $11
million and other decreases of $6 million. The primary factor contributing to
the increase in storage and transportation revenues and the decrease in margins
is the restructuring of pipeline bundled sales services into separate service
components, as required by changing regulations. The depreciation, depletion and
amortization decrease of $41 million results from lower pipeline rates for ANR
Pipeline due to a settlement with the FERC.
1992 Versus 1991. Operating revenues increased in 1992 as a result of
increased sales volumes for the interstate pipelines and gas marketing
companies, higher prices for the gas marketing companies, increased storage and
transportation revenues and the benefit from resolution of outstanding rate
matters and litigation. Decreased gas sales prices for the interstate pipelines
partially offset the increase.
Purchases increased by $267 million in 1992, primarily due to volume
increases for interstate pipelines and gas marketing companies and higher costs
for the gas marketing companies, resulting in a gross profit increase of $74
million.
The operating profit increase of $1 million results from increased sales
volumes of $14 million, improved storage and transportation revenues of $37
million and other increases of $21 million which were partially offset by lower
margins of $32 million, increased operating expenses of $29 million and
increased depreciation, depletion and amortization of $10 million. The other
increases are primarily due to the settlement of outstanding rate matters and
litigation. The sales volumes were up and the margins were down for both the
interstate pipeline companies and gas marketing companies. The storage and
transportation revenue increase results from increased transportation volumes
F-3
and improved storage revenues. The operating expense increase results from
increases for compressor fuel, gas and gas liquids handling charges and rate
settlement related expenses. The depreciation, depletion and amortization
increase results from a non-recurring 1991 retroactive adjustment related to
Wyoming Interstate Company, Ltd.
REFINING AND MARKETING. Refining and marketing operations involve the
purchase, transportation and sale of refined products, crude oil, condensate and
natural gas liquids; the operation of refining and chemical plants; the sale at
retail of gasoline, petroleum products and convenience items; petroleum product
terminaling and marketing of crude oil and refined petroleum products worldwide.
Millions of Dollars
--------------------------------
1993 1992 1991
---------- --------- ---------
Operating revenues........................ $6,200.9 $6,561.1 $6,297.6
Depreciation, depletion and amortization.. 45.6 98.1 40.3
Operating profit (loss)................... 98.0 (192.1) (99.3)
Refined product sales (MM Bbls)........... 294 316 283
1993 Versus 1992. The decrease in operating revenues of $360 million results
from decreased sales prices and lower volumes. Sales volumes decreased primarily
due to a reduction in the sales of products purchased from others. In addition,
crude processing was suspended at the Company's three refineries in Kansas
during 1993.
Purchases for the refining and marketing segment decreased by $550 million, a
result of lower costs and volumes, and increased emphasis on hedging activities
to minimize the impact of price volatility. This resulted in an increased gross
profit of $190 million. Increased margins of $187 million, increased revenues
from marine operations of $4 million and other increases of $8 million, which
were partially offset by reduced volumes of $9 million, make up the gross profit
increase. A portion of the margin increase can be attributed to the Company
concentrating on marketing higher margin, value-added products and services. The
Company eliminated almost 50 marginal third party locations from its
distribution system in 1993. These steps also added to the volume decline in
1993.
The operating profit increase of $290 million results from the improved gross
profit of $190 million, reduced operating expenses of $47 million and lower
depreciation, depletion and amortization of $53 million. The reduction in
operating expenses results from the suspension of crude oil processing at the
Company's refineries in Kansas and the nonrecurrence of the related $35 million
restructuring charge in 1992. Partially offsetting these decreases were
increased expenses for new foreign operations. Depreciation, depletion and
amortization decreased as a result of a 1992 restructuring charge of $50 million
not recurring.
1992 Versus 1991. The increase in 1992 operating revenues of $264 million can
be attributed to increased volumes, primarily for the terminal and marketing
operations, which were partially offset by decreased prices and reduced marine
revenues. The lower prices affected all areas of the segment's operations.
Purchases for the segment increased by $185 million, a result of increased
volumes and lower costs, resulting in a gross profit increase of $79 million.
This $79 million gross profit increase results from volume increases of $84
million and margin increases of $37 million being partially offset by lower
marine revenues of $17 million, reduced gross profit from the sale, trading and
exchanging of third-party products of $12 million and other decreases of $13
million.
The operating profit decrease of $93 million results from increased operating
expenses of $114 million and increased depreciation, depletion and amortization
of $58 million more than offsetting the increased gross profit of $79 million.
The increased operating expenses are attributable to charges for restructuring
and increased maintenance costs. Depreciation, depletion and amortization
increased primarily from a $50 million charge for the restructuring of certain
refining assets.
F-4
EXPLORATION AND PRODUCTION. Exploration and production operations involve
the exploration, development and production of natural gas, crude oil,
condensate and natural gas liquids. The segment also includes related intrastate
natural gas marketing activities and gas plant processing operations.
Millions of Dollars
--------------------------
1993 1992 1991
-------- ------- -------
Operating revenues........................................ $ 357.3 $ 310.0 $ 327.6
Depreciation, depletion and amortization.................. 109.1 83.2 69.4
Operating profit.......................................... 49.9 45.8 45.2
Natural gas production (MMcf/d)........................... 207 147 119
Oil, condensate and natural gas liquids production (bpd).. 13,534 13,002 11,202
Average sales price-net of production taxes (dollars):
Gas (per Mcf)............................................ $ 1.93 $ 1.76 $ 1.67
Oil, condensate and natural gas liquids (per bbl)........ 15.26 17.33 18.83
1993 Versus 1992. The increase in operating revenues of $47 million can be
attributed to increased sales volumes for all products and increased natural gas
prices being partially offset by lower prices for oil, condensate and natural
gas liquids. Natural gas revenue increases of $51 million were partially offset
by decreases for oil, condensate and natural gas liquids of $3 million and other
of $1 million.
The operating profit increase of $4 million results from increased volumes
for all products of $48 million and natural gas price increases of $13 million
being offset by reduced prices for crude oil, condensate and natural gas liquids
of $13 million, increased operating expenses of $15 million, increased
depreciation, depletion and amortization of $26 million and other of $3 million.
The increase in operating expenses results from additional wells in operation
and higher costs associated with operating natural gas plants. Depreciation,
depletion and amortization increased as a result of an increase in volumes.
1992 Versus 1991. Operating revenues decreased in 1992 as reduced revenues
from gas brokerage, lower prices for crude oil, condensate and plant products
and decreased other income were partially offset by increased natural gas prices
and increased volumes for all products. The decrease in other income is due to
the sale in 1991 of two gathering systems.
The operating profit increase for the segment resulted from increased volumes
for all products of $31 million and increased natural gas prices of $5 million
being partially offset by lower prices for oil, condensate and natural gas
liquids of $10 million; increased depreciation, depletion and amortization of
$14 million; reduced revenue from gas brokerage of $2 million and other
decreases of $9 million. Included in the other decreases are non-recurring gains
of $7 million from 1991 property sales. The increase in depreciation, depletion
and amortization can be attributed to increased volumes.
COAL. Coal operations include mining, processing and marketing of coal from
Company-owned reserves and from other sources, and the brokering of coal for
others.
Millions of Dollars
------------------------
1993 1992 1991
-------- ------ ------
Operating revenues............................. $443.2 $447.4 $465.2
Depreciation, depletion and amortization....... 28.5 28.4 27.1
Operating profit............................... 95.1 92.8 91.8
Captive and brokered sales (millions of tons).. 17.4 16.9 16.6
F-5
1993 Versus 1992. The decrease in coal revenues results from decreased prices
more than offsetting increased volumes sold and brokered. The purchase of the
Soldier Creek Mine in late 1993 added 600,000 tons/year of new capacity.
The operating profit increase results from increased volumes of $13 million,
reduced operating expenses of $6 million and other of $1 million more than
offsetting lower prices of $18 million. Operating expenses were reduced by
expanding the percentage of overall production from the lower-cost Utah
operations.
1992 Versus 1991. The decrease in operating revenues is a result of decreased
sales volumes and lower prices. The tonnage, excluding brokerage, decreased
approximately 1%. Sales prices decreased at all mines.
Operating profit increased in 1992 as decreases for coal costs and operating
expenses of $20 million more than offset reduced revenues of $18 million and
increased depreciation, depletion and amortization of $1 million. The decrease
for coal costs and operating expenses results from lower volumes sold and more
efficient operations.
OTHER. Other operations involve trucking, power production operations and
other activities.
Millions of Dollars
--------------------------
1993 1992 1991
-------- ------- -------
Operating revenues........................ $187.0 $196.3 $169.6
Depreciation, depletion and amortization.. 7.9 7.6 7.1
Operating loss............................ (12.8) (19.7) (4.3)
1993 Versus 1992. The $9 million reduction in operating revenues results from
volume decreases for the trucking operations and lower cogeneration revenues.
The $7 million decrease in operating loss results from reduced operating
expenses of $16 million, primarily for the trucking operations, exceeding the
revenue decline; as trucking operations increased by $11 million offset by a $4
million decrease for the other operations. The decreased operating expenses
result from reduced wages and lower rent expense.
1992 Versus 1991. The $27 million increase in 1992 in operating revenues can
be attributed to volume increases for the trucking operations and increased
cogeneration revenues. The operating loss increase of $15 million results from a
$19 million increased loss for trucking partially offset by a $4 million income
increase for other operations, as increased operating expenses more than offset
improved revenues. The increased operating expenses of $41 million are a result
of increased freight volumes and increased cogeneration activities.
OTHER INCOME - NET
1993 Versus 1992. Other income-net increased by $53 million in 1993 due to
increased equity income from unconsolidated subsidiaries of $8 million,
nonrecurrence of the 1992 writedown of refining investments and other assets of
$43 million and other increases of $2 million.
1992 Versus 1991. Other income-net decreased by $43 million in 1992 as a
result of decreased gains from sales of investments of $13 million, the
writedown of refining investments and other assets in 1992 of $43 million,
reduced dividend and interest income of $6 million and other decreases of $18
million offset by increased equity income from unconsolidated subsidiaries of
$37 million.
INTEREST AND DEBT EXPENSE
1993 Versus 1992. Interest and debt expense decreased by $43 million in 1993,
primarily as a result of lower average debt outstanding and lower interest rates
more than offsetting reduced capitalized interest and other financial costs. At
December 31, 1993, after giving effect to interest rate swaps, approximately 16%
of the Company's debt was tied to money market-related rates.
F-6
1992 Versus 1991. Interest and debt expense increased by $47 million in 1992,
primarily as a result of higher average debt outstanding and reduced capitalized
interest more than offsetting lower average interest rates and reduced interest
on pipeline customer refunds.
TAXES ON INCOME
Income taxes fluctuated primarily as a result of changing levels of income
before taxes and changes in the effective federal income tax rate. The 1993
taxes include a $29 million charge for the cumulative effect of adjusting the
deferred federal income tax liability to reflect the change in the corporate
federal income tax rate from 34% to 35%.
EXTRAORDINARY ITEM
The extraordinary loss, net of income taxes, resulted from the early
retirement of debt. See Note 13 in the Notes to Consolidated Financial
Statements.
F-7
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
The Coastal Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of The Coastal
Corporation and subsidiaries as of December 31, 1993 and 1992, and the related
consolidated statements of operations, common stock and other stockholders'
equity and cash flows for each of the three years in the period ended December
31, 1993. Our audits also included the financial statement schedules listed in
the Index at Item 14(a)2. These financial statements and financial statement
schedules are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and financial statement
schedules based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all
material respects, the financial position of The Coastal Corporation and
subsidiaries as of December 31, 1993 and 1992, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1993 in conformity with generally accepted accounting principles.
Also, in our opinion, such financial statement schedules, when considered in
relation to the basic consolidated financial statements taken as a whole,
present fairly in all material respects the information set forth therein.
As discussed in Note 11 to the consolidated financial statements, in 1993 the
Company changed its method of accounting for postretirement benefits other than
pensions to conform with Statement of Financial Accounting Standards No. 106.
DELOITTE & TOUCHE
Houston, Texas
February 3, 1994
F-8
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars Except Per Share)
Year Ended December 31,
---------------------------------
1993 1992 1991
---------- ---------- ---------
OPERATING REVENUES........................................ $10,136.1 $10,062.9 $9,554.8
--------- --------- --------
OPERATING COSTS AND EXPENSES
Purchases................................................ 7,338.1 7,458.0 7,129.3
Operating expenses....................................... 1,806.9 1,851.5 1,650.0
Depreciation, depletion and amortization................. 355.7 423.5 339.9
--------- --------- --------
9,500.7 9,733.0 9,119.2
--------- --------- --------
OPERATING PROFIT.......................................... 635.4 329.9 435.6
--------- --------- --------
OTHER INCOME-NET.......................................... 68.9 15.4 58.5
--------- --------- --------
OTHER EXPENSES (BENEFITS)
General and administrative............................... 60.1 58.6 57.4
Interest and debt expense................................ 442.5 485.2 437.8
Taxes on income.......................................... 83.4 (71.7) (9.8)
--------- --------- --------
586.0 472.1 485.4
--------- --------- --------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM................. 118.3 (126.8) 8.7
Extraordinary item-loss on early extinguishment of debt.. (2.5) - -
--------- --------- --------
NET EARNINGS (LOSS)....................................... 115.8 (126.8) 8.7
DIVIDENDS ON PREFERRED STOCK.............................. 11.3 .5 .5
--------- --------- --------
NET EARNINGS (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS...................................... $ 104.5 $ (127.3) $ 8.2
========= ========= ========
EARNINGS (LOSS) PER SHARE
Before extraordinary item................................ $ 1.02 $ (1.23) $ .08
Extraordinary item....................................... (.02) - -
--------- --------- --------
NET EARNINGS (LOSS) PER COMMON AND
COMMON EQUIVALENT SHARE.................................. $ 1.00 $ (1.23) $ .08
========= ========= ========
See Notes to Consolidated Financial Statements
F-9
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
December 31,
--------------------
1993 1992
--------- ---------
ASSETS
CURRENT ASSETS
Cash and cash equivalents............................. $ 159.2 $ 43.5
Receivables, less allowance for doubtful accounts
$16.1 million (1993) and $16.5 million (1992)........ 1,284.9 1,562.4
Inventories........................................... 992.2 1,252.7
Prepaid expenses and other............................ 137.3 169.3
--------- ---------
Total Current Assets................................. 2,573.6 3,027.9
--------- ---------
PROPERTY, PLANT AND EQUIPMENT-AT COST
Natural gas systems................................... 5,461.6 5,393.1
Refining, crude oil and chemical facilities........... 1,821.3 1,697.2
Gas and oil properties-at full-cost................... 1,204.2 1,194.1
Other................................................. 677.0 633.1
--------- ---------
9,164.1 8,917.5
Accumulated depreciation, depletion and amortization.. 3,216.0 2,981.7
--------- ---------
5,948.1 5,935.8
--------- ---------
OTHER ASSETS
Goodwill.............................................. 563.3 582.2
Investments-equity method............................. 424.7 330.2
Other................................................. 717.4 703.7
--------- ---------
1,705.4 1,616.1
--------- ---------
$10,227.1 $10,579.8
========= =========
See Notes to Consolidated Financial Statements
F-10
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
December 31,
--------------------
1993 1992
--------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable and preferred stock redeemable within one year............... $ 271.7 $ 229.1
Accounts payable........................................................... 1,649.1 1,791.3
Accrued expenses........................................................... 374.0 397.2
Current maturities on long-term debt....................................... 95.1 115.4
--------- ---------
Total Current Liabilities................................................. 2,389.9 2,533.0
--------- ---------
DEBT
Long-term debt, excluding current maturities............................... 3,612.8 4,106.5
Subordinated long-term debt, excluding current maturities.................. 199.7 199.6
--------- ---------
3,812.5 4,306.1
--------- ---------
DEFERRED CREDITS AND OTHER
Deferred income taxes...................................................... 1,339.9 1,339.5
Other deferred credits..................................................... 380.1 354.6
--------- ---------
1,720.0 1,694.1
--------- ---------
MANDATORY REDEMPTION PREFERRED STOCK
Issued by subsidiaries..................................................... 26.6 36.7
--------- ---------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
Cumulative preferred stock (with aggregate
liquidation preference of $210.1 million)................................. 2.7 .1
Class A common stock - Issued (1993-422,857 shares; 1992-444,868 shares)... .1 .1
Common stock - Issued (1993-108,512,342 shares; 1992-107,967,176 shares).. 36.2 36.0
Additional paid-in capital................................................. 1,209.3 1,006.7
Retained earnings.......................................................... 1,162.7 1,099.9
--------- ---------
2,411.0 2,142.8
Less common stock in treasury-at cost (1993 and 1992-4,415,394 shares)..... 132.9 132.9
--------- ---------
2,278.1 2,009.9
--------- ---------
$10,227.1 $10,579.8
========= =========
See Notes to Consolidated Financial Statements
F-11
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
---------------------------
1993 1992 1991
------- -------- --------
NET CASH FLOW FROM OPERATING ACTIVITIES
Earnings (loss)before extraordinary item................. $ 118.3 $(126.8) $ 8.7
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization
before restructuring charges........................... 358.8 377.1 342.3
Deferred income taxes................................... 45.8 (75.6) (53.3)
Amortization of producer contract reformation costs..... 48.3 45.0 17.4
Gain on sale of securities.............................. - - (13.2)
Undistributed earnings from equity investments.......... (54.4) (16.0) (7.7)
Restructuring charges................................... - 125.0 -
Other................................................... (21.0) 30.4 (63.3)
Working capital and other changes, excluding
changes relating to cash and non-operating activities:
Accounts receivable.................................... 231.5 (77.5) 339.1
Inventories............................................ 260.5 104.6 (39.7)
Prepaid expenses and other............................. (45.2) 13.6 49.1
Accounts payable....................................... (109.6) .5 (22.5)
Accrued expenses....................................... (23.2) 33.9 (63.7)
------- ------- --------
809.8 434.2 493.2
------- ------- --------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment............... (392.7) (573.5) (728.9)
Proceeds from sale of property, plant and equipment...... 29.3 14.7 69.0
Additions to investments................................. (74.3) (69.5) (103.6)
Proceeds from investments................................ 39.5 97.9 135.3
Gas supply prepayments and settlements................... (11.4) (43.8) (81.0)
Recovery of gas supply prepayments....................... 31.8 9.1 28.5
------- ------- --------
(377.8) (565.1) (680.7)
------- ------- --------
CASH FLOW FROM FINANCING ACTIVITIES
Increase (decrease) in short-term notes.................. 42.6 (158.6) (148.8)
Redemption of mandatory redemption preferred stock....... (10.1) (12.5) (14.9)
Proceeds from issuing common stock....................... 11.9 7.1 6.0
Proceeds from issuing preferred stock.................... 193.5 - -
Proceeds from long-term debt issues...................... 233.1 684.3 1,043.3
Payments to retire long-term debt........................ (734.3) (327.7) (703.0)
Dividends paid........................................... (53.0) (42.0) (42.0)
------- ------- --------
(316.3) 150.6 140.6
------- ------- --------
Net Increase (Decrease) In Cash and Cash Equivalents...... 115.7 19.7 (46.9)
Cash and cash equivalents at beginning of year........... 43.5 23.8 70.7
------- ------- --------
Cash and cash equivalents at end of year................. $ 159.2 $ 43.5 $ 23.8
======= ======= ========
See Notes to Consolidated Financial Statements
F-12
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK
AND OTHER STOCKHOLDERS' EQUITY
(Millions of Dollars and Thousands of Shares)
Year Ended December 31,
-------------------------------------------------------------
1993 1992 1991
------------------- ----------------- -------------------
Shares Amount Shares Amount Shares Amount
-------- --------- ------- -------- -------- --------
Preferred Stock, Par Value 33-1/3c
Per Share, Authorized 50,000,000 Shares
Cumulative Convertible Preferred:
$1.19, Series A: Beginning
balance...................................... 69 $ - 72 $ - 76 $ -
Converted to common............................ (4) - (3) - (4) -
------- ------- ------- -------- ------- --------
Ending balance............................... 65 - 69 - 72 -
======= ------- ======= -------- ======= --------
$1.83, Series B: Beginning
balance........................................ 95 .1 109 .1 118 .1
Converted to common............................ (6) - (14) - (9) -
------- ------- ------- -------- ------- --------
Ending balance............................... 89 .1 95 .1 109 .1
======= ------- ======= -------- ======= --------
$5.00, Series C: Beginning
balance........................................ 36 - 36 - 37 -
Converted to common............................ (1) - - - (1) -
------- ------- ------- -------- ------- --------
Ending balance............................... 35 - 36 - 36 -
======= ------- ======= -------- ======= --------
Cumulative Preferred:
$2.125, Series H, Liquidation amount of
$25 per share:
Beginning balance.............................. - - - - - -
Issuance....................................... 8,000 2.6 - - - -
------- -------- ------- -------- ------- --------
Ending balance............................... 8,000 2.6 - - - -
======= -------- ======= -------- ======= --------
Class A Common Stock, Par Value 33-1/3c
Per Share, Authorized 2,700,000 Shares
Beginning balance.............................. 445 .1 449 .2 481 .2
Converted to common............................ (108) - (27) (.1) (45) -
Conversion of preferred stock and
exercise of stock options..................... 86 - 23 - 13 -
------- -------- ------- -------- ------- --------
Ending balance............................... 423 .1 445 .1 449 .2
====== -------- ======= -------- ======= --------
Common Stock, Par Value 33-1/3c
Per Share, Authorized 250,000,000 Shares
Beginning balance.............................. 107,967 36.0 107,713 35.8 107,518 35.8
Conversion of preferred stock.................. 42 - 63 - 51 -
Conversion of Class A common stock............. 108 - 27 .1 45 -
Exercise of stock options...................... 395 .2 164 .1 99 -
------- -------- ------- -------- ------- --------
Ending balance............................... 108,512 36.2 107,967 36.0 107,713 35.8
======= -------- ======= -------- ======= --------
Additional Paid-In Capital
Beginning balance............................... 1,006.7 999.7 993.7
Issuance of Series H preferred stock............ 190.9 - -
Exercise of stock options....................... 11.7 7.0 6.0
-------- -------- --------
Ending balance............................... 1,209.3 1,006.7 999.7
-------- -------- --------
Retained Earnings
Beginning balance............................... 1,099.9 1,268.7 1,302.0
Net earnings (loss) for period.................. 115.8 (126.8) 8.7
Cash dividends on preferred stock............... (11.3) (.5) (.5)
Cash dividends on Class A common stock,
36c(1993), 36c(1992) and 36c(1991) per share.. (.2) (.2) (.2)
Cash dividends on common stock, 40c(1993),
40c(1992) and 40c(1991) per share............. (41.5) (41.3) (41.3)
-------- -------- --------
Ending balance................................ 1,162.7 1,099.9 1,268.7
-------- -------- --------
Less Treasury Stock-At Cost..................... 4,415 132.9 4,415 132.9 4,415 132.9
======= -------- ======= -------- ======= ========
Total........................................... $2,278.1 $2,009.9 $2,171.6
======== ======== ========
See Notes to Consolidated Financial Statements
F-13
THE COASTAL CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION - The consolidated financial statements include
accounts of the Company and its wholly owned subsidiaries, after eliminating all
significant intercompany transactions. The equity method of accounting is used
for investments in which the Company has a 20% to 50% continuing interest and
exercises significant influence. Investments in which the Company has less than
a 20% interest are accounted for by the cost method.
STATEMENT OF CASH FLOWS - For purposes of this statement, cash equivalents
include time deposits, certificates of deposit and all highly liquid instruments
with original maturities of three months or less. Cash flows of a hedging
instrument that are accounted for as a hedge of an identifiable transaction are
classified in the same category as the cash flows from the item being hedged.
The Company made cash payments for interest and financing fees (net of amounts
capitalized) of $447.2 million, $480.6 million and $426.6 million in 1993, 1992
and 1991, respectively. Cash payments (refunds) for income taxes amounted to
$21.0 million, ($9.8) million and $81.0 million for 1993, 1992 and 1991,
respectively.
INVENTORIES - Inventories of refined products and crude oil are accounted for
by the first-in, first-out cost method ("FIFO") or market, if lower. Natural gas
inventories are accounted for on the basis used for rate making and in reporting
to the Federal Energy Regulatory Commission ("FERC"). Colorado Interstate Gas
Company ("CIG") uses the last-in, first-out method, while ANR Pipeline Company
uses the first-in, first-out method. Inventories of coal are accounted for at
average cost, or market, if lower. Inventories of materials and supplies are
accounted for at average cost.
HEDGES - The Company frequently enters into futures and other contracts to
hedge the price risks associated with inventories, commitments and certain
anticipated transactions. Coastal defers the impact of changes in the market
value of these contracts until such time as the hedged transaction is completed.
PROPERTY, PLANT AND EQUIPMENT - Property additions include acquisition costs,
administrative costs and, where appropriate, capitalized interest allocable to
construction. Capitalized interest amounted to $8.4 million, $10.7 million and
$22.1 million in 1993, 1992 and 1991, respectively. All costs incurred in the
acquisition, exploration and development of gas and oil properties, including
unproductive wells, are capitalized under the full-cost method of accounting.
Depreciation, depletion and amortization of gas and oil properties are
provided on the unit-of-production basis whereby the unit rate for depreciation,
depletion and amortization is determined by dividing the total unrecovered
carrying value of gas and oil properties plus estimated future development costs
by the estimated proved reserves included therein, as estimated by an
independent engineer. The average amortization rate per equivalent unit of a
thousand cubic feet of gas production for oil and gas operations was $1.00 each
for 1993, 1992 and 1991. Provisions for depletion of coal properties, including
exploration and development costs, are based upon estimates of recoverable
reserves using the unit-of-production method. Provision for depreciation of
other property is primarily on a straight-line basis over the estimated useful
life of the properties.
Costs of minor property units (or components thereof) retired or abandoned
are charged or credited, net of salvage, to accumulated depreciation, depletion
and amortization. Gain or loss on sales of major property units is credited or
charged to income.
GOODWILL - Goodwill, which primarily relates to the acquisitions of American
Natural Resources Company and Colorado Interstate Gas Company, amounted to
$563.3 million at December 31, 1993, and is being amortized on a straight-line
basis over a 40-year period. Amortization expense charged to operations was
approximately $19.0
F-14
million for 1993, 1992 and 1991, respectively. As warranted by facts and
circumstances, the Company periodically assesses the recoverability of the cost
of goodwill from future operating income.
INCOME TAXES - The Company follows the liability method of accounting for
deferred income taxes as required by the provisions of Statement of Financial
Accounting Standards No. 109 - Accounting for Income Taxes.
REVENUE RECOGNITION - The Company's subsidiaries recognize revenues for the
sale of their respective products in the period of delivery. Revenues for
services are recognized in the period the services are provided.
CURRENCY TRANSLATION - The U.S. dollar is the functional currency for
substantially all the Company's foreign operations. For those operations, all
gains and losses from currency translations are included in income currently.
EARNINGS PER SHARE - Earnings (loss) per common and common equivalent share
amounts are based on the average number of common and Class A common shares
outstanding during each period, assuming conversion of preferred stocks which
are common stock equivalents and exercise of all stock options having exercise
prices less than the average market price of the common stock using the treasury
stock method.
Average shares entering into the computations are:
1993............... 104,744,124
1992............... 103,827,362
1991............... 104,651,450
STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 71 (FAS 71) - The interstate
natural gas pipeline operations and certain storage subsidiaries are subject to
the regulations and accounting procedures of the FERC. These subsidiaries meet
the criteria and, accordingly, follow the reporting and accounting requirements
of FAS 71.
RECLASSIFICATION OF PRIOR PERIOD STATEMENTS - Certain minor reclassifications
have been made to conform with current reporting practices. The effect of the
reclassifications was not material to the Company's results of operations or
financial position.
NOTE 2. INVENTORIES
Inventories at December 31 were (millions of dollars):
1993 1992
-------- ---------
Refined products, crude oil
and chemicals....................................... $ 568.8 $ 734.8
Natural gas in underground storage................... 260.4 360.0
Coal, materials and supplies......................... 163.0 157.9
-------- ---------
$ 992.2 $ 1,252.7
======== =========
Elements included in inventory cost are material, labor and manufacturing
expenses.
The excess of replacement cost over the carrying value of natural gas in
underground storage carried by the last-in, first-out method was approximately
$52.6 million and $47.8 million at December 31, 1993 and 1992, respectively.
Natural gas in underground storage at December 31, 1993, includes $161.5
million, pending approval by the FERC, which is to be transferred to Property,
Plant and Equipment for regulatory and accounting purposes.
F-15
NOTE 3. TAKE-OR-PAY OBLIGATIONS
Other assets include $134.0 million and $225.6 million at December 31, 1993
and 1992, respectively, relating to prepayments for gas under gas purchase
contracts with producers and settlement payment amounts relative to the
restructuring of gas purchase contracts as negotiated with producers. Currently,
FERC regulations allow for the billing of a portion of the costs of take-or-pay
settlements and renegotiating gas purchase contracts. Prepayments are normally
recoupable through future deliveries of natural gas.
As a result of the implementation of Order 636 by CIG on October 1, 1993 (See
Note 14 in the Notes to Consolidated Financial Statements), CIG's future gas
sales will be made at negotiated prices and will not be subject to regulatory
price controls. This will not affect the recoverability or the results of
pending take-or-pay litigation or any take-or-pay or contractual reformation
settlements that CIG may achieve with respect to periods before October 1, 1993.
A portion of the costs associated with take-or-pay incurred prior to October 1,
1993, may continue to be recovered by CIG pursuant to FERC's Order No. 528.
Contract reformation and take-or-pay costs incurred as a result of the
mandated Order 636 restructuring will be recovered under the transition cost
mechanisms of Order 636, as well as through negotiated agreements with
customers. The Company believes that these mechanisms provide adequate coverage
for such costs.
Several producers have instituted litigation arising out of take-or-pay
claims against subsidiaries of the Company. In the Company's experience,
producers' claims are generally vastly overstated and do not consider all
adjustments provided for in the contract or allowed by law. The subsidiaries
have resolved the majority of the exposure with their suppliers for
approximately 13% of the amounts claimed. At December 31, 1993, the Company
estimated that unresolved asserted and unasserted producers' claims amounted to
approximately $31 million. The remaining disputes will be settled where possible
and litigated if settlement is not possible.
At December 31, 1993, the Company was committed to make future purchases
under certain take-or-pay contracts with fixed, minimum or escalating price
provisions. Based on contracts in effect at that date, and before considering
reductions provided in the contracts or applicable law, such commitments are
estimated to be $38 million, $30 million, $23 million, $15 million and $4
million for the years 1994-1998, respectively, and $9 million thereafter. Such
commitments have also not been adjusted for all amounts which may be assigned or
released, or for the results of future litigation or negotiation with producers.
The Company has made provisions, which it believes are adequate, for payments
to producers that may be required for settlement of take-or-pay claims and
restructuring of future contractual commitments. In determining the net loss
relating to such provisions, the Company has also made accruals for the
estimated portion of such payments which would be recoverable pursuant to FERC-
approved settlements with customers.
NOTE 4. INVESTMENTS
The Company has interests in corporations and partnerships which are
accounted for on an equity basis. These investments, included in Other Assets,
are Great Lakes Gas Transmission Limited Partnership (50% interest), which
operates an interstate pipeline system; Pacific Refining Company (50% interest),
which operates a refinery and terminal facilities in California; Javelina
Company (40% interest), which operates a gas processing plant in Corpus Christi,
Texas; Eagle Point Cogeneration Partnership (50% interest), which operates a
cogeneration facility in New Jersey; corporate joint ventures (50% interest),
which have developed gas and oil properties in Argentina; and several pipeline
and other ventures. The Company's investment in these entities, including
advances, amounted to $424.7 million and $330.2 million at December 31, 1993 and
1992, respectively. The Company's equity in income of the investments was $71.9
million, $63.8 million and $26.6 million in 1993, 1992 and 1991, respectively,
while dividends and partnership distributions received amounted to $17.5
million, $47.8 million and $18.9 million in 1993, 1992 and 1991, respectively.
The 1992 equity in income excludes the restructuring charges as discussed in
Note 10.
F-16
Summarized financial information of these entities is as follows (millions of
dollars):
December 31,
--------------------
1993 1992
--------- ---------
Current assets......................................................... $ 272.9 $ 375.0
Noncurrent assets...................................................... 2,208.1 1,955.2
--------- ---------
$ 2,481.0 $ 2,330.2
========= =========
Current liabilities.................................................... $ 353.2 $ 369.3
Noncurrent liabilities................................................. 1,129.7 1,139.1
Deferred credits....................................................... 155.5 113.3
Equity................................................................. 842.6 708.5
--------- ---------
$ 2,481.0 $ 2,330.2
========= =========
Year Ended December 31,
--------------------------------
1993 1992 1991
---------- --------- ---------
Revenues................................................................ $ 1,165.2 $ 1,126.4 $ 1,038.2
Operating income........................................................ 192.8 194.1 74.4
Net income.............................................................. 123.7 108.6 25.1
F-17
NOTE 5. DEBT
LONG-TERM DEBT - Balances at December 31 were (millions of dollars):
1993 1992
--------- ---------
The Coastal Corporation:
Notes payable to banks (term credit facilities)................................... $ 100.0 $ 111.8
Notes payable to banks (revolving credit agreements).............................. 80.0 25.0
Swiss franc bonds, 5-3/4%, due 1996............................................... 68.3 119.1
Senior notes:
11-1/4%, due 1996................................................................ - 500.0
10-3/8%, due 2000................................................................ 249.8 249.8
10%, due 2001.................................................................... 298.9 298.8
8-3/4%, due 1999................................................................. 150.0 150.0
8-1/8%, due 2002................................................................. 249.2 249.1
Japanese yen notes, 6.3%,
due 1995 to 1997................................................................. 199.4 199.4
Senior debentures:
11-3/4%, due 2006................................................................ 400.0 400.0
10-1/4%, due 2004................................................................ 199.8 199.8
10-3/4%, due 2010................................................................ 149.5 149.5
9-3/4%, due 2003................................................................. 298.6 298.5
9-5/8%, due 2012................................................................. 149.1 149.0
Other............................................................................. .1 .1
--------- ---------
2,592.7 3,099.9
--------- ---------
Subsidiary Companies:
Notes payable to banks (revolving credit agreements).............................. 473.5 340.5
Notes payable to banks (project financing), due 1995.............................. 46.5 52.6
Long-term notes, 9% to 13-1/2%, due 1994 through 2005............................. 8.2 34.0
First mortgage pipeline bonds, 8-5/8% to 10-5/8%.................................. - 56.0
Debentures, 9-5/8% to 10%, due 2005-2021.......................................... 477.5 499.1
Capitalized lease obligations, 9-3/4% to 11.99%................................... 32.3 48.5
Swiss franc bonds, 6%, due 1995................................................... 58.2 58.1
Other, due 2004-2012.............................................................. 19.0 33.2
--------- ---------
1,115.2 1,122.0
--------- ---------
Total Long-Term Debt.............................................................. 3,707.9 4,221.9
Less Current Maturities........................................................... 95.1 115.4
--------- ---------
$3,612.8 $4,106.5
========= =========
At December 31, 1993, long-term credit agreements with banks totaled $1,198.1
million, including $308.0 million available to The Coastal Corporation. Loans
under these agreements bear interest at money market-related rates (weighted
average 4.16% at December 31, 1993). Annual commitment fees range up to 1/2%
payable on the unused portion of the applicable facility. At December 31, 1993,
$653.5 million was outstanding. Notes payable to banks of $400.0 million are
obligations of a wholly owned subsidiary, Coastal Natural Gas Company (CNG), for
which CNG has pledged the common stock of its first-tier subsidiaries as
collateral. The agreements contain restrictive covenants which, among other
things, limit the payment of dividends by CNG and the amount of additional
indebtedness of CNG and its subsidiaries.
The subsidiary project financing note bears interest at money market-related
rates.
F-18
Various agreements contain restrictive covenants which, among other things,
limit the payment of advances or dividends by certain subsidiaries and
additional indebtedness of certain subsidiaries. At December 31, 1993, net
assets of consolidated subsidiaries amounted to approximately $5.1 billion, of
which $1.7 billion was restricted by such provisions.
In February 1994, ANR Pipeline Company sold $125.0 million of 7-3/8%
Debentures due in 2024. The net proceeds from the sale will be used for capital
expenditures and for other general corporate purposes.
INTEREST RATE AND CURRENCY SWAPS - The Company has entered into a number of
interest rate swap agreements which have effectively fixed interest rates on
$563.5 million of floating rate debt. Under these agreements, Coastal will pay
the counterparties interest at a fixed rate, and the counterparties will pay
Coastal interest at a variable rate based on the London Interbank Offered Rate
(LIBOR). At December 31, 1993, the weighted average fixed rate payable under
these agreements was 9.61%. The Company has also entered into a number of
offsetting interest rate swap agreements which have effectively converted $250.0
million of fixed rate debt into floating rate debt. Terms expire at various
dates through the third quarter of 1996.
The foreign currency exposure relating to certain of the Swiss franc
denominated debt of the Company and one of its subsidiaries and Japanese yen
denominated debt of the Company has been hedged to maturity, resulting in
effective borrowing costs ranging from 8.2% to 11.1%.
Coastal and its subsidiaries have entered into these interest rate and
currency swaps with major banking institutions to reduce the impact of interest
rate and exchange rate fluctuations with respect to certain floating rate and
foreign currency denominated debt. In certain instances, the Company has also
entered into interest rate swaps to convert a portion of its fixed rate debt
into floating rates. Coastal is exposed to loss if one or more of the
counterparties default. Interest rate swap transactions generally involve
exchanges of fixed and floating interest payment obligations without exchanges
of underlying principal amounts. Similarly, currency swaps involve exchanges of
interest payments in differing currencies but provide for the exchange of
principal amounts at maturity, usually through an escrow arrangement to limit
credit risk. Consequently, Coastal's exposure to credit loss is significantly
less than the contracted amounts.
Neither the Company nor the counterparties are required to collateralize
their respective obligations under these swaps. At December 31, 1993, Coastal
had no exposure to credit loss on interest rate swaps and approximately $108.7
million of exposure to credit loss on currency swaps.
SUBORDINATED LONG-TERM DEBT - Balances at December 31 were (millions of
dollars):
1993 1992
------ ------
Subordinated Notes, 11-1/8%, due 1998............ $199.7 $199.6
Less Current Maturities......................... - -
------ ------
$199.7 $199.6
====== ======
MATURITIES - The aggregate amounts of long-term debt (including subordinated)
maturities for the five years following 1993 are (millions of dollars):
1994 $ 95.1 1997 $ 236.0
1995 269.6 1998 234.2
1996 502.3
NOTES PAYABLE - At December 31, 1993, Coastal and its subsidiaries had $264.0
million of outstanding indebtedness to banks under short-term lines of credit,
compared to $221.4 million at December 31, 1992. As of December 31, 1993, $413.0
million was available to be drawn under short-term credit lines.
F-19
RESTRICTIONS ON PAYMENT OF DIVIDENDS - Under the terms of the most
restrictive of the Company's financing agreements, approximately $409.9 million
was available at December 31, 1993, for payment of dividends on the Company's
common and preferred stocks.
GUARANTEES - Coastal and certain subsidiaries have guaranteed specific
obligations of several unconsolidated affiliates. Such affiliates are generally
not required to collateralize their contingent liabilities to the Company. At
December 31, 1993, the Company had guaranteed 50% of a construction financing
entered into by a partially owned partnership, 45% of a construction financing
of a second partnership and 100% of a construction financing entered into by a
third partnership. The Company's proportionate share of the outstanding
principal balances under these guarantees was $135.0 million at December 31,
1993. Other guarantees and indemnities related to obligations of unconsolidated
affiliates amounted to approximately $224.9 million as of the same date. The
Company anticipates that two of the guaranteed construction loans will be
refinanced in 1994 and the third in early 1995, all on a non-recourse basis. The
Company is of the opinion that its unconsolidated affiliates will be able to
perform under their respective financings and other obligations and that no
payments will be required and no losses will be incurred under such guarantees
and indemnities.
Coastal and certain subsidiaries have guaranteed approximately $16.7 million
of obligations of third parties under leases and borrowing arrangements. Where
possible, the Company has obtained security interests and guarantees by the
principals. Cash requirements and losses under these guarantees are expected to
be nominal.
NOTE 6. LEASES
The Company and its subsidiaries had rental expense of approximately $98.2
million, $92.6 million and $98.1 million in 1993, 1992 and 1991, respectively,
excluding leases covering natural resources. Aggregate minimum lease payments
under existing noncapitalized long-term leases are estimated to be $82.8
million, $80.5 million, $77.3 million, $71.0 million, and $59.5 million for the
years 1994-1998, respectively, and $720.7 million thereafter.
NOTE 7. MANDATORY REDEMPTION PREFERRED STOCK
Shares and aggregate redemption value of mandatory redemption preferred stock
outstanding, excluding shares redeemable within one year, were (thousands of
shares and millions of dollars):
Subsidiaries Stock
------------------
Shares Value
------ ------
Balance, December 31, 1990................. 2,115 $ 65.1
Redemptions................................ (346) (15.9)
----- ------
Balance, December 31, 1991................. 1,769 49.2
Redemptions................................ (577) (12.5)
----- ------
Balance, December 31, 1992................. 1,192 36.7
Redemptions................................ (326) (10.1)
----- ------
Balance, December 31, 1993................. 866 $ 26.6
===== ======
CIG has 550,000 shares of $100 par value cumulative preferred stock
authorized, of which 5,560 shares were outstanding at December 31, 1993. The
stock outstanding is due in 1997 with an annual dividend rate of 5.5%. The
series is to be redeemed at par value through annual sinking fund payments.
ANR Pipeline Company had 1,086,640 outstanding shares of $1.00 par value
redeemable cumulative preferred stock at December 31, 1993. The stock consists
of three series with dividends per share of $2.675, $2.12 and $12.00. The $2.675
and $2.12 series were issued at $25 per share and the $12.00 series was issued
at $100 per share. The
F-20
current per share redemption prices are $25.268 for the $2.675 Series (decreases
to issue price by 1995), $25.318 for the $2.12 Series (decreases to issue price
by 1996) and $103.790 for the $12.00 Series (decreases to issue price by 1999).
All series are to be redeemed through annual sinking fund payments.
The aggregate amount of share redemption requirements for the five years
following 1993 are (millions of dollars):
1994 $7.7 1997 $3.7
1995 7.7 1998 2.5
1996 5.1
NOTE 8. FAIR VALUE OF FINANCIAL INSTRUMENTS
The estimated fair value amounts of the Company's financial instruments have
been determined by the Company, using appropriate market information and
valuation methodologies. Considerable judgment is required to develop the
estimates of fair value, thus, the estimates provided herein are not necessarily
indicative of the amounts that the Company could realize in a current market
exchange.
(Millions of dollars)
----------------------------------------------
December 31, 1993 December 31, 1992
--------------------- ---------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
--------- --------- --------- ---------
Financial assets:
Cash and cash equivalents............. $ 159.2 $ 159.2 $ 43.5 $ 43.5
Notes receivable...................... 62.8 64.2 64.8 64.8
Financial liabilities:
Short-term debt....................... 264.0 264.0 221.4 221.4
Long-term debt and currency swaps..... 3,875.3 4,203.5 4,373.0 4,457.2
Mandatory redemption preferred stock.. 34.3 34.9 44.4 44.5
Interest rate swaps and options....... 80.3 106.3 64.8 120.0
The estimated value of the Company's long-term debt and mandatory
redemption preferred stock is based on interest rates at December 31, 1993 and
1992, respectively, for new issues with similar remaining maturities. The fair
market value of the Company's interest rate and foreign currency swaps is based
on the estimated termination values at December 31, 1993 and 1992, respectively.
NOTE 9. COMMON AND PREFERRED STOCK
Shares of common stock and Class A common stock reserved for future issuance
as of December 31, 1993 were:
Class A
Common Common
Stock Stock
---------- -------
Employee stock options......................................... 2,294,372 44,743
Conversion of outstanding Class A common stock................. 422,857 -
Conversion of Class A common stock subject to future issuance.. 67,107 -
Conversion of preferred stock:
$1.19, Series A, redemption value of $33 per share............ 233,945 6,476
$1.83, Series B, redemption value of $50 per share............ 322,126 8,917
$5.00, Series C, redemption value of $100 per share........... 251,854 6,971
---------- -------
3,592,261 67,107
========== =======
F-21
Common stock reserved for conversion is at the rate of one share for each
share of Class A common stock, 3.6125 shares for each share of Series A or
Series B preferred stock and 7.1121094 shares for each share of Series C
preferred stock. Each share of common stock and Series A, Series B and Series C
preferred stock is entitled to one vote while each share of Class A common stock
is entitled to 100 votes. However, 25% of the Company's directors standing for
election at each annual meeting will be determined solely by holders of the
common stock and preferred stocks mentioned above, voting as a class.
In April 1993, the Company completed the public offering of 8,000,000 shares
of $2.125 Cumulative Preferred Stock, Series H, at $25 per share. The net
proceeds from the sale were used to retire short- and long-term debt of the
Company.
Under the 1980 Stock Option Plan, no options were exercisable at December 31,
1993, and 904 common shares and 25 Class A common shares were exercisable at
December 31, 1992. No additional options may be granted under the 1980 Plan.
Under the 1984 Plan, 4,113 Class A common shares and 13,442 common shares
were available for granting of options, and options for 39,262 Class A common
shares and 92,288 common shares were exercisable at December 31, 1993. At
December 31, 1992, nine Class A common shares and 12 common shares were
available for granting of options, and options for 124,448 Class A common shares
and 185,080 common shares were exercisable.
Under the 1985 Plan, 69,758 common shares were available for granting of
options, and options for 953,898 common shares were exercisable at December 31,
1993. At December 31, 1992, 102,773 common shares were available for granting of
options, and options for 1,194,414 common shares were exercisable.
Under the 1990 Plan, 23,717 common shares were available for granting of
options, and options for 181,380 common shares were exercisable at December 31,
1993. At December 31, 1992, 368,690 common shares were available for granting of
options, and options for 42,002 common shares were exercisable.
Options are currently granted under the plans at 100% of market value. The
following table presents a summary of stock option transactions for the three
years ended December 31, 1993:
Class A Option
Common Common Price
Stock Stock Per Share
---------- ------- ---------
December 31, 1990.... 2,372,561 208,325 $ 6.26-35.94
Granted............. 446,800 - 31.50-35.94
Exercised........... (214,537) (27,566) 6.26-28.59
Revoked or expired.. (28,432) (50) 9.87-35.94
--------- -------- ------------
December 31, 1991.... 2,576,392 180,709 7.12-35.94
Granted............. 20,000 - 25.94-28.56
Exercised........... (214,867) (50,116) 7.12-28.59
Revoked or expired.. (147,500) - 17.08-35.94
--------- -------- ------------
December 31, 1992.... 2,234,025 130,593 7.91-35.94
Granted............. 639,879 - 25.50-27.00
Exercised........... (412,128) (85,859) 7.91-28.59
Revoked or expired.. (274,321) (4,104) 26.06-35.94
--------- -------- ------------
December 31, 1993.... 2,187,455 40,630 $ 7.91-35.94
========= ========= ============
F-22
NOTE 10. SEGMENT REPORTING
The Company operates principally in the following lines of business: natural
gas, refining and marketing, exploration and production, and coal. Natural gas
operations involve the production, purchase, gathering, storage, transportation
and sale of natural gas, principally to utilities, industrial customers and
other pipelines, and include the operation of natural gas liquids extraction
plants.
Refining and marketing operations involve the purchase, transportation and
sale of refined products, crude oil, condensate and natural gas liquids; the
operation of refineries and a chemical plant; the sale at retail of gasoline,
petroleum products and convenience items; petroleum product terminaling; and
marketing of crude oil and refined petroleum products worldwide.
Exploration and production operations involve the exploration, development
and production of natural gas, crude oil, condensate and natural gas liquids.
The segment also includes related intrastate natural gas marketing activities
and gas plant processing operations.
Coal operations include the mining, processing and marketing of coal from
Company-owned reserves and from other sources, and the brokering of coal for
others.
Other operations include regional trucking operations involving activities as
common carriers in interstate and intrastate commerce and activities in power
production and other projects.
Operating revenues by segment include both sales to unaffiliated customers,
as reported in the Company's Statement of Consolidated Operations, and
intersegment sales, which are accounted for on the basis of contract, current
market or internally established transfer prices. The intersegment sales are
primarily sales from the exploration and production segment to the natural gas
and refining and marketing segments and from the natural gas segment to the
refining and marketing segment.
Operating profit is total revenues less interest income from affiliates and
operating costs and expenses. Operating expenses exclude income taxes, corporate
general and administrative expenses and interest.
Identifiable assets by segment are those assets that are used in the
Company's operations in each segment. Corporate assets are those assets which
are not specifically identifiable with a segment.
F-23
The Company's operating revenues, operating profit, capital expenditures, and
depreciation, depletion and amortization expense for the years ended December
31, 1993, 1992 and 1991, and identifiable assets as of December 31, 1993, 1992
and 1991, by segment, are shown as follows (millions of dollars):
1993 1992 1991
---------- ---------- ----------
OPERATING REVENUES
Natural gas....................................... $ 3,247.9 $ 2,746.8 $ 2,405.5
Refining and marketing............................ 6,200.9 6,561.1 6,297.6
Exploration and production........................ 357.3 310.0 327.6
Coal.............................................. 443.2 447.4 465.2
Other............................................. 187.0 196.3 169.6
Adjustments and eliminations...................... (300.2) (198.7) (110.7)
--------- --------- ---------
Consolidated totals.............................. $10,136.1 $10,062.9 $ 9,554.8
========= ========= =========
OPERATING PROFIT (LOSS)
Natural gas....................................... $ 405.2 $ 403.1 $ 402.2
Refining and marketing............................ 98.0 (192.1) (99.3)
Exploration and production........................ 49.9 45.8 45.2
Coal.............................................. 95.1 92.8 91.8
Other............................................. (12.8) (19.7) (4.3)
--------- --------- ---------
Consolidated totals.............................. $ 635.4 $ 329.9 $ 435.6
========= ========= =========
CAPITAL EXPENDITURES
Natural gas....................................... $ 119.8 $ 231.7 $ 181.5
Refining and marketing............................ 130.3 173.3 391.5
Exploration and production........................ 91.8 126.8 95.4
Coal.............................................. 36.0 33.3 44.7
Other............................................. 9.5 2.6 11.8
--------- --------- ---------
Segment totals................................... 387.4 567.7 724.9
Corporate assets.................................. 5.3 5.8 4.0
--------- --------- ---------
Consolidated totals.............................. $ 392.7 $ 573.5 $ 728.9
========= ========= =========
DEPRECIATION, DEPLETION AND AMORTIZATION EXPENSE
Natural gas....................................... $ 145.4 $ 187.1 $ 177.0
Refining and marketing............................ 45.6 98.1 40.3
Exploration and production........................ 109.1 83.2 69.4
Coal.............................................. 28.5 28.4 27.1
Other............................................. 7.9 7.6 7.1
--------- --------- ---------
Segment totals................................... 336.5 404.4 320.9
Corporate assets.................................. 3.4 4.2 3.0
--------- --------- ---------
Consolidated totals.............................. $ 339.9 $ 408.6 $ 323.9
========= ========= =========
IDENTIFIABLE ASSETS
Natural gas....................................... $ 5,562.5 $ 5,719.7 $ 5,748.5
Refining and marketing............................ 2,745.9 3,054.1 3,019.0
Exploration and production........................ 801.5 835.8 781.9
Coal.............................................. 450.3 434.6 438.9
Other............................................. 199.7 203.2 210.6
--------- --------- ---------
Segment totals................................... 9,759.9 10,247.4 10,198.9
Corporate assets.................................. 467.2 332.4 321.4
--------- --------- ---------
Consolidated totals.............................. $10,227.1 $10,579.8 $10,520.3
========= ========= =========
F-24
Refining and marketing revenues include gross profit arising from the
selling, trading and exchanging of third party products. Approximate amounts
from these transactions included in revenues and the impact on earnings,
exclusive of interest costs, were (millions of dollars):
1993 1992 1991
---- ---- -----
Revenues............................................... $ 3.1 $ 1.1 $13.1
Impact on earnings..................................... 2.0 .7 8.5
The number and magnitude of such transactions may vary significantly from
year to year, particularly in view of conditions in world petroleum markets.
Results for 1992 reflect a primarily non-cash $125 million pretax charge for
restructuring certain refining and marketing operations. The charge reflects
numerous actions to reduce costs and working capital, limit risks and eliminate
marginal activities, and primarily relates to reducing the carrying value of
certain assets. Eighty-five million dollars of the charge relates to wholly
owned assets and was made against operating profit. The remaining $40 million
relates to partially owned investments and was included in Other Income-Net.
OTHER INCOME - Net for 1991 includes gains of $13.2 million from the sale of
securities. Also included are equity method earnings related to the business
segments as follows (millions of dollars):
Year Ended December 31,
--------------------------
1993 1992 1991
-------- ------- -------
Natural gas.................................... $55.1 $53.6 $31.5
Refining and marketing......................... (3.4) (7.6) (8.3)
Exploration and production..................... 4.7 5.1 -
Power production............................... 16.4 13.7 4.9
Other.......................................... (.9) (1.0) (1.5)
----- ----- -----
$71.9 $63.8 $26.6
===== ===== =====
Revenues from sales to any single customer during 1993, 1992 or 1991 did not
amount to 10% or more of the Company's consolidated revenues for any year.
NOTE 11. BENEFIT PLANS
The Company has non-contributory pension plans covering substantially all
U.S. employees. These plans provide benefits based on final average monthly
compensation and years of service. The Company's funding policy is to contribute
the amount necessary for the plan to maintain its qualified status under the
Employee Retirement Income Security Act of 1974. The pension benefit for 1993,
1992 and 1991 is shown in the following table (millions of dollars):
Year Ended December 31,
--------------------------
1993 1992 1991
-------- ------- -------
Service cost - benefit earned during the period.. $ 16.3 $ 15.2 $ 13.9
Interest cost on projected benefit obligation.... 37.6 38.5 34.4
Actual return on assets.......................... (92.5) (25.3) (108.7)
Net amortization and deferral.................... 18.9 (47.5) 44.1
------ ------ -------
Net periodic pension benefit..................... $(19.7) $(19.1) $ (16.3)
====== ====== =======
The discount rate used in determining the actuarial present value of the
projected benefit obligation was 7.25% in 1993 and 8.25% in 1992 and 1991. The
expected increase in future compensation levels was 4% in 1993 and 6% in 1992
and 1991, and the expected long-term rate of return on assets was 11%.
F-25
The following table sets forth the funded status of the plans and the amounts
recognized in the Company's Consolidated Balance Sheet (millions of dollars):
December 31,
-----------------
1993 1992
------- -------
Actuarial present value of benefit obligations: Accumulated benefit
obligation, including vested benefits of $442.5 million and
$371.5 million, respectively........................................ $(492.4) $(410.3)
======= =======
Projected benefit obligation for service rendered to date............ $(539.6) $(506.3)
Plan assets, primarily equity securities, at fair value.............. 827.6 762.5
------- -------
Plan assets in excess of projected benefit obligation................ 288.0 256.2
Unrecognized net assets at January 1, 1993 and 1992,
being recognized over average remaining service
lives............................................................... (76.1) (85.4)
Prior service cost, not yet recognized............................... 7.1 6.1
Unrecognized net loss from past experience different from
that assumed........................................................ 15.9 19.9
------- -------
Prepaid pension cost................................................. $ 234.9 $ 196.8
======= =======
Plan assets include common stock and Class A common stock of the Company
amounting to a total of 3.75 million shares at December 31, 1993 and 1992.
The Company also participates in several multi-employer pension plans for the
benefit of its employees who are union members. Company contributions to these
plans were $7.1 million each for 1993, 1992 and 1991. The data available from
administrators of the multi-employer pension plans is not sufficient to
determine the accumulated benefit obligations, nor the net assets attributable
to the multi-employer plans in which Company employees participate.
The Company also makes contributions to a thrift plan, which is a trusteed,
voluntary and contributory plan for eligible employees of the Company. The
Company's contributions, which match the contributions made by employees,
amounted to $17.7 million, $16.6 million and $15.4 million in 1993, 1992 and
1991, respectively.
The Company provides certain health care and life insurance benefits for
retired employees. Substantially all U.S. employees are provided these benefits.
Effective January 1, 1993, the Company adopted Statement of Financial Accounting
Standards No. 106, "Employers' Accounting for Postretirement Benefits Other Than
Pensions" ("FAS 106"). FAS 106 requires the Company to accrue the estimated cost
of retiree benefit payments during the years the employee provides services. The
Company previously expensed the cost of these benefits, which are principally
health care, as claims were incurred. FAS 106 allows recognition of the
cumulative effect of the liability in the year of the adoption or the
amortization of the obligation over a period of up to 20 years. The Company has
elected to recognize the initial postretirement benefit obligation of
approximately $133.1 million over a period of 20 years. The Company's cash flows
were not affected by implementation of FAS 106 and the incremental impact on the
Company's 1993 results of operations before income taxes is approximately $13.6
million, of which $8.3 million is being deferred by the Company's rate regulated
subsidiaries. The subsidiaries have filed to include such deferred costs in
their rates.
F-26
[CAPTION]
(Millions of dollars)
---------------------
Accumulated postretirement benefit obligation as of December 31, 1993:
Retirees................................................................ $(105.3)
Fully eligible plan participants........................................ (18.8)
Other active plan participants.......................................... (25.3)
-------
(149.4)
Plan assets at fair value................................................ 2.1
-------
Accumulated postretirement benefit obligations in excess of plan assets.. (147.3)
Unrecognized net transition obligation................................... 126.4
Unrecognized net loss from past experience different from that assumed... 9.3
-------
Postretirement benefit obligation included in balance sheet as of
December 31, 1993....................................................... $ (11.6)
=======
Net periodic postretirement benefit cost for the year ended
December 31, 1993, consisted of the following components:
Service cost - benefits earned during the period........................ $ 1.7
Interest cost on accumulated postretirement benefit obligation.......... 10.6
Amortization of transition obligation................................... 6.7
Deferred regulatory asset............................................... (8.3)
-------
Net periodic postretirement benefit expense............................. $ 10.7
=======
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 16.0% in 1993, declining gradually to 7.0%
by the year 2004. A one percentage point increase in the assumed health care
cost trend rate for each year would increase the accumulated postretirement
benefit obligation as of December 31, 1993, and net postretirement health care
cost by approximately 4.7%. The assumed discount rate used in determining the
accumulated postretirement benefit obligation was 7.25%.
The Company adopted Statement of Financial Accounting Standards No. 112,
"Employer's Accounting for Postemployment Benefits" ("FAS 112") effective
January 1, 1994. This standard covers the accounting for estimated costs of
benefits provided to former or inactive employees before their retirement. The
effect of the new standard will not have a material effect on the Company's
results of operations or financial position.
NOTE 12. TAXES ON INCOME
Pretax earnings (loss) before extraordinary item are composed of the
following (millions of dollars):
Year Ended December 31,
-------------------------
1993 1992 1991
------ -------- -------
United States................................. $171.0 $(139.9) $(25.4)
Foreign....................................... 30.7 (58.6) 24.3
------ ------- ------
$201.7 $(198.5) $ (1.1)
====== ======= ======
F-27
Provisions for income taxes (benefits) before extraordinary item are composed
of the following (millions of dollars):
Year Ended December 31,
-------------------------
1993 1992 1991
------ -------- -------
Current Income Taxes:
Federal................ $34.3 $ 2.5 $ 35.7
State.................. 3.3 1.4 7.8
----- ------ ------
37.6 3.9 43.5
----- ------ ------
Deferred Income Taxes:
Federal................ 39.0 (84.2) (57.1)
State.................. 6.8 8.6 3.8
----- ------ ------
45.8 (75.6) (53.3)
----- ------ ------
Taxes on Income......... $83.4 $(71.7) $ (9.8)
===== ====== ======
The Company and the Internal Revenue Service ("IRS") Appeals Office have
concluded a tentative settlement of all contested adjustments to federal income
tax returns filed for the years 1982 through 1984. The settlement is in the
process of being finalized. The Company's federal income tax returns filed for
the years 1985 through 1987 have been examined by the IRS, and the Company has
received notice of proposed adjustments to the returns for each of those years.
The Company currently is contesting certain of these adjustments with the IRS
Appeals Office. Examinations of the Company's federal income tax returns for
1988, 1989 and 1990 are currently in progress. It is the opinion of management
that adequate provisions for federal income taxes have been reflected in the
consolidated financial statements.
The Company increased its deferred tax liability as a result of legislation
enacted in 1993 increasing the Corporate federal income tax rate from 34% to 35%
commencing in 1993.
Provisions for income taxes were different than the amount computed by
applying the statutory U.S. federal income tax rate to earnings before tax. The
reasons for these differences are (millions of dollars):
Year Ended December 31,
--------------------------
1993 1992 1991
------- -------- -------
Tax expense (benefit) by applying the U.S. federal income
tax rate of 35% (1993) and 34% (1992 and 1991)............ $ 70.6 $(67.5) $ (.3)
Increases (reductions) in taxes resulting from:
Tight sands gas credit.................................... (13.0) - (2.1)
State income tax cost..................................... 6.6 6.6 7.7
Preferred stock dividends................................. 1.4 1.8 2.3
Goodwill.................................................. 6.4 6.4 6.4
Exclusion for dividends and equity earnings............... (3.4) (3.0) (3.4)
Full normalization........................................ (5.4) (6.1) (5.5)
Depletion................................................. (6.3) (5.8) (4.5)
Increase in federal tax rate.............................. 29.0 - -
Other..................................................... (2.5) (4.1) (10.4)
------ ------ ------
Taxes on income............................................ $ 83.4 $(71.7) $ (9.8)
====== ====== ======
F-28
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences and carryforward are
(millions of dollars):
December 31,
-----------------
1993 1992
------ ------
Excess of book basis over tax basis of
property, plant and equipment.................... $1,403.1 $1,344.6
Pensions and benefit costs........................ 41.2 34.0
Purchase gas and other recoverable cost........... 52.6 41.9
-------- --------
Deferred tax liabilities.......................... 1,496.9 1,420.5
-------- --------
Provisions for rate refunds and contested claims.. (3.9) (23.3)
Inventory adjustments............................. (27.4) (42.0)
Alternative minimum tax credit carryforward....... (145.9) (100.4)
Other............................................. (3.3) (16.1)
-------- --------
Deferred tax assets............................... (180.5) (181.8)
-------- --------
Deferred income taxes............................. $1,316.4 $1,238.7
======== ========
NOTE 13. EXTRAORDINARY ITEM
In June 1993, the Company retired $500.0 million of 11 1/4% Senior Notes due
in 1996. The transaction resulted in an extraordinary loss of $2.5 million ($.02
per share), net of income taxes of $1.3 million.
NOTE 14. LITIGATION AND REGULATORY MATTERS
LITIGATION - In December 1992, certain of CIG's natural gas lessors in the
West Panhandle Field filed a complaint in the U.S. District Court for the
Northern District of Texas, claiming underpayment, breach of fiduciary duty,
fraud and negligent misrepresentation. Management believes that CIG has numerous
defenses to the lessors' claims, including (i) that the royalties were properly
paid, (ii) that the majority of the claims were released by written agreement,
and (iii) that the majority of the claims are barred by the statute of
limitations.
A subsidiary of Coastal has initiated a suit against TransAmerican Natural
Gas Corporation in the District Court of Webb County, Texas for breach of two
gas purchase agreements. In February 1993 TransAmerican Natural Gas Corporation
filed a Third Party Complaint and a Counterclaim in this action against Coastal
and certain subsidiaries. TransAmerican alleges breach of contract, fraud,
conspiracy, duress, tortious interference and violations of the Texas Free
Enterprises and Anti-trust Act arising out of the gas purchase agreements.
TransAmerican seeks compensatory damages, exemplary damages and attorney fees.
The matter is set for trial on March 14, 1994.
Numerous other lawsuits and other proceedings which have arisen in the
ordinary course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at this
time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all of the above claims
and that any liability which may finally be determined should not have a
material adverse effect on the Company's consolidated financial position.
RATE REGULATION - On April 8, 1992, the FERC issued Order No. 636 ("Order
636"), which required significant changes in the services provided by interstate
natural gas pipelines. Subsidiaries of the Company and numerous other parties
have sought judicial review of aspects of Order 636.
ANR Pipeline placed its restructured services under Order 636 into effect on
November 1, 1993. ANR Pipeline now offers a wide range of unbundled
transportation, storage and balancing services. Several persons, including ANR
Pipeline, have sought judicial review of aspects of the FERC's orders approving
ANR Pipeline's restructuring filings.
Order 636 also provides mechanisms for recovery of transition costs
associated with compliance with that Order. These transition costs include gas
supply realignment costs, the cost of stranded pipeline investment and the cost
of new facilities required to implement Order 636. ANR Pipeline expects that it
will incur transition costs of
F-29
approximately $150 million. As a result of the recovery mechanisms provided
under Order 636, the Company anticipates that these transition costs will not
have a material adverse effect on the Company's consolidated financial position
or its results of operations.
On December 17, 1992, the FERC issued a policy statement that outlined
changes on how pipelines may recover the costs of employees' post-retirement
benefits other than pensions. The FERC's policy will be to recognize, as a
component of jurisdictional cost-based rates, allowances for FAS 106 costs of
company employees when determined on an accrual basis, provided certain
conditions are met.
On November 1, 1993, ANR Pipeline filed a general rate increase with the
FERC. The proposed rates reflect a $121 million increase in ANR Pipeline's cost
of service from that approved in the settlement of ANR Pipeline's last rate case
and a $218 million increase over ANR Pipeline's approved rates for its
restructured services. The increase represents higher plant investment, Order
636 restructuring costs, rate of return and tax rate changes and increased costs
related to the required adoption of recent accounting rule changes, i.e., FAS
106 and FAS 112. The FERC has permitted ANR Pipeline to place its new rates into
effect on May 1, 1994, subject to refund, and subject to further orders.
On July 2, 1993, CIG submitted to the FERC an unanimous offer of settlement
which resolved all the Order 636 restructuring issues which had been raised in
its restructuring proceedings. That settlement was ultimately approved (except
for minor issues), and CIG's restructured services became effective October 1,
1993.
CIG has "unbundled" its gas sales from its other services. Separate
gathering, transportation, storage and other services are available on a "stand-
alone" basis to any customers desiring them. CIG's Order 636 transition costs
are not expected to be material.
On March 31, 1993, CIG filed at FERC to increase its rates by approximately
$26.5 million annually. Such rates (adjusted to reflect CIG's Order 636 program)
became effective subject to refund on October 1, 1993.
CIG, ANR Pipeline, ANR Storage Company and Wyoming Interstate Company, Ltd.,
subsidiaries, are regulated by the FERC. Certain regulatory issues remain
unresolved among these companies, their customers, their suppliers and the FERC.
The Company has made provisions which represent management's assessment of the
ultimate resolution of these issues. While the Company estimates the provisions
to be adequate to cover potential adverse rulings on these and other issues, it
cannot estimate when each of these issues will be resolved.
ENVIRONMENTAL REGULATION - The Company's operations are subject to extensive
federal, state and local environmental laws and regulations. The Company
anticipates annual capital expenditures of $20 to $40 million over the next
several years aimed at compliance with such laws and regulations. Additionally,
appropriate governmental authorities may enforce the laws and regulations with a
variety of civil and criminal enforcement measures, including monetary penalties
and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." Certain subsidiaries of the Company have been named as a potentially
responsible party ("PRP") in several "Superfund" waste disposal sites. At the 15
sites for which the EPA has developed sufficient information to estimate total
clean-up costs of approximately $350 million, the Company estimates it pro-rata
exposure to be paid over a period of several years is approximately $5 million
and has made appropriate provisions. At three other sites, the EPA is currently
unable to provide the Company with an estimate of total clean-up costs and,
accordingly, the Company is unable to calculate its share of those costs.
Finally, at five other sites, the Company has paid amounts to other PRPs as its
proportional share of associated clean-up costs. As to these latter sites, the
Company believes that its activities were de minimis.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. Future information and developments will require
the Company to continually reassess the expected impact of these environmental
matters. However, the Company has evaluated its total environmental exposure
based on currently available data, including its potential joint and several
liability, and believes that compliance with all applicable laws and regulations
will not have a material adverse impact on the Company's liquidity or financial
position.
F-30
NOTE 15. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the years ended December 31, 1993 and
1992 were (millions of dollars except per share):
Quarter Ended
-------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
1993 1993 1993 1993
---------- -------------- ---------- ---------
Operating revenues......................... $2,647.1 $2,631.9 $2,307.9 $2,549.2
Less purchases............................. 1,968.6 1,949.0 1,635.1 1,785.4
-------- -------- -------- --------
678.5 682.9 672.8 763.8
Other income and expenses.................. 653.5 654.1 684.2 687.9
-------- -------- -------- --------
Earnings (loss) before extraordinary item.. 25.0 28.8 (11.4) 75.9
Extraordinary item - loss on early
extinguishment of debt.................... - (2.5) - -
-------- -------- -------- --------
Net earnings (loss)........................ $ 25.0 $ 26.3 $ (11.4) $ 75.9
======== ======== ======== ========
Earnings (loss) per share:
Before extraordinary item................. $ .24 $ .25 $ (.15) $ .68
Extraordinary item........................ - (.02) - -
-------- -------- -------- --------
Net earnings (loss) per common and
common share equivalent share............. $ .24 $ .23 $ (.15) $ .68
======== ======== ======== ========
Quarter Ended
-----------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
1992 1992 1992 1992
-------- -------- -------- --------
Operating revenues......................... $2,536.1 $2,398.6 $2,594.0 $2,534.2
Less purchases............................. 1,908.0 1,734.1 1,912.8 1,903.1
-------- -------- -------- --------
628.1 664.5 681.2 631.1
Other income and expenses.................. 634.1 652.4 659.5 785.7
-------- -------- -------- --------
Net earnings (loss)........................ $ (6.0) $ 12.1 $ 21.7 $ (154.6)
======== ======== ======== ========
Net earnings (loss) per common and common
equivalent share.......................... $ (.06) $ .11 $ .21 $ (1.49)
======== ======== ======== ========
F-31
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES
Reserves, capitalized costs, costs incurred in oil and gas acquisition,
exploration and development activities, results of operations and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas systems reserves and the related
standardized measure of discounted future net cash flows are separately
presented for natural gas operations. Substantially all of the Company's
properties are located in the United States. In 1992, the Company acquired an
equity method investment with operations in Argentina.
The 1991 revisions of previous estimates of Natural Gas Systems reserves of
natural gas are related to the Company's independent engineer's interpretation
of an agreement, effective January 1, 1991, between the Company's subsidiary,
CIG, and Mesa Operating Limited Partnership. Such revisions are not due to
change in gross reserve estimates for the affected properties.
ESTIMATED QUANTITIES OF PROVED RESERVES
Natural Exploration
Gas and
Systems Production
--------- ----------------------
Natural Gas (MMcf): Developed Developed Undeveloped Total
--------- --------- ----------- ---------
1993.................................................... 379,795 422,657 123,077 925,529
1992.................................................... 418,831 466,695 89,306 974,832
1991.................................................... 456,580 395,694 168,915 1,021,189
Oil, Condensate and Natural Gas Liquids (000 barrels):
1993.................................................... 7 24,851 3,935 28,793
1992.................................................... 14 26,242 6,818 33,074
1991.................................................... 13 22,937 7,485 30,435
F-32
Changes in proved reserves since the end of 1990 are shown in the following
table.
Oil, Condensate and
Natural Gas Natural Gas Liquids
(MMcf) (000 barrels)
-------------------------- -------------------------------
Natural Exploration Natural Exploration
Gas and Gas and
Total Proved Reserves Systems Production Systems Production
------------ ------------ --------------- --------------
Total, end of 1990.............. 302,673 592,830 11 33,054
Production during 1991.......... (45,845) (43,501) (2) (4,087)
Extensions and discoveries...... - 34,252 - 1,275
Acquisitions.................... - 11,267 - 676
Sales of reserves in-place...... - (53,254) - (299)
Revisions of previous quantity
estimates and other............ 199,752 23,015 4 (197)
------- ------- -- ------
Total, end of 1991.............. 456,580 564,609 13 30,422
------- ------- -- ------
Production during 1992.......... (47,754) (53,748) (2) (4,757)
Extensions and discoveries...... - 59,052 - 4,167
Acquisitions.................... - 15,489 - 1,579
Sales of reserves in-place...... - (414) - (95)
Revisions of previous quantity
estimates and other............ 10,005 (28,987) 3 1,744
------- ------- -- ------
Total, end of 1992.............. 418,831 556,001 14 33,060
------- ------- -- ------
Production during 1993.......... (46,524) (75,487) (1) (4,939)
Extensions and discoveries...... - 103,876 - 2,746
Acquisitions.................... - 3,706 - 345
Sales of reserves in-place...... - (8,639) - (198)
Revisions of previous quantity
estimates and other............ 7,488 (33,723) (6) (2,228)
------- ------- -- ------
Total, end of 1993.............. 379,795 545,734 7 28,786
======= ======= == ======
Total proved reserves for natural gas systems exclude storage gas and liquids
volumes. The natural gas systems storage gas volumes are 147,549, 183,741 and
191,351 million cubic feet and storage liquids volumes are approximately
150,000, 159,000 and 207,000 barrels at December 31, 1993, 1992 and 1991,
respectively.
CAPITALIZED COSTS RELATING TO EXPLORATION AND PRODUCTION ACTIVITIES
Accumulated
Depreciation,
Capitalized Depletion and
Proved and Unproved Properties Cost Amortization
- ------------------------------ ---------------- ----------------
(Millions of Dollars) December 31, 1993
----------------------------------
Undeveloped.......................... $ 51 $ 18
Developed............................ 1,103 503
------ -----
$1,154 $ 521
------ -----
December 31, 1992
----------------------------------
Undeveloped.......................... $ 67 $ 17
Developed............................ 1,070 471
------ -----
$1,137 $ 488
------ -----
The Company follows the full-cost method of accounting for oil and gas
properties.
F-33
COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
(Millions of dollars)
Year Ended December 31,
--------------------------
1993 1992 1991
------ ----- -----
Property acquisition costs:
Proved.......................................... $ 6 $ 6 $ 12
Unproved........................................ 11 14 20
Exploration costs................................ 6 11 12
Development costs................................ 65 93 46
RESULTS OF OPERATIONS FOR EXPLORATION AND PRODUCTION ACTIVITIES
(Millions of dollars)
Year Ended December 31,
--------------------------
1993 1992 1991
------ ----- -----
Revenues:
Sales.......................................... $ 139 $ 120 $ 108
Transfers...................................... 96 79 63
------ ----- -----
Total.......................................... 235 199 171
------ ----- -----
Production costs................................ (71) (65) (66)
Operating expenses.............................. (28) (27) (27)
Depreciation, depletion and amortization........ (107) (81) (67)
------ ----- -----
29 26 11
Income tax benefit (expense).................... 3 (9) (3)
------ ----- -----
Results of operations for producing activities
(excluding corporate overhead and interest
costs)....................................... $ 32 $ 17 $ 8
====== ===== =====
The average amortization rate per equivalent Mcf was $1.00 for the years 1993,
1992 and 1991.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO PROVED OIL
AND GAS RESERVE QUANTITIES.
Future cash inflows from the sale of proved reserves and estimated production
and development costs as calculated by the Company's independent engineers are
discounted by 10% after they are reduced by the Company's estimate for future
income taxes. The calculations are based on year-end prices and costs, statutory
tax rates and nonconventional fuel source tax credits that relate to existing
proved oil and gas reserves in which the Company has mineral interests.
F-34
The standardized measure is not intended to represent the market value of
reserves and, in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets, may be subject to material
future revisions (millions of dollars):
Year Ended December 31,
----------------------------------------------------------------------
1993 1992 1991
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
-------- ------------ -------- ------------ -------- ------------
Future cash inflows...... $ 299 $1,698 $ 331 $1,838 $335 $1,527
Future production and
development costs....... (63) (647) (51) (717) (56) (709)
Future income tax
expenses................ (82) (237) (95) (223) (94) (122)
----- ------ ----- ------ ---- ------
Future net cash flows.... 154 814 185 898 185 696
10% annual discount for
estimated timing of
cash flows.............. (59) (252) (82) (289) (75) (240)
----- ------ ----- ------ ---- ------
Standardized measure of
discounted future net
cash flows.............. $ 95 $ 562 $ 103 $ 609 $110 $ 456
===== ====== ===== ====== ==== ======
Principal sources of change in the standardized measure of discounted future net
cash flows during each year are (millions of dollars):
Year Ended December 31,
----------------------------------------------------------------------
1993 1992 1991
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
-------- ------------ -------- ------------ -------- ------------
Sales and transfers,
net of production
costs................... $ (35) $(164) $ (52) $(134) $(50) $(105)
Net changes in prices
and production costs.... (1) 7 12 147 (40) (216)
Extensions and
discoveries............. - 139 - 88 - 25
Acquisitions............. - 5 - 22 - 15
Sales of reserves
in-place................ - (5) - - - (44)
Development costs
incurred during the
period that reduced
estimated future
development costs....... - 21 8 56 - 21
Revisions of previous
quantity estimates,
timing and other......... 12 (87) 11 3 60 (10)
Accretion of discount.... 12 56 12 36 12 58
Net change in income
taxes................... 4 (19) 2 (65) 6 109
----- ----- ----- ----- ---- -----
Net change............... $ (8) $ (47) $ (7) $ 153 $(12) $(147)
===== ===== ===== ===== ==== =====
None of the amounts include any value for natural gas systems storage gas, which
was approximately 41 Bcf of gas for CIG, 107 Bcf for ANR Pipeline and 150,000
barrels of liquids for CIG at the end of 1993.
Share of Equity Method Investment - At December 31, 1993, the net investment in
Argentine properties amounted to $58.5 million, representing net proved reserves
of 144.5 Bcf of gas and 6.51 million barrels of oil, condensate and natural gas
liquids. The standardized measure of discounted future net cash flows related to
these reserves is $78.6 million at December 31, 1993. The Company's share of
earnings for 1993 was approximately $5 million.
F-35
SUPPLEMENTAL STATISTICS FOR COAL MINING OPERATIONS
The following table contains Coastal's estimated recoverable coal reserves
for operating properties. Reserves estimates are prepared by independent mining
consultants and by internal sources (Coastal geologists and engineers). The
reliability of the estimates is a function of the amount and quality of the
geological data generated to date on each property and varies considerably from
property to property. The reserve amounts are subject to change depending on
additional geological data generated and/or actual mining operations.
TOTAL RECOVERABLE RESERVES
(Millions of tons)
December 31,
------------------------------------------
1993 1992 1991 1990 1989
------ ------ ------ ------ ------
Total, beginning of year........... 789 806 828 818 719
Production......................... (24) (18) (18) (18) (16)
Purchases (sales).................. 115 8 (5) 40 110
Changes in estimates............... (9) (7) 1 (12) 5
------ ------ ------ ------ ------
Total, end of year................. 871 789 806 828 818
------ ------ ------ ------ ------
Average market price sold per ton.. $25.80 $27.29 $28.07 $27.81 $26.89
====== ====== ====== ====== ======
F-36
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
December 31,
------------------
1993 1992
-------- --------
ASSETS
- ------
CURRENT ASSETS:
Cash and cash equivalents....................................................... $ 114.6 $ 5.0
Receivables..................................................................... 17.5 14.2
Receivables from subsidiaries................................................... 1,360.8 1,625.8
Prepaid expenses and other...................................................... 1.4 1.3
-------- --------
Total Current Assets........................................................... 1,494.3 1,646.3
-------- --------
PROPERTY, PLANT AND EQUIPMENT - at cost, net..................................... 7.3 7.7
-------- --------
INVESTMENTS IN SUBSIDIARIES AND OTHER ASSETS:
Investment in subsidiaries at cost plus equity in undistributed earnings since
acquisition.................................................................... 2,766.7 2,568.4
Due from subsidiaries........................................................... 1,710.2 1,415.6
Deferred federal income taxes................................................... 85.5 139.6
Other assets.................................................................... 252.4 226.2
-------- --------
4,814.8 4,349.8
-------- --------
$6,316.4 $6,003.8
======== ========
See Notes to Condensed Financial Statements.
S-1
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
December 31,
------------------
1993 1992
-------- --------
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES:
Notes payable............................... $ 253.5 $ 198.4
Accounts payable and accrued expenses....... 151.1 166.2
Payable to subsidiaries..................... 620.0 185.8
Current maturities on long-term debt........ 15.1 62.7
-------- --------
Total Current Liabilities.................. 1,039.7 613.1
-------- --------
DUE TO SUBSIDIARIES.......................... 61.7 -
-------- --------
DEBT:
Long-term debt.............................. 2,577.6 3,037.2
Subordinated long-term debt................. 199.7 199.6
-------- --------
2,777.3 3,236.8
-------- --------
DEFERRED CREDITS AND OTHER................... 159.6 144.0
-------- --------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY.. 2,278.1 2,009.9
-------- --------
$6,316.4 $6,003.8
======== ========
See Notes to Condensed Financial Statements.
S-2
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF OPERATIONS
(Millions of Dollars)
Year Ended December 31,
--------------------------
1993 1992 1991
-------- -------- -------
OPERATING REVENUES........................................ $ 1.0 $ 1.4 $ .9
OPERATING COSTS AND EXPENSES.............................. - - -
------ ------- ------
OPERATING PROFIT.......................................... 1.0 1.4 .9
------ ------- ------
OTHER INCOME:
Equity in net earnings of subsidiaries................... 263.9 31.8 86.6
Interest income from subsidiaries - net.................. 119.6 137.4 172.3
Other income - net....................................... 20.0 20.8 40.0
------ ------- ------
403.5 190.0 298.9
------ ------- ------
OTHER EXPENSES (BENEFITS):
General and administrative............................... 12.1 11.3 5.8
Interest and debt expense................................ 364.6 391.1 338.1
Taxes on income.......................................... (90.5) (84.2) (52.8)
------ ------- ------
286.2 318.2 291.1
------ ------- ------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM................. 118.3 (126.8) 8.7
Extraordinary item-loss on early extinguishment of debt.. (2.5) - -
------ ------- ------
NET EARNINGS (LOSS)....................................... $115.8 $(126.8) $ 8.7
====== ======= ======
See Notes to Condensed Financial Statements.
S-3
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
--------------------------
1993 1992 1991
------- -------- -------
Net Cash Flow From Operating Activities:
Net earnings (loss) before extraordinary item..................... $ 118.3 $(126.8) $ 8.7
Items not requiring (providing) cash:
Depreciation, depletion and amortization......................... .5 .5 .4
Deferred income taxes............................................ (36.2) (36.6) (72.0)
Distributed (undistributed) subsidiary earnings.................. (197.3) 110.6 (18.3)
Gain on sale of securities....................................... - - (13.2)
Other............................................................ (9.0) (5.9) (14.6)
Working capital and other changes, excluding changes relating to
cash and non-operating activities:
Receivables..................................................... (3.3) (7.7) 2.4
Prepaid expenses and other...................................... (.1) (.1) 1.4
Accounts payable and accrued expenses........................... (15.1) 63.7 (15.4)
------- ------- -------
(142.2) (2.3) (120.6)
------- ------- -------
Cash Flow from Investing Activities:
Purchases of property, plant and equipment........................ (.9) (1.0) (.8)
Net change in accounts with subsidiaries.......................... 553.3 (239.9) (145.6)
Additions to investments.......................................... (1.0) (4.0) (39.9)
Proceeds from investments......................................... - 84.8 133.2
------- ------- -------
551.4 (160.1) (53.1)
------- ------- -------
Cash Flow from Financing Activities:
Increase (decrease) in short-term notes........................... 55.1 (152.6) (172.7)
Proceeds from issuing common stock................................ 11.9 7.1 6.0
Proceeds from issuing preferred stock............................. 193.5 - -
Proceeds from long-term debt issues............................... 80.1 543.8 670.0
Payments to retire long-term debt................................. (587.2) (190.0) (287.3)
Dividends paid.................................................... (53.0) (42.0) (42.0)
------- ------- -------
(299.6) 166.3 174.0
------- ------- -------
Net Increase in Cash and Cash Equivalents.......................... 109.6 3.9 .3
Cash and Cash Equivalents at Beginning of Year..................... 5.0 1.1 .8
------- ------- -------
Cash and Cash Equivalents at End of Year........................... $ 114.6 $ 5.0 $ 1.1
======= ======= =======
See Notes to Condensed Financial Statements.
S-4
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE III - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
NOTES TO CONDENSED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Principles of Consolidation -- The financial statements of the Company
reflect the investment in wholly-owned subsidiaries using the equity method.
Statement of Cash Flows -- For purposes of this statement, cash equivalents
include time deposits, certificates of deposit and all highly liquid instruments
with original maturities of three months or less. The Company made cash payments
for interest and financing fees of $357.1 million, $375.6 million and $313.6
million in 1993, 1992 and 1991, respectively. Cash payments (refunds - primarily
from subsidiaries) for income taxes amounted to $(49.8) million, $(63.9) million
and $(6.9) million for 1993, 1992 and 1991, respectively.
Federal Income Taxes -- The Company follows the liability method of
accounting for income taxes as required by the provisions of FAS 109,
"Accounting for Income Taxes."
The Company files a consolidated federal income tax return with its wholly-
owned subsidiaries. Members of the consolidated group with taxable incomes are
charged with the amount of income taxes as if they filed separate federal income
tax returns, and members providing deductions and credits which result in income
tax savings are allocated credits for such savings.
Reclassification of Prior Period Statements - Certain minor reclassifications
of prior period statements have been made to conform with current reporting
practices. The effect of the reclassifications was not material to the Company's
results of operations or financial position.
NOTE 2. CONSOLIDATED FINANCIAL STATEMENTS
Reference is made to the Consolidated Financial Statements and related Notes
of Coastal and Subsidiaries for additional information.
NOTE 3. DEBT AND GUARANTEES
Information on the debt of the Company is disclosed in Note 5 of the Notes to
Consolidated Financial Statements included herein. The Company has guaranteed
certain long-term debt of its subsidiaries (approximately $82.4 million
outstanding at December 31, 1993, including current maturities) and certain
other obligations arising in the ordinary course of business. The Company and
certain of its subsidiaries have entered into interest rate and currency swaps
with major banking institutions. The Company is exposed to loss if one or more
counterparties default. In addition, the Company or certain of its subsidiaries
are guarantors on certain bank loans of corporations and partnerships in which
the Company or certain subsidiaries have equity interests. Information on the
swaps and guarantees is disclosed in Note 5 of the Notes to Consolidated
Financial Statements.
The aggregate amounts of long-term debt (including subordinated debt)
maturities of Coastal for the five years following 1993 are (millions of
dollars):
1994.......... $ 15.1 1997.......... $231.9
1995.......... 162.6 1998.......... 230.0
1996.......... 98.3
NOTE 4. DIVIDENDS RECEIVED
Cash dividends received from consolidated subsidiaries were as follows: 1993
- - $66.6 million, 1992 - $142.8 million and 1991 - $68.1 million.
S-5
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE V - PROPERTY, PLANT AND EQUIPMENT
(Millions of Dollars)
Balance at Other Balance
Beginning Additions Retire- Changes- at End
Classification of Year at Cost ments Add (Deduct) of Year
- -----------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
- ----------------------------
Refining, crude oil and chemical facilities.. $1,697.2 $130.3 $ 17.7 $ 6.2 (A) $1,821.3
5.3 (B)
Gas systems.................................. 5,393.1 119.8 46.7 (7.2)(A) 5,461.6
2.6 (B)
Gas and oil properties....................... 1,194.1 91.8 20.2 (17.3)(A) 1,204.2
(5.3)(B)
(38.9)(C)
Coal......................................... 463.6 36.0 .7 4.6 (A) 511.3
7.8 (B)
Trucking..................................... 46.1 4.0 5.2 - 44.9
Other........................................ 123.4 10.8 2.3 (.7)(A) 120.8
(10.4)(B)
-------- ------ ------ ------ --------
$8,917.5 $392.7 $ 92.8 $(53.3) $9,164.1
======== ====== ====== ====== ========
Year Ended December 31, 1992
- ----------------------------
Refining, crude oil and chemical facilities.. $1,536.4 $173.3 $ 9.7 $ (2.8)(A) $1,697.2
Gas systems.................................. 5,193.2 231.7 18.9 4.5 (A) 5,393.1
(17.4)(E)
Gas and oil properties....................... 1,110.7 126.8 17.9 4.5 (A) 1,194.1
(30.0)(C)
Coal......................................... 434.0 33.3 .4 (3.7)(A) 463.6
.4 (B)
Trucking..................................... 44.9 .7 8.8 9.3 (A) 46.1
Other........................................ 121.0 7.7 .2 (1.7)(A) 123.4
(.4)(B)
(3.0)(D)
-------- ------ ------ ------ --------
$8,440.2 $573.5 $ 55.9 $(40.3) $8,917.5
======== ====== ====== ====== ========
Year Ended December 31, 1991
- ----------------------------
Refining, crude oil and chemical facilities.. $1,152.5 $391.5 $ 15.1 $ 7.5 (A) $1,536.4
Gas systems.................................. 5,017.7 181.5 17.5 4.1 (A) 5,193.2
7.4 (E)
Gas and oil properties....................... 1,099.4 95.4 48.9 (8.9)(A) 1,110.7
(26.3)(C)
Coal......................................... 390.7 44.7 .9 (.5)(A) 434.0
Trucking..................................... 57.5 3.7 20.6 4.3 (A) 44.9
Other........................................ 84.1 12.1 .2 (10.7)(A) 121.0
35.7 (E)
-------- ------ ------ ------ --------
$7,801.9 $728.9 $103.2 $ 12.6 $8,440.2
======== ====== ====== ====== ========
- --------------------
(A) Reclassifications and other miscellaneous adjustments.
(B) Intercompany transfer.
(C) Amortization of exploration cost charged to income.
(D) Writedown of property, plant and equipment.
(E) Reclass -- Investment in partially-owned company.
S-6
Depreciation, depletion and amortization of gas and oil properties costs are
provided on the unit-of-production basis whereby the unit rate for depreciation,
depletion and amortization is determined by dividing the total unrecovered
carrying value of all gas and oil properties plus estimated future development
costs by the estimated proved reserves included therein, as estimated by an
independent engineer. Provisions for depletion of coal properties are based upon
estimates of recoverable reserves using the unit-of-production method. Provision
for depreciation of other property is made primarily on a straight-line basis
over the estimated useful lives of the property.
The annual rates of depreciation are as follows:
Refining, crude oil and chemical facilities.. 3.0% -- 20.0%
Gas systems.................................. 0.7% -- 20.0%
Coal facilities.............................. 5.0% -- 33.3%
Transportation equipment..................... 5.0% -- 33.3%
Office and miscellaneous equipment........... 2.5% -- 20.0%
Buildings and improvements................... 1.3% -- 33.3%
S-7
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE VI - ACCUMULATED DEPRECIATION, DEPLETION AND AMORTIZATION
OF PROPERTY, PLANT AND EQUIPMENT
(Millions of Dollars)
Additions
Balance at Charged to Other Balance
Beginning Costs and Retire- Changes at End
Description of Year Expenses ments Add (Deduct) of Year
- -----------------------------------------------------------------------------------------------------------
Year Ended December 31, 1993
- ----------------------------
Refining, crude oil and chemical facilities.. $ 501.4 $ 45.6 $12.9 $ 6.8 (A) $ 542.0
1.1 (B)
Gas systems.................................. 1,743.8 145.4 20.4 (1.8)(A) 1,867.0
Gas and oil properties....................... 502.1 70.2 20.6 (17.3)(A) 533.3
(1.1)(B)
Coal......................................... 177.7 28.5 (.7) 4.6 (A) 213.9
2.4 (B)
Trucking..................................... 14.9 3.3 2.6 2.2 (A) 17.8
Other........................................ 41.8 8.0 .5 (4.9)(A) 42.0
(2.4)(B)
-------- ------ ----- ------ --------
$2,981.7 $301.0 $56.3 $(10.4) $3,216.0
======== ====== ===== ====== ========
Year Ended December 31, 1992
- ----------------------------
Refining, crude oil and chemical facilities.. $ 407.6 $ 98.1 $ 5.9 $ 1.6 (A) $ 501.4
Gas systems.................................. 1,574.0 187.1 16.1 (1.2)(A) 1,743.8
Gas and oil properties....................... 461.8 53.2 17.6 4.7 (A) 502.1
Coal......................................... 150.1 28.4 .3 (.6)(A) 177.7
.1 (B)
Trucking..................................... 7.2 3.6 6.0 10.1 (A) 14.9
Other........................................ 34.0 8.2 .2 (.1)(A) 41.8
(.1)(B)
-------- ------ ----- ----- --------
$2,634.7 $378.6 $46.1 $14.5 $2,981.7
======== ====== ===== ===== ========
Year Ended December 31, 1991
- ----------------------------
Refining, crude oil and chemical facilities.. $ 371.1 $ 40.3 $ .1 $ (3.7)(A) $ 407.6
Gas systems.................................. 1,414.1 177.0 15.2 (1.9)(A) 1,574.0
Gas and oil properties....................... 439.9 43.1 9.3 (11.9)(A) 461.8
Coal......................................... 125.0 27.1 (.8) (2.8)(A) 150.1
Trucking..................................... 9.5 3.8 13.8 7.7 (A) 7.2
Other........................................ 26.6 6.3 .1 1.2 (A) 34.0
-------- ------ ----- ------ --------
$2,386.2 $297.6 $37.7 $(11.4) $2,634.7
======== ====== ===== ====== ========
- ---------------
(A) Reclassifications and other miscellaneous adjustments.
(B) Intercompany transfer.
S-8
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE VIII - VALUATION AND QUALIFYING ACCOUNTS
(Millions of Dollars)
Additions
Balance at Charged to Balance
Beginning Costs and at End
Description of Year Expenses Other of Year
- -----------------------------------------------------------------------------
Year Ended December 31, 1993
- ----------------------------
Allowance for doubtful accounts $16.5 $11.2 $(11.6)(A) $16.1
===== ===== ====== =====
Year Ended December 31, 1992
- ----------------------------
Allowance for doubtful accounts $16.7 $9.0 $ (9.2)(A) $16.5
===== ==== ====== =====
Year Ended December 31, 1991
- ----------------------------
Allowance for doubtful accounts $22.4 $6.8 $(12.5)(A) $16.7
===== ==== ====== =====
- -----------------
(A) Accounts charged off net of recoveries.
S-9
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE IX - SHORT-TERM BORROWINGS
(Millions of Dollars)
Maximum Average Weighted
Weighted Amount Amount Average
Balance Average Outstanding Outstanding Interest
Category of Aggregate at End Interest During the During the Rate During
Short-Term Borrowings of Year Rate Year Year the Year
- ------------------------------------------------------------------------------------
December 31, 1993
Notes payable to banks $263.5 3.93% $404.4 $216.0 3.80%
====== ==== ====== ====== ====
December 31, 1992
Notes payable to banks $221.4 4.31% $717.0 $517.1 4.43%
====== ==== ====== ====== ====
December 31, 1991
Notes payable to banks $380.0 5.79% $724.3 $454.5 6.66%
====== ==== ====== ====== ====
The average amount of borrowings were computed by averaging the daily
outstanding balances. Where interest expense was affected by commitment and/or
facility fees, the weighted average interest rates were computed by averaging
the daily interest rates, including such fees. If there were no such fees, the
weighted average interest rates were computed by dividing the total interest for
the year by the average aggregate borrowings outstanding.
S-10
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE X - SUPPLEMENTARY INCOME STATEMENT INFORMATION
(Millions of Dollars)
Charged to Costs and Expenses
Year Ended December 31,
-----------------------------
1993 1992 1991
--------- -------- --------
Maintenance and repairs (1) $193.2 $188.8 $180.2
Taxes, other than payroll and income taxes (2) 140.6 130.2 126.0
- -----------
(1) Amounts are charged to operating costs and expenses with the exception of
an insignificant amount which, together with other expenses, are
redistributed to operating, construction and other accounts.
(2) Production taxes are charged against operating revenues.
S-11
EXHIBIT INDEX
Exhibit
Number Document
- ------ --------
[C] [S]
3.1+ Restated Certificate of Incorporation of Coastal, as restated on March
22, 1994. (Filed as Module TCC-Artl-Incorp on March 28, 1994).
3.2+ By-Laws of Coastal, as amended on January 16, 1990 (Exhibit 3.4 to
Coastal's Annual Report on Form 10-K for the fiscal year ended December
31, 1989).
4 (With respect to instruments defining the rights of holders of long-term
debt, the Registrant will furnish to the Commission, on request, any
such documents).
10.1+ The Coastal Corporation Stock Option Plan (Exhibit 10.1 to Coastal's
Annual Report on Form 10-K for the fiscal year ended December 31, 1980).
10.2+ Employment Agreement between Coastal States Gas Corporation and Sam F.
Willson, Jr., dated December 1, 1979 (Exhibit 10.41 to Coastal's Annual
Report on Form 10-K for the fiscal year ended December 31, 1980).
10.3+ First Amendment of The Coastal Corporation Stock Option Plan, dated
September 3, 1981 (Exhibit 10.11 to Coastal's Annual Report on Form 10-K
for the fiscal year ended December 31, 1982).
10.4+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement for the
1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.5+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement for the
1986 Annual Meeting of Stockholders, dated March 27, 1986).
10.6+ The Coastal Corporation Performance Unit Plan effective as of January 1,
1987 (Exhibit 10.5 to Coastal's Annual Report on Form 10-K for the
fiscal year ended December 31, 1987).
10.7+ The Coastal Corporation Replacement Pension Plan effective as of
November 1, 1987 (Exhibit 10.6 to Coastal's Annual Report on
Form 10-K for the fiscal year ended December 31, 1987).
10.8+ Description of Coastal's Key Employees Bonus Plan (Exhibit 10.7 to
Coastal's Annual Report on Form 10-K for the fiscal year ended December
31, 1987).
10.9+ The Coastal Corporation Stock Purchase Plan, as restated on January 1,
1994 (Appendix B to Coastal's Proxy Statement for the 1994 Annual
Meeting of Stockholders dated March 29, 1994).
10.10+ The Coastal Corporation Stock Grant Plan, effective December 1, 1988
(Exhibit 10.12 to Coastal's Annual Report on Form 10-K for the fiscal
year ended December 31, 1988).
10.11+ The Coastal Corporation Deferred Compensation Plan for Directors
(Exhibit 10.13 to Coastal's Annual Report on Form 10-K for the fiscal
year ended December 31, 1988).
10.12+ The Coastal Corporation 1990 Stock Option Plan (Exhibit 10.13 to
Coastal's Annual Report on Form 10-K for the fiscal year ended December
31, 1989).
10.13+ Employment Agreement between The Coastal Corporation and James F. Cordes
dated April 12, 1990 (Exhibit 10.13 to Coastal's Annual Report on Form
10-K for the fiscal year ended December 31, 1990).
EXHIBIT INDEX
Exhibit
Number Document
- ------ --------
10.14* The Coastal Corporation Deferred Compensation Plan.
10.15+ The Coastal Corporation 1994 Incentive Stock Plan (Appendix A to
Coastal's Proxy Statement for the 1994 Annual Meeting of Stockholders
dated March 29, 1994).
10.16* Pension Plan for Employees of The Coastal Corporation as of January 1,
1993, includes Plan as Restated as of January 1, 1989 and First
Amendment dated July 27, 1992, Second Amendment dated December 9, 1992,
Third Amendment dated October 29, 1993.
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23.1* Consent of Deloitte & Touche.
24* Powers of Attorney (included on signature pages herein).
99+ Indemnity Agreement revised and updated as of April, 1988 (Exhibit 28 to
Coastal's Annual Report on Form 10-K for the fiscal year ended December
31, 1990).
_________________________
Note:
+ Indicates documents incorporated by reference from the prior filing
indicated.
* Indicates documents filed herewith.