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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