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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, 1995 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
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Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange
Title of each class on which registered
------------------- ----------------------
Common Stock ($.33 1/3 par value)
$1.19 Cumulative Convertible Preferred Stock,
Series A ($.33 1/3 par value)
$1.83 Cumulative Convertible Preferred Stock,
Series B ($.33 1/3 par value)
$2.125 Cumulative Preferred Stock,
Series H ($.33 1/3 par value) }
11-3/4% Senior Debentures 9-3/4% Senior Debentures New York Stock Exchange
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 7-3/4% Senior Debentures
Securities registered pursuant to Section 12(g) of the Act:
Class A Common Stock ($.33-1/3 par value)
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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 13, 1996, there were outstanding 104,918,785 shares of common
stock, 390,599 shares of Class A common stock, 61,056 shares of $1.19 Cumulative
Convertible Preferred Stock, Series A, 77,495 shares of $1.83 Cumulative
Convertible Preferred Stock, Series B, 32,663 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 $3.5 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 1996 Annual Meeting
of Stockholders, filed pursuant to Regulation 14A under the Securities Exchange
Act of 1934, referred to in Part III hereof.
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TABLE OF CONTENTS
Item No. Page
Glossary...............................................................(ii)
PART I
1. Business............................................................... 1
Introduction....................................................... 1
Natural Gas Systems................................................ 1
Operations..................................................... 1
ANR Pipeline................................................... 3
Colorado....................................................... 4
ANR Storage Company............................................ 5
Gas System Reserves............................................ 5
Wyoming Interstate Company, Ltd................................ 6
Great Lakes Gas Transmission Limited Partnership............... 6
Coastal Gas Services Company................................... 7
Regulations Affecting Gas Systems.............................. 7
Other Developments............................................. 10
Refining, Marketing and Distribution, and Chemicals................ 12
Exploration and Production......................................... 15
Coal............................................................... 18
Power.............................................................. 19
Other Operations................................................... 21
Competition........................................................ 21
Environmental...................................................... 21
2. Properties............................................................. 22
3. Legal Proceedings...................................................... 22
4. Submission of Matters to a Vote of Security Holders.................... 23
PART II
5. Market for the Registrant's Common Equity and Related Stockholder
Matters ............................................................... 24
6. Selected Financial Data................................................ 25
7. Management's Discussion and Analysis of Financial Condition and Results
of Operations.......................................................... 25
8. Financial Statements and Supplementary Data............................ 25
9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure............................................................. 25
PART III
10. Directors and Executive Officers of the Registrant..................... 26
11. Executive Compensation................................................. 27
12. Security Ownership of Certain Beneficial Owners and Management......... 27
13. Certain Relationships and Related Transactions......................... 27
PART IV
14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K....... 28
(i)
GLOSSARY
"ANR Pipeline" means ANR Pipeline Company
"ANR Storage" means ANR Storage Company
"Bcf" means billion cubic feet
"BTU" means British thermal unit
"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
"Huddleston" means Huddleston & Co., Inc., Houston, Texas
"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"
"Long tons" means weight measurement of 2,240 pounds
"Mcf" means thousand cubic feet
"MMcf" means million cubic feet
"NGA" means Natural Gas Act of 1938, as amended
"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.
"Working Gas" means that volume of gas available for withdrawal and use by
the Company's customers
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.
Unless otherwise noted, all natural gas volumes presented in this Annual Report
are stated at a pressure base of 14.73 pounds per square inch absolute and 60
degrees Fahrenheit.
(ii)
PART I
Item 1. Business.
INTRODUCTION
Coastal, acting through its subsidiaries, is a diversified energy holding
company with subsidiary operations in natural gas marketing, processing, storage
and transmission; petroleum refining, marketing and distribution and chemicals;
gas and oil exploration and production; coal mining; and power. 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 15,500 persons as of December 31, 1995.
Annual Reports on Form 10-K for the year ended December 31, 1995 are also
filed by Coastal's subsidiaries, ANR Pipeline and Colorado, and by each of the
two 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, 1995, 1994 and 1993, and the related
identifiable assets as of December 31, 1995, 1994 and 1993, 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 merchant services.
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 and increasingly to the Northeast from (a)
the Hugoton Field and other fields in the Anadarko Basin in Texas and Oklahoma,
(b) the Louisiana onshore and Louisiana and Texas offshore areas and (c) gas
originating in other basins received through interconnections located throughout
its system.
ANR Pipeline's principal pipeline facilities at December 31, 1995
consisted of 12,643 miles of pipeline and 95 compressor stations with 1,069,308
installed horsepower. At December 31, 1995, the design peak day delivery
capacity
1
of the transmission system, considering supply sources, storage, markets and
transportation for others, was approximately 5.6 Bcf per day.
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, 1995 consisted of
6,381 miles of pipeline and 68 compressor stations with approximately 345,000
installed horsepower. At December 31, 1995, the design peak day delivery
capacity of the transmission system was approximately 2 Bcf per day. The
underground storage facilities have a working capacity of approximately 29 Bcf
and a peak day delivery capacity of approximately 780 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. In certain circumstances, the
implementation of Order 636 has resulted in capacity release, secondary delivery
point options and segmentation; thus 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 paid by end users. 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 historical market areas of Wisconsin and Michigan for its transportation,
storage and balancing business. ANR Pipeline also faces competition in the
Northeast markets from Tennessee Gas Pipeline Company, Texas Eastern
Transmission Corporation, CNG Transmission Corporation, Columbia Gas
Transmission Corporation, Transcontinental Gas Pipe Line Corporation and
National Fuel Gas Supply Corporation in serving electric generation plants and
local distribution companies. Increasingly, ANR Pipeline also competes with a
number of marketing companies which aggregate capacity released by firm shippers
for the purpose of managing gas requirements for end users.
2
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. In the first quarter of 1996, ANR Pipeline
entered into agreements to sell a major portion of its Southwest gathering
facilities, as discussed in "Other Developments" included herein.
ANR PIPELINE
Transportation Services and Gas Sales
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 services. 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 $572 million for 1995 compared to
$555 million for 1994 and $533 million for 1993.
Gas sales revenues of ANR Pipeline amounted to $59 million during 1995,
compared to $106 million in 1994 and $604 million in 1993. The significant
decrease in 1994 was due to the elimination of ANR Pipeline's merchant function
effective November 1, 1993, as discussed above. Gas sales revenues in 1995 and
1994 were derived primarily from the auctioning of gas on the open market in
producing areas, as previously discussed.
During 1995, ANR Pipeline's throughput was 1,404 Bcf, of which
approximately 23% was transported for its three largest customers: Wisconsin Gas
Company, Wisconsin Natural Gas Company and Michigan Consolidated Gas Company.
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. 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. In 1995, ANR Pipeline
provided approximately 75% and 30% of the total gas requirements for Wisconsin
and Michigan, respectively.
ANR Pipeline's system deliveries for the years 1995, 1994 and 1993 were as
follows:
Total System Daily Average
Year Deliveries System Deliveries
(Bcf) (MMcf)
---- ------------ -----------------
1995 1,404 3,847
1994 1,371 3,756
1993 1,336 3,660
Gas Purchases
Effective November 1, 1993, as a result of the elimination of ANR
Pipeline's merchant services, 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 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.
3
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 has approximately 205 Bcf of underground working gas storage
capacity, with a maximum day delivery capacity of 2.9 Bcf as late as the end of
February. Working gas storage capacity of 133 Bcf is available from seven owned
and eight leased underground storage facilities in Michigan. In addition, ANR
Pipeline has the contracted rights for 42 Bcf of working gas storage capacity
provided by Blue Lake Gas Storage Company and 30 Bcf of working gas storage
capacity provided by ANR Storage. Excluded from the 205 Bcf is 62.1 Bcf of
working gas storage capacity which ANR Pipeline has reclassified to recoverable
base gas, subject to approval by the FERC as part of ANR Pipeline's general rate
proceeding discussed below.
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. 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.
Gas sales revenues were $124 million in 1995, compared to $139 million in
1994 and $223 million in 1993. The decreases from 1993 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 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. 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.
Pursuant to an operating agreement with CIG Gas Storage Company, an
affiliate, Colorado operates a newly completed storage field located in
northeastern Colorado. When fully developed, the field will have a storage
capacity of 5.3 Bcf with a delivery rate of 200 MMcf per day. Such capacity is
fully subscribed under 30-year contracts.
Colorado's deliveries for the years 1995, 1994 and 1993 were as follows:
Total System Daily Average
Year Deliveries System Deliveries
(Bcf) (MMcf)
---- ------------ -----------------
1995 456 1,248
1994 436 1,195
1993 453 1,241
4
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 109,200 horsepower of compression in its gathering operations.
Colorado owns and operates six gas processing plants which recovered
approximately 81 million gallons of liquid hydrocarbons in 1995, compared to 88
million gallons in 1994 and 86 million gallons in 1993, and 4,600 long tons of
sulfur in 1995, compared to 4,300 long tons in 1994 and 4,400 long tons in 1993.
Additionally, in 1995 and 1994, Colorado processed approximately 6 million
gallons of liquid hydrocarbons owned by others compared to 12 million gallons in
1993. 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.
On October 31, 1995, Colorado filed an application with the FERC seeking
authority to transfer to CIG Field Services Company ("CFS"), a subsidiary of
Colorado, certain facilities presently used for the gathering of natural gas
that are subject to certificates of public convenience and necessity. The filing
was protested by some parties and proceedings are underway at the FERC to
resolve the issues that have been raised by the intervenors. Following receipt
of authorizations, Colorado will transfer the certificated facilities along with
certain noncertificated gathering facilities to CFS.
Colorado has also contracted to operate two helium processing facilities
located in eastern Colorado and the western Oklahoma panhandle area. These
helium facilities are joint venture/partnership arrangements which are partially
owned by affiliates of Colorado.
ANR STORAGE COMPANY
ANR Storage develops and operates natural 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 indirectly a 50% equity interest in three joint venture operating
storage facilities located in Michigan and New York with a total working storage
capacity of approximately 66 Bcf. All of the jointly owned capacity is committed
under long term contracts, including 42 Bcf contracted to ANR Pipeline.
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.
5
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 4,400 MMcf per day. An
additional 300 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 1995, field development, newly connected gas wells, gas
production facilities and pipeline interconnections contributed over 780 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,
1995 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 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 currently
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 other companies for which the WIC line transports gas have entered
into long-term contracts having demand volumes totaling 442 MMcf daily. The FERC
approved an agreement, which became final and nonappealable in 1995, under which
Columbia Gas Transmission Corporation, one of the original firm shippers, is
currently paying WIC an "exit fee" and its contract has been terminated. In
1995, the WIC line transported an average of 455 MMcf daily, compared to 339
MMcf daily in 1994. On January 1, 1992, WIC became an unrestricted open access
transporter. In response to indications of interest by shippers, WIC is
currently considering expanding the capacity of its system. The expansion would
be planned to be in service by August 1997.
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 953 Bcf in 1995 as compared to
897 Bcf in 1994. Great Lakes has long-term contract commitments to transport a
total of 1.4 Bcf per day for TransCanada and affiliates. It also transports up
to 800 MMcf per day primarily for United States markets, including 133 MMcf per
day to Coastal affiliates. 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.
6
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, Coastal Gas
Marketing Company, 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 of 1,182 Bcf of natural gas in 1995, as
compared to 1,047 Bcf in 1994 and 777 Bcf in 1993, and processed 127 Bcf of
natural gas, producing 3.8 million barrels of natural gas liquids in 1995. In
1995, CGS and its affiliates conducted business with 1,466 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 pipeline sales rates. 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. Additionally, subsidiaries of
the Company are subject to similar safety requirements from the Department of
Labor's Occupational Safety and Health Administration related to its processing
plants. 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 gas sales customers and 50% via a surcharge on all
transportation 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. Oral argument in the case was held before the
United States Court of Appeals for the D.C. Circuit in February 1996.
Notwithstanding those appeals, ANR Pipeline, Colorado, WIC, ANR Storage and
Great Lakes have successfully complied with the requirements of Order 636.
7
On January 31, 1996, the FERC issued a "Statement of Policy and Request
for Comments" in Docket Nos. RM95-6 and RM96-7 with respect to a pipeline's
ability to negotiate and charge rates for individual customers' services which
would not be limited to the "cost-based" rates established by the FERC in
traditional rate making. Under this Policy, a pipeline and a customer will be
allowed to negotiate a contract for service which provides for rates and charges
that exceed the pipeline's posted maximum tariff rates, provided that the
shipper agreeing to such negotiated rates has the ability to elect to receive
service at the pipeline's posted maximum rate (known as a "recourse rate"). In
order to implement this Policy, a pipeline must make an initial tariff filing
with the FERC to indicate that it intends to contract for services under this
Policy, and subsequent tariff filings will indicate each instance where the
pipeline has negotiated a rate for service which exceeds the posted maximum
tariff rate. The FERC has also requested comments on whether this "recourse
rate" program should be extended to other terms and conditions of pipeline
transportation services.
Rate Matters
ANR Pipeline. ANR Pipeline placed its restructured services under Order
636 into effect on November 1, 1993. As a result, ANR Pipeline no longer
provides merchant services and now offers a wide range of "unbundled"
transportation, storage and balancing services. 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. Several persons, including ANR Pipeline, have sought judicial
review of aspects of the FERC's orders approving ANR Pipeline's restructuring
filings. These appeals have been held in abeyance by the United States Court of
Appeals for the D.C. Circuit, pending further notice. 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, which were accepted by order issued April 12, 1995.
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. Certain customers have disputed the level of those refunds. By an order
issued February 27, 1995, the FERC approved ANR Pipeline's refund allocation
methodology, and directed ANR Pipeline to make immediate refunds of $45.1
million, together with applicable interest, subject to further investigation of
the claims which the customers have made. On May 2, 1995, the FERC issued a
further order setting these issues for an evidentiary hearing. Initial testimony
has been filed, and the parties are conducting discovery. The hearing is set to
commence in May 1996. Undisputed refunds, including interest, were paid on March
29, 1995. ANR Pipeline submitted an adjusted reconciliation report on October
31, 1995, which was also disputed by certain customers. The subsequent adjusted
reconciliation report has been consolidated with the ongoing evidentiary
hearing. Certain customers have also sought judicial review before the United
States Court of Appeals for the D.C. Circuit of the FERC's approval of the
refund allocation methodology. Briefs have been filed, and oral argument is
scheduled for April 12, 1996.
On November 1, 1993, ANR Pipeline filed a general rate increase with the
FERC under Docket No. 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" ("FAS No. 106") and FAS No. 112,
"Employers' Accounting for Postemployment Benefits" ("FAS No. 112"). 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 hearing commenced on January 31, 1996.
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
8
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. ANR Pipeline sought rehearing of various aspects of
the order. Further, 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
the FERC accepted by order issued February 8, 1995, subject to a further
compliance filing requirement. This compliance filing was submitted by ANR
Pipeline on March 10, 1995, and was accepted by order issued May 3, 1995,
subject to one additional compliance filing requirement, which ANR Pipeline
filed on May 18, 1995 and which was accepted by order issued on June 30, 1995.
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,
which the Court dismissed as premature. The FERC has also issued a series of
orders and orders on rehearing in ANR Pipeline's rate proceeding that apply a
new policy governing the order of attribution of revenues received by ANR
Pipeline related to transition costs under Order 636. Under that new policy, ANR
Pipeline is required to first attribute the revenues it receives for its
services to the recovery of its transition costs under Order 636. In its rate
proceeding, the revenues ANR Pipeline receives for its services in its pending
rate proceeding were first attributed to the recovery of its base cost of
service. The FERC's change in its revenue attribution policy has the effect of
understating ANR Pipeline's currently effective maximum rates and has
accelerated its amortization of transition costs. In light of the FERC's policy,
ANR Pipeline has filed with the FERC to increase its discount recovery
adjustment in its pending rate proceeding. ANR Pipeline has also sought judicial
review of these orders before the United States Court of Appeals for the D.C.
Circuit, and the Court granted the FERC's motion to hold ANR Pipeline's appeal
in abeyance pending the outcome of the Order 636 appeal discussed above.
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. Hearings were held before
the FERC Administrative Law Judge ("ALJ") on the prudence of the Settlement
Agreement, and on December 29, 1995, the ALJ issued an Initial Decision
rejecting the proposed Settlement Agreement. In the Initial Decision, the ALJ
also determined the level of Dakota costs that ANR Pipeline and the other
pipeline companies would be permitted to recover from their customers beginning
as of May 1993. Because the ALJ determined that the appropriate level of costs
is less than the amounts ANR Pipeline has billed to its customers since May 1993
under the ALJ's decision, ANR Pipeline may be required to refund to its
customers the excess amount collected. At December 31, 1995, that refund amount
would be approximately $70 million, plus interest. It is ANR Pipeline's position
that the Settlement Agreement is prudent and that the FERC has no lawful
authority to order refunds for past periods, but even if refunds were ultimately
found to be lawful, ANR Pipeline should not lawfully be required to refund
amounts in excess of the refund amounts it collects from Dakota. ANR Pipeline
has filed with the FERC seeking reversal of the Initial Decision, and approval
of the Settlement Agreement.
Order 636 provides mechanisms for recovery of transition costs associated
with compliance with that Order. ANR Pipeline's transition costs consist
primarily of gas supply realignment costs and pricing differential costs. As of
December 31, 1995, ANR Pipeline incurred transition costs in the amount of $54
million. In addition, ANR Pipeline recorded a contingent liability for $94.1
million representing future above market gas purchase obligations, including
future obligations of $74 million associated with the Settlement Agreement, as
discussed above. The charge related to the contingent liability has been
deferred in anticipation of future rate recovery. ANR Pipeline has filed for
recovery of approximately $44.5 million of incurred transition costs, of which
$42.7 million has been accepted by the FERC for
9
recovery, subject to refund and further proceedings. Of the $42.7 million
accepted by the FERC, $28.6 million has been settled with the parties to the
respective FERC proceedings. Additional transition cost filings will be made by
ANR Pipeline in the future.
Colorado. CIG's gas sales for resale contracts extend through September
30, 1996. 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 the 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.
On March 31, 1993, CIG filed with the FERC under Docket RP93-99 to
increase its rates and such filing 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 and was required to make refunds as a result
of the approval of the settlement. Such refunds were distributed in March and
April 1995 and totaled approximately $22 million, inclusive of interest. CIG had
fully accrued for these refunds and, therefore, such refunds did not have an
adverse effect on its consolidated financial position or results of operations.
On October 31, 1995, CIG filed an application with the FERC seeking
authority to transfer to CFS certain facilities presently used for the gathering
of natural gas that are subject to certificates of public convenience and
necessity. In that filing, CIG requested that the FERC declare that in the hands
of CFS the transferred facilities will be considered "non-jurisdictional"
gathering facilities. The transferred facilities have a net book value of
approximately $36 million. CIG has requested that the FERC issue an order
approving the application to be effective on September 30, 1996. The filing was
protested by some parties and proceedings are underway at the FERC to resolve
the issues that have been raised by the intervenors. Following receipt of
authorizations, CIG will transfer the certificated facilities along with certain
noncertificated gathering facilities to CFS. The facilities to be transferred
comprise most, but not all, of CIG's current gathering assets. Under current
FERC policies, once the facilities are transferred to CFS, the terms and
conditions of service performed by those facilities will cease to be subject to
the FERC's general jurisdiction under the NGA, although the FERC has indicated
that, in certain very narrow circumstances, it will assert regulatory
jurisdiction over gathering by affiliates of interstate pipelines such as CFS.
The FERC's policy with respect to treatment of gathering affiliates of
interstate pipelines is on appeal at this time.
CIG will make a general rate increase filing with the FERC in the first
half of 1996, with such filing expected to become effective, subject to refund,
in late 1996.
CIG, ANR Pipeline, ANR Storage and WIC, subsidiaries of the Company, are
regulated by the FERC. Certain of the above regulatory matters and other
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. As a result,
the Company anticipates that these regulatory matters will not have a material
adverse effect on its consolidated financial position or results of operations.
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
On January 12, 1996, ANR Pipeline and GPM Gas Corporation ("GPM") entered
into a Purchase and Sale Agreement pursuant to which ANR Pipeline agreed to sell
to GPM certain of its Southwest gathering facilities, primarily located in
northwest Oklahoma. The facilities to be sold to GPM comprise a major portion of
ANR Pipeline's Southwest gathering systems and include 1,550 miles of gathering
lines and 14 compressor stations with a total of about 44,000 horsepower. The
gathering systems that ANR Pipeline will sell to GPM gather approximately 200
MMcf per day of natural gas from about 1,100 receipt points. In a separate
transaction, ANR Pipeline and one of its affiliates, ANR Field Services Company
("Field Services"), entered into a Purchase and Sale Agreement in February 1996
pursuant to which ANR Pipeline has agreed to sell to Field Services certain
gathering facilities located in Kansas, Oklahoma, Texas and Wyoming. The
facilities to be sold to Field Services compromise approximately 530 miles of
pipeline, 2,700 horsepower of compression and metering equipment at 351
locations. At December 31, 1995, the aggregate net book value of the
10
facilities to be sold to GPM and Field Services was approximately $5 million.
ANR Pipeline believes that it will not experience a material reduction of
volumes delivered to its transmission mainlines as a result of the proposed
sales of the above mentioned Southwest gathering facilities. ANR Pipeline also
proposes to reclassify any remaining gathering assets, including 130 miles of
pipeline and 750 horsepower of compression, to transmission plant. It is
anticipated that the completion of these transactions will take place in 1996,
subject to receipt of satisfactory governmental and regulatory approvals.
On December 19, 1995, ANR Pipeline received the necessary FERC
authorizations 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
Niagara Gas Transmission Company ("Niagara"), an affiliate of The Consumers' Gas
Company Ltd. ("Consumers"). 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. Niagara has also received its
regulatory authorizations from the Canadian National Energy Board. The project
is expected to be in service by November 1996.
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, as proposed, will provide natural gas transportation and
storage services to markets in the northeastern United States. The proposed
240-mile pipeline would extend east from the Iroquois Gas Transmission System at
Canajoharie, New York, to a location near Boston, Massachusetts, have an initial
design capacity of 350 MMcf per day, and a total project cost of $540 million.
Because of current market conditions, development of the project is inactive and
an estimated in-service date cannot be determined.
In January 1996, Colorado announced an open season for interested parties
to request new transportation capacity on its Wind River Lateral. The lateral
has a current capacity of 195,000 Mcf per day and transports natural gas from
the Wind River Basin, where producers have increased natural gas production by
more than 25 percent since 1992. The expected expansion of the Wind River
Lateral would be sized to meet producer demand based upon the execution of new
transportation agreements.
Colorado has submitted bids and executed precedent agreements with WIC and
with Trailblazer Pipeline Company for 99 thousand and 10 thousand dekatherms per
day of firm transportation capacity, respectively. Colorado has undertaken these
commitments in order to: 1) provide current and future customers of Colorado
with direct access to points of delivery from these pipeline systems without the
customer having to contract separately for and administer contracts on multiple
pipeline systems; and 2) to enhance Colorado's own operational reliability
across the portion of its pipeline system which generally parallels the WIC
system. Colorado anticipates making the appropriate filings at the FERC to hold
this capacity in late March 1996.
Colorado currently has no excess firm pipeline capacity in its Rocky
Mountain states marketing area. In addition, Colorado recently agreed with its
major customer to a long-term transportation and storage contract, subject to
certain conditions.
In January 1996, WIC posted an open season to determine interest in new
transportation capacity on its pipeline system. Bids were received from several
parties and WIC is currently evaluating those bids and the opportunities for
expansion of its system. The expansion would be planned to be in service by
August 1997.
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. Equity participation by other entities will also
be considered.
11
REFINING, MARKETING AND DISTRIBUTION, AND CHEMICALS
The Company has subsidiary operations involved in 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 products worldwide.
Refining
Subsidiaries of the Company operated their wholly-owned refineries at 88%
of average combined capacity in 1995 and at 87% in both 1994 and 1993. The
aggregate sales volumes (millions of barrels) of Coastal's wholly-owned
refineries for the three years ended December 31, 1995 were 142.3 (1995), 136
(1994) and 134.9 (1993). Of the total refinery sales in 1995, 28% was gasoline,
46% was middle distillates, such as jet fuel, diesel fuel and home heating oil,
and 26% was heavy industrial fuels and other products.
The average daily processing capacity of crude oil at December 31, 1995,
average daily throughput and storage capacity at the Company's wholly-owned
operating refineries are set forth below:
Average Daily
Refinery Location Daily Throughput (Barrels) Storage
Capacity -------------------------- Capacity
(Barrels) 1995 1994 (Barrels)
- -------- -------- --------- ---------- ---------- ---------
Aruba Aruba 195,000 145,100 151,700 7,800,000
Corpus Christi Corpus Christi, Texas 100,000 89,000 81,700 7,500,000
Eagle Point Westville, New Jersey 130,000 127,800 111,000 10,700,000
Mobile Mobile, Alabama 17,500 12,400 14,900 600,000
------- ------- ------- ----------
Total Operating 442,500 374,300 359,300 26,600,000
Coastal's refinery in Aruba boosted its throughput capacity from 175,000
barrels per day (bpd) in 1994 to 195,000 bpd in 1995 and completed construction
of a delayed coker unit which allows the Aruba facility to produce additional
yields of lighter, higher-value products. The Aruba delayed coker currently
processes approximately 31,000 bpd, exceeding design projections of 23,000 bpd.
Pacific Refining at Hercules, California had a refining capacity of 55,000
barrels per day. 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 ("PRC"). In August
1995, PRC suspended processing operations at its California refinery. Plans are
to operate this facility as a crude and product terminal as well as for
purchasing and terminaling asphalt for sales to third parties.
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 1995, the products emphasized included premium gasolines and
products for specialty markets such as petrochemical feedstocks, aviation fuels
and asphalt.
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, 875 tons per day of ammonium nitrate, 275
tons
12
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 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 4,200 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, 1995, are set forth
below (thousands of tons):
1995 1994 1993
-------- -------- ---------
Agricultural Sales................................................... 242 188 222
Industrial Sales..................................................... 445 407 410
MTBE................................................................. 203 187 119
-------- -------- ---------
Total .......................................................... 890 782 751
======== ======== =========
Coastal Chem competes with many nitrogen and MTBE producers across the
United States and Canada. The Company's strengths are product quality, service,
and dependability. Coastal Chem produces commodity products with strong price
competition. Reduced rail rates on long hauls has encouraged competition from
Canadian and Eastern U.S. producers.
The petrochemical facility in Montreal East, Quebec, Canada, acquired and
started up in 1994 by a subsidiary of Coastal, has recently been expanded from a
capacity of 180,000 tons per year to 310,000 tons per year of paraxylene, a
component used in the manufacturing of polyester fibers and containers. Although
competing plants are expected to come on line in late 1996 or 1997, the Montreal
East plant holds a competitive position due to the size of the facility, the
Company's low initial investment required to restart the plant, long-term
contracts, and a readily available feedstock base provided by the Company's New
Jersey and Texas refineries.
In January 1996, Coastal Refining & Marketing, Inc., a subsidiary of the
Company, completed the purchase of a chemical production facility at St. Helens,
Oregon. The facility includes a 360-ton-per-day urea plant, a 275-ton-per- day
ammonia plant, and a 65-ton-per-day carbon dioxide plant. The main product of
the facility is an industrial-grade urea used by the adhesives industry. Other
products include fertilizers for the agricultural and forestry industries.
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, 1995, are set forth
below (thousands of barrels):
Type of Sale 1995 1994 1993
- ------------ -------- --------- ---------
Company Produced Refined Products........................................ 142,301 135,973 134,925
Refined Products Purchased from Others................................... 143,913 145,093 140,635
Natural Gas Liquids...................................................... 14,551 17,352 18,155
-------- --------- ---------
Total............................... 300,765 298,418 293,715
======== ========= =========
Subsidiaries of the Company market refined products and liquefied petroleum
gas at wholesale in 36 states through 361 terminals. Coastal Refining &
Marketing, Inc. serves customers in the Midwest, Mississippi Valley and the
Southwest through 275 product and liquefied petroleum gas terminals in 26
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 1995, these subsidiaries' sales volumes were
112 million barrels, which accounted
13
for approximately 37% of the total marketing and distribution sales.
International subsidiaries that acquire feedstocks for the refineries and
products for the distribution system are located in Aruba, Bermuda, London and
Singapore.
Domestically, Coastal looked to increase integration between its marketing
operations and refineries. As a result, the Company withdrew from 60 of its
less-profitable terminal locations and concentrated on terminal locations nearer
core assets. This consolidation should be completed in 1996.
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 was a partner in a joint venture with a subsidiary of the
Malaysian national oil company, Petronas, which used the entire capacity of this
storage facility, but this joint venture was terminated in January 1996.
A subsidiary of Coastal has entered into a joint venture with Baltica
Finance N.V., a Netherlands Antilles company, and Sadkora A.B., a Swedish
company, to develop a petroleum terminal in Estonia and market petroleum
products primarily from Russia and the former republics of the Soviet Union. The
joint venture will refurbish an existing terminal, add additional storage tanks
to expand the terminal storage capacity to 800,000 barrels and build a 4.5 mile
pipeline to connect the terminal to the Port of Muuga for the export of
petroleum products. Work on the pipeline and the other improvements has begun
and is expected to be completed in the spring of 1996.
The Company, through Coastal Mart, Inc. and branded marketers, conducts
retail marketing, using the C-MART(R), C and Design and/or COASTAL(R)
trademarks, in 36 states through approximately 1,655 Coastal branded outlets,
with 671 of those outlets operated by the Company. Fleet fueling operations
include 21 outlets in Texas and 7 in Florida.
Coastal Unilube, Inc., based in West Memphis, Arkansas, blends, packages
and distributes lubricants and automotive products under the COASTAL(R), C and
Design and other trademarks. Coastal Unilube, Inc. distributes lubricants and
automotive products through 14 warehouses servicing customers in 39 states.
Transportation. The Company's transportation facilities include petroleum
liquids pipelines, tank cars, tankers, tank trucks and barges. Coastal operates
approximately 1,700 miles of pipeline for gathering and transporting an average
of 230,000 barrels daily of crude oil, condensate, natural gas liquids and
refined products. Effective July 1, 1995, certain of Coastal's Gulf Coast
pipelines and terminals were sold to Coastal Liquid Partners, L.P., in which
Coastal retains a combined 35% general partnership and limited partnership
interest. Coastal continues to operate the assets which include 226 miles of
crude oil pipelines, 724 miles of refined products pipelines, and 671 miles of
natural gas liquids pipelines, all located principally in Texas. Coastal has
100% ownership of 13 miles of refined products pipelines located in New Jersey
and New York and has a 33.3% interest in an additional 80 miles of refined
products pipelines in New Jersey. In 1995, throughput of crude oil pipelines
averaged 14,441 barrels per day, compared to 18,339 barrels per day in 1994. In
1995, throughput of refined products and natural gas liquid pipelines averaged
215,652 barrels per day, compared to 200,037 barrels per day in 1994.
The marine transportation total fleet at December 31, 1995 consisted of 15
tug boats, 22 oil barges, 9 owned tankers used for the transportation of refined
petroleum products and crude oil and 1 time-chartered tanker.
Competition
The petroleum industry is highly competitive in the United States and
throughout most of the world. The Company's subsidiary operations involved in
refining, marketing and distribution of petroleum products and chemicals compete
with other industries in supplying the energy needs of various types of
consumers. Principle factors affecting sales are price, location and service.
Overall performance is impacted by industry margins, and supply and demand for
both feedstocks and finished products.
14
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 China, Hungary, Indonesia and Peru.
In 1995, the Company's domestic operations sold approximately 62% of all
the gas it produced to its natural gas system affiliates. The Company's domestic
operations make short-term gas sales directly to industrial users and
distribution companies to increase utilization of its excess current gas
production capacity. Oil is sold primarily under short-term contracts at field
prices posted by the principal purchasers of oil in the areas in which the
producing properties are located.
Acreage held under gas and oil mineral leases as of December 31, 1995 is
summarized as follows:
Undeveloped Developed
------------------- --------------------
Area Gross Net Gross Net
---- ------- -------- ------- ---------
(Thousands of Acres)
United States (Domestic)
Onshore................................................ 820 623 1,634 832
Offshore............................................... 146 61 121 90
--------- -------- --------- ---------
Total Domestic......................................... 966 684 1,755 922
--------- -------- --------- ---------
International
China.................................................. 894 358 - -
Hungary................................................ 568 568 - -
Indonesia.............................................. 950 237 - -
Peru................................................... 2,974 2,974 - -
--------- -------- --------- ---------
Total International.................................... 5,386 4,137 - -
--------- -------- --------- ---------
Total Acreage.......................................... 6,352 4,821 1,755 922
========= ======== ========= =========
The domestic net developed acreage is concentrated principally in Texas
(34%), Utah (23%), Oklahoma (10%), offshore Gulf of Mexico (10%), Kansas (5%)
and Wyoming (6%). Approximately 16%, 21% and 8% of the Company's total domestic
net undeveloped acreage is under leases that have minimum remaining primary
terms expiring in 1996, 1997 and 1998, respectively.
Productive wells as of December 31, 1995 are as follows (domestic):
Type of Well Gross Net
------------ --------- ---------
Oil ...................................... 3,477 1,045
Gas ...................................... 2,727 1,468
--------- ---------
Total................................. 6,204 2,513
========= =========
15
Exploration and Drilling
During 1995, Coastal's domestic exploration and production units
participated in drilling 93 gross wells, 40.6 net wells, to the Company's
interest. Coastal's participation in wells drilled in the three years ended
December 31, 1995, is summarized as follows:
1995 1994 1993
------------------- ------------------- --------------------
Exploratory Wells Gross Net Gross Net Gross Net
----------------- -------- -------- --------- -------- --------- ---------
Oil............................ 1 0.3 1 0.2 1 0.5
Gas............................ 6 2.5 2 1.3 - -
Dry Holes...................... 4 2.3 5 2.9 7 4.1
-------- -------- --------- -------- --------- ---------
11 5.1 8 4.4 8 4.6
======== ======== ========= ======== ========= =========
Development Wells
Oil............................ 22 9.8 15 6.1 44 18.6
Gas............................ 59 25.6 82 35.1 104 51.2
Dry Holes...................... 1 0.1 3 2.1 2 1.1
-------- -------- --------- -------- --------- ---------
82 35.5 100 43.3 150 70.9
======== ======== ========= ======== ========= =========
Wells in progress as of December 31, 1995 are as follows (domestic):
Type of Well Gross Net
Exploratory......................................... 1 0.3
Development......................................... 11 8.3
--------- -----
Total............................................ 12 8.6
========= =====
Coastal Limited Ventures, Inc., a domestic subsidiary of Coastal, is the
general partner in two 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.
In August 1995, Coastal's subsidiary, Coastal Oil & Gas Corporation,
acquired, through an affiliate, Tesoro Petroleum Corporation's 70% working
interest in three units covering more than 1,700 acres in the Bob West Field in
south Texas, which gave Coastal subsidiaries 100% working interest in this
acreage.
In December 1995, certain of the Company's oil and gas properties and
related assets in Texas, Utah and offshore in the Gulf of Mexico were conveyed
to a limited partnership. The assets conveyed to the partnership include the
interests in the Bob West Field. This limited partnership is wholly owned by
Coastal subsidiaries.
Domestically in 1995, Coastal continued to concentrate its exploration and
production activities in the Texas/Louisiana Gulf Coast area and offshore in the
Gulf of Mexico. Coastal continued its international exploration opportunities
during 1995 with a subsidiary signing a contract for exploration and development
rights covering a 100% interest in approximately 568,000 acres in central
Hungary and another subsidiary acquiring a 25% interest in exploration and
development rights to approximately 950,000 acres in Indonesia.
Gas and Oil Production
Natural gas production during 1995 averaged 348 MMcf daily, compared to
345 MMcf daily in 1994. Production from non-pipeline-owned wells averaged 234
MMcf daily in 1995, compared to 218 MMcf daily in 1994. Crude oil, condensate
and natural gas liquids production averaged 13,273 barrels daily in 1995,
compared to 12,239 barrels daily in 1994.
16
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, 1995:
Natural Gas
Oil Condensate Liquids
Gas (Thousands (Thousands (Thousands
Year (MMcf) of Barrels) of Barrels) of Barrels)
---- ------- ----------- ---------- -----------
1995 127,053 4,079 437 329
1994 125,773 3,634 429 404
1993 122,011 3,908 440 592
Many of Coastal's domestic gas wells are situated in areas near, and are
connected to, its gas systems. In other areas, gas production is sold to
pipeline companies and other purchasers.
Generally, Coastal's domestic production of crude oil, condensate and
natural gas liquids is purchased at the lease by its marketing and refinery
affiliates. Some quantities are delivered via Coastal's gathering and
transportation lines to its refineries, but most quantities are redelivered to
Coastal through various exchange agreements.
The following table summarizes sales price (net of production taxes) and
production cost information for domestic exploration and production operations
during the three years ended December 31, 1995:
1995 1994 1993
-------- -------- --------
Average sales price (net of production taxes):
Gas - per Mcf................................................. $ 1.50 $ 1.77 $ 1.93
Oil - per barrel.............................................. 16.55 14.96 16.21
Condensate - per barrel....................................... 15.86 14.69 15.55
Natural Gas Liquids - per barrel.............................. 14.59 8.36 8.75
Average production cost per unit (equivalent Mcf)................ 0.74 0.67 0.67
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 1995, total revenues of
$36.5 million were generated from the extraction and sale of 129 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, 1995, as estimated by Huddleston, its independent
engineers, were 36.3 million barrels, compared to 33.7 million barrels at the
end of 1994. Proved gas reserves as of December 31, 1995, net to Coastal's
interest, were estimated by the engineers to be 1,153.5 Bcf compared to 958.4
Bcf as of December 31, 1994.
For information as to Company-owned reserves of oil and gas, see
"Supplemental Information on Oil and Gas Producing Activities (Unaudited)" as
set forth in Item 14(a)1 hereof.
17
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 proxi mity, availability and capacity of gas pipelines and other
facilities for the transportation and marketing of gas. The production and sale
of oil and gas is subject to a variety of federal and state regulations,
including regulation of production levels.
Regulation
In all states in the United States in which Coastal engages in oil and gas
exploration and production, its activities are subject to regulation. Such
regulations may extend to requiring drilling permits, the spacing of wells, the
prevention of waste and pollution, the conservation of natural gas and oil, and
various other matters. Such regulations may impose restrictions on the
production of natural gas and crude oil by reducing the rate of flow from
individual wells below their actual capacity to produce. Likewise, oil and gas
operations on all federal lands are subject to regulation by the Department of
the Interior and other federal agencies.
COAL
The Company, through ANR Coal Company and its subsidiaries ("ANR Coal") in
the eastern United States and through Coastal States Energy Company and its
subsidiaries ("Coastal States Energy") in the 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, 1995, coal properties consisted of the following:
Coal Holdings (Acres)
------------------------------------------------------------ Clean,
Owner Leased Recoverable
-------------------------------- Exchanged Total Tons
Fee Mineral Surface (Net) Acres (Millions)
-------- --------- -------- -------- -------- -------------
Kentucky......................... 12,937 76,283 2,343 23,030 114,593 206
Virginia......................... 24,010 37,286 2,074 17,566 80,936 162
West Virginia.................... 367 55,853 8,160 131,807 196,187 221
Utah............................. 3,557 360 13,663 36,201 53,781 234
-------- --------- -------- -------- -------- ------
Total...................... 40,871 169,782 26,240 208,604 445,497 823
======== ========= ======== ======== ======== ======
- ------------------------
Based on a 65% recovery rate.
At December 31, 1995, the Company controlled approximately 823 million
recoverable tons of bituminous coal reserves. Production in 1995 from the
Company's reserves totalled 18.3 million tons of which 15.4 million tons were
produced from captive operations and 2.9 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 for the majority of its production.
The remaining production is derived from three mines operated by ANR Coal in
Kentucky and West Virginia. Captive production and processing from ANR Coal and
Coastal States Energy in 1995 totalled 6.1 and 9.3 million tons, respectively.
18
Captive sales from ANR Coal and Coastal States Energy were 7.3 million and
9.8 million tons, respectively, in 1995. Brokerage sales in which the Company
receives a commission totalled .9 million tons for the same period.
In 1995, approximately 67% of sales were to domestic utilities, 17% of
sales were to domestic industrial customers and 16% of sales were to export
markets primarily in Asia, Europe and Canada. Nearly one million tons of ANR
Coal's production were sold to domestic and foreign metallurgical markets. Of
the total 1995 tonnage sold, 14.0 million tons (82%) were sold under long-term
contracts. At December 31, 1995, the weighted average remaining life of these
contracts was 48 months.
The Company had approximately 22 million tons of annual production capacity
at December 31, 1995. In the eastern United States, the Company owns and
operates six coal preparation plants and nine loading facilities with a combined
annual capacity of 11.1 million tons. Coastal States Energy's mines in Utah
employ three longwall mining systems, diesel shuttle cars and have a combined
annual capacity of 10.9 million tons.
In addition to its bituminous coal operations, the Company controls
overriding royalty interests in approximately 461 million tons of lignite
reserves in North Dakota. Production from these reserves in 1995 totalled 15.0
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 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.
In February 1996, Coastal announced that it will seek qualified buyers for
its coal operations. The proceeds from the proposed sale, which the Company
plans to complete in 1996, are expected to be used to repay high-cost debt and
other obligations, and to provide improved financial flexibility to pursue
opportunities in other business operations of the Company. Additional
information regarding this announcement is set forth in Note 16 of the Notes to
Consolidated Financial Statements included herein.
POWER
Coastal Power Company ( "Coastal Power") and certain of its affiliates
develop, operate and own various equity interests in cogeneration and
independent power projects. The projects produce and sell electrical energy and,
in the case of cogeneration projects, thermal energy as well. Affiliates of
Coastal Power have interests in four domestic cogeneration projects and three
foreign operating independent power projects.
Capitol District Energy Center Cogeneration Associates ("CDECCA") owns a
combined-cycle cogeneration project with a capacity of approximately 56
megawatts, located in Hartford, Connecticut. An affiliate of Coastal Power owns
a 50% equity 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 a local utility under a long-term
contract. Gas supply is provided to the cogeneration plant by other Coastal
affiliates. Thermal energy from the plant is sold both to a local heating and
cooling supplier in the city of Hartford and an equity partner of CDECCA.
An affiliate of Coastal Power is the managing partner and 50-percent owner
of a combined-cycle cogeneration plant at Coastal's Eagle Point, New Jersey
refinery. The plant has a capacity of approximately 225 megawatts. Power from
the plant is sold to a local utility and Coastal's refinery under long-term
contracts. Steam from the plant is also sold to the refinery under long-term
contract. Gas supply is provided to the cogeneration plant by other Coastal
affiliates. CTI is the operator of the cogeneration plant.
19
Fulton Cogeneration Associates owns a cogeneration facility with a
capacity of approximately 47 megawatts, located in Fulton, New York. This
facility is 100% owned by an affiliate of Coastal Power and another Coastal
subsidiary. Electricity from this project is sold to a New York utility under a
long-term contract. Thermal energy is sold to a local confections manufacturer
adjacent to the project, also under a long-term contract. Approximately one-half
of the gas supply requirements for the project are supplied by an affiliate of
Coastal Power. CTI is the operator of the cogeneration plant.
Coastal, through a wholly-owned subsidiary, has a 10.9% equity interest in
the Midland Cogeneration Venture Limited Partnership, a 1,370 megawatt capacity
gas-fired cogeneration plant in Michigan, which is the largest cogeneration
facility in the United States. Coastal's affiliates provide gas supply and
transmission services for a portion of the project's fuel requirements.
Compania de Electricidad de Puerto Plata, S.A. ("CEPP") owns an
independent power project in Puerto Plata, Dominican Republic. Coastal Power
International Ltd. and other affiliates of Coastal Power together with two other
unrelated parties purchased 100% of the shares of CEPP in 1995. The project has
a total capacity of 66.5 megawatts of which 50 megawatts are barge mounted and
16.5 megawatts are land based. Coastal Power International Ltd. owns a 48.5%
equity interest in CEPP. An affiliate of Coastal Power is involved in arranging
the fuel for the project and another affiliate operates the project pursuant to
a contract with CEPP. The electrical energy is sold to the national electric
utility of the Dominican Republic under a long-term contract.
Coastal Nejapa Ltd. and other affiliates lease an independent power
project near Apopa, El Salvador. The heavy-fuel-oil plant has a capacity of
approximately 91 megawatts, which is currently being expanded by 53 megawatts.
Coastal Power, through its affiliates, currently receives approximately 86.6% of
the distributable cash flow and a Salvadoran investor receives the remainder.
Coastal affiliates provide fuel for this project. The electrical energy is sold
to the national electric utility of El Salvador under a long-term contract.
Coastal Wuxi Power Ltd., an affiliate of Coastal Power, together with two
Chinese partners, formed a Sino-foreign joint venture company to own, construct,
and operate a simple-cycle, diesel-fired peaking plant in April 1995. The
project has a capacity of approximately 40 megawatts and is located in Wuxi
City, Province of Jiangsu, The People's Republic of China. Coastal Wuxi Power
Ltd. owns a 60% equity interest in the joint venture. The project commenced the
sale of electrical energy in the first quarter of 1996.
Coastal Suzhou Power Ltd., a subsidiary of Coastal Power, together with a
Chinese partner, formed a Sino-foreign joint venture to develop, construct, own,
and operate an independent power project, in October 1995. The project, when
completed, will have a capacity of approximately 76 megawatts, and will be
located in Suzhou City, Province of Jiangsu, The People's Republic of China.
Coastal Suzhou Power Ltd. owns a 60% equity interest in the joint venture. When
the project is completed in the summer of 1996, it will sell power to the local
utility under a long-term contract.
In December 1995 Coastal Nanjing Power Ltd., a subsidiary of Coastal
Power, together with two Chinese partners, formed a Sino-foreign joint venture
to develop, construct, own and operate an independent power project. The
project, when completed, will have a capacity of approximately 72 megawatts and
will be located in Nanjing City, Jiangsu Province, The People's Republic of
China. Coastal Nanjing Power Ltd. owns an 80% equity interest in the joint
venture. The project is scheduled to commence operations by the end of 1996 and
plans to sell power to the local utility under a long-term contract, which is
presently under negotiation.
A subsidiary of Coastal Power is in the process of completing negotiations
to build and operate a 140-megawatt capacity natural gas-fired power plant in
Quetta, Pakistan. The Coastal Power subsidiary will hold a 50% voting interest
in the project with Habibullah Energy Limited, a Pakistan entity, holding the
remaining 50%. The power from the project will be sold to the national utility
under a long-term contract.
Competition
Coastal is subject to competition with other energy organizations and
utilities seeking to develop and acquire independent power operations. Due to an
excess of generation capacity in the domestic market, Coastal and many other
20
power producers are concentrating their efforts abroad, where the demand for
independent power production is greater and opportunities exist for greater
rates of return. International competition continues to increase as the world
market for independent power production develops and power purchasers employ
competitive bidding for project awards. In the United States and international
locations, the sale of power and the operation of power cogeneration facilities
are regulated by the applicable laws, rules and regulations of the respective
governments and agencies having jurisdiction.
OTHER OPERATIONS
On November 3, 1995, Advance Transportation Company ("Advance") merged
into the Company's trucking subsidiary, ANR Freight System, Inc. Under the terms
of the merger, the surviving company has changed its name to ANR Advance
Transportation Company, Inc. and is owned by a holding company, ANR Advance
Holdings, Inc., which is in turn owned 50% by a subsidiary of Coastal and 50% by
certain former owners of Advance. The combined company created the third largest
regional carrier in the Great Lakes/Central States region, has a fleet of 7,100
pieces of revenue equipment and serves an area including 16 states as well as
Canada and Mexico from a network of approximately 60 terminals. Due to this
merger, trucking operations do not constitute a business segment of the Company.
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
natural gas systems; refining, marketing and distribution, and chemicals;
exploration and production; coal; and power subsidiaries of Coastal are engaged
in highly competitive businesses against competitors, some of which have
significantly larger facilities and market share. See also the discussion of
competition under "Natural Gas Systems," "Refining, Marketing and Distribution,
and Chemicals," "Exploration and Production," "Coal" and "Power" herein.
ENVIRONMENTAL
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations. The Company spent
approximately $45 million in 1995 on environmental capital projects and
anticipates capital expenditures of approximately $55 million in 1996 in order
to comply with such laws and regulations. The majority of the 1996 expenditures
is attributable to construction projects at the Company's refineries. The
Company currently anticipates capital expenditures for environmental compliance
for the years 1997 through 1999 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 and a company in which Coastal
owns a 50% interest have been named as a potentially responsible party ("PRP")
in several "Superfund" waste disposal sites. At the 15 sites for which the
Environmental Protection Agency ("EPA") has developed sufficient information to
estimate total clean-up costs of approximately $341 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 5 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 9 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.
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.
21
In January 1996, the EPA Region II issued a Notice of Violation to Coastal
Eagle Point Oil Company, a subsidiary of Coastal, and the Eagle Point
Cogeneration Partnership, in which Coastal has an indirect 50% interest. The
EPA's Notice alleges certain violations of air and operating permits at the New
Jersey facility, but the EPA has not specified the relief it is seeking. 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.
The Texas Natural Resources Conservation Commission ("TNRCC") alleges that
Coastal Refining & Marketing, Inc. ("CR&M"), a subsidiary of the Company, has
violated certain solid and hazardous waste laws and regulations, including 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 CR&M 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. IPOC is not affiliated with ANR
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 laws related to the construction and operation
of the Iroquois Pipeline. A global resolution of the federal civil and criminal
investigations and agency proceedings could involve fines and other monetary
sanctions that would not be material to the consolidated financial position or
results of operations of ANR Pipeline. In conjunction with this, and although no
agreements have been reached regarding the disposition of these matters, ANR
Pipeline has recorded a reserve for its share of the potential expense of the
Iroquois investigation and proceedings.
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 United States District
Courts or in state courts, necessary rights-of-way to construct, operate and
maintain pipelines and necessary land or other property for compressor and other
stations and equipment necessary to the operation of pipelines.
Item 3. Legal Proceedings.
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.
22
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 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.
In March of 1995, the Trial Court granted a partial summary judgment in favor of
CIG, holding that the four-year statute of limitations had not been tolled, that
the releases are valid, and dismissing all tort claims and claims for breach of
any duty of disclosure. The remaining claim for underpayment of royalties was
tried to a jury which, in May 1995, made findings favorable to CIG. On June 7,
1995, the Trial Court entered a judgment that the lessors recover no monetary
damages from CIG and permanently estopping the lessors from asserting any claim
based on an interpretation of the contract different than that asserted by CIG
in the litigation. The lessors' motion for a new trial is pending.
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.
23
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 13, 1996, the approximate number of holders of
record of Common Stock was 8,894 and of the Class A Common Stock was 3,458.
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.
1995 1994
----------------------------------- ------------------------------------
Quarters High Low Dividends High Low Dividends
- -------------------- -------- ----- --------- -------- ----- ---------
First Quarter $29.50 $25.13 $.10 $33.75 $27.50 $.10
Second Quarter 31.75 28.38 .10 32.63 26.88 .10
Third Quarter 34.25 30.25 .10 33.25 27.38 .10
Fourth Quarter 37.75 31.13 .10 29.13 24.75 .10
Coastal expects to continue paying dividends in the future. Dividends of
$.09 per share were paid on the Class A Common Stock for each quarterly period
in 1995 and 1994. At December 31, 1995, 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 $528.4 million.
24
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, 1994. The Notes to Consolidated Financial Statements
included herein contain other information relating to this data.
Year Ended December 31,
---------------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ------------ ------------ ------------ ----------
Operating revenues $ 10,447.7 $ 10,215.3 $ 10,136.1 $ 10,062.9 $ 9,554.8
Earnings (loss) before extraordinary item 270.4 232.6 118.3 (126.8) 8.7
Net earnings (loss) 270.4 232.6 115.8 (126.8) 8.7
Earnings (loss) per common and common
equivalent share before extraordinary
item 2.40 2.05 1.02 (1.23) .08
Net earnings (loss) per common and
common equivalent share 2.40 2.05 1.00 (1.23) .08
Cash dividends per common share* .40 .40 .40 .40 .40
Total assets 10,658.8 10,534.6 10,227.1 10,579.8 10,520.3
Debt, excluding current maturities 3,661.7 3,720.2 3,812.5 4,306.1 3,865.6
Mandatory redemption preferred stock,
excluding current maturities .6 .6 26.6 36.7 49.2
* In addition, cash dividends of $.36 per share were paid on the Company's Class A Common Stock in 1995, 1994,
1993, 1992 and 1991.
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-9 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.
25
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 2, 1996 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 13, 1996, were as
follows:
Name (Age), Year First Positions and Offices
Elected An Officer with the Registrant
O. S. Wyatt, Jr. (71), 1955 Chairman of the Board of Directors
David A. Arledge (51), 1982 President, Chief Executive Officer,
Chief Financial Officer and Director
Harold Burrow (81), 1974 Vice Chairman of the Board of
Directors, Chairman of the Board of
Directors of Colorado
James F. Cordes (55), 1985 Executive Vice President and Director
James A. King (56), 1992 Executive Vice President
Sam F. Willson, Jr. (66), 1974 Executive Vice President
Jerry D. Bullock (66), 1992 Senior Vice President
Jeffrey A. Connelly (49), 1988 Senior Vice President
Carl A. Corrallo (52), 1993 Senior Vice President and General
Counsel
Donald H. Gullquist (52), 1994 Senior Vice President
Coby C. Hesse (48), 1986 Senior Vice President and Controller
Dan J. Hill (55), 1978 Senior Vice President
Kenneth O. Johnson (75), 1978 Senior Vice President and Director
Austin M. O'Toole (60), 1974 Senior Vice President and Secretary
Jack C. Pester (61), 1987 Senior Vice President
James L. Van Lanen (51), 1985 Senior Vice President
M. Truman Arnold (67), 1993 Vice President
Daniel F. Collins (54), 1989 Vice President
Robert C. Hart (51), 1994 Vice President
John J. Lipinski (45), 1995 Vice President
Edward A. More (47), 1995 Vice President
M. Frank Powell (45), 1993 Vice President
Thomas M. Wade (43), 1995 Vice President
Ronald D. Matthews (48), 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 management committee of
BP Exploration USA. From 1990 to 1992, he was an independent petroleum
consultant for several major exploration companies.
26
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. 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 Table" and "Performance Graph -
Shareholder Return on Common Stock" in the Coastal Proxy Statement for the May
2, 1996 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 2, 1996 Annual Meeting of Stockholders filed
pursuant to Regulation 14A under the Securities Exchange Act of 1934, and is
incorporated herein by reference.
Item 13. Certain Relationships and Related Transactions.
The information called for by this item is set forth under "Election of
Directors," and "Transactions with Management and Others" in the Coastal Proxy
Statement for the May 2, 1996 Annual Meeting of Stockholders filed pursuant to
Regulation 14A under the Securities Exchange Act of 1934, and is incorporated
herein by reference.
27
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:
1. Financial Statements and Supplemental Information.
The following Consolidated Financial Statements of Coastal and
Subsidiaries and Supplemental Information are included in response to
Item 8 hereof on the attached pages as indicated:
Page
Independent Auditors' Report................................... F-10
Statement of Consolidated Operations for the years ended
December 31, 1995, 1994 and 1993............................ F-11
Consolidated Balance Sheet at December 31, 1995 and 1994....... F-12
Statement of Consolidated Cash Flows for the years ended
December 31, 1995, 1994 and 1993............................ F-14
Statement of Consolidated Common Stock and Other Stockholders'
Equity for the years ended December 31, 1995, 1994 and 1993. F-15
Notes to Consolidated Financial Statements..................... F-16
Supplemental Information on Oil and Gas Producing Activities
(Unaudited)................................................. F-39
Supplemental Statistics for Coal Mining Operations (Unaudited). F-43
2. Financial Statement Schedules.
The following schedules of Coastal and Subsidiaries are included
on the attached pages as indicated:
Page
Schedule I - Condensed Financial Information of the
Registrant.................................... S-1
Schedule II - Valuation and Qualifying Accounts............. S-6
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).
28
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).
10.14* Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Fourth Amendment
dated May 20, 1994, Fifth Amendment dated August 17, 1994,
Sixth Amendment dated August 30, 1994, Seventh Amendment dated
October 30, 1995, Eighth Amendment dated December 29, 1995 and
Ninth Amendment dated December 29, 1995.
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.
29
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.
A report on Form 8-K was filed on October 17, 1995. The item reported was:
Item 7. Financial Statements and Exhibits.
(c) Exhibits
(12) Ratio of Earnings to Fixed Charges
30
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)
DAVID A. ARLEDGE
By: ---------------------------------------
David A. Arledge
President and Chief Executive Officer
March 27, 1996
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.
O. S. WYATT, JR.
By: ---------------------------------------
O. S. Wyatt, Jr.
Chairman of the Board
March 27, 1996
DAVID A. ARLEDGE
By: ---------------------------------------
David A. Arledge
Principal Financial Officer and Director
March 27, 1996
COBY C. HESSE
By: ---------------------------------------
Coby C. Hesse
Principal Accounting Officer
March 27, 1996
JOHN M. BISSELL
By: ---------------------------------------
John M. Bissell
Director
March 27, 1996
* * *
31
GEORGE L. BRUNDRETT, JR.
By: ---------------------------------------
George L. Brundrett, Jr.
Director
March 27, 1996
HAROLD BURROW
By: ---------------------------------------
Harold Burrow
Director
March 27, 1996
ROY D. CHAPIN, JR.
By: ---------------------------------------
Roy D. Chapin, Jr.
Director
March 27, 1996
JAMES F. CORDES
By: ---------------------------------------
James F. Cordes
Director
March 27, 1996
ROY L. GATES
By: ---------------------------------------
Roy L. Gates
Director
March 27, 1996
KENNETH O. JOHNSON
By: ---------------------------------------
Kenneth O. Johnson
Director
March 27, 1996
JEROME S. KATZIN
By: ---------------------------------------
Jerome S. Katzin
Director
March 27, 1996
THOMAS R. McDADE
By: ---------------------------------------
Thomas R. McDade
Director
March 27, 1996
L. D. WOODDY, JR.
By: ---------------------------------------
L. D. Wooddy, Jr.
Director
March 27, 1996
32
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of
Operations includes certain forward-looking statements reflecting the Company's
expectations in the near future; however, many factors which may affect the
actual results, especially commodity prices and changing regulations, are
difficult to predict. Accordingly, there is no assurance that the Company's
expectations will be realized.
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.
1995 1994 1993
-------- -------- --------
Net return on average common stockholders' equity............................ 10.8% 10.0% 5.2%
Cash flow from operating activities to long-term debt........................ 17.7% 18.0% 21.2%
Total debt to total capitalization........................................... 59.4% 61.7% 64.3%
Times interest earned (before tax)........................................... 1.8 1.8 1.4
The above ratios reflect increased earnings and decreased long-term debt
in both 1995 and 1994. The 1995 and 1994 decreases in the cash flow from
operating activities to long-term debt ratio resulted from changes in working
capital partially offset by increased distributions from equity investments as
well as increased earnings.
Cash flows provided from operating activities were $649.1 million in 1995,
$669.1 million in 1994 and $809.8 million in 1993. The decreases for 1995 and
1994 can be primarily attributed to increases for working capital requirements
partially offset by increased earnings and an increase in distributed earnings
from equity investments.
Capital expenditures amounted to $626.8 million, $543.2 million and $392.7
million in 1995, 1994 and 1993, respectively. The 1995 increase is primarily due
to continued expansion in the Exploration and Production segment as reserve
additions in 1995 were more than triple 1995 production. Property additions also
increased in the Natural Gas segment due to additions for the regulated pipeline
subsidiaries. Expenditures were reduced in the Refining, Marketing and Chemicals
segment as major improvements made at the refineries and expansion of
petrochemical operations in 1994 did not recur at the same level in 1995. The
increased expenditures in 1994 were due to expansion of the earnings bases in
the Refining, Marketing and Chemicals and Exploration and Production segments.
Proceeds from the sale of property increased by $79.5 million in 1995 as a
result of the sale of certain Refining, Marketing and Chemicals liquids
pipelines to a limited partnership. Additions to investments in 1995 increased
primarily due to investments in power projects while the 1994 decrease resulted
from reduced advances to gas pipeline partnerships. Proceeds from investments
decreased in 1995 and increased in 1994 primarily as a result of the Company's
sale of exploration and production interests in Argentina. 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 debt by $49.3 million and $208.9 million in
1995 and 1994, respectively, primarily by the use of internally generated funds
and other financial transactions. The 1995 and 1994 changes in redemption of
mandatory redemption preferred stock are due to ANR Pipeline Company ("ANR
Pipeline') redeeming all shares of its outstanding Cumulative Preferred Stock in
1994.
Capital expenditures for 1996, including the Company's equity investments
in partnerships and joint ventures, are currently budgeted at approximately $695
million; however, future expenditures are dependent on conditions in the energy
industry. These expenditures are primarily for completion of projects in
process, operational necessities,
F-1
environmental requirements, expansion projects and increased efficiency. Other
expansion opportunities will continue to be evaluated.
Financing for budgeted expenditures and mandatory debt retirements in 1996
will be accomplished by the use of internally generated funds, existing credit
lines, proceeds from the sale of selective non-core assets and new financings.
On February 28, 1996, the Company announced that it will seek qualified
buyers for its coal operations. The proceeds from the proposed sale, which the
Company plans to complete in 1996, are expected to be used to significantly
strengthen the Company's balance sheet by the repayment of high-cost debt and
other obligations, and to provide improved financial flexibility to pursue
opportunities in the Company's other lines of business. See Note 16 of the Notes
to Consolidated Financial Statements.
Funding for certain proposed 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.
Unused lines of credit at December 31, 1995 were as follows (millions of
dollars):
Short-term....................................... $ 475.3
Long-term*....................................... 553.5
--------
$1,028.8
*$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, 1995, net assets of
consolidated subsidiaries amounted to approximately $5.5 billion, of which
approximately $1.9 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, 1995, the
Company had interest rate swaps with a notional amount of $34.5 million, and a
portfolio of variable rate debt outstanding in the amount of $537.6 million. The
Company has also entered into a number of interest rate swap agreements which
have effectively converted $419.2 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 the year 2000. At December
31, 1995, the Company had no exposure to credit loss on interest rate swaps.
The Company has also entered into a foreign currency swap to fully hedge
to maturity the foreign currency denominated debt of the Company. At December
31, 1995, the Company had outstanding swiss franc-denominated debt of $66.5
million. This swap involves the exchange of interest payments in differing
currencies at exchange rates effective at the time the agreement was entered
into, and provides for the exchange of principal amounts at maturity, usually
through an escrow arrangement to limit credit risk. The Company has also entered
into an interest rate swap with a notional amount of 16.4 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, 1995, the floating rate was
2.0%. At December 31, 1995, Coastal had exposure to credit loss of approximately
$50.0 million on currency swaps.
F-2
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. See Note 8 of 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 reported to and, when necessary,
are approved by the Company's Board of Directors. The Company and its
subsidiaries also 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 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.
The Financial Accounting Standards Board ("FASB") has issued Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("FAS 121"), to
be effective in 1996. The provisions of FAS 121 require the Company to review
long-lived assets and certain identifiable intangibles for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. FAS 121 also requires that a rate-regulated enterprise
recognize an impairment for the amount of costs that a regulator excludes from
the enterprise's allowable costs. If it is determined that an impairment has
occurred, the amount of the impairment should be charged to earnings. The
application of the new standard is not expected to have a material effect on the
Company's results of operations or financial position in 1996.
In October 1995, the FASB issued Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"), which
establishes financial accounting and reporting standards for stock-based
employee compensation plans and for transactions in which an entity issues its
equity instruments to acquire goods and services from nonemployees. FAS 123
requires, among other things, that compensation cost be calculated for fixed
stock options at the grant date by determining fair value using an
option-pricing model. The Company has the option of recognizing the compensation
cost over the vesting period as an expense in the statement of consolidated
operations or making pro forma disclosures in the notes to financial statements
as to the effects on net earnings as if the compensation cost had been
recognized in the statement of consolidated operations. The Company will adopt
FAS 123 in 1996 by making pro forma disclosures in the notes to financial
statements.
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations. The Company spent
approximately $45 million in 1995 on environmental capital projects and
anticipates capital expenditures of approximately $55 million in 1996 in order
to comply with such laws and regulations. The majority of the 1996 expenditures
is attributable to construction projects at the Company's refineries. The
Company currently anticipates capital expenditures for environmental compliance
for the years 1997 through 1999 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 and a company in which Coastal
owns a 50% interest have been named as a potentially responsible party ("PRP")
in several "Superfund" waste disposal sites. At 15 sites for which the
Environmental Protection Agency ("EPA") has developed sufficient information to
estimate total clean-up costs of approximately $341 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 5 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 9 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.
F-3
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, marketing and chemicals; exploration and production;
coal; and power.
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 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. 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.
Million of Dollars
-------------------------------------------
1995 1994 1993
----------- ----------- ----------
Operating revenues.............................................. $ 2,898.6 $ 3,075.7 $ 3,247.9
Depreciation, depletion and amortization........................ 152.3 151.0 145.4
Operating profit................................................ 403.5 431.3 405.2
Total throughput volume (Bcf)................................... 2,102 1,980 1,908
1995 Versus 1994. The decrease in operating revenue of $177 million can be
primarily attributed to decreased prices more than offsetting increased volumes
for the unregulated gas marketing companies. Also contributing to the revenue
decrease was a reduction in the volumes of gas auctioned by ANR Pipeline on the
open market. Partially offsetting the decreases was an increase in
transportation revenue due primarily to increased volumes. Total throughput
volumes for the pipelines increased by approximately 6% while the volumes
managed by the gas marketing companies increased by 15%.
F-4
Purchases decreased by $163 million in 1995, as decreased prices more than
offset increased volumes for the unregulated gas marketing companies, resulting
in a gross profit decrease of $14 million.
The operating profit decrease of $28 million results from decreased sales
margins of $24 million, decreased storage revenue of $23 million, increased
operating expenses of $10 million and other decreases of $7 million offset by
increased transportation revenue of $28 million and increased sales volumes of
$8 million.
The increased operating expense results from non-recurring 1994 expense
reductions of $13 million (primarily related to revisions of certain estimated
costs) and other expense increases partially offset by decreases for storage and
transportation expenses and gas used in operations.
The operating revenue and operating profit decreases reflect the increased
competition in the natural gas industry. The regulated subsidiaries took steps,
such as re-engineering projects and cost-cutting efforts, to meet this
competition, while the unregulated companies expanded their presence across
North America. Also impacting this segment's results is the excess pipeline
capacity in the midwestern United States, where margins have been compressed by
plentiful supplies of natural gas and market distortions caused by an
underpriced secondary market for pipeline capacity. The Company believes this
capacity overhang will lessen by the end of the decade as demand for natural gas
grows and competitors convert or retire underutilized assets.
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 benefited from the 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.
F-5
Refining, Marketing and Chemicals. Refining, marketing and chemicals
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.
Million of Dollars
-------------------------------------------
1995 1994 1993
----------- ----------- ----------
Operating revenues.............................................. $ 6,851.3 $ 6,458.9 $ 6,200.9
Depreciation, depletion and amortization........................ 61.8 53.9 45.6
Operating profit ............................................... 208.8 153.3 98.3
Refined product sales (MM Bbls)................................. 301 298 294
1995 Versus 1994. Operating revenues increased by $392 million as a result
of increased prices and volumes. The volume increase is primarily due to
increased throughput of 15,000 barrels per day at the Company's refineries.
Purchases for the segment increased by $335 million, resulting in an
increased gross profit of $57 million. Increased volumes of $111 million and a
gain of $17 million from the sale of interests in certain liquid pipeline assets
offset by reduced margins of $64 million and other decreases of $7 million make
up the gross profit increase. On an industrywide basis, refinery margins in 1995
were the second worst seen in the past decade.
The operating profit increase of $55 million results from the increased
gross profit of $57 million and reduced operating expenses of $6 million being
offset by increased depreciation, depletion and amortization of $8 million. The
decreased operating expenses result from decreases at the refineries due to
reduced fuel costs and other improvements more than offsetting increases for the
retail and chemical operations. The reduced refinery operating expenses result
from improvements made at the refineries as part of Coastal's objective to be a
low-cost operator. The increases for retail and chemical operations result from
the acquisition of additional convenience stores and expanded chemicals
operations, respectively. Depreciation, depletion and amortization increased due
to the expanded operations noted above.
The marketing of paraxylene from Coastal's petrochemical plant in Montreal
East, Quebec was a strong contributor to the segment's operating profit in 1995
and should continue to make significant contributions. By the end of 1995,
production capacity was boosted to 310,000 tons per year from a capacity of
180,000 tons per year at December 31, 1994 to take advantage of the strong
market.
Also in 1995, the marketing group began a review of their operations to
determine an optimal level of integration with the Company's refineries. As a
result, the Company has pulled out of 60 less profitable terminal facilities.
The restructuring will be completed in 1996.
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 expense 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.
F-6
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 processing plant operations.
Million of Dollars
-------------------------------------------
1995 1994 1993
----------- ----------- ----------
Operating revenues.............................................. $ 268.7 $ 298.9 $ 357.3
Depreciation, depletion and amortization........................ 105.5 106.0 109.1
Operating profit................................................ 24.9 41.8 49.9
Natural gas production (MMcf/d)................................. 234 218 207
Oil, condensate and natural gas liquids production (bpd)........ 13,231 12,237 13,533
Average sales price - net of production taxes (dollars):
Gas (per Mcf)................................................ $ 1.50 $ 1.77 $ 1.93
Oil, condensate and natural gas liquids (per bbl)............ 16.35 14.34 15.26
1995 Versus 1994. Operating revenues decreased by $30 million as lower
natural gas prices and decreased revenues from natural gas marketing activities
were partially offset by increased volumes for all products and higher prices
for crude oil, condensate and natural gas liquids. Natural gas revenue decreases
of $41 million, including $28 million for natural gas marketing, and other
decreases of $6 million were partially offset by increases of $17 million for
crude oil, condensate and natural gas liquids.
The operating profit decrease of $17 million results from decreased
natural gas prices of $23 million, reduced gross profit from natural gas
marketing activities of $4 million, increased operating expenses of $11 million
and other decreases of $5 million offset by increased volumes of $16 million and
increased prices for crude oil, condensate and natural gas liquids of $10
million. The increased operating expenses result from additional producing wells
acquired or drilled during the year.
Even with up to 25 percent of natural gas production shut in earlier in
the year because of unsatisfactory prices, average production of natural gas
increased by 7%. Net production of crude oil and condensate increased by 11%
over the 1994 production. In addition, Coastal added reserves in 1995 that were
more than triple the 1995 production, increasing reserves to more than 1
trillion cubic feet of natural gas equivalent.
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.
F-7
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.
Million of Dollars
-------------------------------------------
1995 1994 1993
----------- ----------- ----------
Operating revenues.............................................. $ 459.6 $ 451.3 $ 443.2
Depreciation, depletion and amortization........................ 31.3 28.9 28.5
Operating profit................................................ 98.7 98.2 95.1
Captive and brokered sales (millions of tons)................... 18.0 17.5 17.4
1995 Versus 1994. The increase in coal revenues is a result of increased
volumes sold more than offsetting reduced prices. Much of the volume increase
came from increased demand in the steam coal market. The segment experienced a
5% increase in volumes sold and produced, while industrywide coal production and
sales decreased about 1%.
The operating profit increase of $1 million results from increased sales
volumes of $14 million offset by decreased prices of $4 million; increased
operating expenses of $4 million; increased depreciation, depletion and
amortization of $3 million and other of $2 million. Operating expenses,
including coal costs, and depreciation, depletion and amortization increased as
a result of the volume increase. The other decrease results from reduced
brokerage and royalty volumes.
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.
Power. Power operations include the ownership of, participation in and
operation of power projects in the United States and internationally.
Million of Dollars
-------------------------------------------
1995 1994 1993
----------- ----------- ----------
Operating revenues.............................................. $ 48.4 $ 27.2 $ 26.1
Depreciation, depletion and amortization........................ 2.0 1.5 1.5
Operating profit................................................ 7.8 2.7 3.9
1995 Versus 1994. The increase in operating revenues of $21 million
results primarily from the power plant in El Salvador beginning operations in
1995. The operating profit increase of $5 million results from the increased
revenues of $21 million offset by increased operating expenses, also due to the
El Salvador operations, of $16 million.
In addition to the El Salvador plant, construction was completed on a
power plant in Wuxi City, China, in which the Company has an equity interest,
and the Company purchased a 48% interest in a power plant in the Dominican
Republic in 1995. The Company's investment in these partially-owned projects is
normally reflected on an equity basis, thus the earnings are classified as other
income-net rather than operating profit. In 1995, the equity income from these
equity investments amounted to $20 million.
1994 Versus 1993. The operating revenues increased by $1 million, while
operating profit decreased by $1 million. The operating profit decrease is due
to expenses related to the acquisition of cogeneration facilities.
F-8
Other. Other operations involve trucking, real estate and other activities.
Million of Dollars
-------------------------------------------
1995 1994 1993
----------- ----------- ----------
Operating revenues.............................................. $ 148.3 $ 181.1 $ 160.9
Depreciation, depletion and amortization........................ 5.7 5.9 6.4
Operating profit (loss)......................................... 7.3 6.3 (16.7)
1995 Versus 1994. Effective November 3, 1995, Coastal's trucking
operations were merged into a new company in which Coastal has a 50% interest.
The $33 million decrease in operating revenues results from decreased rates and
volumes for the trucking operations through October, 1995 and no operating
revenues during the last two months due to the merger noted above. Operating
profit increased by $1 million as the reduced revenues were more than offset by
reduced expenses for the trucking and other operations.
1994 Versus 1993. The $20 million increase in operating revenues results
primarily from volume increases for the trucking operations, while the $23
million increase in operating profit results from the $20 million revenue
increase and a $3 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 $3 million to make up
the 1994 operating profit increase.
Other Income - Net
1995 Versus 1994. Other income-net decreased by $10 million in 1995 due to
reduced equity income from unconsolidated subsidiaries, primarily from the 50%
owned Pacific Refining Company.
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.
Interest and Debt Expense
1995 Versus 1994. Interest and debt expense increased by $8 million in
1995 due to certain favorable 1994 financing costs transactions and interest
adjustments not recurring, partially offset by reduced average debt levels and a
slightly lower average interest rate. At December 31, 1995, after giving effect
to interest rate swaps, approximately 31 percent of the Company's debt was tied
to money-market related rates.
1994 Versus 1993. Interest and debt expense decreased by $35 million in
1994, primarily as a result of lower debt levels, lower average interest rates
and reduced other financial costs more than offsetting increases in interest on
customers refunds.
Taxes on Income
Income taxes fluctuated primarily as a result of changing levels of income
before taxes and changes in the effective federal income tax rate. The effective
federal income tax rate for 1995 was affected by certain foreign subsidiaries'
unremitted earnings, which are considered to be indefinitely reinvested outside
the United States and, accordingly, no U.S. income taxes have been provided on
those earnings. 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 of the Notes to Consolidated Financial
Statements.
F-9
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, 1995 and 1994, 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, 1995. 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, 1995 and 1994, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1995, 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.
DELOITTE & TOUCHE LLP
Houston, Texas
February 1, 1996
F-10
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars Except Per Share)
Year Ended December 31,
--------------------------------------------
1995 1994 1993
----------- ----------- -----------
OPERATING REVENUES.............................................. $ 10,447.7 $ 10,215.3 $ 10,136.1
----------- ----------- -----------
OPERATING COSTS AND EXPENSES
Purchases.................................................... 7,554.2 7,360.5 7,400.2
Operating expenses........................................... 1,764.0 1,758.0 1,744.5
Depreciation, depletion and amortization..................... 378.5 363.2 355.7
----------- ----------- -----------
9,696.7 9,481.7 9,500.4
----------- ----------- -----------
OPERATING PROFIT................................................ 751.0 733.6 635.7
----------- ----------- -----------
OTHER INCOME-NET................................................ 51.6 61.2 68.9
----------- ----------- -----------
OTHER EXPENSES
General and administrative................................... 64.7 62.1 59.7
Interest and debt expense.................................... 415.4 407.8 442.5
Taxes on income.............................................. 52.1 92.3 84.1
----------- ----------- -----------
532.2 562.2 586.3
----------- ----------- -----------
EARNINGS BEFORE EXTRAORDINARY ITEM.............................. 270.4 232.6 118.3
Extraordinary item-loss on early extinguishment of debt...... - - (2.5)
----------- ----------- -----------
NET EARNINGS ................................................... 270.4 232.6 115.8
DIVIDENDS ON PREFERRED STOCK.................................... 17.4 17.4 11.3
----------- ----------- -----------
NET EARNINGS AVAILABLE TO
COMMON STOCKHOLDERS.......................................... $ 253.0 $ 215.2 $ 104.5
=========== =========== ===========
EARNINGS PER SHARE:
Before extraordinary item.................................... $ 2.40 $ 2.05 $ 1.02
Extraordinary item........................................... - - (.02)
----------- ----------- -----------
NET EARNINGS PER COMMON AND
COMMON EQUIVALENT SHARE...................................... $ 2.40 $ 2.05 $ 1.00
=========== =========== ===========
See Notes to Consolidated Financial Statements.
F-11
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
December 31,
---------------------------
1995 1994
----------- ----------
ASSETS
CURRENT ASSETS
Cash and cash equivalents..................................................... $ 58.4 $ 73.5
Receivables, less allowance for doubtful accounts of
$21.4 million (1995) and $19.0 million (1994).............................. 1,192.3 1,306.0
Inventories................................................................... 781.1 818.1
Prepaid expenses and other.................................................... 218.3 230.3
----------- ----------
Total Current Assets....................................................... 2,250.1 2,427.9
----------- ----------
PROPERTY, PLANT AND EQUIPMENT - AT COST
Natural gas systems........................................................... 5,866.2 5,763.7
Refining, crude oil and chemical facilities................................... 1,957.8 2,005.7
Gas and oil properties-at full-cost........................................... 1,450.9 1,283.7
Other......................................................................... 743.1 722.8
----------- ----------
10,018.0 9,775.9
Accumulated depreciation, depletion and amortization.......................... 3,556.1 3,441.2
----------- ----------
6,461.9 6,334.7
OTHER ASSETS
Goodwill...................................................................... 525.7 544.5
Investments - equity method .................................................. 447.4 378.3
Other......................................................................... 973.7 849.2
----------- ----------
1,946.8 1,772.0
----------- ----------
$ 10,658.8 $ 10,534.6
=========== ==========
See Notes to Consolidated Financial Statements.
F-12
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
December 31,
---------------------------
1995 1994
----------- ----------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES
Notes payable................................................................. $ 123.2 $ 57.2
Accounts payable.............................................................. 1,630.2 1,942.0
Accrued expenses.............................................................. 325.4 329.1
Current maturities on long-term debt.......................................... 128.5 185.3
----------- ----------
Total Current Liabilities.................................................. 2,207.3 2,513.6
----------- ----------
DEBT
Long-term debt, excluding current maturities.................................. 3,661.7 3,520.5
Subordinated long-term debt................................................... - 199.7
----------- ----------
3,661.7 3,720.2
DEFERRED CREDITS AND OTHER
Deferred income taxes......................................................... 1,473.8 1,473.9
Other deferred credits........................................................ 636.6 369.1
----------- ----------
2,110.4 1,843.0
MANDATORY REDEMPTION PREFERRED STOCK
Issued by subsidiaries........................................................ .6 .6
----------- ----------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
Cumulative preferred stock (with aggregate
liquidation preference of $209.3 million).................................. 2.7 2.7
Class A common stock - Issued (1995-404,269 shares;
1994-415,711 shares)....................................................... .1 .1
Common stock - Issued (1995-109,168,216 shares;
1994-108,726,115 shares)................................................... 36.4 36.2
Additional paid-in capital.................................................... 1,225.0 1,214.7
Retained earnings............................................................. 1,547.1 1,336.0
----------- ----------
2,811.3 2,589.7
Less common stock in treasury-at cost (1995-4,395,405 shares;
1994-4,395,405 shares)..................................................... 132.5 132.5
----------- ----------
2,678.8 2,457.2
----------- ----------
$ 10,658.8 $ 10,534.6
=========== ==========
See Notes to Consolidated Financial Statements.
F-13
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
--------------------------------------------
1995 1994 1993
----------- ----------- -----------
NET CASH FLOW FROM OPERATING ACTIVITIES
Earnings before extraordinary item .......................... $ 270.4 $ 232.6 $ 118.3
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization.................. 382.0 370.2 358.8
Deferred income taxes..................................... 32.7 39.7 45.8
Amortization of producer contract reformation costs....... 29.0 32.8 48.3
Distributed (undistributed) earnings from equity
investments............................................ 28.6 (36.6) (54.4)
Working capital and other changes, excluding changes
relating to cash and non-operating activities:
Accounts receivable.................................... (8.6) (59.0) 231.5
Inventories............................................ 36.4 (58.1) 260.5
Prepaid expenses and other............................. 19.8 (12.6) (45.2)
Accounts payable....................................... (132.3) 299.7 (109.6)
Accrued expenses....................................... (2.6) (59.1) (23.2)
Other.................................................. (6.3) (80.5) (21.0)
----------- ----------- ----------
649.1 669.1 809.8
----------- ----------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment................ (626.8) (543.2) (392.7)
Proceeds from sale of property, plant and equipment....... 109.6 30.1 29.3
Additions to investments.................................. (75.2) (36.0) (74.3)
Proceeds from investments................................. 27.5 91.5 39.5
Gas supply prepayments and settlements.................... - - (11.4)
Recovery of gas supply prepayments........................ .5 .7 31.8
----------- ----------- ----------
(564.4) (456.9) (377.8)
----------- ----------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Increase (decrease) in short-term notes................... 366.0 (206.8) 42.6
Redemption of mandatory redemption preferred stock........ - (33.7) (10.1)
Proceeds from issuing common stock........................ 10.5 5.4 11.9
Proceeds from issuing preferred stock..................... - - 193.5
Proceeds from long-term debt issues....................... 323.9 199.3 233.1
Payments to retire long-term debt......................... (740.9) (202.8) (734.3)
Dividends paid............................................ (59.3) (59.3) (53.0)
----------- ----------- ----------
(99.8) (297.9) (316.3)
----------- ----------- ----------
NET INCREASE (DECREASE) IN CASH AND
CASH EQUIVALENTS................................................ (15.1) (85.7) 115.7
Cash and cash equivalents at beginning of year............ 73.5 159.2 43.5
----------- ----------- ----------
Cash and cash equivalents at end of year.................. $ 58.4 $ 73.5 $ 159.2
=========== =========== ==========
See Notes to Consolidated Financial Statements.
F-14
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
(Millions of Dollars and Thousands of Shares)
Year Ended December 31,
----------------------------------------------------------------------
1995 1994 1993
------------------- -------------------- -------------------
Shares Amount Shares Amount Shares Amount
-------- -------- -------- -------- -------- --------
Preferred Stock, Par Value 33-1/3 cents
Per Share, Authorized 50,000,000 Shares
Cumulative Convertible Preferred:
$1.19, Series A: Beginning balance 63 $ - 65 $ - 69 $ -
Converted to common............... (2) - (2) - (4) -
-------- -------- -------- -------- ------- --------
Ending balance............. 61 - 63 - 65 -
======== -------- ======== -------- ======= --------
$1.83, Series B: Beginning balance 84 .1 89 .1 95 .1
Converted to common............... (5) - (5) - (6) -
-------- -------- -------- -------- ------- --------
Ending balance............. 79 .1 84 .1 89 .1
======== -------- ======== -------- ======= --------
$5.00, Series C: Beginning balance 34 - 35 - 36 -
Converted to common............... (1) - (1) - (1) -
-------- -------- -------- -------- ------- --------
Ending balance............. 33 - 34 - 35 -
======== -------- ======== -------- ======= --------
Cumulative Preferred:
$2.125, Series H, liquidation
amount of $25 per share:
Beginning balance................. 8,000 2.6 8,000 2.6 - -
Issuance.......................... - - - - 8,000 2.6
-------- -------- -------- -------- ------- --------
Ending balance............. 8,000 2.6 8,000 2.6 8,000 2.6
======== -------- ======== -------- ======= --------
Class A Common Stock, Par Value 33-1/3 cents
Per Share, Authorized 2,700,000 Shares
Beginning balance................. 416 .1 423 .1 445 .1
Converted to common............... (20) - (24) - (108) -
Conversion of preferred stock and
exercise of stock options...... 8 - 17 - 86 -
-------- -------- -------- -------- ------- --------
Ending balance............. 404 .1 416 .1 423 .1
======== -------- ======== -------- ======= --------
Common Stock, Par Value 33-1/3 cents Per Share,
Authorized 250,000,000 Shares
Beginning balance................. 108,726 36.2 108,512 36.2 107,967 36.0
Conversion of preferred stock..... 34 - 31 - 42 -
Conversion of Class A common
stock.......................... 20 - 24 - 108 -
Exercise of stock options......... 388 .2 159 - 395 .2
-------- -------- -------- -------- ------- --------
Ending balance............. 109,168 36.4 108,726 36.2 108,512 36.2
======== -------- ======== -------- ======= --------
Additional Paid-In Capital
Beginning balance................. 1,214.7 1,209.3 1,006.7
Issuance of Series H preferred
stock.......................... - - 190.9
Exercise of stock options......... 10.3 5.4 11.7
-------- -------- --------
Ending balance............. 1,225.0 1,214.7 1,209.3
-------- -------- --------
Retained Earnings
Beginning balance.................... 1,336.0 1,162.7 1,099.9
Net earnings for period.............. 270.4 232.6 115.8
Cash dividends on preferred stock.... (17.4) (17.4) (11.3)
Cash dividends on Class A common
stock, 36 cents (1995), 36 cents
(1994) and 36 cents (1993) per
share............................. (.1) (.2) (.2)
Cash dividends on common stock,
40 cents (1995), 40 cents (1994)
and 40 cents (1993) per share..... (41.8) (41.7) (41.5)
-------- -------- --------
Ending balance............. 1,547.1 1,336.0 1,162.7
-------- -------- --------
Less Treasury Stock-At Cost.............. 4,395 132.5 4,395 132.5 4,415 132.9
======== -------- ======== -------- ======= --------
TOTAL ........................... $2,678.8 $2,457.2 $2,278.1
======== ======== ========
See Notes to Consolidated Financial Statements.
F-15
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. The equity method is also used for investments
in limited partnerships in which the Company has an interest of more than 5%.
Other 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 $443.6 million, $431.8 million and $447.2 million in 1995, 1994
and 1993, respectively. Cash payments for income taxes amounted to $33.3
million, $73.7 million and $21.0 million for 1995, 1994 and 1993, respectively.
Use of Estimates. The preparation of financial statements in conformity
with generally accepted accounting principles requires the Company to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. Actual results could differ from the
estimates and assumptions used.
Inventories. Inventories of refined products and crude oil are accounted
by the first-in, first-out cost method 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 and 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 $5.9 million, $8.3
million and $8.4 million in 1995, 1994 and 1993, 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. Such costs include the costs of all unproved properties
but do not include internal general and administrative costs directly related to
acquisition, exploration and development activities. These amounts are expensed
as incurred.
Depreciation, depletion and amortization ("DD & A") of gas and oil
properties are provided on the unit-of-production basis whereby the unit rate
for DD & A 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 $.89 for 1995, $.96 for 1994 and $1.00
for 1993. Unamortized costs of proved properties are subject to a ceiling which
limits such costs to the estimated future net cash flows from proved gas and oil
properties, net of related income tax effects, discounted at 10 percent. If the
unamortized costs are greater than this ceiling, any excess will be charged to
DD & A expense. No such charge was required in the periods presented. Provisions
for depletion of coal properties, including exploration and development costs,
are based upon estimates of
F-16
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:
Refining, crude oil and chemical facilities......... 3.0% - 20.0%
Gas systems......................................... 0.8% - 20.0%
Coal facilities..................................... 5.0% - 33.3%
Power facilities ................................... 3.3% - 33.3%
Transportation equipment............................ 5.0% - 33.3%
Office and miscellaneous equipment.................. 2.5% - 20.0%
Buildings and improvements.......................... 1.3% - 20.0%
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.
The Financial Accounting Standards Board ("FASB") has issued Statement of
Financial Accounting Standards No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("FAS 121"), to
be effective in 1996. The provisions of FAS 121 require the Company to review
long-lived assets and certain identifiable intangibles for impairment whenever
events or changes in circumstances indicate that the carrying amount of an asset
may not be recoverable. FAS 121 also requires that a rate-regulated enterprise
recognize an impairment for the amount of costs that a regulator excludes from
the enterprise's allowable costs. If it is determined that an impairment has
occurred, the amount of the impairment should be charged to earnings. The
application of the new standard is not expected to have a material effect on the
Company's results of operations or financial position in 1996.
Goodwill. Goodwill, which primarily relates to the acquisitions of
American Natural Resources Company ("ANR") and CIG, amounted to $525.7 million
at December 31, 1995, 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 1995, 1994 and 1993, respectively. As warranted by facts and
circumstances, the Company periodically assesses the recoverability of the cost
of goodwill from future operating income.
Income Taxes. The Company follows the liability method of accounting for
deferred income taxes as required by the provisions of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes".
Revenue Recognition. The Company's subsidiaries recognize revenues for the
sale of their respective products in the period of delivery. Revenues for
services are recognized in the period the services are provided.
Currency Translation. The U.S. dollar is the functional currency for
substantially all the Company's foreign operations. For those operations, all
gains and losses from currency translations are included in income currently.
Earnings per Share. Earnings 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:
1995................................................ 105,434,830
1994................................................ 105,207,492
1993................................................ 104,744,124
Statement of Financial Accounting Standards No. 71, "Accounting for the
Effects of Certain Types of Regulation" ("FAS 71"). The interstate natural gas
pipeline and certain storage subsidiaries are subject to the regulations and
accounting procedures of the FERC. These subsidiaries meet the criteria and,
accordingly, follow the
F-17
reporting and accounting requirements of FAS 71. FAS 71 provides that
rate-regulated public utilities account for and report assets and liabilities
consistent with the economic effect of the way in which regulators establish
rates, if the rates established are designed to recover the costs of providing
the regulated service and if the competitive environment makes it reasonable to
assume that such rates can be charged and collected. Although the accounting
methods for companies subject to rate regulation may differ from those used by
non-regulated companies, the accounting methods prescribed by the regulatory
authority conform to the generally accepted accounting principle of matching
costs with the revenue to which they apply.
Transactions which the subsidiaries have recorded differently than a
non-regulated entity include the following: the subsidiaries (i) have
capitalized the cost of equity funds used during construction, and, (ii) have
deferred purchase gas costs, contract reformation costs,
postemployment/postretirement benefit costs and income tax reductions related to
changes in federal income tax rates. These items are being, or are anticipated
to be, recovered or refunded in rates chargeable to customers.
The subsidiaries have applied FAS 71 and evaluate the applicability of
regulatory accounting and the recoverability of these assets through rate or
other contractual mechanisms on an ongoing basis. If FAS 71 accounting
principles should no longer be applicable to the subsidiaries' operations, an
amount would be charged to earnings as an extraordinary item. At December 31,
1995, this amount was approximately $85 million, net of income taxes. The
Company does not expect that its cash flows would be affected by discontinuing
application of FAS 71. Any potential charge would be noncash and would have no
direct effect on the subsidiaries' ability to include the underlying deferred
items in their future rate proceedings or on their ability to collect the rates
set thereby.
Reclassification of Prior Period Statements. Certain minor
reclassifications have been made to conform with current reporting practices.
The effect of the reclassifications was not material to the Company's results of
operations or financial position.
Note 2. Inventories
Inventories at December 31 were (millions of dollars):
1995 1994
----------- -------
Refined products, crude oil and chemicals.................................. $ 556.5 $ 596.5
Natural gas in underground storage......................................... 49.9 34.8
Coal, materials and supplies............................................... 174.7 186.8
----------- ----------
$ 781.1 $ 818.1
=========== ==========
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
$36.5 million and $31.2 million at December 31, 1995 and 1994, respectively.
Note 3. Take-or-Pay Obligations
Other assets includes $83.2 million and $96.5 million at December 31, 1995
and 1994, 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 of 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
F-18
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, 1995, the Company
estimated that unresolved asserted and unasserted producers' claims amounted to
approximately $18 million. The remaining disputes will be settled where possible
and litigated if settlement is not possible.
At December 31, 1995, 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 $18 million, $12 million, $1 million, $1 million and $1 million
for the years 1996-2000, respectively, and $3 million thereafter. Such
commitments have also not been adjusted for all amounts which may be assigned or
released, or for the results of future litigation or negotiation with producers.
The Company has made provisions, which it believes are adequate, for
payments to producers that may be required for settlement of take-or-pay claims
and restructuring of future contractual commitments. In determining the net loss
relating to such provisions, the Company has also made accruals for the
estimated portion of such payments which would be recoverable pursuant to
FERC-approved settlements with customers. Such provisions and accruals were not
material to the Company for the years 1995, 1994 and 1993.
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; Blue Lake Gas Storage Company (50%
interest), which operates a gas storage system in Michigan; Iroquois Gas
Pipeline System, L.P. (9.4% interest), which operates a natural gas pipeline;
Empire State Pipeline (45% interest), which operates a natural gas pipeline;
Compania de Electricidad de Puerto Plata, S.A. (48% interest), which operates a
power plant in the Dominican Republic; 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 $447.4 million and $378.3
million at December 31, 1995 and 1994, respectively. The Company's equity in
income of the investments, included in Other Income-Net, was $60.6 million,
$75.7 million and $71.9 million in 1995, 1994 and 1993, respectively, while
dividends and partnership distributions received amounted to $89.2 million,
$39.1 million and $17.5 million in 1995, 1994 and 1993, respectively.
F-19
Summarized financial information of these entities is as follows (millions
of dollars):
December 31,
---------------------------
1995 1994
----------- ----------
Current assets............................................................. $ 687.8 $ 590.0
Noncurrent assets.......................................................... 5,140.1 4,955.6
----------- ----------
$ 5,827.9 $ 5,545.6
=========== ==========
Current liabilities........................................................ $ 858.7 $ 769.3
Noncurrent liabilities..................................................... 3,423.3 3,444.3
Deferred credits........................................................... 241.4 181.7
Equity..................................................................... 1,304.5 1,150.3
----------- ----------
$ 5,827.9 $ 5,545.6
=========== ==========
Year Ended December 31,
--------------------------------------------
1995 1994 1993
----------- ----------- -----------
Revenues..................................................... $ 1,924.5 $ 1,882.7 $ 1,851.0
Operating income............................................. 558.9 469.9 456.4
Net income................................................... 153.2 146.4 141.5
F-20
Note 5. Debt
Long-Term Debt - Balances at December 31 were (millions of dollars):
1995 1994
----------- ----------
The Coastal Corporation:
Notes payable (term credit facilities)..................................... $ - $ 100.0
Notes payable (revolving credit agreements)................................ 70.0 -
Swiss franc bonds, 5-3/4%, due 1996........................................ 66.5 68.3
Senior notes:
10-3/8%, due 2000....................................................... 249.9 249.8
10%, due 2001........................................................... 299.2 299.1
8-3/4%, due 1999........................................................ 150.0 150.0
8-1/8%, due 2002........................................................ 249.4 249.3
Japanese yen notes, 6.3%, due 1995 to 1997................................. - 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........................................................ 298.9 298.8
9-5/8%, due 2012........................................................ 149.2 149.2
7-3/4%, due 2035........................................................ 149.9 -
Other...................................................................... .1 .1
----------- ----------
2,432.4 2,513.3
Subsidiary Companies:
Notes payable (term credit facilities)..................................... 50.0 50.0
Notes payable (revolving credit agreements)................................ 264.7 404.2
Notes payable (project financing), due 1998................................ 22.4 26.3
Long-term notes, 13-1/2%, due 2005......................................... - 3.4
Debentures, 7% to 10%, due 2005-2025 ...................................... 677.0 601.8
Capitalized lease obligations, due 2003-2005 .............................. 25.2 29.6
Swiss franc bonds, 6%, due 1995............................................ - 58.2
Other, due 2000-2012....................................................... 18.5 19.0
----------- ----------
1,057.8 1,192.5
Amount reclassified from short-term debt................................... 300.0 -
----------- ----------
Total Long-Term Debt....................................................... 3,790.2 3,705.8
Less Current Maturities.................................................... 128.5 185.3
----------- ----------
$ 3,661.7 $ 3,520.5
=========== ==========
At December 31, 1995, long-term credit agreements with banks totaled
$1,173.2 million, including $235.0 million available to The Coastal Corporation.
Loans under these agreements bear interest at money market-related rates
(weighted average 6.64% at December 31, 1995). Annual commitment fees range up
to 1/2% payable on the unused portion of the applicable facility. At December
31, 1995, $384.7 million was outstanding and $235.0 million of the unused amount
is dedicated to a specific use. Notes payable of $200.0 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
agreement contains 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, 1995, net
assets
F-21
of consolidated subsidiaries amounted to approximately $5.5 billion, of which
$1.9 billion was restricted by such provisions.
In October 1995, the Company completed a public offering of $150 million
of 7.75% Senior Debentures due in October 2035. The net proceeds from the sale
were used to redeem certain outstanding debt.
In June 1995, ANR Pipeline Company ("ANR Pipeline") completed an offering
of $75 million of 7% Debentures due in June 2025. The net proceeds from the sale
were used for the repayment of certain outstanding debt and for general
corporate purposes.
Subordinated Long-Term Debt. Balances at December 31 were (millions of
dollars):
1995 1994
----------- ----------
Subordinated Notes, 11-1/8%, due 1998...................................... $ - $ 199.7
Less Current Maturities.................................................... - -
----------- ----------
$ - $ 199.7
=========== ==========
The Company redeemed the 11-1/8% Subordinated Notes in March 1995.
Maturities. The aggregate amounts of long-term debt maturities for the five
years following 1995 are (millions of dollars):
1996 $128.5 1999 $287.7
1997 292.0 2000 283.1
1998 47.2
Additionally, based on committed credit facilities that were available as
of December 31, 1995, $300.0 million of short-term debt which has been
classified as long-term would mature in 1997.
Notes Payable. At December 31, 1995, Coastal and its subsidiaries had
$423.2 million of outstanding indebted ness to banks under short-term lines of
credit, compared to $57.2 million at December 31, 1994. As of December 31, 1995,
the Company's financial statements reflect $300.0 million of short-term
borrowings which have been reclassified as long-term, based on the availability
of committed credit lines with maturities in excess of one year and the
Company's intent to maintain such amounts as long-term borrowings. There was no
such reclassification as of December 31, 1994. The weighted average interest
rates were 6.16% and 6.17% at December 31, 1995 and 1994, respectively. As of
December 31, 1995, $475.3 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 $528.4 million
of retained earnings was available at December 31, 1995 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, 1995, the Company had guaranteed 45% of a construction financing of
a partially owned partnership and 50% of a construction financing of a second
partially owned partnership. The Company's proportionate share of the
outstanding principal balance under these guarantees was $72.5 million at
December 31, 1995. Both of these loans are expected to be refinanced on a
non-recourse basis in 1996. Other guarantees and indemnities related to
obligations of unconsolidated affiliates amounted to approximately $160.1
million as of the same date. 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.
F-22
Coastal and certain subsidiaries have guaranteed approximately $4.1
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 $218.4
million.
Rental expense amounted to approximately $79.4 million, $72.1 million and
$98.2 million in 1995, 1994 and 1993, respectively, excluding leases covering
natural resources. Aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $96.3 million, $96.8
million, $88.0 million, $88.1 million, and $88.1 million for the years
1996-2000, respectively, and $874.9 million thereafter.
Note 7. Mandatory Redemption Preferred Stock
Shares and aggregate redemption value of mandatory redemption preferred
stock outstanding, excluding shares redeemable within one year, were (thousands
of shares and millions of dollars):
Subsidiaries Stock
---------------------------
Shares Value
----------- ----------
Balance, December 31, 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
Redemptions................................................................... - -
----------- ----------
Balance, December 31, 1995.................................................... 6 $ .6
=========== ==========
CIG has 550,000 shares of $100 par value cumulative preferred stock
authorized, of which 5,560 shares were outstanding at December 31, 1995. The
stock outstanding has an annual dividend rate of 5.5% and the remaining shares
will be redeemed at par value on or before July 1, 1997.
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 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, 1995, the Company had interest rate swaps with a
notional amount of $34.5 million, and a portfolio of variable rate debt
outstanding in the amount of $537.6 million. These interest rate swaps amortize
over a four-year period and mature in 1999. Under these agreements, Coastal will
pay the counterparties interest at a weighted average fixed rate of 6.60%, 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 5.86% at December 31, 1995. 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 $419.2 million of fixed rate debt
into floating rate debt. Under these agreements, Coastal will pay the
counterparties a
F-23
variable rate equal to LIBOR and the Company will receive from the
counterparties a weighted average fixed rate of 5.20%. The weighted average
LIBOR rate applicable to these transactions was 5.79% at December 31, 1995.
The weighted average variable rates are subject to change over time as
LIBOR fluctuates. Terms expire at various dates through the third quarter of the
year 2000.
The Company has also entered into a foreign currency swap to fully hedge
to maturity the foreign currency denominated debt of the Company. At December
31, 1995, the Company had outstanding swiss franc denominated debt in the amount
of $66.5 million. This swap involves the exchange of interest payments in
differing currencies at exchange rates effective at the time the agreement is
entered into, and provides for the exchange of principal amounts at maturity,
usually through an escrow arrangement to limit credit risk. The weighted average
exchange rate for the swiss franc swap is 1.88 swiss francs/dollar. This swap
has resulted in effective borrowing costs of 10.6%. The Company has also entered
into an interest rate swap with a notional amount of 16.4 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, 1995 the floating rate was
2.0%.
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, 1995, Coastal had no
exposure to credit loss on interest rate swaps and approximately $50.0 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 reported to and, when necessary, are approved 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.
F-24
Fair Value of Financial Instruments. The estimated fair value amounts of
the Company's financial instruments have been determined by the Company, using
appropriate market information and valuation methodologies. Considerable
judgment is required to develop the estimates of fair value, thus, the estimates
provided herein are not necessarily indicative of the amounts that the Company
could realize in a current market exchange.
(Millions of Dollars)
------------------------------------------------------------
Dec. 31, 1995 Dec. 31, 1994
---------------------------- -----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ----------- ----------- ------------
Nonderivatives:
Financial assets:
Cash and cash equivalents................... $ 58.4 $ 58.4 $ 73.5 $ 73.5
Notes receivable............................ 172.2 172.2 88.6 88.6
Financial liabilities:
Short-term debt............................. 123.2 123.2 57.2 57.2
Long-term debt ............................. 3,815.0 4,296.6 4,048.8 4,129.6
Mandatory redemption preferred stock........ 0.6 0.6 0.6 0.6
Derivatives relating to:
Commodity swaps loss........................... - (48.5) - (8.1)
Debt:
Currency swaps gain............................ (50.0) (50.0) (172.9) (172.9)
Interest rate swaps loss and options........... 9.8 11.8 31.4 58.7
The estimated value of the Company's long-term debt and mandatory
redemption preferred stock is based on interest rates at December 31, 1995 and
1994, 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, 1995 and 1994, respectively,
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, 1995 and 1994, respectively.
Note 9. Common and Preferred Stock
Shares of common stock and Class A common stock reserved for future
issuance as of December 31, 1995 were:
Class A
Common Common
Stock Stock
--------- -------
Employee stock options........................................................ 3,688,064 14,780
Conversion of outstanding Class A common stock................................ 404,269 -
Conversion of Class A common stock subject to future issuance................. 35,361 -
Conversion of preferred stock:
$1.19, Series A, redemption value of $33 per share......................... 221,565 6,133
$1.83, Series B, redemption value of $50 per share......................... 283,928 7,860
$5.00, Series C, redemption value of $100 per share........................ 237,993 6,588
----------- ----------
4,871,180 35,361
=========== ==========
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
F-25
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 14,324 Class A common shares and 31,155
common shares were exercisable at December 31, 1995. No additional options may
be granted under the 1984 plan. At December 31, 1994, options for 21,679 Class A
common shares and 51,801 common shares were exercisable.
Under the 1985 Plan, 13,759 common shares were available for granting of
options, and options for 557,521 common shares were exercisable at December 31,
1995. At December 31, 1994, 3,958 common shares were available for granting of
options, and options for 835,168 common shares were exercisable.
Under the 1990 Plan, 115,221 common shares were available for granting of
options, and options for 493,479 common shares were exercisable at December 31,
1995. At December 31, 1994, 32,321 common shares were available for granting of
options, and options for 241,073 common shares were exercisable.
Under the 1994 Plan, 1,401,850 common shares were available for granting
of options at December 31, 1995. At December 31, 1994, 1,891,100 common shares
were available for granting of options. No options for common shares were
exercisable at December 31, 1995, or 1994, respectively.
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, 1995:
Class A
Common Common Option Price
Shares Shares Per Share
----------- ----------- ----------------
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
Granted.............................................. 515,250 - 28.50-29.13
Exercised............................................ (415,971) (7,811) 10.72-31.50
Revoked or expired................................... (118,700) - 25.50-35.94
----------- ----------- ----------------
December 31, 1995....................................... 2,157,236 14,780 $ 17.08-35.94
=========== =========== ================
In October 1995, the Financial Accounting Standards Board issued Statement
of Financial Accounting Standards No. 123, "Accounting for Stock-Based
Compensation" ("FAS 123"), which establishes financial accounting and reporting
standards for stock-based employee compensation plans and for transactions in
which an entity issues its equity instruments to acquire goods and services from
nonemployees. FAS 123 requires, among other things, that compensation cost be
calculated for fixed stock options at the grant date by determining fair value
using an option-pricing model. The Company has the option of recognizing the
compensation cost over the vesting period as an expense in the statement of
consolidated operations or making pro forma disclosures in the notes to
financial statements as to the effects on net earnings as if the compensation
cost had been recognized in the statement of consolidated operations. The
Company will adopt FAS 123 in 1996 by making pro forma disclosures in the notes
to financial statements.
F-26
Note 10. Segment and Geographic Reporting
The Company operates principally in the following lines of business:
natural gas; refining, marketing and chemicals; exploration and production;
coal; and power. 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. Sales are primarily made to pipeline
and distribution companies in most major areas of the United States.
Refining, marketing and chemicals operations involve the purchase,
transportation and sale of refined products, crude oil, condensate and natural
gas liquids; the operation of refineries 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. Products
from this segment are sold to customers 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. Sales are made to affiliated companies,
industrial users, interstate pipelines and distribution companies in the Rocky
Mountain, central and southwest areas of the United States and offshore Gulf of
Mexico.
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. Sales are made to utilities and industrial customers in the United
States and to export markets in Asia and Canada.
Power operations involve the ownership of, participation in and operation
of power projects in the United States and internationally. Power is sold to
customers in the northeast United States and internationally in the
Asian/Pacific Rim countries and Latin America.
Other operations include regional trucking operations involving activities
as common carriers in interstate and intrastate commerce and activities in other
projects. Effective November 3, 1995, the trucking operations were merged into a
new company in which Coastal has a 50% interest.
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, marketing and chemicals segments and from the natural gas
segment to the refining, marketing and chemicals 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.
Earnings before interest and taxes is operating profit and other
income-net, including equity income from investments, reduced by corporate
general and administrative expenses.
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-27
The Company's operating revenues, operating profit, earnings before
interest and taxes, capital expenditures, and depreciation, depletion and
amortization expense for the years ended December 31, 1995, 1994 and 1993, and
identifiable assets as of December 31, 1995, 1994 and 1993, by segment, are
shown as follows (millions of dollars):
1995 1994 1993
----------- ----------- -----------
Operating revenues
Natural gas.................................................. $ 2,898.6 $ 3,075.7 $ 3,247.9
Refining, marketing and chemicals ........................... 6,851.3 6,458.9 6,200.9
Exploration and production................................... 268.7 298.9 357.3
Coal......................................................... 459.6 451.3 443.2
Power........................................................ 48.4 27.2 26.1
Other........................................................ 148.3 181.1 160.9
Adjustments and eliminations................................. (227.2) (277.8) (300.2)
----------- ----------- -----------
Consolidated totals....................................... $ 10,447.7 $ 10,215.3 $ 10,136.1
=========== =========== ===========
Operating profit (loss)
Natural gas.................................................. $ 403.5 $ 431.3 $ 405.2
Refining, marketing and chemicals............................ 208.8 153.3 98.3
Exploration and production................................... 24.9 41.8 49.9
Coal......................................................... 98.7 98.2 95.1
Power........................................................ 7.8 2.7 3.9
Other ....................................................... 7.3 6.3 (16.7)
----------- ----------- -----------
Consolidated totals....................................... $ 751.0 $ 733.6 $ 635.7
=========== =========== ===========
Earnings before interest and taxes
Natural gas.................................................. $ 473.9 $ 491.3 $ 460.3
Refining, marketing and chemicals ........................... 184.3 143.9 94.9
Exploration and production................................... 24.9 53.2 54.6
Coal......................................................... 98.7 98.2 95.1
Power........................................................ 27.8 17.1 20.3
Other........................................................ 6.7 5.6 (17.6)
----------- ----------- -----------
Segment totals............................................ 816.3 809.3 707.6
Corporate ................................................... (78.4) (76.6) (65.2)
----------- ----------- -----------
Consolidated totals....................................... $ 737.9 $ 732.7 $ 642.4
=========== =========== ===========
F-28
1995 1994 1993
----------- ----------- -----------
Capital expenditures
Natural gas.................................................. $ 128.6 $ 91.4 $ 119.8
Refining, marketing and chemicals............................ 190.3 228.2 130.3
Exploration and production................................... 230.3 150.3 91.8
Coal......................................................... 54.0 56.9 36.0
Power........................................................ 12.1 .4 .1
Other........................................................ 5.0 9.5 9.4
----------- ----------- -----------
Segment totals............................................ 620.3 536.7 387.4
Corporate.................................................... 6.5 6.5 5.3
----------- ----------- -----------
Consolidated totals....................................... $ 626.8 $ 543.2 $ 392.7
=========== =========== ===========
Depreciation, depletion and amortization expense
Natural gas.................................................. $ 152.3 $ 151.0 $ 145.4
Refining, marketing and chemicals............................ 61.8 53.9 45.6
Exploration and production................................... 105.5 106.0 109.1
Coal......................................................... 31.3 28.9 28.5
Power........................................................ 2.0 1.5 1.5
Other........................................................ 5.7 5.9 6.4
----------- ----------- -----------
Segment totals............................................ 358.6 347.2 336.5
Corporate assets............................................. 4.6 4.2 3.4
----------- ----------- -----------
Consolidated totals....................................... $ 363.2 $ 351.4 $ 339.9
=========== =========== ===========
Identifiable assets
Natural gas.................................................. $ 5,359.8 $ 5,497.0 $ 5,562.5
Refining, marketing and chemicals............................ 3,125.2 3,041.4 2,745.9
Exploration and production................................... 992.0 837.2 801.5
Coal......................................................... 518.6 498.3 450.3
Power........................................................ 140.3 75.6 46.6
Other........................................................ 159.8 193.1 153.1
----------- ----------- -----------
Segment totals............................................ 10,295.7 10,142.6 9,759.9
Corporate assets............................................. 363.1 392.0 467.2
----------- ----------- -----------
Consolidated totals....................................... $ 10,658.8 $ 10,534.6 $ 10,227.1
=========== =========== ===========
Refining, marketing and chemicals 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):
1995 1994 1993
----------- ----------- -----------
Revenues.................................................. $ 2.3 $ .7 $ 3.1
Impact on earnings ....................................... 1.5 .4 2.0
The number and magnitude of such transactions may vary significantly from
year to year, particularly in view of conditions in world petroleum markets.
F-29
The Company's operating revenues and operating profit for the years ended
December 31, 1995, 1994 and 1993 and identifiable assets as of December 31, 1995
1994 and 1993, by geographic area, are shown as follows (millions of dollars):
1995 1994 1993
----------- ----------- -----------
Operating revenues
United States - Third Party............................ $ 9,136.3 $ 9,196.7 $ 9,259.7
- Interarea.............................. 129.1 31.0 64.6
Foreign - Third Party............................ 1,311.4 1,018.6 876.4
- Interarea.............................. 294.5 205.2 183.7
Interarea elimination.................................. (423.6) (236.2) (248.3)
----------- ----------- -----------
Consolidated totals................................ $ 10,447.7 $ 10,215.3 $ 10,136.1
=========== =========== ===========
Operating profit
United States.......................................... $ 597.0 $ 697.9 $ 608.2
Foreign................................................ 154.0 35.7 27.5
----------- ----------- -----------
Consolidated totals................................ $ 751.0 $ 733.6 $ 635.7
=========== =========== ===========
Identifiable assets
United States.......................................... $ 9,590.7 $ 9,503.0 $ 9,240.5
Foreign................................................ 1,068.1 1,031.6 986.6
----------- ----------- -----------
Consolidated totals................................ $ 10,658.8 $ 10,534.6 $ 10,227.1
=========== =========== ===========
Revenues from sales to any single customer during 1995, 1994 or 1993 did
not amount to 10% or more of the Company's consolidated revenues.
Note 11. Benefit Plans
The Company has non-contributory pension plans covering substantially all
U.S. employees. These plans provide benefits based on final average monthly
compensation and years of service. The Company's funding policy is to contribute
the amount necessary for the plan to maintain its qualified status under the
Employment Retirement Income Security Act of 1974, as amended. The pension
benefit for 1995, 1994 and 1993 is shown in the following table (millions of
dollars):
Year Ended December 31,
--------------------------------------------
1995 1994 1993
----------- ----------- -----------
Service cost - benefit earned during the period........... $ 15.8 $ 17.6 $ 16.3
Interest cost on projected benefit obligation............. 42.2 37.7 37.6
Actual return on assets................................... (223.7) 2.0 (92.5)
Net amortization and deferral............................. 152.3 (74.5) 18.9
----------- ----------- -----------
Net periodic pension benefit.............................. $ (13.4) $ (17.2) $ (19.7)
=========== =========== ===========
The discount rate used in determining the actuarial present value of the
projected benefit obligation was 7.25% in 1995, 8.75% in 1994 and 7.25% in 1993.
The expected increase in future compensation levels was 4% in 1995, 5% in 1994
and 4% in 1993, and the expected long-term rate of return on assets was 10% in
both 1995 and 1994 and 11% in 1993.
F-30
The following table sets forth the funded status of the plans and the
amounts recognized in the Company's Consolidated Balance Sheet (millions of
dollars):
December 31,
-----------------------------
1995 1994
----------- ------------
Actuarial present value of benefit obligations:
Accumulated benefit obligation, including vested benefits
of $510.4 million and $397.9 million, respectively..................... $ (559.3) $ (439.3)
=========== ============
Projected benefit obligation for service rendered to date................. $ (620.2) $ (490.1)
Plan assets, primarily equity securities, at fair value................... 938.4 795.0
----------- ------------
Plan assets in excess of projected benefit obligation..................... 318.2 304.9
Unrecognized net assets at January 1, 1995 and 1994, being
recognized over average remaining service lives........................ (54.3) (66.6)
Prior service cost, not yet recognized.................................... 4.0 4.5
Unrecognized net (gain) loss from past experience different
from that assumed...................................................... (25.4) 25.6
----------- ------------
Prepaid pension cost...................................................... $ 242.5 $ 268.4
=========== ============
In 1995, the Company offered an early retirement incentive program to
eligible employees of its rate regulated subsidiaries. The impact of this
program is reflected in the above 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, 1995 and 1994.
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 $6.4 million for 1995, $7.6 million for 1994 and $7.1 million
for 1993. 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 $17.6 million, $17.5 million and $17.7 million in 1995, 1994 and
1993, respectively.
The Company provides certain health care and life insurance benefits for
retired employees. Substantially all U.S. employees are provided these benefits.
The estimated costs of retiree benefit payments are accrued during the years the
employee provides services. Certain costs have been deferred by the
rate-regulated subsidiaries and are being amortized to reflect the impact of
rate regulation.
F-31
The following tables set forth the accumulated postretirement benefit
obligation recognized in the Company's Consolidated Balance Sheet as of December
31, 1995 and 1994 and the benefit cost for the years ended December 31, 1995,
1994 and 1993 (millions of dollars):
December 31,
-----------------------------
1995 1994
----------- ------------
Accumulated postretirement benefit obligation:
Retirees............................................................... $ (78.2) $ (76.8)
Fully eligible plan participants....................................... (2.5) (3.3)
Other active plan participants ........................................ (42.8) (29.4)
----------- ------------
(123.5) (109.5)
Plan assets at fair value................................................. 22.9 14.5
----------- ------------
Accumulated postretirement benefit obligation
in excess of plan assets............................................... (100.6) (95.0)
Unrecognized net transition obligation ................................... 108.1 118.7
Unrecognized net gain from past
experience different from that assumed................................. (22.5) (35.5)
Unrecognized prior service cost........................................... 4.7 3.3
----------- ------------
Postretirement benefit obligation included
in balance sheet ...................................................... $ (10.3) $ (8.5)
=========== ============
Year Ended December 31,
--------------------------------------------
1995 1994 1993
----------- ----------- -----------
Net postretirement benefit cost consisted of the following components:
Service cost - benefits earned during the period.......... $ 2.2 $ 2.5 $ 1.7
Interest cost on accumulated postretirement benefit
obligation............................................. 8.8 8.9 10.6
Actual return on assets................................... (.8) (.1) -
Amortization of transition obligation..................... 6.6 6.6 6.7
Deferred regulatory amounts............................... 2.0 1.8 (8.3)
Other amortization and deferral........................... (1.5) (1.1) -
----------- ----------- -----------
Net postretirement benefit cost........................... $ 17.3 $ 18.6 $ 10.7
=========== =========== ===========
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 11.2% in 1995, declining gradually to 6.0%
by the year 2004. The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation was 12.0% in 1994 and 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, 1995 by approximately 3.8% and the net postretirement health
care cost by approximately 4.2%. The assumed discount rate used in determining
the accumulated postretirement benefit obligation was 7.25%.
Note 12. Taxes on Income
Pretax earnings before extraordinary item are composed of the following
(millions of dollars):
Year Ended December 31,
--------------------------------------------
1995 1994 1993
----------- ----------- -----------
United States............................................. $ 178.1 $ 295.0 $ 171.0
Foreign .................................................. 144.4 29.9 31.4
----------- ----------- -----------
$ 322.5 $ 324.9 $ 202.4
=========== =========== ===========
F-32
Provisions for income taxes before extraordinary item are composed of the
following (millions of dollars):
Year Ended December 31,
--------------------------------------------
1995 1994 1993
----------- ----------- -----------
Current Income Taxes:
Federal................................................ $ 13.0 $ 46.2 $ 34.3
Foreign................................................ 2.7 .3 .7
State ................................................. 3.7 6.1 3.3
----------- ----------- -----------
19.4 52.6 38.3
----------- ----------- -----------
Deferred Income Taxes:
Federal .............................................. 31.0 42.0 39.0
Foreign................................................ .5 - -
State ................................................. 1.2 (2.3) 6.8
----------- ----------- -----------
32.7 39.7 45.8
----------- ----------- -----------
Taxes on Income........................................... $ 52.1 $ 92.3 $ 84.1
=========== =========== ===========
The Company's federal income tax returns filed for the years 1985 through
1987 have been examined by the Internal Revenue Service ("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.
Provisions for income taxes were different than the amount computed by
applying the statutory U.S. federal income tax rate to earnings before tax. The
reasons for these differences are (millions of dollars):
Year Ended December 31,
--------------------------------------------
1995 1994 1993
----------- ----------- -----------
Tax expense by applying the U.S. federal
income tax rate of 35%................................. $ 112.9 $ 113.7 $ 70.8
Increases (reductions) in taxes resulting from:
Tight sands gas credit................................. (11.3) (10.2) (13.0)
State income tax cost ................................. 3.2 2.5 6.6
Goodwill .............................................. 6.4 6.4 6.4
Exclusion for dividends and equity earnings............ (2.9) (5.3) (3.4)
Full normalization..................................... (.4) (2.9) (5.4)
Exclusion for foreign earnings......................... (47.8) (6.9) -
Depletion.............................................. (9.8) (5.2) (6.3)
Increase in federal tax rate........................... - - 29.0
Other.................................................. 1.8 .2 (.6)
----------- ----------- -----------
Taxes on income .......................................... $ 52.1 $ 92.3 $ 84.1
=========== =========== ===========
F-33
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences and carryforwards are
(millions of dollars):
December 31,
-----------------------------
1995 1994
----------- ------------
Excess of book basis over tax basis of property,
plant and equipment ................................................... $ 1,501.4 $ 1,424.8
Pensions and benefit costs................................................ 35.3 22.4
Purchase gas and other recoverable costs.................................. 38.0 54.5
Other ................................................................... .5 7.7
----------- ------------
Deferred tax liabilities .............................................. 1,575.2 1,509.4
----------- ------------
Alternative minimum tax credit carryforward............................... (186.8) (139.3)
Other ................................................................... (9.2) (.2)
----------- ------------
Deferred tax assets....................................................... (196.0) (139.5)
----------- ------------
Deferred income taxes..................................................... $ 1,379.2 $ 1,369.9
=========== ============
U.S. income taxes have been provided for earnings of foreign subsidiaries
that are expected to be distributed to the U.S. parent company. Foreign
subsidiaries' cumulative unremitted earnings of approximately $164.0 million are
considered to be indefinitely reinvested outside the U.S. and, accordingly, no
U.S. income taxes have been provided on those earnings.
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 ("Trans American") 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, 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.
In March of 1995, the Trial Court granted a partial summary judgment in favor of
CIG, holding that the four-year statute of limitations had not been tolled, that
the releases are valid, and dismissing all tort claims and claims for breach of
any duty of disclosure. The remaining claim for underpayment of royalties was
tried to a jury which, in May 1995, made findings favorable to CIG. On June 7,
1995, the Trial Court entered a judgment that the lessors recover no monetary
damages from CIG and permanently estopping the lessors from asserting any claim
based on an interpretation of the contract different than that asserted by CIG
in the litigation. The lessors' motion for a new trial is pending.
F-34
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. Oral argument in
the case was held before the United States Court of Appeals for the D.C. Circuit
in February 1996.
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. These appeals have been held in abeyance by the United
States Court of Appeals for the D.C. Circuit, pending further notice. 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, which were accepted by order
issued April 12, 1995.
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. Certain customers have disputed the level of those refunds. By an order
issued February 27, 1995, the FERC approved ANR Pipeline's refund allocation
methodology, and directed ANR Pipeline to make immediate refunds of $45.1
million, together with applicable interest, subject to further investigation of
the claims which the customers have made. On May 2, 1995, the FERC issued a
further order setting these issues for an evidentiary hearing. Initial testimony
has been filed, and the parties are conducting discovery. The hearing is set to
commence in May 1996. Undisputed refunds, including interest, were paid on March
29, 1995. ANR Pipeline submitted an adjusted reconciliation report on October
31, 1995, which was also disputed by certain customers. The subsequent adjusted
reconciliation report has been consolidated with the ongoing evidentiary
hearing. Certain customers have also sought judicial review before the United
States Court of Appeals for the D.C. Circuit of the FERC's approval of the
refund allocation methodology. Briefs have been filed, and oral argument is
scheduled for April 12, 1996.
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
hearing commenced on January 31, 1996. 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 Settlement and a $182.8 million increase over ANR
Pipeline's approved rates for its restructured services under Order 636. ANR
Pipeline sought rehearing of various aspects of the order. Further 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
F-35
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
the FERC accepted by order issued February 8, 1995, subject to a further
compliance filing requirement. This compliance filing was submitted by ANR
Pipeline on March 10, 1995, and was accepted by order issued May 3, 1995,
subject to one additional compliance filing requirement, which ANR Pipeline
filed on May 18, 1995 and which was accepted by order issued June 30, 1995. 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, which the
Court dismissed as premature. The FERC has also issued a series of orders and
orders on rehearing in ANR Pipeline's rate proceeding that apply a new policy
governing the order of attribution of revenues received by ANR Pipeline related
to transition costs under Order 636. Under that new policy, ANR Pipeline is
required to first attribute the revenues it receives for its services to the
recovery of its transition costs under Order 636. In its rate proceeding, the
revenues ANR Pipeline receives for its services in its pending rate proceeding
were first attributed to the recovery of its base cost of service. The FERC's
change in its revenue attribution policy has the effect of understating ANR
Pipeline's currently effective maximum rates and has accelerated its
amortization of transition costs. In light of the FERC's policy, ANR Pipeline
has filed with the FERC to increase its discount recovery adjustment in its
pending rate proceeding. ANR Pipeline has also sought judicial review of these
orders before the United States Court of Appeals for the D.C. Court, and the
Court granted the FERC's motion to hold ANR Pipeline's appeal in abeyance
pending the outcome of the Order 636 discussed above.
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. Hearings were held before
the FERC Administrative Law Judge ("ALJ") on the prudence of the Settlement
Agreement, and on December 29, 1995, the ALJ issued an Initial Decision
rejecting the proposed Settlement Agreement. In the Initial Decision, the ALJ
also determined the level of Dakota costs that ANR Pipeline and the other
pipeline companies would be permitted to recover from their customers beginning
as of May 1993. Because the ALJ determined that the appropriate level of costs
is less than the amounts ANR Pipeline has billed to its customers since May 1993
under the ALJ's decision, ANR Pipeline may be required to refund to its
customers the excess amounts collected. At December 31, 1995, that refund amount
would be approximately $70 million, plus interest. It is ANR Pipeline's position
that the Settlement Agreement is prudent and that the FERC has no lawful
authority to order refunds for past periods, but even if refunds were ultimately
found to be lawful, ANR Pipeline should not lawfully be required to refund
amounts in excess of the refund amounts it collects from Dakota. ANR Pipeline
has filed with the FERC seeking reversal of the Initial Decision, and approval
of the Settlement Agreement.
Order 636 provides mechanisms for recovery of transition costs associated
with compliance with that Order. ANR Pipeline's transition costs consist
primarily of gas supply realignment costs and pricing differential costs. As of
December 31, 1995, ANR Pipeline incurred transition costs in the amount of $54
million. In addition, ANR Pipeline recorded a contingent liability for $94.1
million representing future above market gas purchase obligations, including
future obligations of $74 million associated with the Settlement Agreement, as
discussed above. The charge related to the contingent liability has been
deferred in anticipation of future rate recovery. ANR Pipeline has filed for
recovery of approximately $44.5 million of incurred transition costs, of which
$42.7 million has been accepted by the FERC for recovery, subject to refund and
further proceedings. Of the $42.7 million accepted by the FERC, $28.6 million
has been settled with the parties to the respective FERC proceedings. Additional
transition cost filings will be made by ANR Pipeline in the future.
F-36
CIG's gas sales for resale contracts extend through September 30, 1996.
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.
On March 31, 1993, CIG filed with the FERC under Docket RP93-99 to
increase its rates and such filing 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 and was required to make refunds as a result
of the approval of the settlement. Such refunds were distributed in March and
April 1995 and totaled approximately $22 million, inclusive of interest. CIG had
fully accrued for these refunds and, therefore, such refunds did not have an
adverse effect on its consolidated financial position or results of operations.
On October 31, 1995, CIG filed an application with the FERC seeking
authority to transfer to CIG Field Services Company ("CFS"), a subsidiary of
CIG, certain facilities presently used for the gathering of natural gas that are
subject to certificates of public convenience and necessity. In that filing, CIG
requested that the FERC declare that in the hands of CFS the transferred
facilities will be considered "non-jurisdictional" gathering facilities. The
transferred facilities have a net book value of approximately $36 million. CIG
has requested that the FERC issue an order approving the application to be
effective on September 30, 1996. The filing was protested by some parties and
proceedings are under way at the FERC to resolve the issues that have been
raised by the intervenors. Following receipt of authorizations, CIG will
transfer the certificated facilities along with certain noncertificated
gathering facilities to CFS. The facilities to be transferred comprise most, but
not all, of CIG's current gathering assets. Under current FERC policies, once
the facilities are transferred to CFS, the terms and conditions of service
performed by those facilities will cease to be subject to the FERC's general
jurisdiction under the Natural Gas Act of 1938 as amended, although the FERC has
indicated that, in certain very narrow circumstances, it will assert regulatory
jurisdiction over gathering by affiliates of interstate pipelines such as CFS.
The FERC's policy with respect to treatment of gathering affiliates of
interstate pipelines is on appeal at this time.
CIG will make a general rate increase filing with the FERC in the first
half of 1996, with such filing expected to become effective, subject to refund,
in late 1996.
CIG, ANR Pipeline, ANR Storage Company and Wyoming Interstate Company,
Ltd., subsidiaries of the Company, are regulated by the FERC. Certain of the
above regulatory matters and other 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 spent approximately $45 million in 1995 on
environmental capital projects and anticipates capital expenditures of
approximately $55 million in 1996 to comply with such laws and regulations. The
majority of the 1996 expenditures is attributable to construction projects at
the Company's refineries. The Company currently anticipates capital expenditures
for environmental compliance for the years 1997 through 1999 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 and a company in which Coastal
owns a 50% interest have been named as a potentially responsible party ("PRP")
in several "Superfund" waste disposal sites. At the 15 sites for which the
Environmental Protection Agency ("EPA") has developed sufficient information to
estimate total clean-up costs of approximately $341 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 5 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
F-37
those costs. Finally, at 9 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.
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.
Note 15. Quarterly Results of Operations (Unaudited)
Results of operations by quarter for the years ended December 31, 1995 and
1994 were (millions of dollars except per share):
Quarter Ended
----------------------------------------------------------------------
March 31, 1995 June 30, 1995 Sept. 30, 1995 Dec. 31, 1995
-------------- ------------- -------------- -------------
Operating revenues......................... $ 2,618.3 $ 2,613.5 $ 2,546.2 $ 2,669.7
Less purchases............................. 1,897.2 1,880.6 1,862.2 1,914.2
---------- ----------- ---------- ---------
721.1 732.9 684.0 755.5
Other income and expenses.................. 663.5 675.7 639.8 644.1
---------- ----------- ---------- ---------
Net earnings............................... $ 57.6 $ 57.2 $ 44.2 $ 111.4
========== =========== ========== =========
Net earnings per common and
common equivalent share................. $ .51 $ .50 $ .38 $ 1.01
========== =========== ========== =========
Quarter Ended
----------------------------------------------------------------------
March 31, 1995 June 30, 1995 Sept. 30, 1995 Dec. 31, 1995
-------------- ------------- -------------- -------------
Operating revenues......................... $ 2,700.8 $ 2,486.9 $ 2,675.5 $ 2,352.1
Less purchases............................. 1,920.6 1,800.4 2,012.0 1,627.5
---------- ----------- ---------- ---------
780.2 686.5 663.5 724.6
Other income and expenses.................. 699.1 643.4 636.9 642.8
---------- ----------- ---------- ---------
Net earnings .............................. $ 81.1 $ 43.1 $ 26.6 $ 81.8
========== =========== ========== =========
Net earnings per common and
common equivalent share................. $ .73 $ .37 $ .21 $ .74
========== =========== ========== =========
Note 16. Subsequent Event (Unaudited)
On February 28, 1996, the Company announced that it will seek qualified
buyers for its coal operations. The proceeds from the proposed sale, which the
Company plans to complete in 1996, are expected to be used to significantly
strengthen the Company's balance sheet by repayment of high-cost debt and other
obligations, and to provide improved financial flexibility to pursue
opportunities in the Company's other lines of business. The Coal operations had
operating revenues of $459.6 million, $451.3 million and $443.2 million for the
years ended December 31, 1995, 1994 and 1993, respectively; with operating
profit for the same periods of $98.7 million, $98.2 million and $95.1 million,
respectively. Identifiable assets of the Coal operations were $518.6 million and
$498.3 million as of December 31, 1995 and 1994, respectively.
F-38
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.
Estimated Quantities of Proved Reserves
Natural Gas Exploration
Systems and Production
------------- --------------------------
Developed Developed Undeveloped Total
------------- -------------------------- -------
Natural Gas (MMcf):
-------------------
1995 ................................................. 302,420 543,509 307,555 1,153,484
1994 ................................................. 334,597 479,660 144,157 958,414
1993 ................................................. 379,795 422,657 123,077 925,529
Oil, Condensate and Natural Gas Liquids (000 barrels):
------------------------------------------------------
1995 ................................................. 126 30,400 5,764 36,290
1994 ................................................. 11 28,030 5,636 33,677
1993 ................................................. 7 24,851 3,935 28,793
Changes in proved reserves since the end of 1992 are shown in the following
table:
Oil, Condensate and
Natural Gas Natural Gas Liquids
(MMcf) (000 barrels)
--------------------------- -------------------------
Natural Exploration Natural Exploration
Gas and Gas and
Total Proved Reserves Systems Production Systems Production
- --------------------- -------- ------------ ------- -----------
Total, end of 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
-------- ---------- ------- ---------
Production during 1995.......................... (41,638) (85,415) (16) (4,829)
Extensions and discoveries...................... - 170,075 - 2,457
Acquisitions.................................... - 141,104 118 696
Sales of reserves in-place...................... - - - -
Revisions of previous quantity estimates and
other......................................... 9,461 1,483 13 4,174
-------- ---------- ------- ---------
Total, end of 1995 ............................. 302,420 851,064 126 36,164
======== ========== ======= =========
F-39
Total proved reserves for natural gas systems exclude storage gas and
liquids volumes. The natural gas systems storage gas volumes are 143,134,
153,781 and 147,549 million cubic feet and storage liquids volumes are
approximately 138,000, 172,000 and 150,000 barrels at December 31, 1995, 1994
and 1993, respectively. Total proved reserves for natural gas includes
approximately 90,000 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)
December 31, 1995 December 31, 1994
---------------------------------- ---------------------------------
Accumulated Accumulated
Depreciation, Depreciation,
Capitalized Depletion and Capitalized Depletion and
Proved and Unproved Properties Cost Amortization Cost Amortization
----------- ----------- ----------- -----------
Undeveloped............................. $ 58 $ 15 $ 55 $ 18
Developed............................... 1,337 589 1,176 544
----------- ----------- ----------- -----------
$ 1,395 $ 604 $ 1,231 $ 562
=========== =========== =========== ===========
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)
Year Ended December 31,
--------------------------------
1995 1994 1993
-------- -------- --------
Property acquisition costs:
Proved................................................................. $ 65 $ 20 $ 6
Unproved............................................................... 16 5 11
Exploration costs............................................................ 33 29 6
Development costs............................................................ 112 91 65
F-40
Results of Operations for Exploration and Production Activities
(Millions of dollars)
Year Ended December 31,
--------------------------------
1995 1994 1993
-------- -------- --------
Revenues:
Sales..................................................................... $ 112 $ 115 $ 139
Transfers................................................................. 112 118 98
-------- -------- --------
Total.................................................................. 224 233 237
-------- -------- --------
Production costs............................................................. (85) (71) (71)
Operating expenses........................................................... (27) (29) (28)
Depreciation, depletion and amortization..................................... (103) (104) (107)
-------- -------- --------
9 29 31
Income tax benefit........................................................... 5 1 2
-------- -------- --------
Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 14 $ 30 $ 33
======== ======== ========
The average amortization rate per equivalent Mcf was $0.89 in 1995, $0.96 in
1994 and $1.00 in 1993.
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):
Year Ended December 31,
----------------------------------------------------------------------------------
1995 1994 1993
------------------------- ------------------------- --------------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
----------- ----------- ----------- ----------- ----------- ------------
Future cash inflows.......... $ 286 $ 2,281 $ 235 $ 1,617 $ 299 $ 1,698
Future production and development
costs....................... (82) (964) (65) (717) (63) (647)
Future income tax expenses... (68) (294) (58) (176) (82) (237)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 136 1,023 112 724 154 814
10% annual discount for estimated
timing of cash flows........ (61) (304) (44) (196) (59) (252)
------------ ----------- ----------- ----------- ----------- -----------
Standardized measure of discounted
future net cash flows....... $ 75 $ 719 $ 68 $ 528 $ 95 $ 562
=========== =========== =========== =========== =========== ===========
Future cash inflows include $139 million for 1995 and $39 million for 1994
related to volumes dedicated to volumetric production payments sold by the
Company.
F-41
Principal sources of change in the standardized measure of discounted future net
cash flows during each year are (millions of dollars):
Year Ended December 31,
----------------------------------------------------------------------------------
1995 1994 1993
------------------------- ------------------------- --------------------------
Natural Exploration Natural Exploration Natural Exploration
Gas and Gas and Gas and
Systems Production Systems Production Systems Production
----------- ----------- ----------- ----------- ----------- ------------
Sales and transfers, net of
production costs............ $ (31) $ (136) $ (39) $ (148) $ (35) $ (164)
Net changes in prices and
production costs............ 46 88 (15) (183) (1) 7
Extensions and discoveries... - 187 - 119 - 139
Acquisitions................. 1 109 - 43 - 5
Sales of reserves in-place... - - - (4) - (5)
Development costs incurred
during the period that
reduced estimated future
development costs........... - 21 - 24 - 21
Revisions of previous quantity
estimates, timing and other. (15) (70) 1 23 12 (87)
Accretion of discount........ 7 49 11 55 12 56
Net change in income taxes... (1) (57) 15 37 4 (19)
----------- ----------- ----------- ----------- ----------- -----------
Net change................... $ 7 $ 191 $ (27) $ (34) $ (8) $ (47)
=========== =========== =========== =========== =========== ===========
None of the amounts include any value for natural gas systems storage gas and
liquids volumes, which was approximately 39 Bcf for CIG, 104 Bcf for ANR
Pipeline and 138,000 barrels of liquids for CIG at the end of 1995.
F-42
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.
Total Recoverable Reserves December 31,
(Millions of tons) -------------------------------------------------------------------
1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
Total, beginning of year.................. 839 871 789 806 828
Production................................ (18) (20) (24) (18) (18)
Purchases (sales)......................... 18 (2) 115 8 (5)
Changes in estimates...................... (16) (10) (9) (7) 1
----------- ----------- ----------- ----------- -----------
Total, end of year........................ 823 839 871 789 806
----------- ----------- ----------- ----------- -----------
Average market price per ton sold......... $ 25.18 $ 25.77 $ 25.80 $ 27.29 $ 28.07
=========== =========== =========== =========== ===========
The following presents additional information on coal operations:
Operating Data
(Millions of tons) 1995 1994 1993 1992 1991
----------- ----------- ----------- ----------- -----------
Sales
East................................. 7.3 7.6 7.2 7.7 8.2
West................................. 9.8 8.7 8.9 7.8 7.4
Brokerage............................ .9 1.2 1.3 1.4 1.0
----------- ----------- ----------- ----------- -----------
Total............................ 18.0 17.5 17.4 16.9 16.6
=========== =========== =========== =========== ===========
Royalty Tonnage
Eastern Bituminous................... 3.7 5.1 3.9 4.2 3.8
Western Lignite...................... 15.0 16.0 16.4 19.7 18.4
----------- ----------- ----------- ----------- -----------
Total............................ 18.7 21.1 20.3 23.9 22.2
=========== =========== =========== =========== ===========
Developed Production Capacity
East................................. 11.1 10.8 10.6 10.5 10.1
West................................. 10.9 10.7 10.6 9.5 7.9
----------- ----------- ----------- ----------- -----------
Total............................ 22.0 21.5 21.2 20.0 18.0
=========== =========== =========== =========== ===========
F-43
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
December 31,
------------------------
1995 1994
--------- ---------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents......................................................... $ 3.3 $ 6.0
Receivables....................................................................... 56.2 26.7
Receivables from subsidiaries..................................................... 1,745.1 1,830.5
Prepaid expenses and other........................................................ 1.5 2.7
--------- ---------
Total Current Assets........................................................... 1,806.1 1,865.9
--------- ---------
PROPERTY, PLANT AND EQUIPMENT - at cost, net......................................... 1.1 1.1
--------- ---------
INVESTMENTS IN SUBSIDIARIES AND OTHER ASSETS:
Investment in subsidiaries at cost plus equity in undistributed earnings since
acquisition.................................................................... 3,294.9 3,033.6
Due from subsidiaries............................................................. 541.6 541.8
Deferred federal income taxes..................................................... 110.0 67.6
Other assets...................................................................... 253.5 280.4
--------- ---------
4,200.0 3,923.4
$ 6,007.2 $ 5,790.4
========= =========
See Notes to Condensed Financial Statements.
S-1
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
BALANCE SHEET
(Millions of Dollars)
December 31,
------------------------
1995 1994
--------- ---------
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Notes payable..................................................................... $ 73.2 $ 50.5
Accounts payable and accrued expenses............................................. 133.9 179.6
Payable to subsidiaries........................................................... 260.8 243.8
Current maturities on long-term debt.............................................. 121.5 97.6
--------- ---------
Total Current Liabilities...................................................... 589.4 571.5
--------- ---------
DEBT:
Long-term debt.................................................................... 2,610.9 2,415.7
Subordinated long-term debt....................................................... - 199.7
--------- ---------
2,610.9 2,615.4
DEFERRED CREDITS AND OTHER........................................................... 128.1 146.3
--------- ---------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY.......................................... 2,678.8 2,457.2
--------- ---------
$ 6,007.2 $ 5,790.4
========= =========
See Notes to Condensed Financial Statements.
S-2
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF OPERATIONS
(Millions of Dollars)
Year Ended December 31,
---------------------------------------
1995 1994 1993
--------- --------- ---------
OPERATING REVENUES..................................................... $ - $ .2 $ 1.0
OPERATING COSTS AND EXPENSES........................................... - - -
--------- --------- ---------
OPERATING PROFIT....................................................... - .2 1.0
--------- --------- ---------
OTHER INCOME:
Equity in net earnings of subsidiaries.............................. 384.2 334.8 263.9
Interest income from subsidiaries - net............................. 152.7 125.3 119.6
Other income - net.................................................. 17.1 14.0 20.0
--------- --------- ---------
554.0 474.1 403.5
--------- --------- ---------
OTHER EXPENSES (BENEFITS):
General and administrative.......................................... 10.4 10.1 12.1
Interest and debt expense........................................... 305.8 306.9 364.6
Taxes on income..................................................... (32.6) (75.3) (90.5)
--------- --------- ---------
283.6 241.7 286.2
--------- --------- ---------
EARNINGS BEFORE EXTRAORDINARY ITEM..................................... 270.4 232.6 118.3
Extraordinary item-loss on early extinguishment of debt............. - - (2.5)
--------- --------- ---------
NET EARNINGS........................................................... $ 270.4 $ 232.6 $ 115.8
========= ========= =========
See Notes to Condensed Financial Statements.
S-3
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE I - CONDENSED FINANCIAL INFORMATION OF THE REGISTRANT
THE COASTAL CORPORATION
STATEMENT OF CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
---------------------------------------
1995 1994 1993
--------- --------- ---------
Net Cash Flow From Operating Activities:
Net earnings before extraordinary item.............................. $ 270.4 $ 232.6 $ 118.3
Items not requiring (providing) cash:
Depreciation, depletion and amortization......................... .1 .3 .5
Deferred income taxes............................................ (22.0) 14.1 (36.2)
Undistributed subsidiary earnings................................ (260.9) (266.9) (197.3)
Working capital and other changes, excluding changes relating to cash and
non-operating activities:
Receivables................................................... (29.5) (9.2) (3.3)
Prepaid expenses and other.................................... 1.2 (1.3) (.1)
Accounts payable and accrued expenses......................... 25.7 46.7 (15.1)
Other......................................................... (11.1) (54.2) (9.0)
--------- --------- ---------
(26.1) (37.9) (142.2)
--------- --------- ---------
Cash Flow from Investing Activities:
Purchases of property, plant and equipment.......................... (.1) (.1) (.9)
Proceeds from sale of property, plant and equipment ................ - 4.9 -
Net change in accounts with subsidiaries............................ 12.4 260.8 553.3
Additions to investments............................................ - - (1.0)
Proceeds from investments........................................... 19.3 - -
--------- --------- ---------
31.6 265.6 551.4
--------- --------- ---------
Cash Flow from Financing Activities:
Increase (decrease) in short-term notes............................. 322.7 (203.0) 55.1
Proceeds from issuing common stock.................................. 10.5 5.4 11.9
Proceeds from issuing preferred stock............................... - - 193.5
Proceeds from long-term debt issues................................. 218.5 - 80.1
Payments to retire long-term debt................................... (500.6) (79.4) (587.2)
Dividends paid...................................................... (59.3) (59.3) (53.0)
--------- ---------- ---------
(8.2) (336.3) (299.6)
--------- --------- ---------
Net Increase (Decrease) in Cash and Cash Equivalents................... (2.7) (108.6) 109.6
Cash and Cash Equivalents at Beginning of Year......................... 6.0 114.6 5.0
--------- --------- ---------
Cash and Cash Equivalents at End of Year............................... $ 3.3 $ 6.0 $ 114.6
========= ========= =========
See Notes to Condensed Financial Statements.
S-4
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 $333.5 million, $340.6 million
and $357.1 million in 1995, 1994 and 1993, respectively. Cash payments (refunds
- - primarily from subsidiaries) for income taxes amounted to $(44.5) million,
$(62.2) million and $(49.8) million for 1995, 1994 and 1993, 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 $72.8 million
outstanding at December 31, 1995, 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 partner
ships 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 maturities of Coastal for the five
years following 1995 are (millions of dollars):
1996 .............. $ 121.5 1999 .............. $ 180.1
1997 .............. 75.0 2000 .............. 280.0
1998 .............. 30.0
Note 4. Dividends Received
Cash dividends received from consolidated subsidiaries were as follows:
1995 - $123.3 million, 1994 - $67.9 million and 1993 - $66.6 million.
S-5
THE COASTAL CORPORATION AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
(Millions of Dollars)
Additions
Balance at Charged to Balance
Beginning Costs and at End
Description of Year Expenses Other of Year
- ------------------------------------------------------------------------------------------------------------------
Year Ended December 31, 1995
Allowance for doubtful accounts.................... $19.0 $ 4.9 $(2.5)(A) $ 21.4
===== ===== ===== =======
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
===== ===== ====== =======
- --------
(A) Accounts charged off net of recoveries.
S-6
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).
10.14* Pension Plan for Employees of The Coastal Corporation as of
January 1, 1993, as further amended by the Fourth Amendment dated
May 20, 1994, Fifth Amendment dated August 17, 1994, Sixth
Amendment dated August 30, 1994, Seventh Amendment dated October
30, 1995, Eighth Amendment dated December 29, 1995 and Ninth
Amendment dated December 29, 1995.
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.