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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, 1994 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 of (I.R.S. Employer Identification No.)
incorporation or organization)
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)
$2.125 Cumulative Preferred Stock, New York Stock Exchange
Series H ($.33 1/3 par value)
11-3/4% Senior Debentures 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
10% 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 15, 1995, there were outstanding 104,363,374 shares of common
stock, 415,949 shares of Class A common stock, 63,118 shares of $1.19 Cumulative
Convertible Preferred Stock, Series A, 83,756 shares of $1.83 Cumulative
Convertible Preferred Stock, Series B, 34,191 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 $2.5 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 1995 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
<TABLE>
<CAPTION>
ITEM NO. PAGE
<S> <C> <C>
Glossary........................................... (ii)
PART I
1. Business......................................... .. 1
Introduction....................................... 1
Natural Gas Systems................................ 1
Operations....................................... 1
ANR Pipeline..................................... 3
Colorado......................................... 4
ANR Storage Company.............................. 5
Gas System Reserves.............................. 6
Wyoming Interstate Company, Ltd.................. 6
Great Lakes Gas Transmission Limited Partnership. 7
Coastal Gas Services Company..................... 7
Regulations Affecting Gas Systems................ 7
Other Developments............................... 10
Refining, Marketing and Distribution............... 11
Exploration and Production......................... 13
Coal............................................... 17
Chemicals.......................................... 18
Independent Power Production....................... 18
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...... 27
PART IV
14. Exhibits, Financial Statement Schedules, and
Reports on Form 8-K.................................. 28
</TABLE>
(i)
<PAGE>
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
"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
"Order 636" means FERC Order No. 636 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)
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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 16,300 persons as of December 31, 1994.
Annual Reports on Form 10-K for the year ended December 31, 1994, are also
filed by Coastal's subsidiaries, ANR Pipeline and Colorado, and by each of the
four 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, 1994, 1993 and 1992, and the related
identifiable assets as of December 31, 1994, 1993 and 1992, 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 transportation, storage, gathering 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 auctions gas on the open market in
producing areas to handle a residual quantity of gas purchased under certain
continuing gas purchase contracts pending renegotiation or expiration of such
contracts. ANR Pipeline operates two 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, an intrastate pipeline extending from Niagara Falls to
Syracuse, New York, in which an affiliate of ANR Pipeline has a 45% interest.
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. ANR Pipeline's principal pipeline facilities at
December 31, 1994 consisted of 12,661 miles of pipeline and 96 compressor
stations with 1,069,398 installed horsepower. At December 31, 1994, 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.
1
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Colorado is involved in the production, gathering, processing,
transportation, storage and sale of natural gas. Colorado purchases and produces
natural gas and makes sales of such gas at the wellhead 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, 1994 consisted of
6,356 miles of pipeline and 66 compressor stations with approximately 348,000
installed horsepower. At December 31, 1994, 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
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. In 1994,
CGS formed Coastal Electric Services Company to market electricity and provide
related physical and financial services.
COMPETITION
ANR Pipeline and Colorado have historically competed with interstate and
intrastate pipeline companies in the sale, transportation and storage 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, Colorado's gas sales contracts
have been unbundled at the producer wellhead and 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. Additional information on Order 636 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 transportation, storage 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 Consolidated Gas Company and CMS Energy Company in its principal market
areas of Michigan and Wisconsin for its transportation, storage and balancing
business. ANR Pipeline's gathering services, which are offered in the southeast
and southwest gas producing areas of the United States, compete with other
providers of such services, including gathering companies, producers and
intrastate and interstate pipeline companies.
2
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ANR PIPELINE
TRANSPORTATION SERVICES AND GAS SALES
On November 1, 1992, as part of its Interim Settlement, ANR Pipeline
implemented a restructuring of its traditional sales services 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" transportation, storage and balancing service
options. Additional information concerning Order 636, including transportation
and storage, is set forth in "Regulations Affecting Gas Systems - General"
included herein.
ANR Pipeline transports gas to markets on its system and also transports gas
to other markets off its system under transportation and exchange arrangements
with other companies including distributors, intrastate and interstate
pipelines, producers, brokers, marketers and end-users. Transportation service
revenues amounted to $555 million for 1994 compared to $533 million for 1993 and
$463 million for 1992. The significant increase in transportation revenues for
1993 was largely attributable to the restructuring of ANR Pipeline's sales
service under the Interim Settlement, as discussed above.
Gas sales revenues of ANR Pipeline amounted to $106 million during 1994,
compared to $604 million in 1993 and $635 million in 1992. The significant
decrease in 1994 is due to the elimination of ANR Pipeline's merchant function
effective November 1, 1993, as discussed above. Gas sales revenues in 1994 were
derived primarily from the auctioning of gas on the open market in producing
areas, as previously discussed.
During 1994, ANR Pipeline's throughput was 1,371 Bcf, of which approximately
24% was transported for 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 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 cities of Racine, Kenosha,
Appleton and their surrounding areas in Wisconsin. In 1994, ANR Pipeline
provided approximately 70% and 35% of the total gas requirements for Wisconsin
and Michigan, respectively.
ANR Pipeline's system deliveries for the years 1994, 1993 and 1992 are as
follows:
<TABLE>
<CAPTION>
Total System Daily Average
Year Deliveries System Deliveries
---------- -------------- -----------------
(Bcf) (MMcf)
<S> <C> <C>
1994 1,371 3,756
1993 1,336 3,660
1992 1,335 3,648
</TABLE>
3
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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 a residual quantity of gas
under certain remaining gas purchase contracts. ANR Pipeline's Order 636
restructured tariff provides a transitional mechanism 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
the auctioning of such gas on the open market in producing areas.
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 reclassified 62.1 Bcf of
working gas to recoverable base gas, which is pending approval before the FERC.
ANR Pipeline also has the contract rights for 42 Bcf of storage capacity
provided by Blue Lake Gas Storage Company and 30 Bcf of storage capacity
provided by ANR Storage. Underground storage services of up to 180 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, 1994, 1993 and 1992 were
113.8 Bcf, 106.5 Bcf and 128.0 Bcf, respectively. The 1994 gas storage reserves
are comprised of 23.4 Bcf of natural gas, maintained under ANR Pipeline's own
account as working gas for system balancing and no-notice services and 90.4 Bcf
of recoverable base gas reserves. Of the total recoverable base gas reserves,
28.3 Bcf represents reserves in the seven owned and eight leased storage fields
and 62.1 Bcf represents working gas which ANR Pipeline has reclassified as
recoverable base gas.
COLORADO
GAS SALES, STORAGE AND TRANSPORTATION
Beginning in October 1993, Colorado implemented Order 636 on its system and
as a result, Colorado's gas sales contracts have been unbundled and such sales
are now made at the producer 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
the 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 October 1, 1993, Colorado assigned an undivided interest in a
portion of its company-owned leases to a new subsidiary. The subsidiary
contracts 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 by Colorado represent those interests retained by
Colorado together with those assigned to the new subsidiary.
Gas sales revenues were $139 million in 1994, compared to $223 million in
1993 and $261 million in 1992. The decreases are 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
4
<PAGE>
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, Colorado has "unbundled" these services
from its sales services and continues to provide these services to third parties
under individual contracts. Such services are at negotiated rates that are
within minimum and maximum levels approved 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 1994, 1993 and 1992 are as follows:
<TABLE>
<CAPTION>
Total System Daily Average
Year Deliveries System Deliveries
------------- -------------- -----------------
(Bcf) (MMcf)
<S> <C> <C>
1994 436 1,195
1993 453 1,241
1992 428 1,169
</TABLE>
GAS GATHERING AND PROCESSING
Colorado 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.
Colorado has approximately 3,000 miles of gathering lines and approximately
110,200 horsepower of compression in its gathering operations. Colorado owns and
operates six gas processing plants which recovered approximately 88 million
gallons of liquid hydrocarbons in 1994, compared to 86 million gallons in 1993
and 77 million gallons in 1992, and 4,300 long tons of sulfur in 1994, compared
to 4,400 long tons in 1993 and 3,600 long tons in 1992. Additionally, in 1994,
Colorado processed approximately 6 million gallons of liquid hydrocarbons owned
by others compared to 12 million in 1993 and 10 million in 1992. 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 COMPANY
ANR Storage develops and operates gas storage reservoirs to store gas for
customers. ANR Storage owns four underground storage fields and related
facilities in northern Michigan, the working storage capacity of which is
approximately 56 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. All of the jointly owned capacity is committed under long term contracts,
including 42 Bcf contracted to ANR Pipeline.
5
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GAS SYSTEM RESERVES
ANR PIPELINE
With the termination of its merchant service, ANR Pipeline no longer reports
on gas system reserves and, therefore, this report has been replaced by a
general discussion set forth in "Producing Area Deliverability", presented
below.
PRODUCING AREA DELIVERABILITY
Shippers on ANR Pipeline have direct access to the two most prolific gas
producing areas in the United States, the Gulf Coast and the Midcontinent.
Statistics published by the Energy Information Agency, Office of Oil and Gas,
U.S. Department of Energy, indicate that approximately 81% of all natural gas in
the lower 48 states is produced from these two areas. Interconnecting pipelines
provide shippers with access to all other major gas producing areas in the
United States and Canada.
Gas deliverability available to shippers on ANR Pipeline's system from the
Midcontinent and Gulf Coast producing areas through direct connections and
interconnecting pipelines and gatherers is approximately 4,200 MMcf per day. An
additional 250 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 sources of natural
gas to facilitate transportation arrangements made by third-party shippers.
During 1994, field development, newly connected gas wells, gas production
facilities and pipeline interconnections contributed over 1,100 MMcf per day to
total deliverability accessible to shippers on ANR Pipeline's pipeline system.
COLORADO
Colorado has reported in its Form 10-K for the year ended December 31, 1994
its gas system reserves based on information prepared by Huddleston, the
Company's independent engineers. Additional information is set forth in
"Reserves Dedicated to a Particular Customer," presented below.
RESERVES DEDICATED TO A PARTICULAR CUSTOMER
Colorado is committed to sell gas to Mesa Operating Company ("Mesa"), a
customer, under a 1928 agreement as amended, from specific owned gas reserves in
the West Panhandle Field of Texas. Under an amendment which became effective
January 1, 1991, a cumulative 23% of the total net production may be taken for
customers other than Mesa. Effective October 1, 1993, an undivided interest in
the West Panhandle Field leases, related to this 23% of the total net production
not committed to Mesa, was assigned by Colorado to a new subsidiary.
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.
The FERC has approved an agreement under which Columbia Gas Transmission
Corporation, one of these shippers, will pay WIC an "exit fee" and its contract
will be terminated. The FERC's order remains pending on rehearing. In 1994, the
WIC line transported an average of 339 MMcf daily, compared to 228 MMcf daily in
1993. On January 1, 1992, WIC became an unrestricted open access transporter.
6
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GREAT LAKES GAS TRANSMISSION LIMITED PARTNERSHIP
Coastal and TransCanada, a non-affiliated company, each own 50% of Great
Lakes which owns a 2,000-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 897 Bcf in 1994 as compared to
854 Bcf in 1993. Great Lakes has long term 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
CGS and its subsidiaries operate the Company's unregulated natural gas
business, including certain of Coastal's natural gas gathering and processing,
gas supply and marketing, price risk management and producer financing
activities. In mid-1994, CGS expanded its functional areas to form Coastal
Electric Services Company to market electricity and provide related physical and
financial services. Additionally, in May, 1994, CGS's subsidiary, CGMC,
accelerated its transition from a national marketing company to a North American
operation by opening Coastal Gas Marketing Canada, in Calgary, Alberta, which
focuses on Canadian markets and supplies. CGS, through its subsidiaries, managed
the sale and delivery of over 1,000 Bcf of natural gas in 1994, as compared to
828 Bcf in 1993, and processed over 109 Bcf of natural gas, producing over 2.6
million barrels of natural gas liquids in 1994. Also, in 1994, CGS arranged a
$250 million production payment facility to make capital available to producers,
including affiliates, with long term oil and natural gas supplies. CGS and its
affiliates conduct business with over 1,200 producer and market customers in
Canada, Mexico and the United States.
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, storage, gathering and
balancing of gas, rates and charges, 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. Additionally the
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 and approved by the 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. Certain other
affiliates of the Company are subject to the jurisdiction of state regulatory
commissions in states where their facilities are located.
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
7
<PAGE>
volumes. Colorado has also filed for and recovered take-or-pay settlement costs
through the same regulatory provisions.
Contract reformation, take-or-pay costs and other costs incurred as a result
of the mandated Order 636 restructuring are recoverable either under the
transition costs mechanisms of Order 636 or through negotiated agreements with
the customers of ANR Pipeline and Colorado.
On April 8, 1992, the FERC issued 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. The case is currently in the briefing phase
before the United States Court of Appeals for the D.C. Circuit. 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. As of October 1, 1993, Colorado separated all of its
services and separately contracts for each service on a stand-alone or
"unbundled" basis. Gathering, storage and transportation services are provided
at negotiated rates established between minimum and maximum levels approved by
the FERC, while gas processing rates are not subject to FERC regulations.
On November 1, 1993, ANR Pipeline placed its Order 636 restructured services
and rates into effect. Several persons, including ANR Pipeline, have sought
judicial review of aspects of the FERC's orders approving ANR Pipeline's
restructuring filings. Those appeals have been held in abeyance by the United
States Court of Appeals for the D.C. Circuit, pending further order. On March
24, 1994, the FERC issued its "Fourth Order on Compliance Filing and Third Order
on Rehearing," which addressed numerous rehearing issues and confirmed that
after minor required tariff modifications, ANR Pipeline is now fully in
compliance with Order 636 and the requirements of the orders on its
restructuring filings. The FERC issued a further order regarding certain
compliance issues on July 1, 1994. In accordance with this order, ANR Pipeline
filed revised tariff sheets on July 18, 1994.
RATE MATTERS
ANR PIPELINE. 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 became effective November 1, 1992 and expired
with ANR Pipeline's implementation of Order 636 on November 1, 1993. Under the
Interim Settlement, gas inventory demand charges were collected from ANR
Pipeline's resale customers for the period November 1, 1992 through October 31,
1993. This method of gas cost recovery required refunds for any over-
collections, and placed ANR Pipeline at risk for under-collections. As required
by the Interim Settlement, ANR Pipeline filed with the FERC on April 29, 1994, a
reconciliation report showing over-collections and, therefore, proposed refunds
totaling $45.1 million. Such refund obligations were recorded at December 31,
1994 and December 31, 1993, and are included in the Consolidated Balance Sheet
under "Deferred Credits and Other." Certain customers have disputed the level of
those refunds. By an order issued in February 1995, the FERC has directed ANR
Pipeline to make immediate refunds of $45.1 million and applicable interest,
subject to further investigation of the claims which the customers have made.
The matter is still pending.
On November 1, 1993, ANR Pipeline filed a general rate increase with the FERC
under Docket RP94-43. The increase represents the effects of 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 No. 106, "Employers' Accounting for Postretirement Benefits
Other Than Pensions" and FAS No. 112, "Employers' Accounting for Postemployment
Benefits." On March 23, 1994, the FERC issued an order granting and denying
various requests for summary disposition and establishing hearing procedures for
issues remaining to be investigated in this proceeding. The order required the
reduction or elimination of certain costs which resulted in revised rates such
that the revised rates reflect an $85.7 million increase in the cost of service
from that approved in the Interim
8
<PAGE>
Settlement and a $182.8 million increase over ANR Pipeline's approved rates for
its restructured services under Order 636. On April 29, 1994, ANR Pipeline filed
a motion with the FERC that placed the new rates into effect May 1, 1994,
subject to refund. On September 21, 1994, the FERC accepted ANR Pipeline's
filing in compliance with the March 23, 1994 order, subject to further
modifications including an additional reduction in cost of service of
approximately $5 million. ANR Pipeline submitted its compliance filing to the
FERC on October 6, 1994, which compliance filing was accepted by order issued
December 8, 1994, subject to a further compliance filing requirement, which ANR
Pipeline submitted on January 9, 1995, and which was accepted by an order issued
in February 1995. Further, on December 8, 1994, the FERC issued its order
denying rehearing of the March 23, 1994 order. On January 26, 1995, ANR Pipeline
sought judicial review of these orders before the United States Court of Appeals
for the D.C. Circuit.
ANR Pipeline has executed a Settlement Agreement (the "Settlement Agreement")
with Dakota Gasification Company ("Dakota") and the Department of Energy which
resolves litigation concerning purchases of synthetic gas by ANR Pipeline from
the Great Plains Coal Gasification Plant (the "Plant"). That litigation,
originally filed in 1990 in the United States District Court in North Dakota,
involved claims regarding ANR Pipeline's obligations under certain gas purchase
and transportation contracts with the Plant. The Settlement Agreement resolves
all disputes between the parties, amends the gas purchase agreement between ANR
Pipeline and Dakota and terminates the transportation contract. The Settlement
Agreement is subject to final FERC approval, including an approval for ANR
Pipeline to recover the settlement costs from its customers. On August 3, 1994,
ANR Pipeline filed a petition with the FERC requesting: (a) that the Settlement
Agreement be approved; (b) an order approving ANR Pipeline's proposed tariff
mechanism for the recovery of the costs incurred to implement the Settlement
Agreement; and (c) an order dismissing a proceeding currently pending before the
FERC, wherein certain of ANR Pipeline's customers have challenged Dakota's
pricing under the original gas supply contract. On October 18, 1994, the FERC
issued an order consolidating ANR Pipeline's petition with similar petitions of
three other pipeline companies and setting the Settlement Agreement and other
Dakota-related proceedings for limited hearing before an Administrative Law
Judge who must render an initial decision by December 31, 1995. On December 20,
1994, ANR Pipeline filed its testimony, and has responded to numerous discovery
requests. The hearing is scheduled to commence on June 20, 1995. ANR Pipeline
believes the ultimate resolution of the Dakota related issues will not have a
material adverse impact on its financial position or results of operations.
Order 636 provides mechanisms for recovery of transition costs associated
with compliance with that Order. ANR Pipeline has estimated that its transition
costs will amount to approximately $150 million, which will consist primarily of
gas supply realignment costs, the cost of stranded pipeline investment and the
Dakota costs described above. As of December 31, 1994, ANR Pipeline has incurred
transition costs in the amount of $43 million. ANR Pipeline has filed for
recovery of approximately $40.5 million of these transition costs, which have
been accepted and made effective by the FERC, subject to refund and subject to
further proceedings. In addition, ANR Pipeline has filed for recovery of
approximately $90 million of costs associated with the Settlement Agreement, as
mentioned above. Additional transition cost filings will be made by ANR Pipeline
in the future. 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 financial position or results of operations.
COLORADO. Colorado's gas sales for resale 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 the FERC. Colorado is also
authorized to abandon all sales for resale without prior FERC approval at such
time as the contracts expire. Pursuant to Order 636, Colorado's gas sales have
been unbundled at the producer wellhead.
On March 31, 1993, Colorado filed at FERC under Docket RP93-99 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. On November 10, 1994, the FERC approved a settlement offer
submitted by Colorado which resolved all of the issues in the proceeding.
Colorado has implemented the rates established in the settlement for prospective
application and will be required to make refunds as a result of the approval of
the settlement. Such refunds will be distributed in March 1995. Colorado has
fully accrued for these refunds and therefore such refunds will not have an
adverse effect on its consolidated financial position or results of operations.
9
<PAGE>
WIC. In 1993, the FERC initiated proceedings under Section 5 of the NGA to
review WIC's rates. Those proceedings resulted in an Administrative Law Judge
decision as well as a FERC order which would have required WIC to reduce its
rates prospectively. However, during the period that such proceedings were under
way, WIC filed to revise its rates and on March 3, 1995, the FERC issued an
order accepting an uncontested settlement between WIC, the FERC staff and the
parties to the case which resolved WIC's rates for the period beginning December
1, 1994. The FERC issued an order on March 21, 1995 which terminated the 1993
rate proceedings and vacated its previously issued orders in that docket. WIC
will be required to make refunds for amounts collected subsequent to December 1,
1994 which are in excess of the amounts that would have been collected under the
settlement rates. WIC has fully accrued for these refunds and therefore such
refunds will not have an adverse effect on its financial position or results of
operations.
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.
OTHER DEVELOPMENTS
Effective September 9, 1994, Florida Power Corporation ("FPC") withdrew as an
equity partner in both the SunShine Interstate Transmission Company and SunShine
Pipeline Company ("SunShine") partnerships. Interests in these partnerships are
now held by affiliates of ANR Pipeline and TransCanada. FPC has also terminated
its agreements with the partnerships to transport gas on the proposed SunShine
system effective March 2, 1995. Future development of the SunShine project is
currently under management review. SunShine has obtained a delay in proceedings
pending before the Florida Department of Environmental Protection until October
1995 and on February 24, 1995, requested that FERC allow ninety days for
SunShine to report the results of its review.
Sponsors of the Liberty Pipeline Project ("Liberty") asked the FERC, on
August 1, 1994, to postpone indefinitely its review of the project following the
withdrawal in early June of one key shipper who was also a project partner and
the withdrawal of another shipper. As a result, the FERC dismissed the
application on August 12, 1994. As originally proposed, Liberty consisted of a
38-mile pipeline extending from New Jersey across New York Harbor to Long Island
with a potential capacity of 500 MMcf per day and was estimated to cost $170
million. A subsidiary of ANR Pipeline holds a 25.9% interest in the project. The
Liberty partners continue to believe that an additional delivery point onto Long
Island, as proposed by Liberty, will be necessary in the future and plan to
continue pursuing that goal.
ANR Pipeline has filed an application with the FERC to construct, at a cost
of $15.3 million, approximately 12 miles of new pipeline in the State of
Michigan (the "Link Project") which would interconnect to approximately 8 miles
of new pipeline to be constructed by The Consumers' Gas Company, Ltd.
("Consumers") at the Canadian-United States border. The Link Project is an
amendment to ANR Pipeline's earlier application to construct the InterCoastal
Pipe Line, which was denied approval by the Canadian National Energy Board. The
new facilities will have a capacity of 150 MMcf per day and will serve markets
in the United States and Canada, including Consumers and Michigan Consolidated
Gas Company. Consumers is expected to file for the necessary Canadian regulatory
approvals by the end of March 1995, and, subject to the receipt of the necessary
FERC and Canadian regulatory approvals, the project could be in service as early
as November 1, 1995.
A subsidiary of ANR Pipeline has a 45% equity interest in the proposed
Mayflower Pipeline project, which will be owned by a partnership consisting of
ANR Pipeline's subsidiary and affiliates of TransCanada and Brooklyn Union Gas
Company. The project is proposed to provide natural gas transportation and
storage services to markets in the northeastern United States. 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 project could be in service by late 1999, subject to
the receipt of federal regulatory approvals of its construction.
10
<PAGE>
In August 1993, ANR Pipeline and NorAm Energy Corporation, formerly Arkla,
Inc. ("NorAm") announced the execution of a restructured agreement under which
ANR Pipeline, subject to certain conditions precedent, will purchase an
ownership interest in 250 MMcf per day of capacity in existing gas transmission
facilities. On March 25, 1994, the FERC issued an Order approving this
acquisition, subject to certain conditions. NorAm and ANR Pipeline have filed
for judicial review of this Order and FERC's Order on Rehearing issued September
20, 1994.
Construction of the new 5.3 Bcf Young Storage Field in northeastern Colorado,
in which an affiliate of Colorado is a 47.5% partner, began in 1994. This new
storage field is expected to be completed in the first half of 1995 and already
is fully subscribed under 30-year contracts.
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.
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
average combined capacity in 1994 and 1993. The aggregate sales volumes
(millions of barrels) of Coastal's wholly-owned refineries for the three years
ended December 31, 1994, were 136 (1994), 134.9 (1993) and 136.7 (1992). A joint
venture, Pacific Refining Company, had sales of 18.8 million barrels in 1994,
19.9 million barrels in 1993 and 21.3 million barrels in 1992 which were
excluded from Coastal's 1994, 1993 and 1992 sales. Of the total refinery sales
in 1994, 28% was gasoline, 47% was middle distillates, such as jet fuel, diesel
fuel and home heating oil, and 25% was heavy industrial fuels and other
products.
The average daily processing capacity of crude oil at December 31, 1994,
average daily throughput and storage capacity at the Company's wholly-owned
operating refineries are set forth below:
<TABLE>
<CAPTION>
Daily Storage
Capacity Average Daily Capacity
Refinery Location (Barrels) Throughput (Barrels) (Barrels)
--------- -------- --------- -------------------- ---------
1994 1993
-------- --------
<S> <C> <C> <C> <C> <C>
Aruba* Aruba 175,000 151,700 136,400 8,000,000
Corpus Christi Corpus Christi, Texas 100,000 81,700 79,300 7,500,000
Eagle Point Westville, New Jersey 130,000 111,000 109,300 10,400,000
Mobile Mobile, Alabama 17,500 14,900 13,500 600,000
------- ------- ------- ----------
Total Operating 422,500 359,300 338,500 26,500,000
</TABLE>
* In March 1995, the Company began a program of comprehensive maintenance
and inspections at its Aruba refinery. The Company is performing the
maintenance now to take advantage of a period of worldwide low refining
margins and to prepare for the integration of a new $100 million delayed
coker unit coming on line at the refinery later this year. The delayed coker
unit will provide for conversion of about 23,000 barrels per day of residual
fuel oil into more valuable light-end petroleum products and petroleum coke.
Process operations at the Aruba refinery have been suspended for the duration
of the maintenance program.
11
<PAGE>
Pacific Refining at Hercules, California has a refining capacity of 55,000
barrels per day at December 31, 1994. 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 1994 and processed 44,142 barrels per day
of crude oil and other feedstocks. Present plans are to continue operation of
the refinery, 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 Amendments of 1990 and California Air Resources Board regulations
compliance upgrades.
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 1994, the products emphasized included premium gasolines and
products for specialty markets such as petrochemical feedstocks, aviation fuels
and asphalt.
In July 1994, Coastal Aruba Refining Company N.V., a subsidiary of Coastal,
acquired approximately 4.5 million barrels of crude oil storage previously under
a long term lease arrangement. A related ship berth capable of handling very
large crude carrier tanker ships was also acquired.
In August 1994, Coastal Canada Petroleum, Inc., a subsidiary of Coastal,
signed agreements under which the Company has restarted production of paraxylene
at a petrochemical plant in Montreal East, Quebec, Canada. The facility has the
capability of producing up to 400 million pounds per year of paraxylene, a
component used in the manufacturing of polyester fibers and containers. Coastal
Canada Petroleum, Inc. acquired the processing equipment and entered into a long
term lease for the plant site. Other aromatic production units could be
restarted as economic conditions and petrochemical markets warrant. The
paraxylene unit was restarted in October. The unit has averaged 88% of capacity
since start-up and now is operating at its rated capacity of 400 million pounds
per year.
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, 1994, are set forth
below (thousands of barrels):
<TABLE>
<CAPTION>
Type of Sale 1994 1993 1992
------------ ------- ------- -------
<S> <C> <C> <C>
Company Produced Refined Products....... 135,973 134,925 136,664
Refined Products Purchased from Others.. 145,093 140,635 162,280
Natural Gas Liquids..................... 17,352 18,155 17,038
------- ------- -------
Total.............. 298,418 293,715 315,982
======= ======= =======
</TABLE>
Subsidiaries of the Company market refined products and liquefied petroleum
gas at wholesale in 37 states through 372 terminals. Coastal Refining &
Marketing, Inc. serves customers in the Midwest, Mississippi Valley and the
Southwest through 263 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 1994, these subsidiaries' sales volumes were
126 million barrels, which accounted for approximately 42% 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.
12
<PAGE>
A subsidiary of Coastal leases 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. Another
subsidiary of Coastal is a partner in a joint venture with a subsidiary of the
Malaysian national oil company, Petronas, which uses 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 37 states
through approximately 1,457 Coastal branded outlets, with 574 of those outlets
operated by the Company. Fleet fueling operations include 21 outlets in Texas
and 8 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 35 states.
TRANSPORTATION. The Company's transportation facilities include petroleum
liquids pipelines, tank cars, tankers, tank trucks and barges. Coastal has
approximately 1,700 miles of pipeline for gathering and transporting an average
of 218,000 barrels daily of crude oil, condensate, natural gas liquids and
refined products. These lines are located principally in Texas and include 226
miles of crude oil pipelines, 737 miles of refined products pipelines and 671
miles of natural gas liquids pipelines, all 100% owned and operated by Coastal
affiliates, and 80 miles of jointly-owned products pipelines with less than a
50% interest. In 1994, throughput of crude oil pipelines averaged 18,339 barrels
per day, compared to 148,199 barrels per day in 1993. In 1994, throughput of
refined products and natural gas liquid pipelines averaged 200,037 barrels per
day, compared to 186,430 barrels per day in 1993.
Other transportation facilities for marketing operations of Coastal
subsidiaries include a regional tank truck fleet which distributes refined
products and liquefied petroleum gas products to customers in parts of Florida,
New England and New York, and another fleet of trucks, which transports
petroleum products and liquefied petroleum gas products for Coastal marketing
subsidiaries serving the Texas area.
The marine transportation total fleet at December 31, 1994 consisted of 15
tug boats, 23 oil barges, 7 owned tankers used for the transportation of refined
petroleum products and crude oil and 2 time-chartered tankers.
EXPLORATION AND PRODUCTION
GAS AND OIL PROPERTIES
Coastal subsidiaries are engaged in gas and oil exploration, development and
production operations 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 addition, Coastal subsidiaries are engaged in exploratory concessions
in Peru and China.
In 1994, the Company's domestic operations sold approximately 60% 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.
13
<PAGE>
Acreage held under gas and oil mineral leases as of December 31, 1994 is
summarized as follows:
<TABLE>
<CAPTION>
UNDEVELOPED DEVELOPED
---------------- ----------------
AREA GROSS NET GROSS NET
---- ----- --------- --------- -----
(Thousands of Acres)
<S> <C> <C> <C> <C>
United States (Domestic)
Onshore................ 892 643 1,814 943
Offshore............... 116 46 102 76
----- ----- ----- -----
Total Domestic......... 1,008 689 1,916 1,019
----- ----- ----- -----
International
China.................. 894 358 - -
Peru................... 2,974 2,974 - -
----- ----- ----- -----
Total International.... 3,868 3,332 - -
----- ----- ----- -----
TOTAL.................. 4,876 4,021 1,916 1,019
===== ===== ===== =====
</TABLE>
The domestic net acreage held for production is concentrated principally in
Texas (32%), Utah (22%), Oklahoma (9%), West Virginia (7%), offshore Gulf of
Mexico (7%), Kansas (5%) and Wyoming (5%). Approximately 25%, 17% and 21% of the
Company's total domestic undeveloped net acreage is under leases that have
minimum remaining primary terms expiring in 1995, 1996 and 1997, respectively.
Productive wells as of December 31, 1994 are as follows (domestic):
<TABLE>
<CAPTION>
TYPE OF WELL GROSS NET
------------ ----- -----
<S> <C> <C>
Oil.................. 3,563 1,007
Gas.................. 2,682 1,420
----- -----
TOTAL............... 6,245 2,427
===== =====
</TABLE>
EXPLORATION AND DRILLING
During 1994, Coastal's domestic exploration and production units participated
in drilling 108 gross wells, 47.7 net wells, to the Company's interest.
Coastal's participation in wells drilled in the three years ended December 31,
1994, is summarized as follows:
<TABLE>
<CAPTION>
1994 1993 1992
----------- ----------- -----------
EXPLORATORY WELLS GROSS NET GROSS NET GROSS NET
----------------- ----- --- ----- --- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Oil............... 1 0.2 1 0.5 6 1.8
Gas............... 2 1.3 - - 3 1.7
Dry Holes......... 5 2.9 7 4.1 16 9.1
---- ---- --- ---- --- -----
8 4.4 8 4.6 25 12.6
==== ==== === ==== === =====
DEVELOPMENT WELLS
----------------------
Oil............... 15 6.1 44 18.6 47 18.4
Gas............... 82 35.1 104 51.2 141 108.5
Dry Holes......... 3 2.1 2 1.1 11 8.3
---- ---- --- ---- --- -----
100 43.3 150 70.9 199 135.2
==== ==== === ==== === =====
</TABLE>
14
<PAGE>
Wells in progress as of December 31, 1994 are as follows (domestic):
TYPE OF WELL GROSS NET
------------ ----- ---
Exploratory........ 1 0.4
Development........ 21 7.8
--- -----
Total............. 22 8.2
=== =====
Coastal Limited Ventures, Inc., a domestic subsidiary of Coastal, is the
general partner in four 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.
Coastal renewed its emphasis on the Gulf of Mexico in 1994 by acquiring over
79,000 net leasehold acres, including reserves, platforms, production facilities
and exploration acreage. Coastal began to emphasize international exploration
opportunities during 1994 with a subsidiary signing a contract for exploration
and development rights covering a 100% interest in approximately 2.97 million
acres in central Peru and another subsidiary acquiring a 40% interest in
exploration and development rights to approximately 895,000 acres in the East
China Sea.
GAS AND OIL PRODUCTION
Natural gas production during 1994 averaged 345 MMcf daily, compared to 334
MMcf daily in 1993. Production from non-pipeline-owned wells averaged 218 MMcf
daily in 1994, compared to 207 MMcf daily in 1993. Crude oil, condensate and
natural gas liquids production averaged 12,239 barrels daily in 1994, compared
to 13,534 barrels daily in 1993.
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, 1994:
<TABLE>
<CAPTION>
NATURAL GAS
OIL CONDENSATE LIQUIDS
GAS (THOUSANDS (THOUSANDS (THOUSANDS
YEAR (MMCF) OF BARRELS) OF BARRELS) OF BARRELS)
-------------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
1994 125,773 3,634 429 404
1993 122,011 3,908 440 592
1992 101,502 3,823 496 440
</TABLE>
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.
15
<PAGE>
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, 1994:
<TABLE>
<CAPTION>
1994 1993 1992
------ ------ ------
<S> <C> <C> <C>
Average sales price (net of production taxes):
Gas - per Mcf..................................... $ 1.77 $ 1.93 $ 1.76
Oil - per barrel.................................. 14.96 16.21 18.21
Condensate - per barrel........................... 14.69 15.55 17.40
Natural Gas Liquids - per barrel.................. 8.36 8.75 9.62
Average production cost per unit (equivalent Mcf).. 0.67 0.67 0.79
</TABLE>
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 1994, total revenues of
$34.5 million were generated from the extraction and sale of 124 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, 1994, as estimated by Huddleston, its independent
engineers, were 33.7 million barrels, compared to 28.8 million barrels at the
end of 1993. Proved gas reserves as of December 31, 1994, net to Coastal's
interest, were estimated by the engineers to be 958.4 Bcf compared to 925.5 Bcf
as of December 31, 1993.
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.
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.
16
<PAGE>
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 western United States, 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, 1994, coal properties consisted of the following:
<TABLE>
<CAPTION>
Coal Holdings (Acres)
-------------------------------------------------- Clean,
Owned Leased Recoverable
---------------------------- Exchanged Total Tons
Fee Mineral Surface (Net) Acres (Millions)(1)
------ ----------- ------- ----------- --------- -------------
<S> <C> <C> <C> <C> <C> <C>
Kentucky....... 14,284 75,728 2,331 25,832 118,175 209
Virginia....... 23,800 37,495 2,072 21,289 84,656 165
West Virginia.. 1,867 36,772 4,156 124,352 167,147 223
Utah........... - 2,480 - 32,077 34,557 242
------ ------- ----- ------- ------- ---
TOTAL....... 39,951 152,475 8,559 203,550 404,535 839
====== ======= ===== ======= ======= ===
</TABLE>
________________________
(1) Based on a 65% recovery rate.
At December 31, 1994, the Company controlled approximately 839 million
recoverable tons of bituminous coal reserves. Production in 1994 from the
Company's reserves totalled 20.4 million tons of which 16.1 million tons were
produced from captive operations and 4.3 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 1994 totalled 7.0 and 9.1 million
tons, respectively.
Captive sales from ANR Coal and Coastal States Energy were 7.6 million and
8.7 million tons, respectively, in 1994. Brokerage sales in which the Company
receives a commission on coal sold for third parties totalled 1.2 million tons
for the same period.
In 1994, approximately 67% of sales were to domestic utilities, 18% of sales
were to domestic industrial customers and 15% of sales were to export markets
primarily in Asia and Canada. Of the total 1994 tonnage sold, 12.5 million tons
(77%) were sold under long-term contracts. At December 31, 1994, the weighted
average remaining life of these contracts was 60 months.
The Company had approximately 21.5 million tons of annual production capacity
at December 31, 1994. In the eastern United States, the Company owns and
operates six coal preparation plants and nine loading facilities with a combined
annual capacity of 10.8 million tons. Coastal States Energy's mines in Utah
employ three longwall mining systems, diesel shuttle cars and have a combined
annual capacity of 10.7 million tons.
In addition to its bituminous coal operations, the Company controls
overriding royalty interests in approximately 468 million tons of lignite
reserves in North Dakota. Production from these reserves in 1994 totalled 16.0
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
17
<PAGE>
the Company to remain a major supplier of steam coal to domestic utilities under
the Clean Air Act Amendments 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, which facility produces 400 tons per day. The
LoDAN/(R)/ product is used primarily as a blasting agent in surface mining.
Coastal Chem also operates an integrated methyl tertiary butyl ether ("MTBE")
plant with a production capacity of 4,000 barrels per day. MTBE is a gasoline
additive which adds oxygen and boosts octane of the blended mixture.
Sales volumes for the three years ended December 31, 1994, are set forth
below (thousands of tons):
<TABLE>
<CAPTION>
1994 1993 1992
---- ---- ----
<S> <C> <C> <C>
Agricultural Sales.. 188 222 214
Industrial Sales.... 407 410 407
MTBE................ 187 119 -
---- ---- ----
TOTAL............ 782 751 621
==== ==== ====
</TABLE>
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
18
<PAGE>
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.
In February 1995, Coastal Power signed a letter of intent to form a joint
venture to build and operate one or more power plants of up to 120 megawatts in
the industrial center of Wuxi City in the People's Republic of China. Phase one
of this project is estimated to have approximately 40 megawatts of capacity at a
cost to Coastal Power of $15 to $18 million. The other joint venturer would be a
company formed between the Wuxi New Energy Investment Company, a subsidiary of
the local power bureau, and China National Aero-Engine Corporation, a subsidiary
of Aviation Industries of China.
In January 1995, a subsidiary of Coastal Power initialled an acquisition
agreement contemplating the purchase of the stock of Compania de Electricidad de
Puerto Plata, S.A. ("CEPP"), an independent power company in the Dominican
Republic with a capacity of 69.5 megawatts of which 50 megawatts are barge
mounted and 19.5 megawatts are land based. A subsidiary of Coastal Power would
own about 48.5% of CEPP's shares and Commonwealth Development Corporation of the
United Kingdom would also own about 48.5% of CEPP's shares. The remainder of
shares would be owned by Basic Energy Ltd., a Bermuda corporation.
In August 1994, construction commenced on a 91-megawatt power plant in El
Salvador leased by a subsidiary of Coastal Power in association with a
Salvadoran investor and to be operated by a Coastal subsidiary. Electricity from
this new power plant, which is expected to be in operation in the second half of
1995, will be sold to the Salvadoran national utility under a 20 year power
purchase agreement.
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 1994, ANR Freight transported approximately 1.6 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 1.4 million tons
in 1993. LTL shipments comprised approximately 40% of total tonnage hauled by
ANR Freight and generated approximately 81% of its operating revenues. As of
December 31, 1994, ANR Freight operated 40 terminals and almost 4,000 trucks,
tractors and trailers.
The expanded scope of deregulation has increased competition among motor
carriers. 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, private carriers of truckload general freight,
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 have been adopted by most carriers. ANR
Freight may continue to participate, on a limited basis, in collective rate
making within the regional rate bureaus as still authorized under the Trucking
Industry Regulatory Reform Act of 1994. ANR Freight also carries freight under
contract and under general and individual tariff arrangements.
19
<PAGE>
New federal legislation (the Negotiated Rates Act of 1993, the Trucking
Industry Regulatory Reform Act of 1994, and the Federal Aviation Authorization
Act of 1994) eliminated state regulation of rates, routes and service of all
motor carriers and eliminated filing requirements for individually established
tariffs and for all contract carriage arrangements at the federal level.
Regulatory oversight of the motor carrier industry now focuses on safety and
financial responsibility. The Interstate Commerce Commission, which also
regulates accounting practices in the motor carrier industry, has been reduced
in staff and scope of responsibility. 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, driver qualifications and alcohol and drug testing. 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 and evolving federal, state
and local environmental laws and regulations. The Company anticipates capital
expenditures of $70 million in 1995 in order to comply with such laws and
regulations. The majority of the 1995 expenditures is attributable to major
construction projects on the sulfur recovery units at two of the Company's
refineries. The Company currently anticipates capital expenditures for
environmental compliance for years 1996 through 1998 of $20 to $40 million per
year. 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
seventeen sites for which the EPA has developed sufficient information to
estimate total clean-up costs of approximately $400 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, 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 four other sites, the Company has paid amounts
to other PRPs or to the EPA as its proportional share of associated clean-up
costs. As to these latter sites, the Company believes that its activities were
de minimis. In addition, a subsidiary of Coastal has been named as a de minimis
PRP in one state "Superfund" site. However, since the agency having jurisdiction
over the state site is currently unable to provide an estimate of the total
clean-up costs, the Company is unable to calculate its subsidiary's share of
those costs.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. The states have regulatory programs that mandate
waste clean-up. The Clean Air Act Amendments of 1990 include new permitting
regulations which will result in increased operating expenditures. Coastal is
also supplying reduced-emission reformulated gasoline in all markets where it is
required or optionally requested.
20
<PAGE>
In October 1994, the Texas Natural Resources Conservation Commission
("TNRCC") sent a notification letter to Coastal Refining & Marketing, Inc.
("CR&M"), a subsidiary of the Company, alleging violations of the Resources
Conservation and Recovery Act. The TNRCC has referred the allegations to the
office of the Attorney General of the State of Texas. The Company believes that
this action could result in monetary sanctions which, while not material to the
Company and its subsidiaries, could exceed $100,000.
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.
A subsidiary of ANR Pipeline owns a 9.4% interest in Iroquois Gas
Transmission System, L.P. ("Iroquois"), a 370-mile pipeline which transports gas
from Canada to the northeastern United States (the "Iroquois Pipeline").
Iroquois contracted with Iroquois Pipeline Operating Company ("IPOC") for IPOC
to construct and operate the Iroquois Pipeline. Federal and state agencies
(including the United States Attorney's office for the Northern District of New
York) have been investigating alleged civil and criminal violations of
environmental laws related to the construction and operation of the Iroquois
Pipeline by IPOC. It is possible that this investigation could result in
monetary sanctions, of which ANR Pipeline's subsidiary's share, while not
material to the Company and its subsidiaries, could exceed $100,000.
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, financial position or
results of operations.
ITEM 2. PROPERTIES.
Information on properties of Coastal is included in Item 1, "Business"
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 U.S. 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 were 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 were subject to "permitted
liens" as defined in such Mortgage and Deed of Trust. The First Mortgage Pipe
Line Bonds were retired in 1993 and the associated Mortgage and Deed of Trust
was terminated in 1994.
ITEM 3. LEGAL PROCEEDINGS.
A subsidiary of the Company 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 the Company
and certain subsidiaries. TransAmerican alleged 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. Final
Judgment in this matter was entered April 22, 1994. The subsidiary was awarded
approximately $2.0 million, including pre-judgment interest and attorney fees.
All of TransAmerican's claims and causes of action were denied. The judgment has
been
21
<PAGE>
appealed by TransAmerican and the case is presently pending before the Court of
Appeals for the Fourth Judicial District at San Antonio, Texas.
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. Trial has been set for March 22, 1995.
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 or
results of operations. 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
<PAGE>
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 15, 1995, the approximate number of holders of
record of Common Stock was 9,452 and of the Class A Common Stock was 3,682.
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.
<TABLE>
<CAPTION>
1994 1993
------------------------- -------------------------
Quarters High Low Dividends High Low Dividends
---------------- ------ ------ --------- ------ ------ ---------
<S> <C> <C> <C> <C> <C> <C>
First Quarter $33.75 $27.50 $.10 $27.38 $23.50 $.10
Second Quarter 32.63 26.88 .10 28.50 25.63 .10
Third Quarter 33.25 27.38 .10 31.38 25.63 .10
Fourth Quarter 29.13 24.75 .10 29.50 26.13 .10
</TABLE>
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
1994 and 1993. At December 31, 1994, 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 $583.2 million.
23
<PAGE>
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, 1993. The Notes to Consolidated Financial Statements
included herein contain other information relating to this data.
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------
1994 1993 1992 1991 1990
--------- --------- ---------- --------- ---------
<S> <C> <C> <C> <C> <C>
Operating revenues $10,215.3 $10,136.1 $10,062.9 $ 9,554.8 $ 9,613.8
Earnings (loss) before extraordinary item 232.6 118.3 (126.8) 8.7 264.2
Net earnings (loss) 232.6 115.8 (126.8) 8.7 264.2
Earnings (loss) per common and common
equivalent share before extraordinary
item 2.05 1.02 (1.23) .08 2.52
Net earnings (loss) per common and
common equivalent share 2.05 1.00 (1.23) .08 2.52
Cash dividends per common share* .40 .40 .40 .40 .40
Total assets 10,534.6 10,227.1 10,579.8 10,520.3 10,399.8
Debt, excluding current maturities 3,720.2 3,812.5 4,306.1 3,865.6 3,438.8
Mandatory redemption preferred stock,
excluding current maturities .6 26.6 36.7 49.2 65.1
</TABLE>
* In addition, cash dividends of $.36, $.36, $.36, $.36 and $.18, were paid on
the Company's Class A Common Stock in 1994, 1993, 1992, 1991 and 1990,
respectively.
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-8 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
<PAGE>
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 4, 1995 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 15, 1995, were as
follows:
NAME (AGE), YEAR FIRST
ELECTED AN OFFICER POSITIONS AND OFFICES WITH THE REGISTRANT
--------------------------- -----------------------------------------
O. S. Wyatt, Jr. (70), 1955 Chairman of the Board of Directors and Chief
Executive Officer
David A. Arledge (50), 1982 President, Chief Operating Officer, Chief
Financial Officer and Director
Harold Burrow (80), 1974 Vice Chairman of the Board of Directors,
Chairman of the Board of Directors of Colorado
James F. Cordes (54), 1985 Executive Vice President and Director
James A. King (55), 1992 Executive Vice President
Sam F. Willson, Jr. (65), 1974 Executive Vice President
Jerry D. Bullock (65), 1992 Senior Vice President
Jeffrey A. Connelly (48), 1988 Senior Vice President
Carl A. Corrallo (51), 1993 Senior Vice President and General Counsel
Donald H. Gullquist (51), 1994 Senior Vice President
Coby C. Hesse (47), 1986 Senior Vice President and Controller
Dan J. Hill (54), 1978 Senior Vice President
Kenneth O. Johnson (74), 1978 Senior Vice President and Director
Austin M. O'Toole (59), 1974 Senior Vice President and Secretary
Jack C. Pester (60), 1987 Senior Vice President
James L. Van Lanen (50), 1985 Senior Vice President
M. Truman Arnold (66), 1993 Vice President
Daniel F. Collins (53), 1989 Vice President
Robert C. Hart (50), 1994 Vice President
John J. Lipinski (44), 1995 Vice President
Edward A. More (46), 1995 Vice President
M. Frank Powell (44), 1993 Vice President
E. C. Simpson (59), 1990 Vice President
Thomas M. Wade (42), 1995 Vice President
Ronald D. Matthews (47), 1994 Treasurer
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
<PAGE>
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. 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. Lipinski was elected Vice President of Coastal in March 1995. He has held
various positions with subsidiaries of Coastal since 1985.
Mr. Matthews was elected Treasurer of the Company and Vice President and
Treasurer of ANR Pipeline in September 1994. He was also elected Vice President
and Treasurer of Colorado in October 1994. He has served as Assistant Treasurer
of Coastal since 1983 and as Vice President of Coastal States Management
Corporation, a subsidiary of Coastal, since 1991.
Mr. More was elected Vice President of Coastal in March 1995. He has held
various positions with subsidiaries of Coastal since 1991. Prior thereto, he
served as Executive Vice President at Harken Marketing, Inc. from 1987 to 1991.
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.
Mr. Wade was elected Vice President of Coastal in March 1995. He has held
various positions with subsidiaries of Coastal since 1980.
ITEM 11. EXECUTIVE COMPENSATION.
The information called for by this item is set forth under "Executive
Compensation", "Compensation and Executive Development Committee Report on
Executive Compensation", "Pension Plan" and "Performance Graphs--Shareholder
Return on Common Stock" in the Coastal Proxy Statement for the May 4, 1995
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 4, 1995 Annual Meeting of Stockholders filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, and is
incorporated herein by reference.
26
<PAGE>
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 4, 1995 Annual Meeting
of Stockholders filed pursuant to Regulation 14A under the Securities Exchange
Act of 1934, and is incorporated herein by reference.
27
<PAGE>
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:
<TABLE>
<CAPTION>
Page
----
<S> <C>
Independent Auditors' Report............................................................................. F-9
Statement of Consolidated Operations for the years ended December 31, 1994, 1993 and 1992 F-10
Consolidated Balance Sheet at December 31, 1994 and 1993................................................. F-11
Statement of Consolidated Cash Flows for the years ended December 31, 1994, 1993 and 1992................ F-13
Statement of Consolidated Common Stock and Other Stockholders'
Equity for the years ended December 31, 1994, 1993 and 1992............................................ F-14
Notes to Consolidated Financial Statements............................................................... F-15
Supplemental Information on Oil and Gas Producing Activities (Unaudited)................................. F-35
Supplemental Statistics for Coal Mining Operations (Unaudited)........................................... F-39
</TABLE>
2. Financial Statement Schedules.
The following schedules of Coastal and Subsidiaries are included
on the attached pages as indicated:
<TABLE>
<CAPTION>
Page
----
<S> <C>
Schedule I -- Condensed Financial Information of the Registrant........................................... S-1
Schedule II-- Valuation and Qualifying Accounts........................................................... S-6
</TABLE>
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+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement
for the 1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.2+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement
for the 1986 Annual Meeting of Stockholders, dated March 27,
1986).
10.3+ 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).
28
<PAGE>
10.4+ 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).
10.5+ 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).
10.6+ 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).
10.7+ 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).
10.8+ 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).
10.9+ 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).
10.10+ 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).
10.11+ The Coastal Corporation Deferred Compensation Plan (Exhibit 10.14
to Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1993).
10.12+ 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).
10.13+ 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 (Exhibit
10.16 to Coastal's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993).
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23* Consent of Deloitte & Touche LLP.
24* Powers of Attorney (included on signature pages herein).
27* Financial Data Schedule.
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, 1994.
29
<PAGE>
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 28, 1995
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
By: O. S. WYATT, JR.
------------------------
O. S. Wyatt, Jr.
Chairman of the Board and Chief Executive Officer
March 28, 1995
By: DAVID A. ARLEDGE
------------------------
David A. Arledge
Principal Financial Officer and Director
March 28, 1995
By: COBY C. HESSE
------------------------
Coby C. Hesse
Principal Accounting Officer
March 28, 1995
By: JOHN M. BISSELL
------------------------
John M. Bissell
Director
March 28, 1995
* * *
30
<PAGE>
By: GEORGE L. BRUNDRETT, JR. By: KENNETH O. JOHNSON
----------------------------- -----------------------------
George L. Brundrett, Jr. Kenneth O. Johnson
Director Director
March 28, 1995 March 28, 1995
By: HAROLD BURROW By: JEROME S. KATZIN
----------------------------- -----------------------------
Harold Burrow Jerome S. Katzin
Director Director
March 28, 1995 March 28, 1995
By: ROY D. CHAPIN, JR. By: THOMAS R. McDADE
----------------------------- -----------------------------
Roy D. Chapin, Jr. Thomas R. McDade
Director Director
March 28, 1995 March 28, 1995
By: JAMES F. CORDES By:
----------------------------- -----------------------------
James F. Cordes J. Howard Marshall, II
Director Director
March 28, 1995 March ___, 1995
By: ROY L. GATES By: L. D. WOODDY, JR.
----------------------------- -----------------------------
Roy L. Gates L. D. Wooddy, Jr.
Director Director
March 28, 1995 March 28, 1995
31
<PAGE>
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.
<TABLE>
<CAPTION>
1994 1993 1992
----- ----- ------
<S> <C> <C> <C>
Net return on average common stockholders' equity...... 10.0% 5.2% (6.0%)
Cash flow from operating activities to long-term debt.. 18.0% 21.2% 10.1%
Total debt to total capitalization..................... 61.7% 64.3% 69.3%
Times interest earned (before tax)..................... 1.8 1.4 .6
</TABLE>
The above ratios reflect increased earnings and decreased long-term debt in
both 1994 and 1993. The 1994 decrease in cash flow from operating activities to
long-term debt resulted from decreased cash flow as a result of changes in
working capital offset by a reduction in long-term debt, while the 1993 increase
resulted from increased cash flow from operations and reduced long-term debt.
Cash flows provided from operating activities were $669.1 million in 1994 and
$809.8 million in 1993. The 1994 decrease can be attributed to increases for
working capital requirements partially offset by increased earnings.
Capital expenditures amounted to $543.2 million in 1994 and $392.7 million in
1993. The increased expenditures in 1994 were due to expansion of the earnings
bases in the Refining and Marketing and Exploration and Production segments. The
Refining and Marketing increase is primarily due to improvements made at the
refineries to produce higher value products and expansion of petrochemical
operations into Canada. The Exploration and Production segment increase results
from reserve additions which were more than double the 1994 production. The
Company had returned to a lower level of capital spending in 1993 as it
emphasized debt reduction. Proceeds from equity investments exceeded additions
by $55.5 million in 1994 while the additions exceeded proceeds by $34.8 million
in 1993. Prepayments for gas supply and payments for settlement of natural gas
contract disputes required an investment of $11.4 million in 1993.
The Company was able to reduce total debt by $208.9 million in 1994,
primarily by the use of internally generated funds and other financial
transactions. Dividend payments increased by $6.3 million as a result of the new
preferred stock issue in 1993. The increase in redemption of mandatory
redemption preferred stock is due to ANR Pipeline redeeming all shares of its
outstanding Cumulative Preferred Stock under sinking fund provisions and
optional redemption provisions.
Capital expenditures for 1995, including the Company's equity investments in
partnerships and joint ventures, are currently budgeted at approximately $540
million; however, future expenditures are dependent on conditions in the energy
industry. 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 1995
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
<PAGE>
On September 23, 1993, ANR Pipeline Company ("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 were used for capital expenditures and for other general corporate
purposes.
Unused lines of credit at December 31, 1994 were as follows (millions of
dollars):
<TABLE>
<CAPTION>
<S> <C>
Short-term..................... $ 753.1
Long-term*..................... 694.5
--------
$1,447.6
========
</TABLE>
* $235 million of unused long-term credit lines is dedicated to a specific
use.
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, 1994, net assets of
consolidated subsidiaries amounted to approximately $5.1 billion, of which
approximately $1.8 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.
The Company's operations involve managing market risks related to changes in
interest rates and foreign exchange rates. Derivative financial instruments,
specifically interest rate swaps and foreign currency swaps, are used to reduce
and manage these risks. The Company currently does not hold or issue financial
instruments for trading purposes.
The Company has entered into a number of interest rate swap agreements
designated as a partial hedge of the Company's portfolio of variable rate debt.
The purpose of these swaps is to fix interest rates on variable rate debt and
reduce the exposure to interest rate fluctuations. At December 31, 1994, the
Company had interest rate swaps with a notional amount of $550.0 million, and a
portfolio of variable rate debt outstanding in the amount of $643.2 million. The
Company has also entered into a number of interest rate swap agreements which
have effectively converted $250.0 million of fixed rate debt into floating rate
debt. The variable rate swaps have rates equal to the London Interbank Offered
Rate ("LIBOR"), which is subject to change over time as LIBOR fluctuates. Terms
expire at various dates through the third quarter of 1996. At December 31, 1994,
the Company had no exposure to credit loss on interest rate swaps.
The Company has also entered into a number of foreign currency swaps to fully
hedge to maturity the foreign currency denominated debt of the Company and its
subsidiaries. At December 31, 1994, the Company had outstanding yen-denominated
debt of $199.4 million and the Company and its subsidiaries had swiss franc
denominated debt of $126.5 million. These swaps involve the exchange of interest
payments in differing currencies at exchange rates effective at the time the
agreement is entered into, and provide for the exchange of principal amounts at
maturity, usually through an escrow arrangement to limit credit risk. At
December 31, 1994, Coastal had exposure to credit loss of approximately $172.9
million on currency swaps.
Neither the Company nor the counterparties are required to collateralize
their respective obligations under these swaps. Coastal is exposed to loss if
one or more of the counterparties default. The counterparties on these
transactions are prominent banking institutions and the Company is of the
opinion that there is no material exposure to credit loss on these swaps. See
Note 8 in the Notes to Consolidated Financial Statements for more information on
these swaps. The Company does not believe that any reasonably likely change in
interest rates or foreign currency indexes would have a material adverse effect
on the financial position or the results of operations of the Company.
All interest rate and currency swaps are individually reviewed by the
Company's Board of Directors.
The Company and its subsidiaries frequently enter into swaps, futures and
other contracts to hedge the price risks associated with inventories,
commitments and certain anticipated transactions. The swaps, futures and other
contracts are with established exchanges, energy companies and major financial
institutions. The Company believes
F-2
<PAGE>
its credit risk is minimal on these transactions, as the counterparties are
required to meet stringent credit standards. There is continuous day-to-day
involvement by senior management in the hedging decisions, operating under
resolutions adopted by each subsidiary's board of directors.
In 1994, the Company adopted Statement of Financial Accounting Standards No.
112, "Employers' 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 did
not have a material effect on the Company's results of operations or financial
position.
The Company's operations are subject to extensive and evolving federal, state
and local environmental laws and regulations. The Company anticipates capital
expenditures of $70 million in 1995 to comply with such laws and regulations.
The majority of the 1995 expenditures is attributable to major construction
projects on the sulfur recovery units at two of the Company's refineries. The
Company currently anticipates capital expenditures for environmental compliance
for years 1996 through 1998 of $20 to $40 million per year. Additionally,
appropriate governmental authorities may enforce these 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 17
sites for which the Environmental Protection Agency ("EPA") has developed
sufficient information to estimate total clean-up costs of approximately $400
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, 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 four other sites,
the Company has paid amounts to other PRPs or to the EPA as its proportional
share of associated clean-up costs. As to these latter sites, the Company
believes that its activities were de minimis. In addition, a subsidiary of the
Company has been named as a de minimis PRP at one state "Superfund" site.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. The states have regulatory programs that mandate
waste clean-up. The Clean Air Act Amendments of 1990 include new permitting
regulations which will result in increased operating expenditures. Coastal is
also supplying reduced-emission reformulated gasoline in all markets where it is
required or optionally requested.
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, financial position or
results of operations.
RESULTS OF OPERATIONS
The Company operates principally in the following lines of business: natural
gas, refining and marketing, exploration and production, and coal.
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. The operations involve both regulated
and unregulated companies.
On April 8, 1992 the Federal Energy Regulatory Commission ("FERC") issued
Order 636 which required significant changes in the services provided by
interstate natural gas pipelines (see Note 14 of the Notes to Consolidated
Financial Statements). The intent of Order 636 is to insure that interstate
pipeline transportation services are equal in quality for all gas supplies,
whether the buyer purchases gas from the pipeline or from any other gas
supplier. The FERC amended its regulations to require the use of the straight
fixed variable ("SFV") rate setting
F-3
<PAGE>
methodology. In general, SFV provides that all fixed costs of providing service
to firm customers (including an authorized return on rate base and associated
taxes) are to be received through fixed monthly reservation charges, which are
not a function of volumes transported, while including within the commodity
billing component the pipeline's variable operating costs. In addition, Order
636 has resulted in the incurrence of transition costs. However, Order 636
provides mechanisms for the recovery of such costs within a reasonable time
period.
ANR Pipeline placed its restructured services under Order 636 into effect on
November 1, 1993, and Colorado Interstate Gas Company's ("CIG") restructured
services became effective October 1, 1993. Both subsidiaries now offer a wide
range of "unbundled" storage, transportation and balancing services. As a result
of Order 636, ANR Pipeline no longer offers merchant services. CIG's gas sales
for resale contracts, which have been unbundled at the producer wellhead per
Order 636, extend through September 30, 1996, but provide for reduced customer
purchases to be made each year. While operating revenues for interstate
pipelines have been reduced as a result of the implementation of Order 636,
purchases and other related costs have also been reduced by a similar amount.
<TABLE>
<CAPTION>
Millions of Dollars
-----------------------------
1994 1993 1992
--------- -------- --------
<S> <C> <C> <C>
Operating revenues........................ $3,075.7 $3,247.9 $2,746.8
Depreciation, depletion and amortization.. 151.0 145.4 187.1
Operating profit.......................... 431.3 405.2 403.1
Total throughput volume (Bcf)............. 1,980 1,908 1,885
</TABLE>
1994 Versus 1993. The decrease in operating revenues of $172 million can be
attributed to decreased sales volumes for the interstate pipelines and lower
prices being partially offset by higher transportation and storage revenues for
the interstate pipelines and increased sales volumes for the gas marketing
companies. The primary factor contributing to the increase in storage and
transportation revenues was revenues associated with cost recovery mechanisms
related to above market gas purchases and certain transportation services
provided by others. Also contributing to the storage and transportation revenue
increase and the decrease in sales revenues for the interstate pipelines is the
restructuring of pipeline bundled sales services into separate service
components as required by changed regulations. Total throughput volumes for the
interstate pipelines increased by approximately 4%, while the volume managed by
the gas marketing companies increased by 29%.
Purchases decreased by $200 million in 1994, as volume decreases for the
interstate pipelines and lower gas costs more than offset volume increases for
the gas marketing companies, resulting in a gross profit increase of $28
million. The gas marketing companies accounted for $21 million of this increase.
The operating profit increase of $26 million results from improved
transportation revenues of $83 million, higher storage revenues of $52 million
and other increases of $6 million which were partially offset by lower sales
margins of $58 million; reduced sales volumes of $51 million and increased
depreciation, depletion and amortization of $6 million. The increased
depreciation, depletion and amortization results from capital expansion.
The Natural Gas group continued to show improvement in 1994 even as weather
patterns varied from a frigid first quarter to a balmy last quarter. The
regulated operations benefitted from SFV rate methodology decisions made by the
FERC, while the unregulated operations found opportunities in the marketplace as
customers and end-users sought more efficient ways to obtain and manage their
gas.
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.
F-4
<PAGE>
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.
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.
<TABLE>
<CAPTION>
Millions of Dollars
-----------------------------
1994 1993 1992
-------- -------- ---------
<S> <C> <C> <C>
Operating revenues......................... $6,458.9 $6,200.9 $6,561.1
Depreciation, depletion and amortization.. 53.9 45.6 98.1
Operating profit (loss).................... 153.1 98.0 (192.1)
Refined product sales (MM Bbls)............ 298 294 316
</TABLE>
1994 Versus 1993. Operating revenues increased by $258 million as a result of
increased volumes partially offset by lower prices. The volume increase results
from an increase in the sales of products purchased from others and an increase
in the average throughput at the three core refineries of approximately 20,000
barrels per day.
Purchases for the segment increased by $175 million as a result of increased
volumes offset by lower costs, resulting in a gross profit increase of $83
million. Increased margins of $53 million, increased volumes of $22 million and
other increases of $8 million make up the gross profit increase. The margin
increase relates largely to improved refinery yields of higher value products,
and stronger petrochemical prices.
The operating profit increase of $55 million results from the increased gross
profit of $83 million being partially offset by increased operating expenses of
$20 million and higher depreciation, depletion and amortization of $8 million.
The increase in operating expenses results from expanded petrochemical
operations and volume increases in other areas; while the higher depreciation,
depletion and amortization is a result of expanded foreign and petrochemical
operations.
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
F-5
<PAGE>
increased expenses for new foreign operations. Depreciation, depletion and
amortization decreased as a result of a 1992 restructuring charge of $50 million
not recurring.
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.
<TABLE>
<CAPTION>
Millions of Dollars
--------------------------
1994 1993 1992
-------- ------- -------
<S> <C> <C> <C>
Operating revenues........................................ $ 298.9 $ 357.3 $ 310.0
Depreciation, depletion and amortization.................. 106.0 109.1 83.2
Operating profit.......................................... 41.8 49.9 45.8
Natural gas production (MMcf/d)........................... 218 207 147
Oil, condensate and natural gas liquids production (bpd).. 12,237 13,533 12,997
Average sales price - net of production taxes (dollars):
Gas (per Mcf)........................................... $ 1.77 $ 1.93 $ 1.76
Oil, condensate and natural gas liquids (per bbl)....... 14.34 15.26 17.33
</TABLE>
1994 Versus 1993. The decrease in operating revenues of $58 million can be
attributed to reduced revenues from natural gas marketing activities, reduced
prices for all products and lower crude oil, condensate and plant products
volumes partially offset by increased natural gas volumes. Natural gas revenue
decreases of $48 million, including $43 million from gas marketing, and the
crude oil, condensate and natural gas liquids decrease of $11 million were
partially offset by other revenue increases of $1 million.
The operating profit decrease of $8 million results from decreased prices for
all products of $16 million and reduced volumes for crude oil, condensate and
plant products of $10 million offset by increased volumes for natural gas of $8
million, a $4 million increase from natural gas marketing sales, a $3 million
decrease in depreciation, depletion and amortization and other of $3 million.
Depreciation, depletion and amortization decreased as a result of a lower rate
exceeding the change due to increased volumes.
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.
F-6
<PAGE>
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.
<TABLE>
<CAPTION>
Millions of Dollars
----------------------
1994 1993 1992
------ ------ ------
<S> <C> <C> <C>
Operating revenues............................. $451.3 $443.2 $447.4
Depreciation, depletion and amortization....... 28.9 28.5 28.4
Operating profit............................... 98.2 95.1 92.8
Captive and brokered sales (millions of tons).. 17.5 17.4 16.9
</TABLE>
1994 Versus 1993. The increase in coal revenues is a result of increased
volumes sold and brokered more than offsetting reduced prices. The purchase of
the Soldier Creek Mine in late 1993 added 600,000 tons/year of new capacity.
The operating profit increase of $3 million results from increased volumes of
$6 million and other increases of $4 million, primarily from brokerage and
royalty volumes, partially offset by decreased prices of $2 million and
increased operating expenses of $5 million. Operating expenses, including coal
costs, increased as a result of the volume increase.
1993 Versus 1992. The decrease in coal revenues results from decreased prices
more than offsetting increased volumes sold and brokered.
The operating profit increase results from the 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.
OTHER. Other operations involve trucking, power production, real estate and
other activities.
<TABLE>
<CAPTION>
Millions of Dollars
-------------------------
1994 1993 1992
------- ------- -------
<S> <C> <C> <C>
Operating revenues........................ $208.3 $187.0 $196.3
Depreciation, depletion and amortization.. 7.4 7.9 7.6
Operating profit (loss)................... 9.0 (12.8) (19.7)
</TABLE>
1994 Versus 1993. The $21 million increase in operating revenues results
primarily from volume increases for the trucking operations, while the $22
million increase in operating profit results from the $21 million revenue
increase and a $1 million decrease in operating expenses. The trucking
operations operating profit increased by $14 million, real estate activities
increased by $6 million and other operations increased by $2 million to make up
the 1994 operating profit increase.
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.
OTHER INCOME - NET
1994 Versus 1993. Other income-net decreased by $8 million in 1994 due to the
nonrecurrence of a 1993 settlement amount of $3 million and other decreases of
$5 million.
F-7
<PAGE>
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.
INTEREST AND DEBT EXPENSE
1994 Versus 1993. Interest and debt expense decreased by $35 million in 1994,
primarily as a result of lower average debt levels, lower average interest rates
and reduced other financial costs more than offsetting increases in interest on
customers' refunds. At December 31, 1994, after giving effect to interest rate
swaps, approximately 8.6% of the Company's debt was tied to money-market related
rates.
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.
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 included 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 1993 extraordinary loss, net of income taxes, resulted from early
retirement of debt. See Note 13 in the Notes to Consolidated Financial
Statements.
F-8
<PAGE>
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, 1994 and 1993, 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, 1994. 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 consolidated financial position of The Coastal
Corporation and subsidiaries as of December 31, 1994 and 1993, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1994, in conformity with generally accepted accounting
principles. 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 LLP
Houston, Texas
February 2, 1995
F-9
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars Except Per Share)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------
1994 1993 1992
--------- ---------- ----------
<S> <C> <C> <C>
OPERATING REVENUES........................................ $10,215.3 $10,136.1 $10,062.9
--------- --------- ---------
OPERATING COSTS AND EXPENSES
Purchases................................................ 7,290.0 7,338.1 7,458.0
Operating expenses....................................... 1,828.7 1,806.9 1,851.5
Depreciation, depletion and amortization................. 363.2 355.7 423.5
--------- --------- ---------
9,481.9 9,500.7 9,733.0
--------- --------- ---------
OPERATING PROFIT.......................................... 733.4 635.4 329.9
--------- --------- ---------
OTHER INCOME-NET.......................................... 61.2 68.9 15.4
--------- --------- ---------
OTHER EXPENSES (BENEFITS)
General and administrative............................... 62.2 60.1 58.6
Interest and debt expense................................ 407.8 442.5 485.2
Taxes on income.......................................... 92.0 83.4 (71.7)
--------- --------- ---------
562.0 586.0 472.1
--------- --------- ---------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM................. 232.6 118.3 (126.8)
Extraordinary item-loss on early extinguishment of debt.. - (2.5) -
--------- --------- ---------
NET EARNINGS (LOSS)....................................... 232.6 115.8 (126.8)
DIVIDENDS ON PREFERRED STOCK.............................. 17.4 11.3 .5
--------- --------- ---------
NET EARNINGS (LOSS) AVAILABLE TO
COMMON STOCKHOLDERS...................................... $ 215.2 $ 104.5 $ (127.3)
========= ========= =========
EARNINGS (LOSS) PER SHARE:
Before extraordinary item................................ $ 2.05 $ 1.02 $ (1.23)
Extraordinary item....................................... - (.02) -
--------- --------- ---------
NET EARNINGS (LOSS) PER COMMON AND
COMMON EQUIVALENT SHARE.................................. $ 2.05 $ 1.00 $ (1.23)
========= ========= =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-10
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
--------------------
1994 1993
--------- ---------
<S> <C> <C>
ASSETS
------
CURRENT ASSETS
Cash and cash equivalents............................. $ 73.5 $ 159.2
Receivables, less allowance for doubtful accounts
$19.0 million (1994) and $16.1 million (1993)....... 1,306.0 1,284.9
Inventories........................................... 818.1 992.2
Prepaid expenses and other............................ 230.3 137.3
--------- ---------
Total Current Assets................................ 2,427.9 2,573.6
--------- ---------
PROPERTY, PLANT AND EQUIPMENT - AT COST
Natural gas systems................................... 5,763.7 5,461.6
Refining, crude oil and chemical facilities........... 2,005.7 1,821.3
Gas and oil properties-at full-cost................... 1,283.7 1,204.2
Other................................................. 722.8 677.0
--------- ---------
9,775.9 9,164.1
Accumulated depreciation, depletion and amortization.. 3,441.2 3,216.0
--------- ---------
6,334.7 5,948.1
--------- ---------
OTHER ASSETS
Goodwill.............................................. 544.5 563.3
Investments - equity method........................... 378.3 424.7
Other................................................. 849.2 717.4
--------- ---------
1,772.0 1,705.4
--------- ---------
$10,534.6 $10,227.1
========= =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-11
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
--------------------
1994 1993
--------- ---------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
------------------------------------
CURRENT LIABILITIES
Notes payable and preferred stock redeemable within one year... $ 57.2 $ 271.7
Accounts payable............................................... 1,942.0 1,649.1
Accrued expenses............................................... 329.1 374.0
Current maturities on long-term debt........................... 185.3 95.1
--------- ---------
Total Current Liabilities.................................... 2,513.6 2,389.9
--------- ---------
DEBT
Long-term debt, excluding current maturities................... 3,520.5 3,612.8
Subordinated long-term debt.................................... 199.7 199.7
--------- ---------
3,720.2 3,812.5
--------- ---------
DEFERRED CREDITS AND OTHER
Deferred income taxes.......................................... 1,473.9 1,339.9
Other deferred credits......................................... 369.1 380.1
--------- ---------
1,843.0 1,720.0
--------- ---------
MANDATORY REDEMPTION PREFERRED STOCK
Issued by subsidiaries......................................... .6 26.6
--------- ---------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
Cumulative preferred stock (with aggregate
liquidation preference of $209.7 million).................... 2.7 2.7
Class A common stock - Issued (1994-415,711 shares;
1993-422,857 shares)......................................... .1 .1
Common stock - Issued (1994-108,726,115 shares;
1993-108,512,342 shares)..................................... 36.2 36.2
Additional paid-in capital..................................... 1,214.7 1,209.3
Retained earnings.............................................. 1,336.0 1,162.7
--------- ---------
2,589.7 2,411.0
Less common stock in treasury-at cost (1994-4,395,404 shares;
1993-4,415,394 shares)....................................... 132.5 132.9
--------- ---------
2,457.2 2,278.1
--------- ---------
$10,534.6 $10,227.1
========= =========
</TABLE>
See Notes to Consolidated Financial Statements.
F-12
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
NET CASH FLOW FROM OPERATING ACTIVITIES
Earnings (loss) before extraordinary item.............. $ 232.6 $ 118.3 $(126.8)
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization
before restructuring charges........................ 370.2 358.8 377.1
Deferred income taxes................................ 39.7 45.8 (75.6)
Amortization of producer contract reformation costs.. 32.8 48.3 45.0
Undistributed earnings from equity investments....... (36.6) (54.4) (16.0)
Restructuring charges................................ - - 125.0
Working capital and other changes, excluding changes
relating to cash and non-operating activities:
Accounts receivable................................. (59.0) 231.5 (77.5)
Inventories......................................... (58.1) 260.5 104.6
Prepaid expenses and other.......................... (12.6) (45.2) 13.6
Accounts payable.................................... 299.7 (109.6) .5
Accrued expenses.................................... (59.1) (23.2) 33.9
Other............................................... (80.5) (21.0) 30.4
------- ------- -------
669.1 809.8 434.2
------- ------- -------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment........... (543.2) (392.7) (573.5)
Proceeds from sale of property, plant and equipment.. 30.1 29.3 14.7
Additions to investments............................. (36.0) (74.3) (69.5)
Proceeds from investments............................ 91.5 39.5 97.9
Gas supply prepayments and settlements............... - (11.4) (43.8)
Recovery of gas supply prepayments................... .7 31.8 9.1
------- ------- -------
(456.9) (377.8) (565.1)
------- ------- -------
CASH FLOW FROM FINANCING ACTIVITIES
Increase (decrease) in short-term notes.............. (206.8) 42.6 (158.6)
Redemption of mandatory redemption preferred stock... (33.7) (10.1) (12.5)
Proceeds from issuing common stock................... 5.4 11.9 7.1
Proceeds from issuing preferred stock................ - 193.5 -
Proceeds from long-term debt issues.................. 199.3 233.1 684.3
Payments to retire long-term debt.................... (202.8) (734.3) (327.7)
Dividends paid....................................... (59.3) (53.0) (42.0)
------- ------- -------
(297.9) (316.3) 150.6
------- ------- -------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS........................................ (85.7) 115.7 19.7
Cash and cash equivalents at beginning of year....... 159.2 43.5 23.8
------- ------- -------
Cash and cash equivalents at end of year............. $ 73.5 $ 159.2 $ 43.5
======= ======= =======
</TABLE>
See Notes to Consolidated Financial Statements.
F-13
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
(Millions of Dollars and Thousands of Shares)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------------------------
1994 1993 1992
------------------- ------------------- -------------------
Shares Amount Shares Amount Shares Amount
-------- --------- -------- --------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
Preferred Stock, Par Value 33-1/3c
Per Share, Authorized 50,000,000 Shares
Cumulative Convertible Preferred:
$1.19, Series A: Beginning balance....... 65 $ - 69 $ - 72 $ -
Converted to common...................... (2) - (4) - (3) -
------- -------- ------- -------- ------- --------
Ending balance....................... 63 - 65 - 69 -
======= -------- ======= -------- ======= --------
$1.83, Series B: Beginning balance....... 89 .1 95 .1 109 .1
Converted to common...................... (5) - (6) - (14) -
------- -------- ------- -------- ------- --------
Ending balance....................... 84 .1 89 .1 95 .1
======= -------- ======= -------- ======= --------
$5.00, Series C: Beginning balance....... 35 - 36 - 36 -
Converted to common...................... (1) - (1) - - -
------- -------- ------- -------- ------- --------
Ending balance....................... 34 - 35 - 36 -
======= -------- ======= -------- ======= --------
Cumulative Preferred:
$2.125, Series H, liquidation
amount of $25 per share:
Beginning balance........................ 8,000 2.6 - - - -
Issuance................................. - - 8,000 2.6 - -
------- -------- ------- -------- ------- --------
Ending balance....................... 8,000 2.6 8,000 2.6 - -
======= -------- ======= -------- ======= --------
Class A Common Stock, Par Value 33-1/3c
Per Share, Authorized 2,700,000 Shares
Beginning balance........................ 423 .1 445 .1 449 .2
Converted to common...................... (24) - (108) - (27) (1)
Conversion of preferred stock and
exercise of stock options.............. 17 - 86 - 23 -
------- -------- ------- -------- ------- --------
Ending balance....................... 416 .1 423 .1 445 .1
======= -------- ======= -------- ======= --------
Common Stock, Par Value 33-1/3c Per Share,
Authorized 250,000,000 Shares
Beginning balance........................ 108,512 36.2 107,967 36.0 107,713 35.8
Conversion of preferred stock............ 31 - 42 - 63 -
Conversion of Class A common
stock.................................. 24 - 108 - 27 .1
Exercise of stock options................ 159 - 395 .2 164 .1
------- -------- ------- -------- ------- --------
Ending balance....................... 108,726 36.2 108,512 36.2 107,967 36.0
======= -------- ======= -------- ======= --------
Additional Paid-In Capital
Beginning balance........................ 1,209.3 1,006.7 999.7
Issuance of Series H preferred
stock.................................. - 190.9 -
Exercise of stock options................ 5.4 11.7 7.0
-------- -------- --------
Ending balance....................... 1,214.7 1,209.3 1,006.7
-------- -------- --------
Retained Earnings
Beginning balance.......................... 1,162.7 1,099.9 1,268.7
Net earnings (loss) for period............. 232.6 115.8 (126.8)
Cash dividends on preferred stock.......... (17.4) (11.3) (.5)
Cash dividends on Class A common
stock, 36c(1994), 36c(1993) and
36c (1992) per share..................... (.2) (.2) (.2)
Cash dividends on common stock,
40c(1994), 40c(1993) and 40c(1992)
per share................................ (41.7) (41.5) (41.3)
-------- -------- --------
Ending balance....................... 1,336.0 1,162.7 1,099.9
-------- -------- --------
Less Treasury Stock-At Cost................. 4,395 132.5 4,415 132.9 4,415 132.9
======= -------- ======= -------- ======= --------
TOTAL....................................... $2,457.2 $2,278.1 $2,009.9
======== ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.
F-14
<PAGE>
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% continuing 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 is accounted for as a hedge of an identifiable transaction is
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 $431.8 million, $447.2 million and $480.6 million in 1994, 1993
and 1992, respectively. Cash payments (refunds) for income taxes amounted to
$73.7 million, $21.0 million and $(9.8) million for 1994, 1993 and 1992,
respectively.
INVENTORIES - Inventories of refined products and crude oil are accounted 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. 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 swaps, 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. The Company also enters into interest rate and foreign currency swaps
to manage interest rates and foreign currency risk. Income and expense related
to interest rate swaps is accrued as interest rates change and is recognized in
income over the life of the agreement. Gains or losses from foreign currency
swaps are deferred and are recognized as payments are made on the related
foreign currency denominated debt. Such gains or losses are essentially offset
by gains or losses on the related debt.
PROPERTY, PLANT AND EQUIPMENT - Property additions include acquisition costs,
administrative costs and, where appropriate, capitalized interest allocable to
construction. Capitalized interest amounted to $8.3 million, $8.4 million and
$10.7 million in 1994, 1993 and 1992, 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 $.96 for
1994 and $1.00 for the years 1993 and 1992. 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. The annual rates of depreciation
are as follows:
F-15
<PAGE>
<TABLE>
<S> <C> <C>
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%
</TABLE>
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 ("ANR") and CIG, amounted to $544.5 million at
December 31, 1994, and is being amortized on a straight-line basis over a 40-
year period. Amortization expense charged to operations was approximately $19.0
million for 1994, 1993 and 1992, 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 include 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:
<TABLE>
<CAPTION>
<S> <C>
1994..................... 105,207,492
1993..................... 104,744,124
1992..................... 103,827,362
</TABLE>
STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 71, "ACCOUNTING FOR THE
EFFECTS OF CERTAIN TYPES OF REGULATION" ("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.
F-16
<PAGE>
NOTE 2. INVENTORIES
Inventories at December 31 were (millions of dollars):
<TABLE>
<CAPTION>
1994 1993
------ ------
<S> <C> <C>
Refined products, crude oil and chemicals.. $596.5 $568.8
Natural gas in underground storage......... 34.8 260.4
Coal, materials and supplies............... 186.8 163.0
------ ------
$818.1 $992.2
====== ======
</TABLE>
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
$31.2 million and $52.6 million at December 31, 1994 and 1993, respectively.
Natural gas in underground storage at December 31, 1993, included $207.5
million which was transferred to Property, Plant and Equipment in 1994 for
regulatory and accounting purposes.
NOTE 3. TAKE-OR-PAY OBLIGATIONS
Other assets includes $96.5 million and $134.0 million at December 31, 1994
and 1993, 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 gas sales are
made at negotiated prices and are not subject to regulatory price controls. This
does 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 costs incurred as a result of the mandated Order 636
restructuring will be recovered either under the transition cost mechanisms of
Order 636 or 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, 1994, the Company
estimated that unresolved asserted and unasserted producers' claims amounted to
approximately $20 million. The remaining disputes will be settled where possible
and litigated if settlement is not possible.
At December 31, 1994, 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 $22 million, $18 million, $11 million, $1 million and $1 million
for the years 1995-1999, respectively, and $4 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.
F-17
<PAGE>
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. Such provisions and accruals were not
material to the Company for the years 1994, 1993 and 1992.
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; and several pipeline and other ventures.
The Company's investment in these entities, including advances, amounted to
$378.3 million and $424.7 million at December 31, 1994 and 1993, respectively.
The Company's equity in income of the investments, included in Other Income-Net,
was $75.7 million, $71.9 million and $63.8 million in 1994, 1993 and 1992,
respectively, while dividends and partnership distributions received amounted to
$39.1 million, $17.5 million and $47.8 million in 1994, 1993 and 1992,
respectively. The 1992 equity in income excludes the restructuring charges as
discussed in Note 10.
Summarized financial information of these entities is as follows (millions of
dollars):
<TABLE>
<CAPTION>
December 31,
------------------
1994 1993
-------- --------
<S> <C> <C>
Current assets............ $ 338.6 $ 272.9
Noncurrent assets......... 2,127.7 2,208.1
-------- --------
$2,466.3 $2,481.0
======== ========
Current liabilities....... $ 485.8 $ 353.2
Noncurrent liabilities.... 923.0 1,129.7
Deferred credits.......... 159.2 155.5
Equity.................... 898.3 842.6
-------- --------
$2,466.3 $2,481.0
======== ========
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Revenues.................. $1,159.5 $1,165.2 $1,126.4
Operating income.......... 196.8 192.8 194.1
Net income................ 109.8 123.7 108.6
</TABLE>
F-18
<PAGE>
NOTE 5. DEBT
LONG-TERM DEBT - Balances at December 31 were (millions of dollars):
<TABLE>
<CAPTION>
1994 1993
-------- --------
<S> <C> <C>
The Coastal Corporation:
Notes payable to banks (term credit facilities)........ $ 100.0 $ 100.0
Notes payable to banks (revolving credit agreements)... - 80.0
Swiss franc bonds, 5-3/4%, due 1996.................... 68.3 68.3
Senior notes:
10-3/8%, due 2000.................................... 249.8 249.8
10%, due 2001........................................ 299.1 298.9
8-3/4%, due 1999..................................... 150.0 150.0
8-1/8%, due 2002..................................... 249.3 249.2
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..................................... 298.8 298.6
9-5/8%, due 2012..................................... 149.2 149.1
Other.................................................. .1 .1
-------- --------
2,513.3 2,592.7
-------- --------
Subsidiary Companies:
Notes payable to banks (term credit facilities)........ 50.0 -
Notes payable to banks (revolving credit agreements)... 404.2 473.5
Notes payable to banks (project financing), due 1995.. 26.3 46.5
Long-term notes, 13-1/2%, due 2005..................... 3.4 8.2
Debentures, 7-3/8% to 10%, due 2005-2024............... 601.8 477.5
Capitalized lease obligations, 9-3/4% to 13.11%........ 29.6 32.3
Swiss franc bonds, 6%, due 1995........................ 58.2 58.2
Other, due 2004-2012................................... 19.0 19.0
-------- --------
1,192.5 1,115.2
-------- --------
Total Long-Term Debt................................... 3,705.8 3,707.9
Less Current Maturities................................ 185.3 95.1
-------- --------
$3,520.5 $3,612.8
======== ========
</TABLE>
At December 31, 1994, long-term credit agreements with banks totaled $1,248.7
million, including $328.0 million available to The Coastal Corporation. Loans
under these agreements bear interest at money market-related rates (weighted
average 6.73% at December 31, 1994). Annual commitment fees range up to 1/2%
payable on the unused portion of the applicable facility. At December 31, 1994,
$554.2 million was outstanding and $235.0 million of the unused amount is
dedicated to a specific use. Notes payable to banks of $350.0 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.
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, 1994, net
assets
F-19
<PAGE>
of consolidated subsidiaries amounted to approximately $5.1 billion, of which
$1.8 billion was restricted by such provisions.
In February 1994, ANR Pipeline Company ("ANR Pipeline") sold $125.0 million
of 7-3/8% Debentures due in 2024. The net proceeds from the sale were used for
capital expenditures and for other general corporate purposes.
SUBORDINATED LONG-TERM DEBT - Balances at December 31 were (millions of
dollars):
<TABLE>
<CAPTION>
1994 1993
------ ------
<S> <C> <C>
Subordinated Notes, 11-1/8%, due 1998.. $199.7 $199.7
Less Current Maturities................ - -
------ ------
$199.7 $199.7
====== ======
</TABLE>
The Company has notified the Trustee for its 11-1/8% Subordinated Notes of
its intention to redeem such notes, at par, in March 1995.
MATURITIES - The aggregate amounts of long-term debt (including subordinated)
maturities for the five years following 1994 are (millions of dollars):
<TABLE>
<CAPTION>
<S> <C> <C> <C>
1995 $185.3 1998 $233.4
1996 155.8 1999 233.3
1997 585.2
</TABLE>
NOTES PAYABLE - At December 31, 1994, Coastal and its subsidiaries had $57.2
million of outstanding indebtedness to banks under short-term lines of credit,
compared to $264.0 million at December 31, 1993. The weighted average interest
rates were 6.17% and 3.93% at December 31, 1994 and 1993, respectively. As of
December 31, 1994, $753.1 million was available to be drawn under short-term
credit lines.
RESTRICTIONS ON PAYMENT OF DIVIDENDS - Under the terms of the most
restrictive of the Company's financing agreements, approximately $583.2 million
was available at December 31, 1994 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, 1994, the Company had guaranteed 45% of a construction financing of
a partially owned partnership. The Company's proportionate share of the
outstanding principal balance under this guarantee was $66.6 million at December
31, 1994. Other guarantees and indemnities related to obligations of
unconsolidated affiliates amounted to approximately $259.7 million as of the
same date. The Company anticipates that the guaranteed construction loan will be
refinanced within the next 12 months, 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 $16.4 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 AND COMMITMENTS
The Company leases property, plant and equipment under various operating
leases, certain of which contain renewal and purchase options and residual value
guarantees. Such residual value guarantees amount to approximately $177.7
million.
F-20
<PAGE>
Rental expense amounted to approximately $72.1 million, $98.2 million and
$92.6 million in 1994, 1993 and 1992, respectively, excluding leases covering
natural resources. Aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $87.7 million, $86.2
million, $83.5 million, $73.7 million, and $72.1 million for the years 1995-
1999, respectively, and $786.8 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):
<TABLE>
<CAPTION>
Subsidiaries Stock
------------------
Shares Value
-------- -------
<S> <C> <C>
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
Redemptions................. (860) (26.0)
----- ------
Balance, December 31, 1994.. 6 $ .6
===== ======
</TABLE>
CIG has 550,000 shares of $100 par value cumulative preferred stock
authorized, of which 5,560 shares were outstanding at December 31, 1994. 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.
On June 16, 1994, ANR Pipeline Company redeemed all shares of its outstanding
Cumulative Preferred Stock under sinking fund provisions and optional redemption
provisions. Such redemption included the payment of accrued dividends to June
16, 1994.
NOTE 8. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's operations involve managing market risks related to changes in
interest rates, foreign exchange rates and commodity prices. Derivative
financial instruments, specifically swaps and other contracts, are used to
reduce and manage those risks. The Company does not currently hold or issue
financial instruments for trading purposes.
INTEREST RATE AND CURRENCY SWAPS - The Company has entered into a number of
interest rate swap agreements designated as a partial hedge of the Company's
portfolio of variable rate debt. The purpose of these swaps is to fix interest
rates on variable rate debt and reduce the Company's exposure to interest rate
fluctuations. At December 31, 1994, the Company had interest rate swaps with a
notional amount of $550.0 million, and a portfolio of variable rate debt
outstanding in the amount of $643.2 million. Under these agreements, Coastal
will pay the counterparties interest at a weighted average fixed rate of 9.34%,
and the counterparties will pay Coastal interest at a variable rate equal to the
London Interbank Offered Rate (LIBOR). The weighted average LIBOR rate
applicable to these agreements was 5.76% at December 31, 1994. The notional
amounts do not represent amounts exchanged by the parties, and thus are not a
measure of exposure of the Company. The amounts exchanged are normally based on
the notional amounts and other terms of the swaps.
The Company has also entered into a number of interest rate swap agreements
which have effectively converted $250.0 million of fixed rate debt into floating
rate debt. Under these agreements, Coastal will pay the counterparties a
variable rate equal to LIBOR, and the Company will receive from the
counterparties a weighted average fixed rate of 4.52%. The weighted average
LIBOR rate applicable to these transactions was 5.74% at December 31, 1994.
The weighted average variable rates are subject to change over time as LIBOR
fluctuates. Terms expire at various dates through the third quarter of 1996.
F-21
<PAGE>
The Company has also entered into a number of foreign currency swaps to fully
hedge to maturity the foreign currency denominated debt of the Company and its
subsidiaries. At December 31, 1994, the Company had outstanding yen-denominated
debt of $199.4 million, and the Company and its subsidiaries had swiss franc
denominated debt in the amount of $126.5 million. These swaps involve the
exchange of interest payments in differing currencies at exchange rates
effective at the time the agreement is entered into, and provide for the
exchange of principal amounts at maturity, usually through an escrow arrangement
to limit credit risk. The weighted average exchange rate for the yen swaps is
146.47 yen/dollar, and the weighted average exchange rate for the swiss franc
swaps is 2.00 swiss francs/dollar. The Company has also entered into an interest
rate swap with a notional amount of 19.7 million swiss francs under which the
Company pays a fixed rate of 4.72% and receives a floating rate established in
the interbank market. At December 31, 1994, the floating rate was 4.44%. These
swaps have resulted in effective borrowing costs ranging from 10.0% to 11.1%.
Neither the Company nor the counterparties are required to collateralize
their respective obligations under these swaps. Coastal is exposed to loss if
one or more of the counterparties default. At December 31, 1994, Coastal had no
exposure to credit loss on interest rate swaps and approximately $172.9 million
of exposure to credit loss on currency swaps. However, the counterparties on
these transactions are prominent banking institutions and the Company is of the
opinion that there is no material exposure to credit loss on these swaps. The
Company does not believe that any reasonably likely change in interest rates or
foreign currency indexes would have a material adverse effect on the financial
position or the results of operations of the Company. All interest rate and
currency swaps are reviewed by the Company's Board of Directors.
OTHER DERIVATIVES - The Company and its subsidiaries also frequently enter
into swaps and other contracts to hedge the price risks associated with
inventories, commitments and certain anticipated transactions. The swaps and
other contracts are with established energy companies and major financial
institutions. The Company believes its credit risk is minimal on these
transactions, as the counterparties are required to meet stringent credit
standards. There is continuous day-to-day involvement by senior management in
the hedging decisions, operating under resolutions adopted by each subsidiary's
board of directors.
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.
<TABLE>
<CAPTION>
(Millions of dollars)
----------------------------------------------------
December 31, 1994 December 31, 1993
--------------------------- --------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
--------- ----------- ----------- ---------
<S> <C> <C> <C> <C>
Nonderivatives:
Financial assets:
Cash and cash equivalents............. $ 73.5 $ 73.5 $ 159.2 $ 159.2
Notes receivable...................... 88.6 88.6 62.8 64.2
Financial liabilities:
Short-term debt....................... 57.2 57.2 264.0 264.0
Long-term debt........................ 4,048.8 4,129.6 3,984.0 4,418.1
Mandatory redemption preferred stock.. 0.6 0.6 34.3 34.9
Derivatives relating to:
Commodity swaps loss.................... - (8.1) - (6.5)
Debt:
Currency swaps gain................... (172.9) (172.9) (108.7) (108.7)
Interest rate swaps loss and options.. 31.4 58.7 80.3 106.3
</TABLE>
F-22
<PAGE>
The estimated value of the Company's long-term debt and mandatory redemption
preferred stock is based on interest rates at December 31, 1994 and 1993,
respectively, for new issues with similar remaining maturities. The fair value
of the derivatives relating to commodity swaps reflects the estimated amount to
terminate the contracts at December 31, 1994 and 1993, taking into account
unrealized gains or losses. Dealer quotes are available for these derivatives.
The fair market value of the Company's interest rate and foreign currency swaps
is based on the estimated termination values at December 31, 1994 and 1993,
respectively.
NOTE 9. COMMON AND PREFERRED STOCK
Shares of common stock and Class A common stock reserved for future issuance
as of December 31, 1994 were:
<TABLE>
<CAPTION>
Class A
Common Common
Stock Stock
--------- -------
<S> <C> <C>
Employee stock options......................................... 4,104,035 22,591
Conversion of outstanding Class A common stock................. 415,711 -
Conversion of Class A common stock subject to future issuance.. 44,100 -
Conversion of preferred stock:
$1.19, Series A, redemption value of $33 per share............ 228,349 6,321
$1.83, Series B, redemption value of $50 per share............ 303,962 8,414
$5.00, Series C, redemption value of $100 per share........... 244,734 6,774
--------- ------
5,340,891 44,100
========= ======
</TABLE>
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.
Under the 1984 Plan, options for 21,679 Class A common shares and 51,801
common shares were exercisable at December 31, 1994. No additional options may
be granted under the 1984 plan. At December 31, 1993, 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.
Under the 1985 Plan, 3,958 common shares were available for granting of
options, and options for 835,168 common shares were exercisable at December 31,
1994. At December 31, 1993, 69,758 common shares were available for granting of
options, and options for 953,898 common shares were exercisable.
Under the 1990 Plan, 32,321 common shares were available for granting of
options, and options for 241,073 common shares were exercisable at December 31,
1994. At December 31, 1993, 23,717 common shares were available for granting of
options, and options for 181,380 common shares were exercisable.
Under the 1994 Plan, 1,891,100 common shares were available for granting of
options. No options for common shares were exercisable at December 31, 1994.
F-23
<PAGE>
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, 1994:
<TABLE>
<CAPTION>
Class A
Common Common Option Price
Shares Shares Per Share
---------- -------- ------------
<S> <C> <C> <C>
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
Granted............. 232,900 - 28.31-32.69
Exercised........... (172,914) (16,823) 7.91-31.50
Revoked or expired.. (70,784) (1,216) 26.06-35.94
--------- ------- ------------
December 31, 1994.... 2,176,657 22,591 $10.72-35.94
========= ======= ============
</TABLE>
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-24
<PAGE>
The Company's operating revenues, operating profit, capital expenditures, and
depreciation, depletion and amortization expense for the years ended December
31, 1994, 1993 and 1992, and identifiable assets as of December 31, 1994, 1993
and 1992, by segment, are shown as follows (millions of dollars):
<TABLE>
<CAPTION>
1994 1993 1992
---------- ---------- ----------
<S> <C> <C> <C>
OPERATING REVENUES
Natural gas................... $ 3,075.7 $ 3,247.9 $ 2,746.8
Refining and marketing........ 6,458.9 6,200.9 6,561.1
Exploration and production.... 298.9 357.3 310.0
Coal.......................... 451.3 443.2 447.4
Other......................... 208.3 187.0 196.3
Adjustments and eliminations.. (277.8) (300.2) (198.7)
--------- --------- ---------
Consolidated totals........ $10,215.3 $10,136.1 $10,062.9
========= ========= =========
OPERATING PROFIT (LOSS)
Natural gas................... $ 431.3 $ 405.2 $ 403.1
Refining and marketing........ 153.1 98.0 (192.1)
Exploration and production.... 41.8 49.9 45.8
Coal.......................... 98.2 95.1 92.8
Other......................... 9.0 (12.8) (19.7)
--------- --------- ---------
Consolidated totals........ $ 733.4 $ 635.4 $ 329.9
========= ========= =========
CAPITAL EXPENDITURES
Natural gas................... $ 91.4 $ 119.8 $ 231.7
Refining and marketing........ 228.2 130.3 173.3
Exploration and production.... 150.3 91.8 126.8
Coal.......................... 56.9 36.0 33.3
Other......................... 9.9 9.5 2.6
--------- --------- ---------
Segment totals............. 536.7 387.4 567.7
Corporate assets.............. 6.5 5.3 5.8
--------- --------- ---------
Consolidated totals........ $ 543.2 $ 392.7 $ 573.5
========= ========= =========
DEPRECIATION, DEPLETION AND
AMORTIZATION EXPENSE
Natural gas................... $ 151.0 $ 145.4 $ 187.1
Refining and marketing........ 53.9 45.6 98.1
Exploration and production.... 106.0 109.1 83.2
Coal.......................... 28.9 28.5 28.4
Other......................... 7.4 7.9 7.6
--------- --------- ---------
Segment totals............. 347.2 336.5 404.4
Corporate assets............... 4.2 3.4 4.2
--------- --------- ---------
Consolidated totals........ $ 351.4 $ 339.9 $ 408.6
========= ========= =========
IDENTIFIABLE ASSETS
Natural gas................... $ 5,497.0 $ 5,562.5 $ 5,719.7
Refining and marketing........ 3,041.4 2,745.9 3,054.1
Exploration and production.... 837.2 801.5 835.8
Coal.......................... 498.3 450.3 434.6
Other......................... 268.7 199.7 203.2
--------- --------- ---------
Segment totals............. 10,142.6 9,759.9 10,247.4
Corporate assets.............. 392.0 467.2 332.4
--------- --------- ---------
Consolidated totals........ $10,534.6 $10,227.1 $10,579.8
========= ========= =========
</TABLE>
F-25
<PAGE>
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):
<TABLE>
<CAPTION>
1994 1993 1992
----- ----- -----
<S> <C> <C> <C>
Revenues............ $ .7 $ 3.1 $ 1.1
Impact on earnings.. .4 2.0 .7
</TABLE>
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 includes equity method earnings related to the business
segments as follows (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------
1994 1993 1992
------ ------ ------
<S> <C> <C> <C>
Natural gas................................ $60.0 $55.1 $53.6
Refining and marketing..................... (9.4) (3.4) (7.6)
Exploration and production................. 11.4 4.7 5.1
Power production........................... 14.4 16.4 13.7
Other...................................... (.7) (.9) (1.0)
----- ----- -----
$75.7 $71.9 $63.8
===== ===== =====
</TABLE>
Revenues from sales to any single customer during 1994, 1993 or 1992 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 generally 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 Employment Retirement Income Security Act of 1974. The pension benefit
for 1994, 1993 and 1992 is shown in the following table (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------
1994 1993 1992
-------- ------- -------
<S> <C> <C> <C>
Service cost - benefit earned during the period.. $ 17.6 $ 16.3 $ 15.2
Interest cost on projected benefit obligation.... 37.7 37.6 38.5
Actual return on assets.......................... 2.0 (92.5) (25.3)
Net amortization and deferral.................... (74.5) 18.9 (47.5)
------ ------ ------
Net periodic pension benefit..................... $(17.2) $(19.7) $(19.1)
====== ====== ======
</TABLE>
The discount rate used in determining the actuarial present value of the
projected benefit obligation was 8.75% in 1994, 7.25% in 1993 and 8.25% in 1992.
The expected increase in future compensation levels was 5% in 1994,
F-26
<PAGE>
4% in 1993 and 6% in 1992, and the expected long-term rate of return on assets
was 10% in 1994 and 11% in both 1993 and 1992.
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):
<TABLE>
<CAPTION>
December 31,
------------------
1994 1993
-------- --------
<S> <C> <C>
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits
of $397.9 million and $442.5 million, respectively......... $(439.3) $(492.4)
======= =======
Projected benefit obligation for service rendered to date... $(490.1) $(539.6)
Plan assets, primarily equity securities, at fair value..... 795.0 827.6
------- -------
Plan assets in excess of projected benefit obligation....... 304.9 288.0
Unrecognized net assets at January 1, 1994 and 1993, being
recognized over average remaining service lives............ (66.6) (76.1)
Prior service cost, not yet recognized...................... 4.5 7.1
Unrecognized net loss from past experience different from
that assumed............................................... 25.6 15.9
------- -------
Prepaid pension cost........................................ $ 268.4 $ 234.9
======= =======
</TABLE>
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, 1994 and 1993.
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 $7.6 million for 1994 and $7.1 million each for 1993 and 1992. 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 are based on matching employee contributions,
amounted to $17.5 million, $17.7 million and $16.6 million in 1994, 1993 and
1992, 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"), which requires the Company to accrue the estimated cost
of retiree benefit payments during the years the employee provides services.
Previously, the Company expensed the costs of these benefits as claims were
incurred. The Company's cash flows were not affected by the implementation of
FAS 106 and the incremental impact on the Company's results of operations before
income taxes was approximately $10.9 million in 1994 and $13.6 million, of which
$8.3 million was deferred by the Company's rate regulated subsidiaries, in 1993.
The Company's rate regulated subsidiaries have deferred certain costs consistent
with their rates.
F-27
<PAGE>
The following tables set forth the accumulated postretirement benefit
obligation recognized in the Company's Consolidated Balance Sheet and the
benefit cost for the years ended December 31, 1994 and 1993 (millions of
dollars):
<TABLE>
<CAPTION>
December 31,
------------------
1994 1993
-------- --------
<S> <C> <C>
Accumulated postretirement benefit obligation:
Retirees....................................................... $ (76.8) $(105.3)
Fully eligible plan participants............................... (3.3) (18.8)
Other active plan participants................................. (29.4) (25.3)
------- -------
(109.5) (149.4)
Plan assets at fair value....................................... 14.5 2.1
------- -------
Accumulated postretirement benefit obligation
in excess of plan assets....................................... (95.0) (147.3)
Unrecognized net transition obligation.......................... 118.7 126.4
Unrecognized net (gain) loss from past
experience different from that assumed......................... (35.5) 9.3
Unrecognized prior service cost................................. 3.3 -
------- -------
Postretirement benefit obligation included
in balance sheet............................................... $ (8.5) $ (11.6)
======= =======
Year Ended
December 31,
-------------
1994 1993
------ ------
Net postretirement benefit cost consisted of the
following components:
Service cost - benefits earned during the period................ $ 2.5 $ 1.7
Interest cost on accumulated postretirement benefit obligation.. 8.9 10.6
Amortization of transition obligation........................... 6.6 6.7
Deferred regulatory amounts..................................... 1.8 (8.3)
Other amortization and deferral................................. (1.2) -
------- -------
Net postretirement benefit cost................................. $ 18.6 $ 10.7
======= =======
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 12.0% in 1994, declining gradually to 6.0%
by the year 2005. The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation was 16.0% in 1993. 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, 1994 by approximately 4.9% and the net postretirement health care
cost by approximately 4.4%. The assumed discount rate used in determining the
accumulated postretirement benefit obligation was 8.75%.
The Company adopted Statement of Financial Accounting Standards No. 112,
"Employers' Accounting for Postemployment Benefits" 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 did not have a material effect on the Company's results of operations
or financial position.
F-28
<PAGE>
NOTE 12. TAXES ON INCOME
Pretax earnings (loss) before extraordinary item are composed of the
following (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------
1994 1993 1992
------ ------ --------
<S> <C> <C> <C>
United States.. $295.0 $171.0 $(139.9)
Foreign........ 29.6 30.7 (58.6)
------ ------ -------
$324.6 $201.7 $(198.5)
====== ====== =======
</TABLE>
Provisions for income taxes (benefits) before extraordinary item are composed
of the following (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------
1994 1993 1992
------- ------ --------
<S> <C> <C> <C>
Current Income Taxes:
Federal................ $46.2 $34.3 $ 2.5
State.................. 6.1 3.3 1.4
----- ----- ------
52.3 37.6 3.9
----- ----- ------
Deferred Income Taxes:
Federal................ 42.0 39.0 (84.2)
State.................. (2.3) 6.8 8.6
----- ----- ------
39.7 45.8 (75.6)
----- ----- ------
Taxes on Income......... $92.0 $83.4 $(71.7)
===== ===== ======
</TABLE>
The Company and the Internal Revenue Service ("IRS") Appeals Office have
settled all contested adjustments to federal income tax returns filed for the
years 1982 through 1984. 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.
F-29
<PAGE>
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):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------
1994 1993 1992
-------- ------- -------
<S> <C> <C> <C>
Tax expense (benefit) by applying the U.S. federal
income tax rate of 35% (1994 and 1993) and 34%
(1992)............................................. $113.6 $ 70.6 $(67.5)
Increases (reductions) in taxes resulting from:
Tight sands gas credit........................... (10.2) (13.0) -
State income tax cost............................ 2.5 6.6 6.6
Goodwill......................................... 6.4 6.4 6.4
Exclusion for dividends and equity earnings...... (5.3) (3.4) (3.0)
Full normalization............................... (2.9) (5.4) (6.1)
Exclusion for foreign earnings................... (6.9) - -
Depletion........................................ (5.2) (6.3) (5.8)
Increase in federal tax rate..................... - 29.0 -
Other............................................ - (1.1) (2.3)
------ ------ ------
Taxes on income..................................... $ 92.0 $ 83.4 $(71.7)
====== ====== ======
</TABLE>
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences and carryforwards are
(millions of dollars):
<TABLE>
<CAPTION>
December 31,
--------------------
1994 1993
--------- ---------
<S> <C> <C>
Excess of book basis over tax basis of property,
plant and equipment.............................. $1,424.8 $1,403.1
Pensions and benefit costs........................ 22.4 41.2
Purchase gas and other recoverable cost........... 54.5 52.6
Other............................................. 7.7 -
-------- --------
Deferred tax liabilities.......................... 1,509.4 1,496.9
-------- --------
Inventory adjustments............................. (.2) (27.4)
Alternative minimum tax credit carryforward....... (139.3) (145.9)
Other............................................. - (7.2)
-------- --------
Deferred tax assets............................... (139.5) (180.5)
-------- --------
Deferred income taxes............................. $1,369.9 $1,316.4
======== ========
</TABLE>
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, REGULATORY AND ENVIRONMENTAL MATTERS
LITIGATION - A subsidiary of Coastal 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 alleged 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. Final
judgment in this matter was entered April 22, 1994. The subsidiary was awarded
approximately $2.0 million,
F-30
<PAGE>
including pre-judgment interest and attorney fees. All of TransAmerican's claims
and causes of action were denied. The judgment has been appealed by
TransAmerican and the case is presently pending before the Court of Appeals for
the Fourth Judicial District at San Antonio, Texas.
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. The matter has
been set for trial in March 1995.
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 or
results of operations.
REGULATORY MATTERS - 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. The case is currently in
the briefing phase before the United States Court of Appeals for the D.C.
Circuit.
On November 1, 1993, ANR Pipeline placed its Order 636 restructured services
and rates into effect. Several persons, including ANR Pipeline, have sought
judicial review of aspects of the FERC's orders approving ANR Pipeline's
restructuring filings. Those appeals have been held in abeyance by the United
States Court of Appeals for the D.C. Circuit, pending further order. On March
24, 1994, the FERC issued its "Fourth Order on Compliance Filing and Third Order
on Rehearing," which addressed numerous rehearing issues and confirmed that
after minor required tariff modifications, ANR Pipeline is now fully in
compliance with Order 636 and the requirements of the orders on its
restructuring filings. The FERC issued a further order regarding certain
compliance issues on July 1, 1994. In accordance with this order, ANR Pipeline
filed revised tariff sheets on July 18, 1994.
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 became effective November 1, 1992 and expired with ANR Pipeline's
implementation of Order 636 on November 1, 1993. Under the Interim Settlement,
gas inventory demand charges were collected from ANR Pipeline's resale customers
for the period November 1, 1992 through October 31, 1993. This method of gas
cost recovery required refunds for any over-collections, and placed ANR Pipeline
at risk for under-collections. As required by the Interim Settlement, ANR
Pipeline filed with the FERC on April 29, 1994, a reconciliation report showing
over-collections and, therefore, proposed refunds totaling $45.1 million. Such
refund obligations were recorded at December 31, 1994 and December 31, 1993, and
are included in the Consolidated Balance Sheet under "Deferred Credits and
Other." Certain customers have disputed the level of those refunds. By an order
issued in February 1995, the FERC has directed ANR Pipeline to make immediate
refunds of $45.1 million and applicable interest, subject to further
investigation of the claims which the customers have made. The matter is still
pending.
On November 1, 1993, ANR Pipeline filed a general rate increase with the FERC
under Docket RP94-43. The increase represents the effects of 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., Statement of Financial Accounting Standards No. 106, "Employers'
Accounting for Postretirement Benefits Other Than Pensions" and Statement of
Financial Accounting Standards No. 112, "Employers' Accounting for
Postemployment Benefits." On March 23, 1994, the FERC issued an order granting
and denying various requests for summary disposition and establishing hearing
procedures for issues remaining to be investigated in this proceeding. The
order required the reduction or elimination of certain costs which resulted in
revised rates such that the revised rates reflect an $85.7
F-31
<PAGE>
million increase in the cost of service from that approved in the Interim
Settlement and a $182.8 million increase over ANR Pipeline's approved rates for
its restructured services under Order 636. On April 29, 1994, ANR Pipeline filed
a motion with the FERC that placed the new rates into effect May 1, 1994,
subject to refund. On September 21, 1994, the FERC accepted ANR Pipeline's
filing in compliance with the March 23, 1994 order, subject to further
modifications including an additional reduction in cost of service of
approximately $5 million. ANR Pipeline submitted its compliance filing to the
FERC on October 6, 1994, which compliance filing was accepted by order issued
December 8, 1994, subject to a further compliance filing requirement, which ANR
Pipeline submitted on January 9, 1995, and which was accepted by an order issued
in February 1995. Further, on December 8, 1994, the FERC issued its order
denying rehearing of the March 23, 1994 order. On January 26, 1995, ANR Pipeline
sought judicial review of these orders before the U.S. Court of Appeals for the
D.C. Circuit.
ANR Pipeline has executed a Settlement Agreement (the "Settlement Agreement")
with Dakota Gasification Company ("Dakota") and the Department of Energy which
resolves litigation concerning purchases of synthetic gas by ANR Pipeline from
the Great Plains Coal Gasification Plant (the "Plant"). That litigation,
originally filed in 1990 in the United States District Court in North Dakota,
involved claims regarding ANR Pipeline's obligations under certain gas purchase
and transportation contracts with the Plant. The Settlement Agreement resolves
all disputes between the parties, amends the gas purchase agreement between ANR
Pipeline and Dakota and terminates the transportation contract. The Settlement
Agreement is subject to final FERC approval, including an approval for ANR
Pipeline to recover the settlement costs from its customers. On August 3, 1994,
ANR Pipeline filed a petition with the FERC requesting: (a) that the Settlement
Agreement be approved; (b) an order approving ANR Pipeline's proposed tariff
mechanism for the recovery of the costs incurred to implement the Settlement
Agreement; and (c) an order dismissing a proceeding currently pending before the
FERC, wherein certain of ANR Pipeline's customers have challenged Dakota's
pricing under the original gas supply contract. On October 18, 1994, the FERC
issued an order consolidating ANR Pipeline's petition with similar petitions of
three other pipeline companies and setting the Settlement Agreement and other
Dakota-related proceedings for limited hearing before an Administrative Law
Judge who must render an initial decision by December 31, 1995. On December 20,
1994, ANR Pipeline filed its testimony, and has responded to numerous discovery
requests. The hearing is scheduled to commence on June 20, 1995. ANR Pipeline
believes the ultimate resolution of the Dakota related issues will not have a
material adverse impact on its financial position or results of operations.
Order 636 provides mechanisms for recovery of transition costs associated
with compliance with that Order. ANR Pipeline has estimated that its transition
costs will amount to approximately $150 million, which will consist primarily of
gas supply realignment costs, the cost of stranded pipeline investment and the
Dakota costs described above. As of December 31, 1994, ANR Pipeline has
incurred transition costs in the amount of $43 million. ANR Pipeline has filed
for recovery of approximately $40.5 million of these transition costs, which
have been accepted and made effective by the FERC, subject to refund and subject
to further proceedings. In addition, ANR Pipeline has filed for recovery of
approximately $90 million of costs associated with the Settlement Agreement, as
mentioned above. Additional transition costs filings will be made by ANR
Pipeline in the future. 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 its financial position or results of operations.
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. As of October 1, 1993, CIG separated all of its services and separately
contracts for each service on a stand-alone or "unbundled" basis. Gathering,
storage and transportation services are provided at negotiated rates established
between minimum and maximum levels approved by the FERC, while gas processing
rates are not subject to FERC regulations.
CIG's gas sales for resale contracts extend through September 30, 1996, but
provide for reduced customer purchases to be made each year. Under Order 636,
CIG's certificate to sell gas for resale allows sales to be made at negotiated
prices and not at prices established by FERC. CIG is also authorized to abandon
all sales for resale without prior FERC approval at such time as the contracts
expire. Pursuant to Order 636, CIG's gas sales have been unbundled at the
producer wellhead.
F-32
<PAGE>
On March 31, 1993, CIG filed at FERC under Docket RP93-99 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.
On November 10, 1994, the FERC approved a settlement offer submitted by CIG
which resolved all of the issues in the proceeding. CIG has implemented the
rates established in the settlement for prospective application and will be
required to make refunds as a result of the approval of the settlement. Such
refunds will be distributed in March 1995. CIG has fully accrued for these
refunds and therefore such refunds will not have an adverse effect on its
consolidated financial position or results of operations.
CIG, ANR Pipeline, ANR Storage Company and Wyoming Interstate Company, Ltd.,
subsidiaries of the Company, 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
and evolving federal, state and local environmental laws and regulations. The
Company anticipates capital expenditures of $70 million in 1995 to comply with
such laws and regulations. The majority of the 1995 expenditures is attributable
to construction projects on the sulfur recovery units at two of the Company's
refineries. The Company currently anticipates capital expenditures for
environmental compliance for the years 1996 through 1998 of $20 to $40 million
per year. 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 17
sites for which the Environmental Protection Agency ("EPA") has developed
sufficient information to estimate total clean-up costs of approximately $400
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, 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 four other sites,
the Company has paid amounts to other PRPs or to the EPA as its proportional
share of associated clean-up costs. As to these latter sites, the Company
believes that its activities were de minimis. In addition, a subsidiary of the
Company has been named as a de minimis PRP at one state "Superfund" site.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. The states have regulatory programs that mandate
waste clean-up. The Clean Air Act Amendments of 1990 include new permitting
regulations which will result in increased operating expenditures. Coastal is
also supplying reduced-emission reformulated gasoline in all markets where it is
required or optionally requested.
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, financial position or
results of operations.
F-33
<PAGE>
NOTE 15. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the years ended December 31, 1994 and 1993
were (millions of dollars except per share):
<TABLE>
<CAPTION>
Quarter Ended
-------------
March 31, 1994 June 30, 1994 Sept. 30, 1994 Dec. 31, 1994
-------------- -------------- --------------- -------------
<S> <C> <C> <C> <C>
Operating revenues.................... $2,700.8 $2,486.9 $2,675.5 $2,352.1
Less purchases........................ 1,900.0 1,780.0 1,996.3 1,613.7
-------- -------- -------- --------
800.8 706.9 679.2 738.4
Other income and expenses............. 719.7 663.8 652.6 656.6
-------- -------- -------- --------
Net earnings.......................... $ 81.1 $ 43.1 $ 26.6 $ 81.8
======== ======== ======== ========
Net earnings per common and
common equivalent share.............. $ .73 $ .37 $ .21 $ .74
======== ======== ======== ========
Quarter Ended
-------------
March 31, 1993 June 30, 1993 Sept. 30, 1993 Dec. 31, 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 equivalent share.......... $ .24 $ .23 $ (.15) $ .68
======== ======== ======== ========
</TABLE>
F-34
<PAGE>
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
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.
<TABLE>
<CAPTION>
ESTIMATED QUANTITIES OF PROVED RESERVES
Natural Gas Exploration
Systems and Production
------------ ---------------------------------
Developed Developed Undeveloped Total
------------ ------------ -------------------- --------------------
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
-----------------------------------------------------------
1994..................................................... 334,597 479,660 144,157 958,414
1993..................................................... 379,795 422,657 123,077 925,529
1992..................................................... 418,831 466,695 89,306 974,832
Oil, Condensate and Natural Gas Liquids (000 barrels):
-----------------------------------------------------------
1994..................................................... 11 28,030 5,636 33,677
1993..................................................... 7 24,851 3,935 28,793
1992..................................................... 14 26,242 6,818 33,074
Changes in proved reserves since the end of 1991 are shown n 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 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
------- ------- ------- -------
Production during 1994..................................... (46,288) (79,485) (1) (4,466)
Extensions and discoveries................................. - 106,985 - 3,932
Acquisitions............................................... - 36,924 - 5,010
Sales of reserves in-place................................. - (4,031) - (931)
Revisions of previous quantity estimates and
other..................................................... 1,090 17,690 5 1,335
------- ------- ------- -------
Total, end of 1994......................................... 334,597 623,817 11 33,666
======= ======= ======= =======
</TABLE>
F-35
<PAGE>
Total proved reserves for natural gas systems exclude storage gas and liquids
volumes. The natural gas systems storage gas volumes are 153,781, 147,549 and
183,741 million cubic feet and storage liquids volumes are approximately
172,000, 150,000 and 159,000 barrels at December 31, 1994, 1993 and 1992,
respectively. Total proved reserves for natural gas includes approximately
27,000 MMcf associated with volumetric production payments sold by the Company.
All of the Company's proved reserves are located in the United States.
International activities are connected with the evaluation of various
concessions. Therefore, the tables setting forth statistical data on reserves
and cash flows are for properties located in the United States while the tables
on costs and results of operations contain certain capitalized and expense
transactions attributable to start-up activities connected with international
operations. These capitalized and expensed international transactions are not
material in nature.
CAPITALIZED COSTS RELATING TO EXPLORATION AND PRODUCTION ACTIVITIES
(Millions of dollars)
<TABLE>
<CAPTION>
December 31, 1994 December 31, 1993
------------------------------- ----------------------------------
Accumulated Accumulated
Depreciation, Depreciation,
Capitalized Depletion and Capitalized Depletion and
Proved and Unproved Properties Cost Amortization Cost Amortization
--------------------------------------------------------------- --------------- -------------- -------------- ------------------
<S> <C> <C> <C> <C>
Undeveloped.................................................... $ 55 $ 18 $ 51 $ 18
Developed...................................................... 1,176 544 1,103 503
--------------- -------------- -------------- ------------------
$1,231 $ 562 $1,154 $ 521
=============== ============== ============== ==================
</TABLE>
The Company follows the full-cost method of accounting for oil and gas
properties.
COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
(Millions of dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------
1994 1993 1992
------ ------ ------
<S> <C> <C> <C>
Property acquisition costs:
Proved........................................................ $ 20 $ 6 $ 6
Unproved...................................................... 5 11 14
Exploration costs.............................................. 29 6 11
Development costs.............................................. 91 65 93
</TABLE>
F-36
<PAGE>
<TABLE>
<CAPTION>
RESULTS OF OPERATIONS FOR EXPLORATION AND PRODUCTION ACTIVITIES
(Millions of dollars)
Year Ended December 31,
----------------------
1994 1993 1992
------ ----- -----
<S> <C> <C> <C>
Revenues:
Sales............................................................... $ 115 $ 139 $ 120
Transfers........................................................... 118 98 77
----- ----- -----
Total.............................................................. 233 237 197
----- ----- -----
Production costs..................................................... (71) (71) (65)
Operating expenses................................................... (29) (28) (27)
Depreciation, depletion and amortization............................. (104) (107) (81)
----- ----- -----
29 31 24
Income tax benefit (expense)......................................... 1 2 (8)
----- ----- -----
Results of operations for producing activities (excluding corporate
overhead and interest costs)........................................ $ 30 $ 33 $ 16
===== ===== =====
</TABLE>
The average amortization rate per equivalent Mcf was $0.96 in 1994 and $1.00 for
the years 1993 and 1992.
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.
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):
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------
1994 1993 1992
---------------------- ---------------------- ----------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
-------- ------------ -------- ------------ -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows................. $ 235 $1,617 $ 299 $1,698 $331 $1,838
Future production and development
costs.............................. (65) (717) (63) (647) (51) (717)
Future income tax expenses.......... (58) (176) (82) (237) (95) (223)
----- ------ ----- ------ ---- ------
Future net cash flows............... 112 724 154 814 185 898
10% annual discount for estimated
timing of cash flows............... (44) (196) (59) (252) (82) (289)
----- ------ ----- ------ ---- ------
Standardized measure of discounted
future net cash flows.............. $ 68 $ 528 $ 95 $ 562 $103 $ 609
===== ====== ===== ====== ==== ======
</TABLE>
Future cash inflows for 1994 include $39 million related to volumes dedicated to
volumetric production payments sold by the Company.
F-37
<PAGE>
Principal sources of change in the standardized measure of discounted future net
cash flows during each year are (millions of dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------------------------------------------------
1994 1993 1992
---------------------- ---------------------- ----------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
-------- ------------ -------- ------------ -------- ------------
<S> <C> <C> <C> <C> <C> <C>
Sales and transfers, net of
production costs............... $ (39) $(148) $ (35) $(164) $(52) $(134)
Net changes in prices and
production costs............... (15) (183) (1) 7 12 147
Extensions and discoveries...... - 119 - 139 - 88
Acquisitions.................... - 43 - 5 - 22
Sales of reserves in-place...... - (4) - (5) - -
Development costs incurred
during the period that
reduced estimated future
development costs.............. - 24 - 21 8 56
Revisions of previous quantity
estimates, timing and other.... 1 23 12 (87) 11 3
Accretion of discount........... 11 55 12 56 12 36
Net change in income taxes...... 15 37 4 (19) 2 (65)
----- ----- ----- ----- ---- -----
Net change...................... $ (27) $ (34) $ (8) $ (47) $ (7) $ 153
===== ===== ===== ===== ==== =====
</TABLE>
None of the amounts include any value for natural gas systems storage gas, which
was approximately 40 Bcf for CIG, 114 Bcf for ANR Pipeline and 172,000 barrels
of liquids for CIG at the end of 1994.
F-38
<PAGE>
SUPPLEMENTAL STATISTICS FOR COAL MINING OPERATIONS (UNAUDITED)
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.
<TABLE>
<CAPTION>
TOTAL RECOVERABLE RESERVES December 31,
(Millions of tons) --------------------------------------------
1994 1993 1992 1991 1990
-------- ------- ------- ------- -------
<S> <C> <C> <C> <C> <C>
Total, beginning of year........................................... 871 789 806 828 818
Production......................................................... (20) (24) (18) (18) (18)
Purchases (sales).................................................. (2) 115 8 (5) 40
Changes in estimates............................................... (10) (9) (7) 1 (12)
------ ------ ------ ------ ------
Total, end of year................................................. 839 871 789 806 828
------ ------ ------ ------ ------
Average market price per ton sold.................................. $25.77 $25.80 $27.29 $28.07 $27.81
====== ====== ====== ====== ======
The following presents additional information on coal operations:
OPERATING DATA
(Millions of tons) 1994 1993 1992 1991 1990
------ ------ ------ ------ ------
Sales
East............................................................. 7.6 7.2 7.7 8.2 8.5
West............................................................. 8.7 8.9 7.8 7.4 6.6
Brokerage........................................................ 1.2 1.3 1.4 1.0 1.5
------ ------ ------ ------ ------
Total......................................................... 17.5 17.4 16.9 16.6 16.6
====== ====== ====== ====== ======
Royalty Tonnage
Eastern Bituminous............................................... 5.1 3.9 4.2 3.8 4.2
Western Lignite.................................................. 16.0 16.4 19.7 18.4 17.6
------ ------ ------ ------ ------
Total......................................................... 21.1 20.3 23.9 22.2 21.8
====== ====== ====== ====== ======
Developed Production Capacity
East............................................................. 10.8 10.6 10.5 10.1 9.9
West............................................................. 10.7 10.6 9.5 7.9 6.6
------ ------ ------ ------ ------
Total......................................................... 21.5 21.2 20.0 18.0 16.5
====== ====== ====== ====== ======
</TABLE>
F-39
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
------------------
1994 1993
-------- --------
<S> <C> <C>
ASSETS
CURRENT ASSETS:
Cash and cash equivalents....................................................... $ 6.0 $ 114.6
Receivables..................................................................... 26.7 17.5
Receivables from subsidiaries................................................... 1,830.5 1,360.8
Prepaid expenses and other...................................................... 2.7 1.4
-------- --------
Total Current Assets.......................................................... 1,865.9 1,494.3
-------- --------
PROPERTY, PLANT AND EQUIPMENT - at cost, net..................................... 1.1 7.3
-------- --------
INVESTMENTS IN SUBSIDIARIES AND OTHER ASSETS:
Investment in subsidiaries at cost plus equity in undistributed earnings since
acquisition................................................................... 3,033.6 2,766.7
Due from subsidiaries........................................................... 541.8 1,710.2
Deferred federal income taxes................................................... 67.6 85.5
Other assets.................................................................... 280.4 252.4
-------- --------
3,923.4 4,814.8
-------- --------
$5,790.4 $6,316.4
======== ========
</TABLE>
See Notes to Condensed Financial Statements.
S-1
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
------------------
1994 1993
-------- --------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable............................... $ 50.5 $ 253.5
Accounts payable and accrued expenses....... 179.6 151.1
Payable to subsidiaries..................... 243.8 620.0
Current maturities on long-term debt........ 97.6 15.1
-------- --------
Total Current Liabilities................. 571.5 1,039.7
-------- --------
DUE TO SUBSIDIARIES.......................... - 61.7
-------- --------
DEBT:
Long-term debt.............................. 2,415.7 2,577.6
Subordinated long-term debt................. 199.7 199.7
-------- --------
2,615.4 2,777.3
-------- --------
DEFERRED CREDITS AND OTHER................... 146.3 159.6
-------- --------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY.. 2,457.2 2,278.1
-------- --------
$5,790.4 $6,316.4
======== ========
</TABLE>
See Notes to Condensed Financial Statements.
S-2
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF OPERATIONS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------
1994 1993 1992
------- ------- --------
<S> <C> <C> <C>
OPERATING REVENUES........................................ $ .2 $ 1.0 $ 1.4
OPERATING COSTS AND EXPENSES.............................. - - -
------ ------ -------
OPERATING PROFIT.......................................... .2 1.0 1.4
------ ------ -------
OTHER INCOME:
Equity in net earnings of subsidiaries................... 334.8 263.9 31.8
Interest income from subsidiaries - net.................. 125.3 119.6 137.4
Other income - net....................................... 14.0 20.0 20.8
------ ------ -------
474.1 403.5 190.0
------ ------ -------
OTHER EXPENSES (BENEFITS):
General and administrative............................... 10.1 12.1 11.3
Interest and debt expense................................ 306.9 364.6 391.1
Taxes on income.......................................... (75.3) (90.5) (84.2)
------ ------ -------
241.7 286.2 318.2
------ ------ -------
EARNINGS (LOSS) BEFORE EXTRAORDINARY ITEM................. 232.6 118.3 (126.8)
Extraordinary item-loss on early extinguishment of debt.. - (2.5) -
------ ------ -------
NET EARNINGS (LOSS)....................................... $232.6 $115.8 $(126.8)
====== ====== =======
</TABLE>
See Notes to Condensed Financial Statements.
S-3
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
----------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
Net Cash Flow From Operating Activities:
Net earnings (loss) before extraordinary item..................... $ 232.6 $ 118.3 $(126.8)
Items not requiring (providing) cash:
Depreciation, depletion and amortization........................ .3 .5 .5
Deferred income taxes........................................... 14.1 (36.2) (36.6)
Distributed (undistributed) subsidiary earnings................. (266.9) (197.3) 110.6
Working capital and other changes, excluding changes relating to
cash and non-operating activities:
Receivables.................................................... (9.2) (3.3) (7.7)
Prepaid expenses and other..................................... (1.3) (.1) (.1)
Accounts payable and accrued expenses.......................... 46.7 (15.1) 63.7
Other.......................................................... (54.2) (9.0) (5.9)
------- ------- -------
(37.9) (142.2) (2.3)
------- ------- -------
Cash Flow from Investing Activities:
Purchases of property, plant and equipment........................ (.1) (.9) (1.0)
Proceeds from sale of property, plant and equipment............... 4.9 - -
Net change in accounts with subsidiaries.......................... 260.8 553.3 (239.9)
Additions to investments.......................................... - (1.0) (4.0)
Proceeds from investments......................................... - - 84.8
------- ------- -------
265.6 551.4 (160.1)
------- ------- -------
Cash Flow from Financing Activities:
Increase (decrease) in short-term notes........................... (203.0) 55.1 (152.6)
Proceeds from issuing common stock................................ 5.4 11.9 7.1
Proceeds from issuing preferred stock............................. - 193.5 -
Proceeds from long-term debt issues............................... - 80.1 543.8
Payments to retire long-term debt................................. (79.4) (587.2) (190.0)
Dividends paid.................................................... (59.3) (53.0) (42.0)
------- ------- -------
(336.3) (299.6) 166.3
------- ------- -------
Net Increase (Decrease) in Cash and Cash Equivalents............... (108.6) 109.6 3.9
Cash and Cash Equivalents at Beginning of Year..................... 114.6 5.0 1.1
------- ------- -------
Cash and Cash Equivalents at End of Year........................... $ 6.0 $ 114.6 $ 5.0
======= ======= =======
</TABLE>
See Notes to Condensed Financial Statements.
S-4
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - 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 $340.6 million, $357.1 million and $375.6
million in 1994, 1993 and 1992, respectively. Cash payments (refunds - primarily
from subsidiaries) for income taxes amounted to $(62.2) million, $(49.8) million
and $(63.9) million for 1994, 1993 and 1992, respectively.
Federal Income Taxes -- The Company follows the liability method of
accounting for income taxes as required by the provisions of FAS No. 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.
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 $62.4 million
outstanding at December 31, 1994, 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, joint ventures and
partnerships in which the Company or certain subsidiaries have equity interests.
Information on the guarantees and swaps is disclosed in Notes 5 and 8,
respectively, 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 1994 are (millions of
dollars):
<TABLE>
<CAPTION>
<S> <C> <C> <C>
1995... $ 97.6 1998... $229.4
1996... 97.7 1999... 179.5
1997... 231.3
</TABLE>
NOTE 4. DIVIDENDS RECEIVED
Cash dividends received from consolidated subsidiaries were as follows: 1994
- $67.9 million, 1993 - $66.6 million and 1992 - $142.8 million.
S-5
<PAGE>
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Millions of Dollars)
<TABLE>
<CAPTION>
Additions
Balance at Charged to Balance
Beginning Costs and at End
Description of Year Expenses Other of Year
------------ --------- ---------- ----- -------
<S> <C> <C> <C> <C>
Year Ended December 31, 1994
----------------------------
Allowance for doubtful accounts $16.1 $ 6.2 $ (3.3)(A) $19.0
===== ===== ====== =====
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
===== ===== ====== =====
</TABLE>
(A) Accounts charged off net of recoveries.
S-6
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
------ --------
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+ 1984 Stock Option Plan (Appendix B to Coastal's Proxy Statement for the
1984 Annual Meeting of Stockholders, dated May 14, 1984).
10.2+ 1985 Stock Option Plan (Appendix A to Coastal's Proxy Statement for the
1986 Annual Meeting of Stockholders, dated March 27, 1986).
10.3+ 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).
10.4+ 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).
10.5+ 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).
10.6+ 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).
10.7+ 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).
10.8+ 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).
10.9+ 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).
10.10+ 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).
10.11+ The Coastal Corporation Deferred Compensation Plan (Exhibit 10.14 to
Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1993).
10.12+ 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).
10.13+ 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 (Exhibit 10.16
to Coastal's Annual Report on Form 10-K for the fiscal year ended
December 31, 1993).
<PAGE>
EXHIBIT INDEX
Exhibit
Number Document
------ --------
11* Statement re Computation of Per Share Earnings.
21* Subsidiaries of Coastal.
23* Consent of Deloitte & Touche LLP.
24* Powers of Attorney (included on signature pages herein).
27* Financial Data Schedule.
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.
<PAGE>
EXHIBIT 11
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT RE COMPUTATION OF PER SHARE EARNINGS
(Millions of Dollars, Except Per Share Amounts, and Thousands of Shares)
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------
1994 1993 1992
-------- -------- --------
<S> <C> <C> <C>
COMMON STOCK AND EQUIVALENTS:
----------------------------
Net earnings (loss) applicable to common stock and common
stock equivalents................................................. $ 215.2 $ 104.5 $ (127.3)
======== ======== ========
Average number of common shares outstanding........................ 104,266 103,762 103,385
Class A common shares.............................................. 421 435 442
Common share equivalent:
$1.19 Cumulative Convertible Preferred, Series A*................. 235 241 -
Dilutive effect of outstanding stock options after application of
treasury stock method*............................................ 285 306 -
-------- -------- --------
Average common and common equivalent shares........................ 105,207 104,744 103,827
======== ======== ========
Net earnings (loss) per average common and common equivalent
shares outstanding:
Earnings (loss) before extraordinary item......................... $ 2.05 $ 1.02 $ (1.23)
Extraordinary item................................................ - (.02) -
-------- -------- --------
Net earnings (loss)............................................... $ 2.05 $ 1.00 $ (1.23)
======== ======== ========
ASSUMING FULL DILUTION:
-----------------------
Net earnings (loss) applicable to common stock and common
stock equivalents................................................. $ 215.2 $ 104.5 $ (127.3)
Dividends applicable to dilutive preferred stock:
Series B.......................................................... .2 .2 -
Series C.......................................................... .2 .2 -
-------- -------- --------
Adjusted net earnings (loss) assuming full dilution................ $ 215.6 $ 104.9 $ (127.3)
======== ======== ========
Average number of common shares outstanding........................ 104,266 103,762 103,385
Class A common shares.............................................. 421 435 442
Common share equivalents:
Series A Preferred Stock*......................................... 235 241 -
Equivalent common shares from:
Series B and C Preferred Stock*................................... 564 590 -
Dilutive effect of outstanding stock options after application of
treasury stock method*............................................ 293 326 -
-------- -------- --------
Fully diluted shares............................................... 105,779 105,354 103,827
======== ======== ========
Fully diluted earnings (loss) per share**:
Earnings (loss) before extraordinary item......................... $ 2.04 $ 1.02 $ (1.23)
Extraordinary item................................................ - (.02) -
-------- -------- --------
Net earnings (loss)............................................... $ 2.04 $ 1.00 $ (1.23)
======== ======== ========
</TABLE>
--------
* Convertible securities and options are not considered in the calculations if
the effect of the conversion is anti-dilutive.
** Reporting not required by generally accepted accounting principles because
of small variance from earnings on average common and common equivalent
shares.
<PAGE>
Exhibit 21
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
-----------------------------
<S> <C>
Coastal Capital Corporation....................... Delaware
Subsidiaries:
Coastal Finance Corporation.................. Delaware
Coastal Financial B.V. ...................... The Netherlands
Subsidiary:
Coastal Financial Antilles N.V. ....... Netherlands Antilles
Coastal Netherlands Financial B.V. .......... The Netherlands
Coastal Offshore Insurance Ltd. ............. Bermuda
Coastal Gas Services Company...................... Delaware
Subsidiaries:
ANR Gas Supply Company....................... Delaware
Coastal Electric Services Company............ Delaware
Coastal Gas Gathering and Processing Company. Delaware
Coastal Gas Marketing Company................ Delaware
Coastal Multi-Fuels, Inc. ................... Delaware
Coastal Pan American Corporation............. Delaware
Subsidiaries:
Coastal Cape Horn Ltd. ................ Cayman Islands
Coastal Latin America Ltd. ............ Cayman Islands
Coastal Southern Pipeline Company............ Delaware
Coastal States Gas Transmission Company...... Delaware
Coastal Holding Corporation....................... Delaware
Subsidiaries:
CIC Industries, Inc. ........................ Delaware
Subsidiaries:
Coastal Chem, Inc. .................... Delaware
Coastal Crude Pipeline Corporation..... Delaware
Coastal Pipeline Company............... Delaware
Coastal Refining & Marketing, Inc. .... Delaware
Subsidiaries:
Coastal Refined Products
Corporation.................... Delaware
Coastal States Crude
Gathering Company.............. Texas
Subsidiary:
Coastal Crude
Transportation
Corporation.............. Delaware
Coastal Transport Corporation.......... Delaware
Coastal Catalyst Technology, Inc. ........... Delaware
Coastal Cat Process Marketing, Inc. ......... Delaware
Coastal Eagle Point Oil Company.............. Delaware
Coastal Energy Corporation................... Delaware
Coastal Mobile Refining Company.............. Delaware
Coastal Petrochemical International A.V.V. .. Aruba
Coastal West Ventures, Inc. ................. Delaware
Coastal Limited Ventures, Inc. ................... Texas
Coastal Mart, Inc. ............................... Delaware
Coastal Midland, Inc. ............................ Delaware
Coastal Natural Gas Company....................... Delaware
Subsidiaries:
American Natural Resources Company........... Delaware
Subsidiaries:
ANR Coal Company....................... Delaware
Subsidiaries:
ANR Western Coal Development
Company........................ Delaware
Birmingham Coal Company.......... West Virginia
Brooks Run Coal Company.......... Delaware
</TABLE>
1
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
------------------------------
<S> <C>
Cat Run Coal Company............... Delaware
Coastal Coal Sales, Inc. .......... Delaware
Enterprise Coal Company............ Kentucky
Greenbrier Coal Company............ Delaware
Kingwood Coal Company.............. Delaware
Virginia City Coal Company......... Delaware
Virginia Iron, Coal and
Coke Company..................... Delaware
ANR Credit Corporation................... Delaware
ANR Development Corporation.............. Delaware
ANRFS Holdings, Inc. .................... Delaware
Subsidiaries:
ANR Freight System, Inc. .......... Delaware
Transport USA, Inc. ............... Pennsylvania
ANR Intrastate Gas Company, Inc. ........ Delaware
ANR One Woodward Corp. .................. Delaware
ANR Pipeline Company..................... Delaware
Subsidiaries:
ANR Atlantic Pipeline Company...... Delaware
ANR Energy Conversion Company...... Michigan
ANR Iroquois, Inc. ................ Delaware
ANR Mayflower Company.............. Delaware
ANR Southern Pipeline Company...... Delaware
American Natural Offshore Company.. Delaware
Subsidiaries:
Texas Offshore Pipeline
System, Inc. .............. Delaware
Unitex Offshore
Transmission Company....... Delaware
ANR Production Company................... Delaware
Subsidiary:
Coastal Shuttle Corporation........... Delaware
ANR Ren-Cen, Inc. ....................... Connecticut
ANR Storage Company...................... Michigan
Subsidiaries:
ANR Blue Lake Company............... Delaware
ANR Cold Springs Company............ Delaware
ANR Eaton Company................... Michigan
ANR Jackson Company................. Delaware
ANR Northeastern Gas Storage
Company........................... Delaware
ANR Western Storage Company......... Delaware
ANR Venture Eagle Point Company.......... Delaware
ANR Venture Fulton Company............... Delaware
ANR Venture Management Company........... Delaware
Coastal Great Lakes, Inc. ............... Delaware
Empire State Pipeline Company, Inc. ..... New York
CIC Stock Corporation.......................... Delaware
Subsidiaries:
CIG Gas Storage Company.................. Delaware
CIG Resources Company.................... Delaware
Subsidiary:
Keyes Helium Company LLC (75%)...... Colorado
Colorado Solar-Tech, Inc. ............... Delaware
CIG-Canyon Compression Company............... Delaware
CIG Gas Supply Company....................... Delaware
</TABLE>
2
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
-----------------------------
<S> <C>
CIG Overthrust, Inc. ...................... Delaware
Colorado Interstate Gas Company............ Delaware
Subsidiaries:
CIG Exploration, Inc. ................ Delaware
Colorado Water Supply Company......... Delaware
Subsidiary:
Colorado Interstate
Production Company............. Delaware
Great Lakes Gas Transmission
Company (50%)............................ Delaware
Wyoming Gas Supply, Inc. .................. Delaware
Coastal Oil Chelsea, Inc. ....................... Texas
Coastal Oil & Gas Corporation.................... Delaware
Subsidiaries:
COGC Resale Company........................ Delaware
Coastal China Ltd. ........................ Cayman Islands
CoastalDril, Inc. ......................... Delaware
Coastal Javelina, Inc. .................... Delaware
Coastal Peru Ltd. ......................... Cayman Islands
Coastal Vietnam Ltd. ...................... Cayman Islands
Coastal Power Production Company................. Delaware
Subsidiaries:
Coastal Power International Ltd. .......... Cayman Islands
Subsidiary:
Energia Coastal Guatemala, S.A. ..... Guatemala
Coastal Salvadoran Power Ltd. ............. Cayman Islands
Subsidiary:
Coastal Nejapa Ltd. (90%)............ Cayman Islands
Coastal States Energy Company.................... Texas
Subsidiaries:
Coastal Development Company................ Delaware
Cravat Coal Export Company, Inc. .......... Virgin Islands
Sage Point Coal Company.................... Delaware
Subsidiary:
Soldier Creek Coal Company........... Delaware
Skyline Coal Company....................... Delaware
Southern Utah Fuel Company................. Delaware
Unique Mining Systems, Inc. ............... Delaware
Utah Fuel Company.......................... Delaware
Coastal States Management Corporation............ Colorado
Subsidiaries:
ABCO Aviation, Inc. ....................... Delaware
ABCO Leasing, Inc. ........................ Delaware
ANR Media Company.......................... Michigan
Coastal Travel Mart, Inc. ................. Delaware
Coastal States Trading, Inc. .................... Delaware
Coastal Technology, Inc. ........................ Delaware
Subsidiary:
Coastal Technology Salvador, S.A.
de C.V. (99%)............................ El Salvador
Coastal Unilube, Inc. ........................... Tennessee
Coastal Unilube of Iowa L.C. .................... Iowa
Cosbel Petroleum Corporation..................... Delaware
Subsidiaries:
Coastal Canada Petroleum, Inc. ............ New Brunswick, Canada
</TABLE>
3
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
-----------------------------
<S> <C>
Coastal Fuels Marketing, Inc. ................ Florida
Subsidiaries:
Coastal Fuels of Puerto Rico, Inc. ..... Delaware
Coastal Offshore Fuels, Inc. ........... Liberia
Coastal Terminals, Inc. ................ Florida
Coastal Tug and Barge, Inc. ............ Florida
Subsidiary:
Manatee Towing Company............ Florida
Coastal Oil New England, Inc. ................ Massachusetts
Coastal Oil New York, Inc. ................... Delaware
Coscol Petroleum Corporation....................... Delaware
Subsidiaries:
Coastal Coker Corporation Aruba N.V. ......... Aruba
Coastal Securities Company Limited............ Bermuda
Subsidiaries:
Coastal Aruba Holding Company N.V. ..... Aruba
Subsidiaries:
Coastal Aruba Maintenance/
Operations Company N.V. ........ Aruba
Coastal Aruba Refining
Company N.V. ................... Aruba
Subsidiaries:
Coastal Petroleum Asia N.V.. Aruba
Coastal Energy of Panama,
Inc. ..................... Panama
Coastal Petroleum N.V. ..... Aruba
Subsidiary:
Coastal Petroleum
Argentina, S.A. .... Argentina
Subic Bay Petroleum
Products Ltd. (50%)....... Cayman Islands
Coastal Belcher Petroleum Pte. Ltd. .... Singapore
Coastal (Bermuda) Petroleum Limited..... Bermuda
Subsidiary:
Same as Coastal Stock Company
Limited
Coastal Management Services (Singapore)
Pte. Ltd. ............................ Singapore
Coastal Petroleum (Far East) Pte Ltd.... Singapore
Coastal (Rotterdam) B.V. ............... The Netherlands
Subsidiary:
Coastal States Petroleum
(Espana) S.A. .................. Spain
Coastal (Subic Bay) Petroleum, Inc. Texas
Subsidiary:
Coastal Subic Bay Terminal, Inc. ....... Philippines
Holborn Oil Trading Limited................... Bermuda
Coastal Stock Company Limited................. Bermuda
Subsidiary:
Coastal Europe Limited.................. England
Subsidiaries:
Coastal States Petroleum
(U.K.) Limited.................. England
Coastal States Tankers
(U.K.) Limited.................. England
Colbourne Insurance
Company Limited................. England
Coastal Tankships U.S.A., Inc. ............... Delaware
Coscol Marine Corporation..................... Texas
Subsidiary:
Coscol Operations Corporation........... Delaware
Subsidiary:
Coastal Interstate Corporation.... Delaware
</TABLE>
4
<PAGE>
SUBSIDIARIES OF THE COASTAL CORPORATION
<TABLE>
<CAPTION>
State or Other Jurisdiction of
Incorporation or Organization
-----------------------------
<S> <C>
Golden Carriers Corporation..................... Liberia
Jade Carriers Corporation....................... Liberia
Texas Tank Ship Agency, Inc. ................... Delaware
</TABLE>
The above subsidiaries, with the exception of Great Lakes Gas Transmission
Company, are included in the Consolidated Financial Statements of The Coastal
Corporation. The names of certain subsidiaries have been omitted from the above
listing because such subsidiaries, considered in the aggregate as a single
subsidiary, would not constitute a significant subsidiary. The voting stock of
each corporation is owned 100% by its immediate parent, unless otherwise
indicated above, except that Coastal Europe Limited is 49% owned by Coastal
(Bermuda) Petroleum Limited; Colbourne Insurance Company Limited is 23% owned by
Coastal Capital Corporation and Coastal Unilube of Iowa, L.C. is 50% owned by
Coastal Natural Gas Company.
5
<PAGE>
Exhibit 23
CONSENT OF DELOITTE & TOUCHE LLP
We consent to the incorporation by reference in Registration Statements No.
33-21095, 33-40263, 33-53952, 33-5214, 2-97766, 33-5218 and 33-42696 of The
Coastal Corporation on Forms S-8 and Registration Statement No. 33-48435 of The
Coastal Corporation on Form S-3 of our report dated February 2, 1995, appearing
in this Annual Report on Form 10-K of The Coastal Corporation for the year ended
December 31, 1994.
DELOITTE & TOUCHE LLP
Houston, Texas
March 28, 1995
<TABLE> <S> <C>
<PAGE>
<ARTICLE> 5
<LEGEND>
THE SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE COASTAL
CORPORATION FORM 10-K ANNUAL REPORT FOR THE PERIOD ENDED DECEMBER 31, 1994 AND
IS QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH FINANCIAL STATEMENTS.
</LEGEND>
<MULTIPLIER> 1,000,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1994
<PERIOD-END> DEC-31-1994
<CASH> 74
<SECURITIES> 0
<RECEIVABLES> 1,306
<ALLOWANCES> 0
<INVENTORY> 818
<CURRENT-ASSETS> 2,428
<PP&E> 9,776
<DEPRECIATION> 3,441
<TOTAL-ASSETS> 10,535
<CURRENT-LIABILITIES> 2,514
<BONDS> 3,720
<COMMON> 36
1
3
<OTHER-SE> 2,418
<TOTAL-LIABILITY-AND-EQUITY> 10,535
<SALES> 10,215
<TOTAL-REVENUES> 10,277
<CGS> 7,290
<TOTAL-COSTS> 9,482
<OTHER-EXPENSES> 62
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 408
<INCOME-PRETAX> 325
<INCOME-TAX> 92
<INCOME-CONTINUING> 233
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> 233
<EPS-PRIMARY> 2.05
<EPS-DILUTED> 2.05
</TABLE>
