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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 1-7320
ANR PIPELINE COMPANY
(Exact name of registrant as specified in its charter)
Delaware 38-1281775
(State or other jurisdiction (I.R.S. Employer
of incorporation or organization) Identification No.)
500 Renaissance Center,
Detroit, Michigan 48243-1902
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code: (313) 496-0200
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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
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9-5/8% Debentures, due 2021
7-3/8% Debentures, due 2024 } New York Stock Exchange
7% Debentures, due 2025
Securities registered pursuant to Section 12(g) of the Act: None
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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 1,000 shares of common stock
of the Registrant, $100 par value per share, its only class of common stock.
None of the voting stock of the Registrant is held by nonaffiliates.
Documents incorporated by reference: None
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TABLE OF CONTENTS
Item No. Page
Glossary............................................................(ii)
PART I
1. Business............................................................ 1
Introduction.................................................... 1
Natural Gas System.............................................. 1
Operations.................................................. 1
General................................................. 1
Transportation Services and Gas Sales................... 1
Gas Purchases........................................... 2
Gas Storage............................................. 2
Competition............................................. 3
Producing Area Deliverability............................... 3
Regulations Affecting Gas System............................ 4
General................................................. 4
Rate Matters............................................ 5
Environmental............................................... 6
Other Developments.......................................... 7
2. Properties.......................................................... 8
3. Legal Proceedings................................................... 8
4. Submission of Matters to a Vote of Security Holders................. 8
PART II
5. Market for the Registrant's Common Equity and Related Stockholder
Matters........................................................ 9
6. Selected Financial Data............................................. 9
7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.......................................... 9
8. Financial Statements and Supplementary Data......................... 9
9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure........................................... 9
PART III
10. Directors and Executive Officers of the Registrant.................. 10
11. Executive Compensation.............................................. 12
12. Security Ownership of Certain Beneficial Owners and Management...... 21
13. Certain Relationships and Related Transactions...................... 24
PART IV
14. Exhibits, Financial Statement Schedules and Reports on Form 8-K..... 25
(i)
GLOSSARY
"ANR" means American Natural Resources Company
"ANR Pipeline" or the "Company" means ANR Pipeline Company
"ANR Storage" means ANR Storage Company
"Bcf" means billion cubic feet
"Coastal" means The Coastal Corporation
"Coastal Natural Gas" means Coastal Natural Gas Company
"Colorado" means Colorado Interstate Gas Company
"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
"HIOS" means High Island Offshore System
"Interim Settlement" means the Company's Stipulation and Agreement submitted to
the FERC which is more fully described in Item 1, "Business, Regulations
Affecting Gas System - Rate Matters"
"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 System - General"
"TransCanada" means TransCanada PipeLines Limited
"UTOS" means U-T Offshore System
"Working Gas" means that volume of gas available for withdrawal and use by the
Company's customers
NOTE: 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
ANR Pipeline is a Delaware corporation organized in 1945. All of ANR
Pipeline's outstanding common stock is owned by ANR. ANR is a direct,
wholly-owned subsidiary of Coastal Natural Gas, and an indirect subsidiary of
Coastal. ANR Pipeline owns and operates an interstate natural gas pipeline
system. At December 31, 1995, the Company had 2,039 employees engaged in the
operation of ANR Pipeline and 123 employees engaged in the operation of HIOS,
UTOS and Empire.
NATURAL GAS SYSTEM
OPERATIONS
General
The Company 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, the Company was also engaged in the
sale for resale of natural gas. With the Company'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. The Company 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. The Company 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. The Company
also operates Empire, an intrastate pipeline extending from Niagara Falls to
Syracuse, New York, in which an affiliate of the Company has a 45% interest.
The Company'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.
The Company'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 of the
transmission system, considering supply sources, storage, markets and
transportation for others, was approximately 5.6 Bcf per day.
Transportation Services and Gas Sales
Effective November 1, 1993, the Company implemented Order 636. This Order
required significant changes in the services provided by ANR Pipeline and
resulted in the elimination of the Company's merchant services. The Company 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 System - 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
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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 the Company'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, the Company's gas purchases
decreased substantially. However, the Company still purchases a residual
quantity of gas under certain remaining gas purchase contracts. The Company'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 the Company recovers through the auctioning
of such gas on the open market in producing areas.
Some of ANR Pipeline's remaining gas purchase contracts with independent
producers contain provisions which require taking minimum volumes and/or making
prepayments for volumes not taken if purchases fall below specified levels
during the contract year ("take-or-pay"). Additional information on take-or-pay
matters is set forth in Note 5 of 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, the
Company 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 the Company has reclassified to recoverable
base gas, subject to approval by the FERC as part of the Company's general rate
proceeding discussed below.
2
Competition
ANR Pipeline has historically competed with interstate pipeline companies
in the sale, transportation and storage of gas and with independent producers,
brokers, marketers and other pipelines in the gathering and sale of gas within
its service areas. On November 1, 1993, the Company implemented Order 636 on its
system. As a consequence, the Company is no longer a seller of natural gas to
resale customers. The implementation of Order 636 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. This is particularly true in the Midwest region in which the
Company primarily operates. Additional information on the impacts of Order 636
is set forth in "Regulations Affecting Gas System" and "Management's Discussion
and Analysis of Financial Condition and Results of Operations" 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.
ANR Pipeline's transportation, storage and balancing services are
influenced by its customers' access to alternative providers of such services.
The Company 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.
The Company'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, the Company entered
into agreements to sell a major portion of its Southwest gathering facilities,
as discussed in "Other Developments" included herein.
PRODUCING AREA DELIVERABILITY
Shippers on ANR Pipeline have direct access to the two most prolific gas
producing areas in the United States, the Gulf Coast and the Midcontinent.
Statistics published by the Energy Information Agency, Office of Oil and Gas, U.
S. Department of Energy, indicate that approximately 81% of all natural gas in
the lower 48 states is produced from these two areas. Interconnecting pipelines
provide shippers with access to all other major gas producing areas in the
United States and Canada.
Gas deliverability available to shippers on ANR Pipeline's system from the
Midcontinent and Gulf Coast producing areas through direct connections and
interconnecting pipelines and gatherers is approximately 4,400 MMcf per day. An
additional 300 MMcf per day of deliverability is accessible to shippers on
Company-owned, or partially-owned, pipeline segments not directly connected to a
Company mainline.
The Company 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 the Company's pipeline
system.
3
REGULATIONS AFFECTING GAS SYSTEM
General
Under the NGA, the FERC has jurisdiction over ANR Pipeline 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. ANR Pipeline, where required, holds certificates of
public convenience and necessity issued by the FERC covering its jurisdictional
facilities, activities and services.
ANR Pipeline is also subject to regulation with respect to safety
requirements in the design, construction, operation and maintenance of its
interstate gas transmission and storage facilities by the Department of
Transportation. Operations on United States government land are regulated by the
Department of the Interior.
On November 1, 1990, the FERC issued Order No. 528 in which it sets forth
guidelines for an acceptable allocation method for a fixed direct charge to
collect take-or-pay settlement costs. Pursuant to Order No. 528, the Company 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
the Company's former gas sales customers and 50% via a surcharge on all
transportation volumes. Contract reformation and take-or-pay costs incurred as a
result of the mandated Order 636 restructuring will be recovered under the
transition costs mechanisms of Order 636, as well as through negotiated
agreements with the Company's customers.
On April 8, 1992, the FERC issued Order 636, which required significant
changes in the services provided by interstate natural gas pipelines. 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. ANR Pipeline placed its
restructured services under Order 636 into effect on November 1, 1993. As a
result, the Company no longer provides merchant services and now offers a wide
range of "unbundled" transportation, storage and balancing services. However,
the Company still purchases a residual quantity of gas under certain remaining
gas purchase contracts. The Company'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 the Company 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 the Company'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, the Company 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, the Company
filed revised tariff sheets on July 18, 1994, which were accepted by order
issued April 12, 1995.
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.
4
Rate Matters
All of the Company's service options are subject to rate regulation by the
FERC. Under the NGA, ANR Pipeline must file with the FERC to establish or adjust
its service rates. The FERC may also initiate proceedings to determine whether
the Company's rates are "just and reasonable."
On March 10, 1992, the Company 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 the
Company's implementation of Order 636 on November 1, 1993. Under the Interim
Settlement, gas inventory demand charges were collected from the Company'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 the Company at risk for under-collections. As required by the Interim
Settlement, the Company 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 the Company's refund allocation
methodology, and directed the Company 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. The Company 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, the Company 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
in the cost of service from that approved in the Interim Settlement and a $182.8
million increase over the Company's approved rates for its restructured services
under Order 636. The Company sought rehearing of various aspects of the order.
Further, on April 29, 1994, the Company 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 the Company'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. The Company 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 the Company on March 10,
1995, and was accepted by order issued May 3, 1995, subject to one additional
compliance filing requirement, which the Company 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, the Company 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 the Company's rate proceeding that apply a new policy governing the order of
attribution of revenues received by the Company related to transition costs
under Order 636. Under that new policy, the Company 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 the
Company 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 the Company's
currently effective maximum rates and has accelerated its amortization of
transition costs. In light of the FERC's policy, the Company has filed with the
FERC to increase its discount recovery adjustment in its pending rate
proceeding. The Company 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 the Company's appeal in abeyance pending the outcome
of the Order 636 appeal discussed above.
5
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 the
Company 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 the Company'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 the Company and Dakota and terminates the transportation
contract. The Settlement Agreement is subject to final FERC approval, including
an approval for the Company to recover the settlement costs from its customers.
On August 3, 1994, the Company 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 the Company'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. The Company's transition costs consist
primarily of gas supply realignment costs and pricing differential costs. As of
December 31, 1995, the Company incurred transition costs in the amount of $54
million. In addition, the Company 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. The Company has filed for
recovery of approximately $44.5 million of incurred transition costs, of which
$42.7 million has been accepted by the FERC for recovery, subject to refund and
further proceedings. Of the $42.7 million accepted by the FERC, $28.6 million
has been settled with the parties to the respective FERC proceedings. Additional
transition cost filings will be made by the Company in the future.
Certain of the above regulatory matters and other regulatory issues remain
unresolved among the Company, its customers, its suppliers and the FERC. The
Company has made provisions which represent management's assessment of the
ultimate resolution of the above 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.
ENVIRONMENTAL
A subsidiary of the Company 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
6
ANR Pipeline. In conjunction with this, and although no agreements have been
reached regarding the disposition of these matters, the Company has recorded a
reserve for its share of the potential expense of the Iroquois investigation and
proceedings.
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations which may affect such
operations and costs as a result of their effect on the construction, operation
and maintenance of its pipeline facilities. The Company spent approximately $.6
million in 1995 on environmental capital projects and anticipates annual capital
expenditures of $2.8 million per year over the next several years aimed at
maintaining compliance with such laws and regulations. Additionally, appropriate
governmental authorities may enforce the laws and regulations with a variety of
civil and criminal enforcement measures, including monetary penalties and
remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as Superfund, as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." The Company has been named as a potentially responsible party in
five Superfund waste disposal sites. At these sites, the EPA has developed
sufficient information to estimate total cleanup costs of approximately $45.1
million and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $.9 million. At a sixth site, the
Company had been named a de minimis potentially responsible party and has
settled the claim for approximately $20,000.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. The states have regulatory programs that mandate
waste cleanup. The Clean Air Act Amendments of 1990 include new permitting
regulations which will result in increased operating expenditures.
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, consolidated
financial position or results of operations.
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 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, the Company 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
7
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 the Company has a 45% equity interest in the proposed
Mayflower Pipeline project, which will be owned by a partnership consisting of
the Company'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.
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.
Item 2. Properties.
Information on properties of ANR Pipeline is in Item 1, "Business,"
included herein.
The real property owned by the Company in fee consists principally of
sites for compressor and metering stations and microwave and terminal
facilities. With respect to the seven 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 gas rights. Under the NGA, the Company 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.
Numerous 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 such 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 5 and 6 of Notes to Consolidated Financial Statements included
herein.
Item 4. Submission of Matters to a Vote of Security Holders.
None.
8
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters.
All common stock of ANR Pipeline is owned by ANR.
Item 6. Selected Financial Data.
The following selected financial data (in millions of dollars) for the
periods indicated 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. Management's Discussion and Analysis of Financial
Condition and Results of Operations and the Notes to Consolidated Financial
Statements included herein contain information relating to this data.
1995 1994 1993 1992 1991
-------- -------- --------- -------- --------
Operating Revenues:
Storage and transportation....................... $ 702.8 $ 706.3 $ 634.7 $ 534.0 $ 441.4
Gas sales........................................ 59.2 106.1 603.5 634.5 641.2
Other revenues................................... 58.7 29.7 33.6 23.3 31.8
--------- --------- --------- --------- ---------
Total...................................... $ 820.7 $ 842.1 $ 1,271.8 $ 1,191.8 $ 1,114.4
========= ========= ========= ========= =========
Net Earnings........................................ $ 151.3 $ 152.1 $ 157.0 $ 151.0 $ 148.4
========= ========= ========= ========= =========
Dividends Declared on Common Stock.................. $ 30.1 $ 331.0 $ 33.7 $ 28.6 $ 320.0
========= ========= ========= ========= =========
Total Assets........................................ $ 2,040.6 $ 1,858.6 $ 1,920.3 $ 1,968.0 $ 1,905.1
========= ========= ========= ========= =========
Capital Structure:
Common stock and other stockholder's
equity........................................ $ 909.7 $ 788.5 $ 969.3 $ 850.1 $ 732.8
Mandatory redemption cumulative
preferred stock............................... - - 26.0 36.1 48.3
Long-term debt and capital lease
obligations................................... 509.3 437.0 374.0 435.1 482.6
--------- --------- --------- --------- ---------
Total...................................... $ 1,419.0 $ 1,225.5 $ 1,369.3 $ 1,321.3 $ 1,263.7
========= ========= ========= ========= =========
Since all of the outstanding common stock of ANR Pipeline is owned by ANR,
earnings and cash dividends per common share have no significance and are not
presented.
Item 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Management's Discussion and Analysis of Financial Condition and Results of
Operations is presented on pages F-1 through F-4 herein.
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) herein.
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
9
PART III
Item 10. Directors and Executive Officers of the Registrant.
The directors and executive officers of ANR Pipeline as of March 13, 1996,
were as follows:
Name (Age), Year First Elected Positions and Offices
Director and/or Officer with the Registrant
- --------------------------------- ----------------------------------
James F. Cordes (55), 1982 Chairman of the Board of Directors
Jeffrey A. Connelly (49), 1988 and 1983 President, Chief Executive Officer
and Director
David A. Arledge (51), 1994 Director
John M. Bissell (65), 1994 Director
Harold Burrow (81), 1994 Vice Chairman of the Board of
Directors
Roy D. Chapin, Jr. (80), 1994 Director
Lawrence P. Doss (68), 1994 Director
Martha O. Hesse (53), 1994 Director
Richard A. Lietz (50), 1994 and 1984 Executive Vice President, Chief
Operating Officer and Director
Wilber H. Mack (85), 1994 Director
J. Carleton MacNeil, Jr. (61), 1994 Director
James H. McNeal, Jr. (68), 1994 Director
O. S. Wyatt, Jr. (71), 1994 Director
Stanley A. Babiuk (44), 1989 Senior Vice President
Daniel F. Collins (54), 1986 Senior Vice President
Donald H. Gullquist (52), 1994 Senior Vice President
Coby C. Hesse (48), 1994 Senior Vice President
Wilbur A. Hitchcock (47), 1994 Senior Vice President
John P. Lucido (48), 1988 Senior Vice President
Rebecca H. Noecker (44), 1989 Senior Vice President and General
Counsel
Austin M. O'Toole (60), 1985 Senior Vice President and Assistant
Secretary
Steven R. Anderson (46), 1996 Vice President
Scott P. Anger (51), 1990 Vice President
Michael J. Armiak (48), 1996 Vice President
Daniel M. Ives (48), 1995 Vice President
T. E. Jackson, Jr. (56), 1994 Vice President
William L. Johnson (38), 1991 Vice President and Controller
Richard H. Leehr (46), 1991 Vice President
Michael B. Lobin (46), 1991 Vice President
Lawrence R. Marantette (46), 1992 Vice President
Ronald D. Matthews (48), 1994 Vice President and Treasurer
Lynn M. Nichols (49), 1995 Vice President
Dennis J. Paruch (50), 1984 Vice President
Elias A. Shaptini (65), 1981 Vice President
Michael J. Whims (49), 1996 Vice President
C. D. Wilkerson (62), 1987 Vice President
Michael J. Williams (49), 1996 Vice President
Steven W. Zuckweiler (45), 1995 Vice President
Frederick H. Clark (67), 1984 Secretary
The above named persons bear no family relationship to each other. Their
respective terms of office expire coincident with ANR Pipeline's Annual Meeting
of the Sole Stockholder and Annual Meeting of the Board of Directors
10
to be held in May 1996. Each of the directors and officers named above have been
directors or officers of ANR Pipeline, Colorado and/or Coastal for five years or
more except for the following:
Mr. Anderson was elected Vice President of the Company in January 1996.
Prior thereto, he served as Vice President of Coastal Gas Services since 1993
and Vice President of the Company from 1986 to 1993.
Mr. Armiak was elected Vice President of the Company in January 1996.
Prior thereto, he has served in various capacities with the Company since 1971.
Mr. Bissell was elected a Director in September 1994. He has been a
Director of Coastal since 1985 and of ANR since 1979. He is currently Chairman
of the Board of Directors and Chief Executive Officer of Bissell Inc., a
position he has held since 1971.
Mr. Burrow was elected Vice Chairman of the Board of Directors in
September 1994. He has served as a Director of Coastal since 1973 and as
Chairman of the Board of Directors of Colorado since 1974.
Mr. Chapin was elected a Director in September 1994. He has been a
Director of Coastal since 1988 and of ANR since 1973. Mr. Chapin was Chairman
and Chief Executive Officer of American Motors Corporation from 1967 until his
retirement in 1978.
Mr. Doss was elected a Director in September 1994. He has been a Director
of ANR since 1980. He is a former partner of Coopers & Lybrand, an international
accounting and consulting firm.
Mr. Gullquist was elected Senior Vice President of the Company in
September 1994. From 1988 to 1989 he served as Vice President, Finance at Enron
Corporation; from 1989 to 1990 he served as president of Enron Finance
Corporation.
Ms. Hesse was elected a Director in September 1994. Ms. Hesse is currently
President of Hesse Gas Company, a position she has held since 1991. Prior
thereto she served as Senior Vice President of First Chicago Corporation since
1990. She was Chairman of the Federal Energy Regulatory Commission from 1986 to
1989. She has been a Director of ANR since 1990.
Mr. Hitchcock was elected a Senior Vice President of ANR Pipeline in March
1994. He previously served as a Vice President of Northern Indiana Public
Service Company, where he had been employed since 1990. From 1984 to 1990, he
was employed by Natural Gas Pipeline Company in various positions.
Mr. Ives was elected Vice President of the Company in September 1995.
Prior to joining the Company, he was General Manager - Rates for Algonquin Gas
Transmission Company, a unit of PanEnergy Corp since 1992 and prior thereto, he
was Director of Rates and Regulatory Affairs for Washington Gas Light Company
since 1976.
Mr. Johnson was elected Vice President and Controller of ANR Pipeline in
August 1991. Prior thereto he was employed by Great Lakes Gas Transmission
Company from 1982 until 1991. He became an Assistant Controller for Great Lakes
in 1987 and served as its Controller from 1989 to 1991.
Mr. Leehr was elected a Vice President of ANR Pipeline in July 1991. Prior
thereto he held various positions with ANR Pipeline.
Mr. Mack was elected a Director in September 1994. Mr. Mack was an
executive with ANR for 24 years, retiring in 1976 as Chairman and Chief
Executive Officer and serving on the Board until 1982. He was re-elected to the
Board of ANR in 1986.
Mr. MacNeil was elected a Director in September 1994. He has been a
Director of ANR since 1993. Mr. MacNeil has been self employed in the securities
and brokerage industry since 1980.
11
Mr. McNeal was elected a Director in September 1994. He has been a
Director of ANR since 1982. Mr. McNeal served in various capacities with The
Budd Company, retiring in 1989 as Chairman and Chief Executive Officer.
Mr. Marantette was elected a Vice President of ANR Pipeline in May 1992.
He has held various positions with other subsidiaries of ANR, including
President of ANR Development Corporation since 1985.
Mr. Matthews was elected Vice President and Treasurer in September 1994.
He was elected Vice President and Treasurer of Colorado in October 1994. He has
held various positions in financial management with Coastal and its affiliates
since 1981, and was elected Treasurer of Coastal in September 1994.
Ms. Nichols was elected Vice President in January 1995. Most recently she
served as Director - Application and Maintenance for Whirlpool Corporation,
where she worked for more than four years. Prior thereto, she served in various
capacities for the Pillsbury Corporation for 21 years.
Mr. Whims was elected Vice President of the Company in January 1996. He
has served in various capacities with ANR Storage since 1979.
Mr. Williams was elected Vice President of the Company in January 1996. He
has served in various capacities with the Company since 1969.
Mr. Zuckweiler was elected Vice President of the Company in March 1995. He
has served as Vice President of Colorado since 1991 and prior thereto, as
Assistant Vice President since 1988.
Item 11. Executive Compensation.
ANR Pipeline is an indirect, wholly-owned subsidiary of Coastal.
Information concerning the cash compensation and certain other compensation of
the directors and officers of Coastal is contained in this section.
The following table sets forth information for the fiscal years ended
December 31, 1995, 1994 and 1993 as to cash compensation paid by Coastal and its
subsidiaries, as well as certain other compensation paid or accrued for those
years, to Coastal's Chief Executive Officer ("CEO") and its four other most
highly compensated executive officers (the "Named Executive Officers").
12
Summary Compensation Table
Long Term Compensation
------------------------------
Annual Compensation Awards Payouts
---------------------------------- ------------ -------------
Securities All Other
Underlying LTIP Compen-
Name and Options/ Payouts sation
Principal Position Year Salary ($) Bonus ($) SARs (#) ($) $
- ------------------ ---- ---------- --------- ------------ ------------- -------------
O. S. Wyatt, Jr., 1995 849,093 300,000 -0- -0- 67,928
Chairman of the Board 1994 849,093 200,000 -0- 67,928
(and CEO through 1993 962,495 90,000 -0- 71,690
October 4, 1995)
David A. Arledge, 1995 622,867 300,000 50,000 85,875 49,829
President, (CEO 1994 553,873 150,000 -0- 44,310
commencing October 5, 1993 473,211 70,000 38,848 42,042
1995) and Director
James F. Cordes, 1995 592,222 135,000 15,000 42,937 47,378
Executive V.P. 1994 592,223 130,000 -0- 47,378
and Director 1993 624,675 50,000 32,094 48,414
James A. King, 1995 343,823 80,000 10,000 -0- 10,141
Executive V.P. 1994 343,823 75,000 -0- 6,877
1993 324,658 28,000 20,000 3,254
Sam F. Willson, Jr. 1995 334,062 75,000 10,000 25,762 26,725
Executive V.P. 1994 334,062 75,000 -0- 26,725
1993 334,062 28,000 15,000 28,600
- ------------------------
Does not include the value of perquisites and other personal benefits because
the aggregate amount of such compensation, if any, does not exceed the lesser of
$50,000 or 10 percent of annual salary and bonus for any named individual.
Salary amounts for Messrs. Wyatt, Arledge and Cordes for 1993 include directors'
fees paid during this period. Directors' fees for members of management of
Coastal were eliminated in September 1993. There was no salary change for Mr.
Wyatt during 1994 and 1995; the reduced base pay level for 1994 and 1995 was due
to the September 1993 salary reduction (reported in the 1994 Proxy Statement)
being in effect for all of 1994 and 1995.
The 1995 bonuses were based on the following factors: the individual's position;
the individual's responsibility; and the individual's ability to impact
Coastal's financial success.
The options do not carry any stock appreciation rights.
During 1995, Messrs. Arledge, Cordes and Willson received one-time cash payments
in the amounts indicated in connection with awards made in 1987 under Coastal's
Performance Unit Plan. No further awards have been made under this Plan.
All Other Compensation for 1995 consists of: (i) Coastal contributions to the
Coastal Thrift Plan (O. S. Wyatt, Jr. $12,000; David A. Arledge $12,000; James
F. Cordes $12,000; James A. King $3,000; and Sam F. Willson, Jr. $12,000); and
(ii) certain payments in lieu of Thrift Plan contributions (O. S. Wyatt, Jr.
$55,928; David A.
13
Arledge $37,829; James F. Cordes $35,378; James A. King $7,141; and Sam F.
Willson, Jr., $14,725). These payments are made to all employees of Coastal and
its subsidiaries who participate in the Thrift Plan who must discontinue their
Thrift Plan participation due to federal statutory limits.
Coastal is negotiating an employment contract with James L. Van Lanen,
Senior Vice President of Coastal responsible for coal operations, at his current
annual rate of salary which will become effective upon the completion of the
previously announced prospective sale of Coastal's coal subsidiaries, and which
will extend through January 26, 2000. In addition, Coastal anticipates an
agreement with Mr. Van Lanen under which he will receive a bonus based on the
proceeds of the sale of such subsidiaries.
Stock Options
The following table sets forth information with respect to stock options
granted on March 1, 1995 for the fiscal year ended December 31, 1995 to the
Named Executive Officers.
Option/SAR Grants in Last Fiscal Year (1995)
Number of Percent of Total
Securities Options/SARs
Underlying Granted to Exercise Grant Date
Options/SARs Employees in Price Expiration Present
Name Granted Fiscal Year ($/Sh) Date Value ($)
---- ------------- ----------------- --------- ---------- ------------
O. S. Wyatt, Jr. -0- -0- -0- -0- -0-
David A. Arledge 50,000 -0- 28.50 2/28/05 623,153
James F. Cordes 15,000 -0- 28.50 2/28/05 186,946
James A. King 10,000 -0- 28.50 2/28/05 124,631
Sam F. Willson, Jr. 10,000 -0- 28.50 2/28/05 124,631
- --------------------
Options expire ten years from the date of issuance and are granted at the fair
market value of the Common Stock of Coastal on the date of grant. Options vest
cumulatively at a rate of 20% of the option shares on each anniversary date of
the date of grant beginning with the second anniversary.
The options do not carry any stock appreciation rights.
Based on the Black-Scholes option pricing model expressed as a ratio .4373 x
exercise price x number of shares. The actual value, if any, an executive may
realize will depend on the excess of the stock price over the exercise price on
the date the option is exercised, so that there is no assurance the value
realized by an executive will be at or near the value estimated by the
Black-Scholes model. The estimated values under that model are based on
assumptions that include (i) a stock price volatility of .2343, calculated using
monthly stock prices for the three years prior to the grant date, (ii) an
interest rate of 7.4%, (iii) a dividend yield of 1.42% and (iv) an option
exercise term of ten years. No adjustments were made for the non-transferability
of the options or to reflect any risk of forfeiture prior to vesting. The
Securities and Exchange Commission ("S.E.C.") requires disclosure of the
potential realizable value or present value of each grant. Coastal's use of the
Black-Scholes model to indicate the present value of each grant is not an
endorsement of this valuation, which is based on certain assumptions, including
the assumption that the option will be held for the full ten-year term prior to
exercise. Studies conducted by Coastal's independent consultants indicate that
options are usually exercised before the end of the full ten-year term.
14
Option/SAR Exercises and Holdings
The following table sets forth information with respect to the Named
Executive Officers, concerning the exercise of options during the last fiscal
year and unexercised options and SARs held as of the fiscal year ("FY") ended
December 31, 1995.
Aggregated Option/SAR Exercises In Last Fiscal Year
And FY-End Option/SAR Values (1995)
Number of
Securities Value of
Underlying Unexercised
Unexercised In-the-Money
Options/SARs Options/SARs
at FY-End (#) at FY-End ($)
Shares Acquired Exercisable/ Exercisable/
Name on Exercise (#) Value Realized ($) Unexercisable Unexercisable
- -------------------- ----------------- --------------------- ----------------- ---------------
O. S. Wyatt, Jr. -0- -0- -0- / -0- -0- / -0-
David A. Arledge -0- -0- 222,373 / 98,000 2,501,525 / 833,300
James F. Cordes 121,787 1,036,099 16,000 / 49,000 20,000 / 414,850
James A. King -0- -0- 24,000 / 16,000 258,800 / 154,400
Sam F. Willson, Jr. 16,149 64,743 36,000 / 31,000 226,560 / 258,350
- ------------------
$-based on the market price of $37.19 at December 31, 1995.
COMPENSATION AND EXECUTIVE DEVELOPMENT COMMITTEE
REPORT ON EXECUTIVE COMPENSATION
The following report has been provided by Coastal's Compensation and
Executive Development Committee (the "Committee") of the Board of Directors in
accordance with current S.E.C. proxy statement disclosure requirements. The
members of the Committee include John M. Bissell (Chairman), Roy D. Chapin, Jr.,
and Jerome S. Katzin.
This material states Coastal's current overall compensation philosophy and
program objectives. Detailed descriptions of Coastal's compensation programs are
provided as well as the information on Coastal's 1995 pay levels for the CEO.
Overall Objectives of the Executive Compensation Program
Coastal's compensation philosophy and program objectives are directed by
two primary guiding principles. First, the program is intended to provide fully
competitive levels of compensation - at expected levels of performance - in
order to attract, motivate and retain talented executives. Second, the program
is intended to create an alignment of interests between Coastal's executives and
stockholders such that a significant portion of each executive's compensation is
directly linked to maximizing stockholder value.
In support of this philosophy, the executive compensation program is
designed to reward performance that is directly relevant to Coastal's short-term
and long-term success. As such, Coastal attempts to provide both short-term and
long-term incentive pay that varies based on corporate and individual
performance.
15
To accomplish these objectives, the Committee has structured the executive
compensation program with three primary underlying components: base salary,
annual incentives, and long-term incentives (i.e., stock options). The following
sections describe Coastal's plans by element of compensation and discuss how
each component relates to Coastal's overall compensation philosophy.
In reviewing this information, reference is often made to the use of
competitive market data as criteria for establishing targeted compensation
levels. Coastal targets the market 50th percentile for its total compensation
program and actual total compensation rates in 1995 were at or below the
targeted level. (However, Coastal's competitive pay posture varies by pay
element, as described below.) Several market data sources are used by Coastal,
including energy industry norms for the publicly traded peer companies included
in Coastal's shareholder return performance graph, as reflected in these
companies' proxy statements. In addition, we utilize published survey data and
data obtained from independent consultants that are for general industry
companies similar in size (i.e., revenues) to Coastal. The published surveys
include data on over 50 companies of comparable size to Coastal, as measured by
revenues. Greater emphasis is placed on the published data and data obtained
from consultants than on the data for proxy peers, since the published data and
consulting data are reflective of company size.
Base Salary Program
Coastal's base salary program is based on a philosophy of providing base
pay levels that fall between the market 50th and 75th percentiles. Coastal
periodically reviews its executive pay levels to assure consistency with the
external market. Generally, Coastal's actual base salary levels for 1995 for
executives as a group were consistent with the targeted percentiles. We believe
it is crucial to provide strongly competitive salaries over time in order to
attract and retain executives who are highly talented.
Annual salary adjustments for Coastal are based on several factors:
general levels of market salary increases, individual performance, competitive
base salary levels, and Coastal's overall financial results. Coastal reviews
performance qualitatively considering total shareholder returns, the level of
earnings, return on equity, return on total capital and individual business unit
performance. These criteria are assessed qualitatively and are not weighted. All
base salary increases are based on a philosophy of pay-for-performance and
perceptions of an individual's long-term value to Coastal. As a result,
employees with higher levels of performance sustained over time will be paid
correspondingly higher salaries.
The Annual Bonus Plan
Coastal's Annual Bonus Plan is intended to (1) reward key employees based
on company/business unit and individual performance; (2) motivate key employees;
and (3) provide competitive cash compensation opportunities to plan
participants. Under the plan, target award opportunities vary by individual
position and are expressed as a percent of base salary. The individual target
award opportunities, which are slightly below market median levels, are then
aggregated into a total target pool which is adjusted as described below. The
amount a particular executive may earn is directly dependent on the individual's
position, responsibility, and ability to impact our financial success.
The actual bonus pool is established each year by modifying the target
pool based on Coastal's overall performance against measures established by the
Committee. In fiscal year 1995, the key performance measure considered was
earnings before interest and taxes ("EBIT") against plan. This measure was
weighted 50% of the total bonus program. In 1995 Coastal's EBIT performance was
above threshold standards (minimum performance level for bonus payment) but
below a very aggressive plan, resulting in the EBIT portion of the bonus paid
being below target. The remaining 50% of the annual bonus opportunity in 1995 is
a discretionary annual bonus pool. As a result, no formula performance measures
were used in establishing the size of awards under this portion of the plan.
However, in establishing the size of the discretionary bonus pool, the Committee
considered Coastal's Return on Equity relative to industry peers (using the same
peers included in the shareholder return graph), Return on Total Capital
compared to industry peers, the EBIT performance of each business unit, progress
made toward improving Coastal's operational and financial performance, and the
need to reward unique individual contributions. These measures were not formally
weighted by the Committee. The size of the discretionary bonus pool element was
established above threshold but below target based on the
16
qualitative performance assessment described above. As a result, actual bonus
payments for 1995 were below target and median market levels.
Individual awards from the established bonus pool are recommended by
senior management, with advice and consent from the Committee. Individual awards
from the pool are based on business unit and individual employee performance,
future potential, and competitive considerations. All individual performance
assessments are conducted in a non-formula fashion without specific goal
weightings. The total bonus awards made may not exceed the amount of funds in
the bonus pool.
Long-Term Incentive Plan
Coastal's Long-Term Incentive Plan ("LTIP") is designed to focus executive
efforts on the long-term goals of Coastal and to maximize total return to our
shareholders. While Coastal's LTIP allows the Committee to use a variety of
long-term incentive devices, the Committee has relied solely on stock option
awards to provide long-term incentive opportunities in recent years.
Stock options align the interests of employees and shareholders by
providing value to the executive through stock price appreciation only. All
stock options have a ten-year term before expiration and are fully exercisable
within 7 years of the grant date.
Stock options were granted to the Named Executive Officers in 1995 and it
is anticipated that stock option awards will be made periodically at the
discretion of the Committee in the future. As in past years, the number of
shares actually granted to a particular participant is also based on Coastal's
financial success, its future business plans, and the individual's position and
level of responsibility within Coastal. All of these factors are assessed
subjectively and are not weighted.
1995 Chief Executive Officer Pay
As previously described, the Committee considers several factors in
developing an executive's compensation package. For the CEO, these include
competitive market practices (consistent with the philosophy described for other
executives), experience, achievement of strategic goals, and the financial
success of Coastal (considering the factors described under the annual bonus
plan above).
O. S. Wyatt, Jr.
Mr. Wyatt served as CEO through October 4, 1995 when, at his
recommendation, the Board of Directors elected Mr. Arledge to the CEO position.
Mr. Wyatt received no salary increase in 1995. The Committee took no
action regarding Mr. Wyatt's base salary, in spite of significantly improved
Coastal performance during the year. This lack of any adjustment is not a
reflection of performance; rather, it is based on considering strong input from
the Chairman, who wants to see continued improvement in shareholder returns
before receiving any base salary increase.
Mr. Wyatt's bonus for 1995 performance was $300,000 payable in 1996. This
bonus award was below targeted levels (and below market median levels) since
Coastal's aggregate performance on the measures described in the annual bonus
section of this report was below the aggressive Coastal targets.
The Committee granted no stock options to Mr. Wyatt in 1995 (consistent
with past practices), considering his strongly expressed and longstanding
opinion on this issue. Mr. Wyatt and the Committee considered Mr. Wyatt's
current level of stock ownership in reaching this decision.
17
David A. Arledge
Mr. Arledge was elected CEO on October 5, 1995. During 1995, his base
annual salary was increased to $625,000.
Mr. Arledge's bonus for 1995 was $300,000 payable in 1996. This award was
below targeted levels (and below market median levels) since Coastal's aggregate
performance on the measures described in the annual bonus section of this report
were below the aggressive Coastal targets.
The Committee granted stock options for 50,000 shares to Mr. Arledge in
1995 in recognition of his performance and as an incentive to continue his
efforts to increase shareholder value. These awards are tied to performance in
that the executive only realizes income from stock options if the stock price
rises. The grant is below market levels for the executive positions held by him.
$1 Million Pay Deductibility Cap
Under Section 162(m) of the Internal Revenue Code, public companies are
precluded from receiving a tax deduction on compensation paid to executive
officers in excess of $1 million. To address the $1 million pay deductibility
cap issue, Coastal's 1995 LTIP is structured so that stock option awards (which
are intended to be the primary long-term incentive vehicle for the present time)
qualify for an exemption from the $1 million pay deductibility limit.
Also, at the present time, the Chairman of the Board of Directors and the
CEO are the only executives whose base salary plus target bonus exceeds $1
million. In order to preserve Coastal's tax deduction for base salary plus bonus
for these individuals, Coastal has established a nonqualified deferred
compensation program. Under this program, any annual incentive awards that bring
cash compensation to a level over $1 million may be deferred so that payments
occur after the individual is no longer a Named Executive Officer, thus
preserving the deductibility of the pay for Coastal.
Compensation and Executive Development Committee
John M. Bissell, Chairman
Roy D. Chapin, Jr.
Jerome S. Katzin
18
Pension Plan
The following table shows for illustration purposes the estimated annual
benefits payable currently under the Pension Plan and Coastal's Replacement
Pension Plan described below upon retirement at age 65 based on the compensation
and years of credited service indicated.
Pension Plan Table
Years of Credited Service
--------------------------------------------------------------------
5-Year Final
Average Pay 15 Years 20 Years 25 Years 30 Years 35 Years
----------- --------------------------------------------------------------------
$ 125,000................... $ 34,133 $ 45,511 $ 56,889 $ 68,266 $ 67,518
150,000................... 41,633 55,511 69,389 83,266 82,518
175,000................... 41,633 55,511 69,389 83,266 82,518
200,000................... 41,633 55,511 69,389 83,266 82,518
225,000................... 41,633 55,511 69,389 83,266 82,518
250,000................... 41,633 55,511 69,389 83,266 82,518
300,000................... 41,633 55,511 69,389 83,266 82,518
400,000................... 41,633 55,511 69,389 83,266 82,518
450,000................... 41,633 55,511 69,389 83,266 82,518
500,000................... 41,633 55,511 69,389 83,266 82,518
(A) Compensation covered under the Pension Plan for employees of Coastal and
Coastal Replacement Pension Plan generally includes only base salary and
is limited to $150,000 for 1995.
(B) Federal legislation has reduced the benefit which may be earned due to
future service; however, benefits previously earned may not be reduced. At
December 31, 1995 each of the individuals named in the Summary
Compensation Table had covered salary for future benefit accrual of
$150,000 and the following years of credited service and pension payable
at age 65 (or current age, if over 65): Mr. Wyatt, 40 years, $461,297; Mr.
Arledge, 15 years, $56,288; Mr. Cordes, 18 years, $76,087; Mr. King, 3
years $12,141 (not vested); and Mr. Willson, 23 years, $99,715.
(C) The normal form of retirement income is a straight life annuity. Benefits
payable under the Pension Plan are subject to offset by 1.5% of applicable
monthly social security benefits multiplied by the number of years of
credited service (up to 33 1/3 years).
The Employee Retirement Income Security Act of 1974, as amended by
subsequent legislation, limits the retirement benefits payable under the
tax-qualified Pension Plan. Where this occurs, Coastal will provide to certain
executives, including persons named in the Summary Compensation Table,
additional nonqualified retirement benefits under a Coastal Replacement Pension
Plan. These benefits, plus payments under the Pension Plan, will not exceed the
maximum amount which Coastal would have been required to provide under the
Pension Plan before application of the legislative limitations, and are
reflected in the above table and footnote (B).
19
PERFORMANCE GRAPH - SHAREHOLDER RETURN ON COMMON STOCK
[GRAPH]
Five-Year Cumulative Values
$100 Invested 12/31/90
Dividends Reinvested
DOLLAR VALUE OF $100 INVESTMENT AT DECEMBER 31,
-----------------------------------------------------------------------
1990 1991 1992 1993 1994 1995
---- ---- ---- ---- ---- ----
Coastal $ 100 $ 78 $ 77 $ 91 $ 85 $ 121
S&P 500 100 130 140 154 156 215
Index 100 83 75 89 108 97
The Index is based on Value Line's Diversified Natural Gas Group - the
Performance Graph reflects total shareholder return weighted to reflect the
market capitalizations of the peer companies. The peer group is comprised of:
Arkla/NorAm, Burlington Res., Cabot, Columbia, Consolidated Nat. Gas, Eastern
Enterprises, Enron, Enserch, Equitable Res., KN Energy, Mitchell Energy,
National Fuel Gas, PanEnergy, Questar, Seagull Energy, Sonat, Southwestern
Energy, Tenneco, Valero and Williams Cos.
Coastal is excluded from the Index.
Transactions with Management and Others
In 1987, Coastal Mart, Inc. ("Coastal Mart"), a subsidiary of Coastal,
entered into a ten-year lease/purchase agreement with Pester Marketing Company
("Pester Marketing") for 220 gasoline service stations (subsequently reduced to
182 stations through disposition of assets) located in the midwestern region of
the United States. Jack Pester, a principal stockholder and Chief Executive
Officer of Pester Marketing, subsequently became an employee, officer and
director of Coastal Mart and was elected a Senior Vice President of Coastal. Mr.
Pester is no longer active in the management of Pester Marketing, and his stock
interest in that company has been placed in trust. In 1994, the lease
transaction was terminated pursuant to an agreement under which Coastal Mart
acquired ownership of and title to 175 of the gasoline service stations and
Pester Marketing retained the seven remaining stations.
During 1995 Coastal and/or its subsidiaries sold approximately 13,447,600
gallons of gasoline to Pester Marketing at prevailing market prices totaling
approximately $8,352,300.
20
The following table sets forth ownership of units of limited partnership
interests in the Coastal 1987 Drilling Program, Ltd. by directors and all
directors and executive officers as a group.
Directors Units
- --------- -----
O. S. Wyatt, Jr................................................. 750
Harold Burrow................................................... 100
David A. Arledge................................................ -
John M. Bissell................................................. -
George L. Brundrett, Jr......................................... -
Roy D. Chapin, Jr............................................... 20
James F. Cordes................................................. -
Roy L. Gates.................................................... -
Kenneth O. Johnson.............................................. -
Jerome S. Katzin................................................ -
Thomas R. McDade................................................ -
L. D. Wooddy, Jr................................................ -
All directors and executive
officers as a group (31 persons,
including the above)........................................ 890
Item 12. Security Ownership of Certain Beneficial Owners and Management.
(a) Security ownership of certain beneficial owners.
The following is information, as of March 13, 1996, on each person known
or believed by ANR Pipeline to be the beneficial owner of 5% or more of any
class of its voting securities:
Amount and Nature
Name and Address of Beneficial Percent
Title of Class of Beneficial Owner Ownership of Class
- -------------- ----------------------------------- ------------------ --------
Common Stock, American Natural Resources Company 1,000 shares direct 100%
$100 par value per share One Woodward Avenue
Detroit, Michigan 48226
(b) Security ownership of management.
ANR Pipeline is an indirect, wholly-owned subsidiary of Coastal.
Information concerning the security ownership of certain beneficial owners and
management of Coastal is contained in this section.
The total number of shares of stock of Coastal outstanding as of March 13,
1996 is 113,480,598: consisting of 61,056 shares of $1.19 Cumulative Convertible
Preferred Stock, Series A (the "Series A Preferred Stock"); 77,495 shares of
$1.83 Cumulative Convertible Preferred Stock, Series B (the "Series B Preferred
Stock"); 32,663 shares of $5.00 Cumulative Convertible Preferred Stock, Series C
(the "Series C Preferred Stock"); 8,000,000 non-voting shares of $2.125
Cumulative Preferred Stock, Series H; 104,918,785 shares of Common Stock and
390,599 shares of Class A Common Stock.
Each voting share of Common Stock or Preferred Stock entitles the holder
to one vote with respect to all matters to come before a shareholders' meeting,
while each share of Class A Common Stock entitles the holder to 100 votes.
However, 25% of Coastal's directors standing for election at each annual meeting
will be determined solely by holders of the Common Stock and voting Preferred
Stock voting as a class.
The following table sets forth information, as of March 13, 1996, with
respect to each person known or believed by Coastal to be the beneficial owner,
who has or shares voting and/or investment power (other than as set forth
below), of more than five percent (5%) of any class of its voting securities.
21
Name and Address Percent (%)
of Beneficial Owner Title of Class Number of Shares of Class
- ---------------------------- --------------------- ---------------- ------------
O. S. Wyatt, Jr. Class A Common Stock 154,577 38.2
Chairman of the Board
of Coastal
Nine Greenway Plaza
Houston, Texas 77046-0995
Trustee/Custodian under the Common Stock 13,476,985 12.8
Thrift Plan, ESOP and Class A Common Stock 71,537 17.7
Pension Plan of Coastal
and its subsidiaries
Texas Commerce Bank
National Association
600 Travis, 10th Flr.
Houston, Texas 77002
FMR Corp. Common Stock 7,475,935 7.1
82 Devonshire Street
Boston, Massachusetts 02109
Isabel H. Long Series A Preferred Stock 28,976 47.5
485 S. Parkview Ave.,
Columbus, Ohio 43209-1075
The DeZurik Family Series C Preferred Stock 32,663 100.0
c/o David DeZurik
2460 S.E. 8th St.
Pompano Beach, Florida 33062
- ----------
Class includes presently exercisable stock options held by directors and
executive officers.
Includes 7,354 shares of Class A Common Stock owned by the spouse and a son of
Mr. Wyatt, as to which shares beneficial ownership is disclaimed.
The Trustee/Custodian is the record owner of these shares; and also is the
record owner of 826 shares of the Series B Preferred Stock, each of which is
convertible into 3.6125 shares of Common Stock and 0.1 share of Class A Common
Stock. Voting instructions are requested from each participant in the Thrift
Plan and ESOP and from the trustees under a Pension Trust. Absent timely voting
instructions, the Trustee is permitted to vote Thrift Plan and ESOP shares on
any matter, but has no authority to vote Pension Plan shares. Nor does the
Trustee/Custodian have any authority to dispose of shares except pursuant to
instructions of the administrator of the Thrift Plan and ESOP or pursuant to
instructions from the trustees under the Pension Trust.
Members of the DeZurik family acquired the Series C Preferred Stock in
connection with a 1972 Agreement of Merger involving the acquisition of
Colorado, a subsidiary of Coastal.
The following table sets forth information, as of March 13, 1996,
regarding each of the current directors, including Class I directors standing
for election, and all directors and executive officers as a group. Each director
has furnished the information with respect to age, principal occupation and
ownership of shares of stock of Coastal. Messrs. Bissell, Burrow, Chapin and
Katzin are Class I directors whose terms expire in 1996; Messrs. Arledge,
Brundrett, Wooddy and Wyatt are Class II directors whose terms expire in 1997
and Messrs. Cordes, Gates, Johnson and McDade are Class III directors whose
terms expire in 1998.
22
Number of Shares
Name, (Age), Year Offices with Coastal Beneficially Percent (%)
First Became Director and/or Principal Occupation Title of Class Owned of Class*
--------------------- --------------------------- -------------- ---------------- -----------
O. S. Wyatt, Jr. Chairman of the Board Common Stock 2,866,558 2.7
(71), 1955 Class A Common Stock 154,577 38.2
Harold Burrow Vice Chairman of the Board; Common Stock 154,281
(81), 1973 Chairman of Colorado and ANR Class A Common Stock 13,603 3.4
David A. Arledge President and Common Stock 234,634
(51), 1988 Chief Executive Officer Class A Common Stock 14,396 3.6
John M. Bissell Chairman and Chief Executive Common Stock 4,576
(65), 1985 Officer of Bissell Inc. Class A Common Stock -0-
George L. Brundrett, Jr. Attorney; Former Senior Vice President Common Stock 4,910
(74), 1973 and General Counsel of Coastal Class A Common Stock 2,290
Roy D. Chapin, Jr. Former Chairman and Common Stock 3,250
(80), 1988 Chief Executive Officer Class A Common Stock -0-
of American Motors Corporation
James F. Cordes Executive Vice President; Common Stock 38,131
(55), 1985 President of ANR; Class A Common Stock -0-
President, Natural Gas Group
Roy L. Gates Retired; Ranching and Investments Common Stock 4,095
(67), 1969 Class A Common Stock 2,736
Kenneth O. Johnson Senior Vice President Common Stock 59,128
(75), 1988 Class A Common Stock 9,604 2.4
Jerome S. Katzin Retired Investment Banker Common Stock 41,803
(77), 1983 Class A Common Stock -0-
Thomas R. McDade Senior Partner, Law Firm of McDade Common Stock 500
(63), 1993 & Fogler L.L.P., Houston Class A Common Stock -0-
L. D. Wooddy, Jr. Retired; Former President of Exxon Common Stock 2,000
(69), 1992 Pipeline Company Class A Common Stock -0-
All directors and executive officers as a group Common Stock 3,985,862 3.8
(31 persons, including the above) Class A Common Stock 200,522 49.5
(See footnotes on following page)
* Less than one percent unless otherwise indicated. Class includes
outstanding shares and presently exercisable stock options held by
directors and executive officers. Excluding presently exercisable
stock options, directors and executive officers as a group would own
186,198 shares of Class A Common Stock, which would constitute 47.7%
of the shares of such class.
Except for the shares referred to in Notes 2 and 3 below, and the shares
represented by presently exercisable stock options, the holders are believed by
Coastal to have sole voting and investment power as to the shares indicated.
Amounts include shares in the Coastal ESOP and Thrift Plan, and presently
exercisable stock options held by Messrs. Burrow (14,189 shares of Common
Stock), Arledge (215,049 shares of Common Stock and 14,324 shares of Class A
Common Stock), Cordes (21,000 shares of Common Stock), and Johnson (27,848
shares of Common Stock).
Includes shares owned by the spouse and a son of Mr. Wyatt (266,595 shares of
Common Stock and 7,354 shares of Class A Common Stock), by the spouse of Mr.
Burrow (5,000 shares of Common Stock) and by
23
the spouse of Mr. Chapin (1,000 shares of Common Stock), as to which shares
beneficial ownership is disclaimed.
Includes presently exercisable stock options to purchase 677,979 shares of
Common Stock and 14,324 shares of Class A Common Stock; also includes 279,811
shares of Common Stock and 7,354 shares of Class A Common Stock owned by spouses
and children, as to which shares beneficial ownership is disclaimed. In
addition, one executive officer owns 8 shares of Series B Preferred Stock, each
of which is convertible into 3.6125 shares of Common Stock and 0.1 share of
Class A Common Stock.
No incumbent director is related by blood, marriage or adoption to another
director or to any executive officer of Coastal or its subsidiaries or
affiliates.
Except as hereafter indicated, the above table includes the principal
occupation of each of the directors during the past five years. The listed
executive officers have held various executive positions with Coastal, ANR, ANR
Pipeline and/or Colorado during the five-year period.
Mr. Bissell is a member of the Boards of Directors of Old Kent Financial
Corporation and Batts Inc.
Mr. Cordes is a member of the Board of Directors of Comerica Inc.
Mr. Katzin is a member of the Board of Directors of Qualcomm Incorporated.
Mr. McDade is a trial lawyer and the founding senior partner of the
Houston law firm of McDade & Fogler L.L.P. Prior to forming McDade & Fogler
L.L.P., he was a senior partner in the Houston law firm of Fulbright & Jaworski.
He is a member of the Board of Directors of Equity Corporation International.
Messrs. Arledge, Burrow, Cordes and Wyatt are directors of Colorado and
ANR Pipeline Messrs. Bissell and Chapin are directors of ANR Pipeline. Both of
these subsidiaries of Coastal are subject to the reporting requirements of the
Securities Exchange Act of 1934, as amended.
Item 13. Certain Relationships and Related Transactions.
(a) Transactions with management and others.
ANR Pipeline participates in a program which matches short-term cash
excesses and requirements of participating affiliates, thus minimizing
borrowings from outside sources. At December 31, 1995, the Company had advanced
$384.8 million to an associated company at a market rate of interest. Such
amount is repayable on demand.
Additional information called for by this item is set forth under Item 11,
"Executive Compensation," and Note 10 of Notes to Consolidated Financial
Statements included herein.
(b) Certain business relationships.
None.
(c) Indebtedness of management.
None.
(d) Transactions with promoters.
Not applicable.
24
PART IV
Item 14. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
(a) The following documents are filed as part of this Annual Report or
incorporated herein by reference:
1. Financial Statements.
The following Consolidated Financial Statements of ANR Pipeline
and Subsidiaries are included in response to Item 8 hereof on the
attached pages as indicated:
Page
Independent Auditors' Report................................... F-5
Consolidated Balance Sheet at December 31, 1995 and 1994....... F-6
Statement of Consolidated Earnings for the Years Ended
December 31, 1995, 1994 and 1993.......................... F-8
Statement of Consolidated Retained Earnings for the Years
Ended December 31, 1995, 1994 and 1993.................... F-8
Statement of Consolidated Cash Flows for the Years Ended
December 31, 1995, 1994 and 1993.......................... F-9
Notes to Consolidated Financial Statements..................... F-10
2. Financial Statement Schedules.
Schedules are omitted as not applicable or not required, or the
required information is shown in the Consolidated Financial
Statements or Notes thereto.
3. Exhibits.
(3.1)+ Composite Certificate of Incorporation of ANR Pipeline
effective as of December 31, 1987 (Filed as Module
ANRCertIncorp on March 29, 1994).
(3.2)+ Amended By-laws of ANR Pipeline effective as of
September 21, 1994. (Filed as Exhibit 3.2 to ANR
Pipeline's Annual Report on Form 10-K for the fiscal
year ended December 31, 1994.)
(4) With respect to instruments defining the rights of
holders of long-term debt, the Company will furnish to
the Securities and Exchange Commission any such
document on request.
(4.1)+ Board Resolution dated September 22, 1975 establishing
the $2.675 Series of Cumulative Preferred Stock (Filed
as Module BoardRes_092275 on March 29, 1994).
(4.2)+ Board Resolution dated October 26, 1976 establishing
the $2.12 Series of Cumulative Preferred Stock (Filed
as Module BoardRes_102676 on March 29, 1994).
(4.3)+ Board Resolution dated May 12, 1980 establishing the
$12.00 Series of Cumulative Preferred Stock (Filed as
Module BoardRes_051280 on March 29, 1994).
(4.4)+ Indenture dated as of February 15, 1994 and First
Supplemental Indenture dated as of February 15, 1994
for the $125 million of 7-3/8% Debentures due February
15, 2024. (Filed as Exhibit 4.4 to ANR Pipeline's
Annual Report on Form 10-K for the fiscal year ended
December 31, 1993.)
(10.1)+ Form of Employment Agreement between ANR Pipeline and
certain of its executive officers (Filed as a Module
ANREmployAgree on March 29, 1994).
25
(10.2)+ Form of Employment Agreement between Coastal and
certain Company executive officers (Filed as Module
TCCEmployAgree on March 29, 1994).
(10.3)* Agreement for Consulting Services between ANR Pipeline
and Harold Burrow, dated as of January 1, 1996.
(21)* Subsidiaries of the Company.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
- ----------------------
Note:
+ Indicates documents incorporated by reference from the prior
filings indicated.
* Indicates documents filed herewith.
(b) Reports on Form 8-K.
No reports on Form 8-K were filed during the quarter ended December 31,
1995.
26
POWER OF ATTORNEY
Each person whose signature appears below hereby appoints Coby C. Hesse,
William L. Johnson and Austin M. O'Toole and each of them, any one of whom may
act without the joinder of the others, as his attorney-in-fact to sign on his
behalf and in the capacity stated below and to file all amendments to this
Annual Report on Form 10-K, which amendment or amendments may make such changes
and additions thereto as such attorney-in-fact may deem necessary or
appropriate.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized.
ANR PIPELINE COMPANY
(Registrant)
By: JEFFREY A. CONNELLY
-----------------------------------
Jeffrey A. Connelly
President, Chief Executive
Officer and Director
March 29, 1996
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
Registrant and in the capacities and on the dates indicated.
By: JAMES F. CORDES
-----------------------------------
James F. Cordes
Chairman
March 29, 1996
By: WILLIAM L. JOHNSON
-----------------------------------
William L. Johnson
Principal Accounting Officer
March 29, 1996
By: RICHARD A. LIETZ
-----------------------------------
Richard A. Lietz
Executive Vice President,
Chief Operating Officer and Director
March 29, 1996
By: DAVID A. ARLEDGE
-----------------------------------
David A. Arledge
Principal Financial Officer and Director
March 29, 1996
By: HAROLD BURROW
-----------------------------------
Harold Burrow
Vice Chairman
March 29, 1996
By: JOHN M. BISSELL
-----------------------------------
John M. Bissell
Director
March 29, 1996
27
By: ROY D. CHAPIN, JR.
-----------------------------------
Roy D. Chapin, Jr.
Director
March 29, 1996
By: MARTHA O. HESSE
-----------------------------------
Martha O. Hesse
Director
March 29, 1996
By: J. CARLETON MACNEIL, JR.
-----------------------------------
J. Carleton MacNeil, Jr.
Director
March 29, 1996
By: O. S. WYATT, JR.
-----------------------------------
O. S. Wyatt, Jr.
Director
March 29, 1996
By: LAWRENCE P. DOSS
-----------------------------------
Lawrence P. Doss
Director
March 29, 1996
By: WILBER H. MACK
-----------------------------------
Wilber H. Mack
Director
March 29, 1996
By: JAMES H. MCNEAL, JR.
-----------------------------------
James H. McNeal, Jr.
Director
March 29, 1996
28
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
Management's Discussion and Analysis of Financial Condition and Results of
Operations includes certain forward-looking statements reflecting the Company's
expectations in the near future; however, many factors which may affect the
actual results, especially natural gas prices and changing regulations, are
difficult to predict. Accordingly, there is no assurance that the Company's
expectations will be realized.
The Notes to Consolidated Financial Statements contain information that is
pertinent to the following analysis.
Liquidity and Capital Resources
Overview. Internally generated funds have been the primary source to meet
mandatory debt and preferred stock retirements and other cash requirements of
the Company over the past three years.
On September 23, 1993, the Company filed a shelf registration statement
with the Securities and Exchange Commission for the public offering of up to
$200 million in senior unsecured debt securities, which became effective on
October 5, 1993. Subsequently, in February 1994, the Company completed an
offering of $125 million in principal amount of 7-3/8% 30-year Debentures due on
February 15, 2024. On June 1, 1995, the Company fully utilized the shelf
registration by offering $75 million in principal amount of 7% Debentures due
June 1, 2025, putable by the holders for redemption at par on June 1, 2005. The
net proceeds from the sale of the Debentures were used for the payment of common
stock dividends and for the repayment of outstanding Swiss franc bonds which
matured in October 1995. The 125 million Swiss franc bonds had a dollar
equivalence of $58.1 million and an effective interest rate of 10.7%. The
remaining net proceeds from the Debentures were added to the general funds of
the Company and were used for capital expenditures and for other general
corporate purposes.
On June 16, 1994, the Company redeemed all of the outstanding shares of
its Cumulative Preferred Stock. For additional information regarding this
matter, see Note 2 of Notes to Consolidated Financial Statements included
herein.
The Company uses the following consolidated ratios to measure liquidity
and ability to meet future funding needs and debt service requirements.
1995 1994 1993
--------- -------- ---------
Cash flows from operating activities to long-term debt
and capital lease obligations.......................................... 42.5% 56.3% 66.0%
Long-term debt and capital lease obligations to total capitalization.... 35.9% 35.7% 27.3%
The decreases in 1995 and 1994 in the ratio of cash flows from operating
activities to long-term debt and capital lease obligations resulted from an
increase in long-term debt due to the issuance of $75 million and $125 million
of Debentures in 1995 and 1994, respectively, as discussed above. A reduction in
accounts payable in 1995 also contributed to the decrease. The ratio of
long-term debt and capital lease obligations to total capitalization in 1995
approximated that of 1994, due to the increase in long-term debt being offset by
an increase in retained earnings during 1995. The increase in 1994 in the ratio
of long-term debt and capital lease obligations to total capitalization resulted
from issuance of long-term debt and a decrease in retained earnings resulting
from dividends paid.
Management believes that the Company's stable financial position and
earnings ability will enable it to continue to generate and obtain capital for
financing needs in the foreseeable future.
Expenditures for each of the years 1993 through 1995 and the sources of
capital used to finance these expenditures are summarized in the "Statement of
Consolidated Cash Flows."
F-1
Capital Expenditures. Capital expenditures were $48.1 million in 1995 and
$62 million in 1994. Capital expenditures for 1996 are currently budgeted at $71
million.
Funding for certain proposed natural gas pipeline projects is anticipated
to be provided through nonrecourse financings in which the projects' assets and
contracts will be pledged as collateral. Equity participation by other entities
will also be considered. To the extent required, cash for equity contributions
to projects will be from general corporate funds. Financing for the remaining
budgeted expenditures in 1996 will be accomplished by the use of internally
generated funds. Information concerning certain of these projects is contained
in Part I herein under Item 1, "Business - Other Developments."
Financing Alternatives. Alternatives to finance additional capital and
other expenditures are limited principally by the terms of certain debt
instruments of the Company and certain affiliates. Under the most restrictive of
such instruments, as of December 31, 1995, ANR Pipeline and certain affiliates
could incur in the aggregate approximately $765 million of additional
indebtedness. For the Company and these affiliates to incur indebtedness for
borrowed money in excess of this amount, $200 million of indebtedness of Coastal
Natural Gas would need to be retired.
The Company participates in a program which matches short-term cash
excesses and requirements of participating affiliates, thus minimizing
borrowings from outside sources. At December 31, 1995, the Company had advanced
$384.8 million to an associated company at a market rate of interest. Such
amount is repayable upon demand.
Environmental. The Company's operations are subject to extensive and
evolving federal, state and local environmental laws and regulations which may
affect such operations and costs as a result of their effect on the
construction, operation and maintenance of its pipeline facilities. The Company
spent approximately $.6 million in 1995 on environmental capital projects and
anticipates annual capital expenditures of $2.8 million per year over the next
several years aimed at maintaining compliance with such laws and regulations.
Additionally, appropriate governmental authorities may enforce the laws and
regulations with a variety of civil and criminal enforcement measures, including
monetary penalties and remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as Superfund, as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." The Company has been named as a potentially responsible party in
five Superfund waste disposal sites. At these sites, the EPA has developed
sufficient information to estimate total cleanup costs of approximately $45.1
million and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $.9 million. At a sixth site, the
Company had been named a de minimis potentially responsible party and has
settled the claim for approximately $20,000.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. The states have regulatory programs that mandate
waste cleanup. The Clean Air Act Amendments of 1990 include new permitting
regulations which will result in increased operating expenditures.
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, consolidated
financial position or results of operations.
Results of Operations
On April 8, 1992 the FERC issued Order 636 which required significant
changes in the services provided by interstate natural gas pipelines (see Note 6
of Notes to Consolidated Financial Statements included herein). The intent of
Order 636 is to insure that interstate pipeline transportation services are
equal in quality for all gas supplies, whether the buyer purchases gas from the
pipeline or from any other gas supplier. The FERC amended its regulations to
require the use of the straight fixed variable ("SFV") rate setting methodology.
In general, SFV provides that all fixed costs of providing service to firm
customers (including an authorized return on rate base and associated taxes) are
to be received
F-2
through fixed monthly reservation charges, which are not a function of volumes
transported, while including within the commodity billing component the
pipeline's variable operating costs. In addition, Order 636 has resulted in the
incurrence of transition costs. However, Order 636 provides mechanisms for the
recovery of such costs within a reasonable time period.
ANR Pipeline placed its restructured services under Order 636 into effect
on November 1, 1993. The Company now offers a wide range of "unbundled" storage,
transportation, and balancing services, primarily in the Midwest and
increasingly in the Northeast regions of the United States. The Midwest region
is continuing to experience intensified competition due to excess pipeline
capacity, and as a result, capacity is trading at artificially low rates because
of remarketing of capacity at discounted rates by customers. The Company
believes this excess pipeline capacity will lessen by the end of the decade as
demand for natural gas grows and competitors convert or retire underutilized
assets. Although the Company's transportation capacity is currently sold out in
this region, the Company has instituted reengineering projects and cost-cutting
efforts, which included an early retirement incentive program in 1995, in order
to remain competitive in the Midwest region. For additional information
regarding the early retirement incentive program, see Note 9 of Notes to
Consolidated Financial Statements included herein.
As a result of Order 636, the Company no longer offers merchant services
and has bought out or assigned a significant portion of its gas purchase
contracts. The Company is continuing to negotiate the termination of the
remaining gas purchase contract obligations. In 1995 and 1994, gas sales
revenues reflect amounts related to the auctioning of gas in producing areas
acquired under these remaining gas purchase contracts, in addition to purchased
gas adjustment recoveries from customers associated with purchase periods prior
to Order 636. The Company's Order 636 restructured tariff provides mechanisms
for the purpose of recovering from its transportation customers any pricing
differential between costs incurred to purchase gas under these contracts and
the amounts recovered through the auctioning of such gas. While operating
revenues have been reduced as a result of the implementation of Order 636,
purchases and other related costs have also been reduced by a similar amount,
thereby having minimal net impact on earnings.
Revenues. Storage and transportation revenues decreased by $3.5 million in
1995 as compared to 1994. The primary factor contributing to the decrease was
lower storage and transportation revenues of $14.7 million resulting from
continued, intensified competition across the United States natural gas
industry, particularly in the Midwest region in which the Company operates, as
discussed above. The decrease in storage and transportation revenues is
partially offset by an increase in contract settlements of $10.6 million.
Provisions for regulatory matters were $37 million and $37.6 million in 1995 and
1994, respectively.
Storage and transportation revenues increased by $71.6 million in 1994 as
compared to 1993. The primary factor contributing to the increase was revenues
associated with cost recovery mechanisms related to above market gas purchases
and certain transportation services provided by others, which were offset by
amounts included in cost of gas and operation and maintenance. Revenues have
been reduced in 1994 by provisions for regulatory matters.
Gas sales revenues decreased by $46.9 million in 1995 as compared to 1994
primarily due to a decrease of $37 million related to a reduction in the
quantity of gas auctioned on the open market, as discussed above. Lower spot
market prices also resulted in a decrease in revenues of $7.8 million.
Gas sales revenues declined significantly in 1994 as compared to 1993 as a
result of the elimination of the Company's merchant services, as discussed
above.
Other revenues increased by $29 million in 1995 as compared to 1994. This
increase includes increased interest income from a related party of $11.2
million and adjustments to revenue reserves associated with certain transition
cost recovery mechanisms of $8.7 million.
Cost of Gas. Cost of gas decreased by $27.3 million in 1995 as compared to
1994. Cost of gas includes purchases required under certain remaining gas
purchase contracts and the amortization of purchased gas adjustment recoveries
from customers. The variance primarily results from a decrease of $43.8 million
due to reductions in the quantity of gas purchased under the Company's remaining
gas purchase contracts. This decrease in cost was partially offset by an
F-3
increase in the amortization of previously deferred costs associated with above
market gas purchases of $19.2 million, partially as a result of the
implementation of the FERC's policy governing the order of attribution of
revenues received by the Company related to transition costs under Order 636
(see Note 6 of Notes to Consolidated Financial Statements).
Cost of gas significantly declined during 1994, as compared to 1993,
primarily as a result of the elimination of the Company's merchant services, as
discussed above.
Operation and Maintenance. Operation and maintenance expenses decreased by
$4.1 million in 1995 as compared to 1994. The decrease primarily results from a
reduction of $13 million in storage and transportation services provided by
others, partially offset by an $8.3 million benefit included in 1994 related to
revisions of certain estimated costs.
Operation and maintenance expenses decreased by $17.8 million in 1994 as
compared to 1993. This decrease was largely due to a $19.2 million reduction in
transportation services provided by others and a $7.2 million reduction in costs
associated with maintenance of pipeline and compressor station facilities. This
decrease was partially offset by a $6.9 million increase in benefit costs
related to the required adoption of FAS Nos. 106 and 112. The variance also
includes an additional benefit in 1993 of $7.4 million related to revisions of
certain estimated costs.
Interest Expense. Interest expense increased by $5.9 million in 1995 as
compared to 1994 largely due to an increase in expense associated with changes
in provisions for regulatory matters.
Recent Pronouncement of the FASB
The FASB has issued FAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of" ("FAS No. 121"),
to be effective in 1996. The provisions of this statement require the Company to
review long-lived assets and certain identifiable intangibles for impairment
whenever events or changes in circumstances indicate that the carrying amount of
an asset may not be recoverable. FAS No. 121 also requires that a rate-regulated
enterprise recognize an impairment for an amount of costs that a regulator
excludes from the enterprise's allowable costs. If it is determined that an
impairment has occurred, the amount of the impairment should be charged to
earnings. The application of the new standard is not expected to have a material
effect on the Company's consolidated financial position or results of operations
in 1996.
F-4
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholder
ANR Pipeline Company
Detroit, Michigan
We have audited the accompanying consolidated balance sheets of ANR
Pipeline Company (an indirect, wholly-owned subsidiary of The Coastal
Corporation) and subsidiaries as of December 31, 1995 and 1994, and the related
consolidated statements of earnings, retained earnings and cash flows for each
of the three years in the period ended December 31, 1995. These financial
statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of ANR Pipeline Company and
subsidiaries as of December 31, 1995 and 1994, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 1995, in conformity with generally accepted accounting principles.
DELOITTE & TOUCHE LLP
Detroit, Michigan
February 1, 1996
F-5
ANR PIPELINE COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
December 31,
----------------------
1995 1994
---------- ---------
ASSETS
Property, Plant and Equipment, at cost................................................... $ 3,468.5 $ 3,421.3
Less - Accumulated depreciation....................................................... 2,273.0 2,226.1
---------- ---------
1,195.5 1,195.2
---------- ---------
Current Assets:
Cash and cash equivalents............................................................. 22.9 22.0
Note receivable from related party.................................................... 384.8 235.2
Accounts receivable:
Others............................................................................. 73.5 65.4
Related parties.................................................................... 14.0 23.5
Materials and supplies, at average cost............................................... 34.4 41.1
Other................................................................................. .6 .8
---------- ---------
530.2 388.0
---------- ---------
Other Assets:
Assets related to excess gas supply................................................... 78.3 90.8
Investment in pipeline partnerships................................................... 35.2 41.2
Order 636 transition costs............................................................ 127.6 39.9
Deferred charges and other............................................................ 73.8 103.5
---------- ---------
314.9 275.4
---------- ---------
$ 2,040.6 $ 1,858.6
========== =========
See Notes to Consolidated Financial Statements.
F-6
ANR PIPELINE COMPANY AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
December 31,
----------------------
1995 1994
---------- ---------
STOCKHOLDER'S EQUITY AND LIABILITIES
Common Stock and Other Stockholder's Equity:
Common stock, $100 par value, authorized, issued and
outstanding 1,000 shares........................................................... $ .1 $ .1
Additional paid-in capital............................................................ 466.2 466.2
Retained earnings..................................................................... 443.4 322.2
---------- ---------
909.7 788.5
---------- ---------
Long-Term Debt and Capital Lease Obligations............................................. 509.3 437.0
---------- ---------
Current Liabilities:
Maturities of long-term debt and capital lease
obligations........................................................................ 3.0 61.1
Accounts payable:
Others............................................................................. 131.0 168.8
Related parties.................................................................... 6.0 7.4
Taxes on income....................................................................... ( 14.0) 2.5
Other taxes........................................................................... 21.5 23.9
Provision for regulatory matters...................................................... 79.2 38.1
Other................................................................................. 30.4 28.6
---------- ---------
257.1 330.4
---------- ---------
Deferred Credits and Other:
Accumulated deferred income taxes..................................................... 223.0 229.2
Other................................................................................. 141.5 73.5
---------- ---------
364.5 302.7
---------- ---------
$ 2,040.6 $ 1,858.6
========== =========
See Notes to Consolidated Financial Statements.
F-7
ANR PIPELINE COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED EARNINGS
(Millions of Dollars)
Year Ended December 31,
-----------------------------------
1995 1994 1993
--------- ---------- ---------
Revenues:
Storage and transportation:
Others................................................................ $ 695.5 $ 689.0 $ 620.9
Related parties....................................................... 7.3 17.3 13.8
Gas sales:
Others................................................................ 21.4 23.9 582.8
Related parties....................................................... 37.8 82.2 20.7
Other revenues:
Others................................................................ 25.7 12.1 17.5
Related parties....................................................... 33.0 17.6 16.1
--------- ---------- ---------
820.7 842.1 1,271.8
--------- ---------- ---------
Costs and Expenses:
Operation and maintenance:
Others................................................................ 275.6 277.3 299.8
Related parties....................................................... 100.1 102.5 97.8
Cost of gas:
Others................................................................ 96.9 108.6 469.0
Related parties....................................................... - 15.6 70.6
Depreciation and amortization............................................ 50.6 50.5 46.6
Interest expense......................................................... 59.4 53.5 50.8
Taxes on income.......................................................... 86.8 82.0 80.2
--------- ---------- ---------
669.4 690.0 1,114.8
--------- ---------- ---------
Net Earnings................................................................ $ 151.3 $ 152.1 $ 157.0
========= ========== =========
STATEMENT OF CONSOLIDATED RETAINED EARNINGS
(Millions of Dollars)
Year Ended December 31,
-----------------------------------
1995 1994 1993
--------- ---------- ---------
Balance - Beginning of Year................................................. $ 322.2 $ 503.0 $ 383.7
Net Earnings................................................................ 151.3 152.1 157.0
Preferred Stock Redemption Premium Adjustment............................... - ( .3) -
Dividends:
Common stock............................................................. ( 30.1) ( 331.0) ( 33.7)
Preferred stock.......................................................... - ( 1.6) ( 4.0)
--------- ---------- ---------
Balance - End of Year....................................................... $ 443.4 $ 322.2 $ 503.0
========= ========== =========
See Notes to Consolidated Financial Statements.
F-8
ANR PIPELINE COMPANY AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
Year Ended December 31,
--------------------------------
1995 1994 1993
-------- -------- --------
Cash Flows from Operating Activities:
Net earnings................................................................ $ 151.3 $ 152.1 $ 157.0
Adjustments to reconcile net earnings to net cash provided by operating
activities:
Depreciation and amortization............................................ 53.2 52.9 48.6
(Decrease) increase in deferred income taxes............................. ( 6.2) 12.4 31.5
Increase (decrease) in provision for regulatory matters.................. 41.1 35.7 ( 4.5)
Producer contract reformation cost recoveries............................ 28.9 29.9 47.1
Provision for producer settlements....................................... .6 - ( 5.1)
Equity in earnings of pipeline partnerships.............................. ( 7.0) ( 5.3) ( 6.5)
Changes in other assets and liabilities affecting operating activities:
(Increase) decrease in accounts receivable:
Others................................................................ ( 8.1) 7.8 7.2
Related parties....................................................... 9.5 ( 14.2) 8.9
Decrease in gas in underground storage................................... - - 67.4
(Decrease) increase in accounts payable and other accruals:
Others................................................................ ( 55.0) 11.6 ( 56.0)
Related parties....................................................... ( 1.4) ( 5.9) ( 17.6)
Net increase (decrease) in other assets/liabilities...................... 9.3 ( 30.8) ( 31.1)
-------- -------- --------
Total adjustments..................................................... 64.9 94.1 89.9
-------- -------- --------
Net cash provided by operating activities............................. 216.2 246.2 246.9
-------- -------- --------
Cash Flows from Investing Activities:
(Increase) decrease in note receivable from related party................... ( 149.6) 50.3 ( 58.0)
Gas supply settlements and prepayments...................................... ( 1.4) - ( 4.3)
Recovery of gas supply prepayments.......................................... .2 .3 24.9
Capital expenditures........................................................ ( 48.1) ( 62.0) ( 49.4)
-------- -------- --------
Net cash used in investing activities................................. ( 198.9) ( 11.4) ( 86.8)
-------- -------- --------
Cash Flows from Financing Activities:
Net proceeds from issuance of long-term debt................................ 74.6 123.0 -
Retirement of long-term debt and capital lease obligations.................. ( 60.9) ( 2.9) ( 81.3)
Redemptions and early retirement of preferred stock......................... - ( 34.0) ( 10.2)
Common stock dividends paid................................................. ( 30.1) ( 331.0) ( 33.7)
Preferred stock dividends paid.............................................. - ( 1.8) ( 4.1)
-------- -------- --------
Net cash used in financing activities................................. ( 16.4) ( 246.7) ( 129.3)
-------- -------- --------
Net Increase (Decrease) in Cash and Cash Equivalents........................... .9 ( 11.9) 30.8
Cash and Cash Equivalents at Beginning of Period............................... 22.0 33.9 3.1
-------- -------- --------
Cash and Cash Equivalents at End of Period..................................... $ 22.9 $ 22.0 $ 33.9
======== ======== ========
See Notes to Consolidated Financial Statements.
F-9
ANR PIPELINE COMPANY AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. Summary of Significant Accounting Policies
- - Basis of Presentation
ANR Pipeline is a subsidiary of ANR, which is a direct subsidiary of
Coastal Natural Gas and an indirect subsidiary of Coastal. The financial
statements presented herewith are presented on the basis of historical cost and
do not reflect the basis of cost to Coastal Natural Gas. The preparation of
these financial statements, in conformity with generally accepted accounting
principles, requires estimates and assumptions that affect the reported amounts
of assets and liabilities and the reported amounts of revenues and expenses.
Actual results could differ from the estimates and assumptions used.
The Company is subject to the regulations and accounting procedures of the
FERC. The Company meets the criteria and, accordingly, follows the reporting and
accounting requirements of FAS No. 71, "Accounting for the Effects of Certain
Types of Regulation" ("FAS No. 71"). This statement provides that rate-regulated
public utilities account for and report assets and liabilities consistent with
the economic effect of the way in which regulators establish rates, if the rates
established are designed to recover the costs of providing the regulated service
and if the competitive environment makes it reasonable to assume that such rates
can be charged and collected. Although the accounting methods for companies
subject to rate regulation may differ from those used by non-regulated
companies, the accounting methods prescribed by the regulatory authority conform
to the generally accepted accounting principle of matching costs with the
revenue to which they apply.
Transactions which the Company has recorded differently than a
non-regulated entity include the following: the Company (i) has capitalized the
cost of equity funds used during construction, and, (ii) has deferred purchase
gas costs, contract reformation costs, postemployment/postretirement benefit
costs and income tax reductions related to changes in federal income tax rates.
These items are being, or are anticipated to be, recovered or refunded in rates
chargeable to customers.
The Company has applied FAS No. 71 and evaluates the applicability of
regulatory accounting and the recoverability of those assets through rate or
other contractual mechanisms on an ongoing basis. If FAS No. 71 accounting
principles should no longer be applicable to the Company's operations, an amount
would be charged to earnings as an extraordinary item. At December 31, 1995,
this amount was approximately $156 million, net of income taxes. The Company
does not expect that its cash flows would be affected by discontinuing
application of FAS No. 71. Any potential charge to earnings would be noncash and
would have no direct effect on either the Company's ability to include the
underlying deferred items in future rate proceedings or on its ability to
collect the rates set thereby.
- - Reclassifications
Certain reclassifications of prior period statements have been made to
conform with current reporting practices. The effect of these reclassifications
was not material to the Company's consolidated financial position or results of
operations.
- - Principles of Consolidation
The consolidated financial statements include the accounts of the Company
and its wholly-owned subsidiaries, after eliminating all significant
intercompany transactions. The equity method of accounting is used for
investments in which the Company has a 20% to 50% continuing interest and
exercises significant influence. The equity method has also been used in 1995
for an investment in a limited partnership in which the Company has an interest
of more than 5%.
F-10
- - Depreciation of Gas Plant
The Company's annual provisions for depreciation of gas plant are computed
on a straight-line basis using rates of depreciation which vary by type of
property. The annual composite depreciation rate for 1993 through 1995 was
approximately 1.7%. The determination of book depreciation useful lives and the
resulting depreciation rates are consistent with the policies and practices
normally followed under generally accepted accounting principles. A calculation
of the cumulative effect on recorded depreciation resulting from the use of
recovery periods for regulatory purposes different from the estimated useful
lives absent regulation has not been prepared.
Costs of minor property units (or components thereof) retired or abandoned
are charged or credited, net of salvage, to accumulated depreciation. Gain or
loss on sales of major property units is credited or charged to income.
The FASB has issued FAS No. 121 to be effective in 1996. The provisions of
this statement require the Company to review long-lived assets and certain
identifiable intangibles for impairment whenever events or changes in
circumstances indicate that the carrying amount of an asset may not be
recoverable. FAS No. 121 also requires that a rate-regulated enterprise
recognize an impairment for the amount of costs that a regulator excludes from
the enterprise's allowable costs. If it is determined that an impairment has
occurred, the amount of the impairment should be charged to earnings. The
application of the new standard is not expected to have a material effect on the
Company's consolidated financial position or results of operations in 1996.
- - Income Taxes
The Company is a member of a consolidated group which files a consolidated
federal income tax return. Members of the consolidated group with taxable
incomes are charged with the amount of income taxes as if they filed separate
federal income tax returns, and members providing deductions and credits which
result in income tax savings are allocated credits for such savings.
- - Statement of Cash Flows
For purposes of these financial statements, cash equivalents include time
deposits, certificates of deposit and all highly liquid instruments with
original maturities of three months or less. The Company made cash payments for
interest, net of interest capitalized, of $55.7 million, $50.2 million and $53.0
million in 1995, 1994 and 1993, respectively. Cash payments for income taxes
amounted to $110.4 million, $54.9 million and $103.2 million in 1995, 1994 and
1993, respectively.
- - Allowance for Funds Used During Construction
In accordance with the accounting requirements of the FERC, an allowance
for equity and borrowed funds used during construction is included in the cost
of the Company's major additions to gas plant. These costs amounted to $1.2
million in each of the years 1995 and 1994 and $1.5 million in 1993.
- - Nature of Operations and Concentrations of Credit Risk
ANR Pipeline is involved in the transportation, storage and balancing of
natural gas primarily in the Midwest and increasingly in the Northeast regions
of the United States. The Company operates under arrangements with other
companies including distributors, intrastate and interstate pipelines,
producers, brokers, marketers and end-users. As a result, the Company has a
concentration of receivables due from these customers. This may affect the
Company's overall credit risk in that the customers may be similarly affected by
changes in economic, regulatory and other factors. Trade receivables are
generally not collateralized; however, the Company analyzes customers' credit
positions prior to extending credit.
2. Common Stock and Other Stockholder's Equity
All of ANR Pipeline's common stock is owned by ANR.
F-11
On June 16, 1994, the Company redeemed all outstanding shares of its
Cumulative Preferred Stock. A $328,000 premium paid in excess of par value to
redeem the remaining outstanding preferred stock was charged directly to
retained earnings in accordance with FERC accounting procedures.
3. Long-Term Debt
Balances at December 31 were as follows (millions of dollars):
1995 1994
-------- --------
Debentures:
9-5/8% series, due 2021.......................................................... $ 300.0 $ 300.0
7-3/8% series, due 2024.......................................................... 125.0 125.0
7% series, due 2025.............................................................. 75.0 -
Unsecured Debt:
Swiss Franc Bonds due 1995*...................................................... - 58.1
Unamortized discount related to outstanding debt, net of premium.................... ( 2.3) ( 2.4)
-------- --------
497.7 480.7
Less maturities .................................................................... - 58.1
-------- --------
$ 497.7 $ 422.6
======== ========
* In October 1995, the Company retired its 6%, 125 million Swiss franc
bonds at a U.S. dollar equivalence of $58.1 million. The foreign
currency swap agreements, entered into by the Company to manage the
foreign exchange exposure related to these bonds, also matured
concurrent with the retirement of this debt.
None of the above debt issuances have maturity or sinking fund
requirements prior to their retirement due dates.
Alternatives to finance additional capital and other expenditures are
limited principally by the terms of certain debt instruments of the Company and
certain affiliates. Under the most restrictive of such instruments, as of
December 31, 1995, ANR Pipeline and certain affiliates could incur in the
aggregate approximately $765 million of additional indebtedness. For the Company
and these affiliates to incur indebtedness for borrowed money in excess of this
amount, $200 million of indebtedness of Coastal Natural Gas would need to be
retired.
4. Value of Financial Instruments
The estimated fair value amounts of the Company's financial instruments
have been determined by the Company, using appropriate market information and
valuation methodologies. Considerable judgment is required to develop the
estimates of fair value, thus, the estimates provided herein are not necessarily
indicative of the amounts that the Company could realize in a current market
exchange.
F-12
December 31, 1995 December 31, 1994
-------------------------- -------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
------------ ----------- ------------ ---------
(Millions of dollars)
Nonderivatives:
Financial assets:
Cash and cash equivalents................... $ 22.9 $ 22.9 $ 22.0 $ 22.0
Marketable security of a related party...... 2.0 2.1 2.0 2.1
Note receivable from a related party........ 384.8 384.8 235.2 235.2
Financial liabilities:
Long-term debt.............................. 500.0 589.5 522.6 511.4
Derivatives relating to long-term debt:
Foreign currency swap gains................... - - ( 39.5) ( 39.5)
The estimated fair value of the marketable security of a related party is
based on market quotes at December 31, 1995 and 1994, respectively, and is
included under "Deferred charges and other" assets. The note receivable from a
related party is at a floating market rate of interest and therefore, the
carrying amount is a reasonable estimate of its fair value. The estimated values
of the Company's long-term debt are based on interest rates at December 31, 1995
and 1994, respectively, for new issues with similar remaining maturities. The
fair market values of the Company's foreign currency swaps, which matured in
October 1995, were based on the estimated termination values at December 31,
1994.
5. Take-or-Pay Obligations
"Assets related to excess gas supply" consists of $78.3 million and $90.8
million at December 31, 1995 and 1994, respectively, relating to prepayments for
gas under gas purchase contracts with producers and settlement payment amounts
relative to the restructuring of gas purchase contracts as negotiated with
producers. Currently, FERC regulations allow for the billing of a portion of the
costs of take-or-pay settlements and renegotiating gas purchase contracts.
Prepayments are normally recoupable through future deliveries of natural gas.
Contract reformation costs incurred as a result of the mandated Order 636
restructuring will be recovered under the transition cost mechanisms of Order
636, as well as through negotiated agreements with the Company's customers. The
Company believes that these mechanisms provide adequate coverage for such costs.
Several producers have instituted litigation arising out of take-or-pay
claims against the Company. In the Company's experience, producers' claims are
generally vastly overstated and do not consider all adjustments provided for in
the contract or allowed by law. The Company has resolved the majority of the
exposure with its suppliers for approximately 13% of the amounts claimed. At
December 31, 1995, the Company estimated that unresolved asserted and unasserted
producers' claims were negligible.
At December 31, 1995, the Company was committed to make future purchases
under certain take-or-pay contracts with fixed, minimum or escalating price
provisions. Based on contracts in effect at that date, and before considering
reductions provided in the contracts or applicable law, such commitments are
estimated to be $17 million and $11 million for the years 1996 and 1997,
respectively, and $1 million thereafter. Such commitments have also not been
adjusted for all amounts which may be assigned or released, or for the results
of future litigation or negotiation with producers.
The Company has made provisions, which it believes are adequate, for
payments to producers that may be required for settlement of take-or-pay claims
and restructuring of future contractual commitments. In determining the net loss
relating to such provisions, the Company has also made accruals for the
estimated portion of such payments which would be recoverable pursuant to
FERC-approved settlements with customers. Such provisions and accruals were not
material to the Company for the years 1995, 1994 and 1993.
F-13
6. Litigation, Environmental and Regulatory Matters
- - Litigation
Numerous 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 such 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.
- - Environmental
The Company's operations are subject to extensive and evolving federal,
state and local environmental laws and regulations which may affect such
operations and costs as a result of their effect on the construction, operation
and maintenance of its pipeline facilities. The Company spent approximately $.6
million in 1995 on environmental capital projects and anticipates annual capital
expenditures of $2.8 million per year over the next several years aimed at
maintaining compliance with such laws and regulations. Additionally, appropriate
governmental authorities may enforce the laws and regulations with a variety of
civil and criminal enforcement measures, including monetary penalties and
remediation requirements.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as Superfund, as reauthorized, imposes liability, without regard to
fault or the legality of the original act, for disposal of a "hazardous
substance." The Company has been named as a potentially responsible party in
five Superfund waste disposal sites. At these sites, the EPA has developed
sufficient information to estimate total cleanup costs of approximately $45.1
million and the Company estimates its pro-rata exposure, to be paid over a
period of several years, is approximately $.9 million. At a sixth site, the
Company had been named a de minimis potentially responsible party and has
settled the claim for approximately $20,000.
There are additional areas of environmental remediation responsibilities
which may fall on the Company. The states have regulatory programs that mandate
waste cleanup. The Clean Air Act Amendments of 1990 include new permitting
regulations which will result in increased operating expenditures.
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, consolidated
financial position or results of operations.
- - Regulatory Matters
On March 10, 1992, the Company 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 the
Company's implementation of Order 636 on November 1, 1993. Under the Interim
Settlement, gas inventory demand charges were collected from the Company'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
the Company at risk for under-collections. As required by the Interim
Settlement, the Company 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 the Company's refund allocation
methodology, and directed the Company 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. The Company 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
F-14
refund allocation methodology. Briefs have been filed, and oral argument is
scheduled for April 12, 1996.
On April 8, 1992, the FERC issued Order 636, which required significant
changes in the services provided by interstate natural gas pipelines. 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. ANR Pipeline placed its
restructured services under Order 636 into effect on November 1, 1993. As a
result, the Company no longer provides merchant services and now offers a wide
range of "unbundled" transportation, storage and balancing services. However,
the Company still purchases a residual quantity of gas under certain remaining
gas purchase contracts. The Company'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 the Company 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 the Company'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, the Company 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, the Company
filed revised tariff sheets on July 18, 1994, which were accepted by order
issued April 12, 1995.
On November 1, 1993, the Company 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
in the cost of service from that approved in the Interim Settlement and a $182.8
million increase over the Company's approved rates for its restructured services
under Order 636. The Company sought rehearing of various aspects of the order.
Further, on April 29, 1994, the Company 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 the Company'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. The Company 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 the Company on March 10,
1995, and was accepted by order issued May 3, 1995, subject to one additional
compliance filing requirement, which the Company 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, the Company 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 the Company's rate proceeding that apply a new policy governing the order of
attribution of revenues received by the Company related to transition costs
under Order 636. Under that new policy, the Company 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 the
Company 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 the Company's
currently effective maximum rates and has accelerated its amortization of
transition costs. In light of the FERC's policy, the Company has filed with the
FERC to increase its discount recovery adjustment in its pending rate
proceeding. The Company 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 the Company'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 the
Company 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 the Company's obligations under certain
gas
F-15
purchase and transportation contracts with the Plant. The Settlement Agreement
resolves all disputes between the parties, amends the gas purchase agreement
between the Company and Dakota and terminates the transportation contract. The
Settlement Agreement is subject to final FERC approval, including an approval
for the Company to recover the settlement costs from its customers. On August 3,
1994, the Company 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 the Company's petition with similar
petitions of three other pipeline companies. Hearings were held before the FERC
Administrative Law Judge ("ALJ") on the prudence of the Settlement Agreement,
and on December 29, 1995, the ALJ issued an Initial Decision rejecting the
proposed Settlement Agreement. In the Initial Decision, the ALJ also determined
the level of Dakota costs that ANR Pipeline and the other pipeline companies
would be permitted to recover from their customers beginning as of May 1993.
Because the ALJ determined that the appropriate level of costs is less than the
amounts ANR Pipeline has billed to its customers since May 1993 under the ALJ's
decision, ANR Pipeline may be required to refund to its customers the excess
amounts collected. At December 31, 1995, that refund amount would be
approximately $70 million, plus interest. It is ANR Pipeline's position that the
Settlement Agreement is prudent and that the FERC has no lawful authority to
order refunds for past periods, but even if refunds were ultimately found to be
lawful, ANR Pipeline should not lawfully be required to refund amounts in excess
of the refund amounts it collects from Dakota. ANR Pipeline has filed with the
FERC seeking reversal of the Initial Decision, and approval of the Settlement
Agreement.
Order 636 provides mechanisms for recovery of transition costs associated
with compliance with that Order. The Company's transition costs consist
primarily of gas supply realignment costs and pricing differential costs. As of
December 31, 1995, the Company incurred transition costs in the amount of $54
million. In addition, the Company 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. The Company has filed for
recovery of approximately $44.5 million of incurred transition costs, of which
$42.7 million has been accepted by the FERC for recovery, subject to refund and
further proceedings. Of the $42.7 million accepted by the FERC, $28.6 million
has been settled with the parties to the respective FERC proceedings. Additional
transition cost filings will be made by the Company in the future.
Certain of the above regulatory matters and other regulatory issues remain
unresolved among the Company, its customers, its suppliers and the FERC. The
Company has made provisions which represent management's assessment of the
ultimate resolution of the above 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.
7. Lease Commitments
The Company is the lessee of eight storage fields under capital leases.
The storage field leases expire on May 1, 2003. However, the Company has the
option to extend each of the leases for up to two successive five-year periods.
The net present value of the future minimum lease payments is included as part
of "Property, Plant and Equipment" in the Company's Consolidated Balance Sheet
as follows (millions of dollars):
December 31,
--------------------
1995 1994
--------- ---------
Storage property................................................ $ 122.1 $ 121.9
Less: Accumulated depreciation................................. 107.5 104.5
--------- ---------
$ 14.6 $ 17.4
========= =========
The annual provision for depreciation included as a part of depreciation
and amortization expense was $3 million for 1995, 1994 and 1993.
F-16
Future minimum lease payments under capital leases together with the
present value of the net minimum lease payments as of December 31, 1995 are as
follows (millions of dollars):
Year ending December 31:
1996................................................ $ 9.4
1997................................................ 8.8
1998................................................ 8.1
1999................................................ 7.5
2000................................................ 6.5
2001 through 2003................................... 10.7
------
Total minimum lease payments........................ 51.0
Less: Amount representing executory costs.......... 15.0
------
Net minimum lease payments.......................... 36.0
Less: Amount representing interest................. 21.4
------
Present value of net minimum lease payments......... $ 14.6
======
Operating lease rentals included in operating expenses totaled $15.0
million for 1995, $13.7 million for 1994 and $16.2 million for 1993. Aggregate
minimum lease payments under existing noncapitalized, long-term leases are
approximately $14.0 million for each of the years 1996 through 2000, and $100.7
million thereafter.
8. Taxes On Income
Provisions for income taxes are composed of the following (millions of
dollars):
Year Ended December 31,
--------------------------------
1995 1994 1993
-------- -------- --------
Federal:
Currently payable................................................... $ 98.6 $ 85.6 $ 62.0
Deferred ........................................................... ( 17.2) ( 8.1) 14.5
-------- -------- --------
81.4 77.5 76.5
-------- -------- --------
State and City:
Currently payable................................................... 6.8 5.2 2.1
Deferred ........................................................... ( 1.4) ( .7) 1.6
-------- -------- --------
5.4 4.5 3.7
-------- -------- --------
Total income taxes................................................ $ 86.8 $ 82.0 $ 80.2
======== ======== ========
Provisions for income taxes were different from the amount computed by
applying the statutory U.S. federal income tax rate to earnings before tax. The
reasons for these differences are (millions of dollars):
Year Ended December 31,
--------------------------------
1995 1994 1993
-------- -------- --------
Tax expense computed by applying the U.S. federal income tax rate
of 35%.............................................................. $ 83.3 $ 81.9 $ 83.0
Increases (reductions) in taxes resulting from:
State and city income taxes reduced by federal income tax benefit... 3.5 2.9 2.4
Normalization adjustment for liberalized depreciation............... - ( 2.8) ( 4.8)
Other............................................................... - - ( .4)
-------- -------- --------
Taxes on income................................................. $ 86.8 $ 82.0 $ 80.2
======== ======== ========
F-17
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences are (millions of
dollars):
December 31,
--------------------
1995 1994
-------- --------
Depreciation........................................................................ $ 166.5 $ 162.8
Purchased gas and other recoverable costs........................................... 43.5 53.5
Other............................................................................... 15.1 15.4
-------- --------
Deferred tax liabilities......................................................... 225.1 231.7
-------- --------
Provision for regulatory matters.................................................... ( 30.3) ( 14.6)
Inventory capitalization............................................................ ( 1.6) ( 1.6)
Benefit plans and accrued expenses.................................................. ( 5.1) ( 8.0)
Other............................................................................... ( 8.4) ( 10.0)
-------- --------
Deferred tax assets.............................................................. ( 45.4) ( 34.2)
-------- --------
Deferred income taxes............................................................ $ 179.7 $ 197.5
======== ========
The Coastal consolidated federal income tax returns for the years 1985
through 1987 have been examined by the Internal Revenue Service. The examination
did not result in any significant adjustments to the Company's portion of these
returns. Examination of such consolidated federal income tax returns for 1988,
1989 and 1990 is currently in progress. It is the opinion of management that
adequate provisions for federal income taxes have been reflected in the
Company's consolidated financial statements.
9. Benefit Plans
The Company participates with its affiliates in the non-contributory
pension plan of Coastal (the "Plan") which covers substantially all employees.
The Plan provides benefits based on final average monthly compensation and years
of service. As of December 31, 1995, the Plan did not have an unfunded
accumulated benefit obligation. ANR Pipeline made no contributions to the Plan
for 1995, 1994 or 1993. Assets of the Plan are not segregated or restricted by
its participating subsidiaries and pension obligations for Company employees
would remain the obligation of the Plan if the Company were to withdraw.
The Company offered an early retirement incentive program to all of its
eligible employees (age 55 before January 1, 1996 and having five or more years
of service before January 1, 1996), who were employed through December 31, 1995.
All benefits provided under this program are being funded by the Plan and will
not have a material impact on the Company's consolidated cash flow or financial
position.
ANR Pipeline also makes contributions to a thrift plan, which is a
trusteed, voluntary and contributory plan for eligible employees of the Company.
The Company's contributions, which are based on matching employee contributions,
amounted to $6.0 million, $6.3 million and $5.9 million for 1995, 1994 and 1993,
respectively.
The Company provides certain health care and life insurance benefits for
substantially all of its retired employees. The estimated costs of retiree
benefit payments are accrued during the years the employee provides services.
Certain costs have been deferred and are being amortized, to reflect the impact
of rate regulation.
F-18
The following tables set forth the accumulated postretirement benefit
obligation recognized in the Company's Consolidated Balance Sheet as of December
31, 1995 and 1994 and the benefit cost for the years ended December 31, 1995,
1994 and 1993 (millions of dollars):
1995 1994
-------- --------
Accumulated postretirement benefit obligation:
Retirees......................................................................... $( 42.7) $( 40.8)
Fully eligible plan participants................................................. ( .5) ( 2.1)
Other active plan participants................................................... ( 13.1) ( 8.9)
-------- --------
( 56.3) ( 51.8)
Plan assets at fair value........................................................... 17.0 11.0
-------- --------
Accumulated postretirement benefit obligation in excess of plan assets.............. ( 39.3) ( 40.8)
Unrecognized net transition obligation.............................................. 53.2 56.3
Unrecognized net gain from past experience different from
that assumed..................................................................... ( 12.3) ( 15.1)
-------- --------
Postretirement benefit prepayment included in
Consolidated Balance Sheet....................................................... $ 1.6 $ .4
======== ========
Year Ended December 31,
--------------------------------
1995 1994 1993
-------- -------- --------
Netperiodic postretirement benefit cost consisted of the following
components:
Service cost - benefits earned during the period.................. $ .5 $ .5 $ .4
Interest cost on accumulated postretirement benefit obligation.... 4.1 4.2 5.0
Amortization of transition obligation............................. 3.1 3.1 3.1
Return on assets, net of deferrals................................ ( 1.3) ( .4) -
-------- -------- --------
Net periodic postretirement benefit cost.......................... 6.4 7.4 8.5
Deferred regulatory amounts....................................... .9 .8 ( 6.5)
-------- -------- --------
Net postretirement benefit cost recognized in Statement of
Consolidated Earnings............................................ $ 7.3 $ 8.2 $ 2.0
======== ======== ========
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 11.2% in 1995, declining gradually to 6.0%
by the year 2004. The assumed health care cost trend rate used in measuring the
accumulated postretirement benefit obligation was 12.0% and 16.0% in 1994 and
1993, respectively. A one percentage point increase in the assumed health care
cost trend rate for each year would increase the accumulated postretirement
benefit obligation as of December 31, 1995 by approximately 4.3% and the net
postretirement health care cost by approximately 5.4%. The assumed discount rate
used in determining the accumulated postretirement benefit obligation was 7.25%.
F-19
10. Transactions with Major Customers and Related Parties
- - Major Customers:
The Statement of Consolidated Earnings includes revenues from major
customers as follows (millions of dollars):
1995 1994 1993
------------------ ------------------ -----------------
Percent Percent Percent
Amount of Total Amount of Total Amount of Total
-------- -------- -------- -------- -------- --------
Wisconsin Gas Company...................... $ 94.6 11.5% $ 100.8 12.0% $ 223.0 17.5%
Michigan Consolidated Gas Company.......... 70.3 8.6 65.7 7.8 241.7 19.0
- - Related Parties:
"Operation and maintenance" expenses within the Statement of Consolidated
Earnings includes affiliate and other related party transactions as follows
(millions of dollars):
1995 1994 1993
-------- -------- --------
Storage and transportation expense - affiliates........................ $ 18.0 $ 20.9 $ 25.6
Storage and transportation expense - other related parties............. 41.2 39.9 31.9
Services provided at cost - affiliates................................. 24.4 26.8 23.8
Facilities rental expense - affiliates................................. 16.5 14.9 16.5
Services provided by the Company at cost for affiliated companies were
$10.3 million for 1995, $9.9 million for 1994 and $10.1 million for 1993. The
services provided by the Company to affiliates, and by affiliates to the
Company, primarily reflect the allocation of costs relating to the sharing of
facilities and administrative functions, characteristic of group operations.
Such costs are allocated using a three-factor formula consisting of revenues,
property and payroll, which is reasonable and has been applied on a consistent
basis.
The Company has lease agreements with Coastal and its affiliates for the
rental of office space and certain pipeline facilities. One such lease with
Coastal, for pipeline facilities, was terminated during 1994 in conjunction with
the terms of the lease.
ANR Pipeline participates in a program which matches short-term cash
excesses and requirements of participating affiliates, thus minimizing
borrowings from outside sources. At December 31, 1995, the Company had advanced
$384.8 million to an associated company at a market rate of interest. Such
amount is repayable on demand.
F-20
11. Quarterly Results of Operations (Unaudited)
The results of operations by quarter for the years ended December 31, 1995
and 1994 were (millions of dollars):
1995 Quarter Ended
--------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- --------- -------- ---------
Revenues................................................ $ 220.8 $ 194.8 $ 213.6 $ 191.5
Cost of gas............................................. 32.3 21.5 25.2 17.9
--------- --------- -------- ---------
Revenues less cost of gas............................ 188.5 173.3 188.4 173.6
Other costs and expenses................................ 139.6 141.2 154.0 137.7
--------- --------- -------- ---------
Net earnings......................................... $ 48.9 $ 32.1 $ 34.4 $ 35.9
========= ========= ======== =========
1994 Quarter Ended
--------------------------------------------------
March 31, June 30, Sept. 30, Dec. 31,
--------- --------- -------- ---------
Revenues*............................................... $ 244.4 $ 202.6 $ 197.5 $ 197.6
Cost of gas*............................................ 40.3 31.5 26.9 25.5
--------- --------- -------- ---------
Revenues less cost of gas............................ 204.1 171.1 170.6 172.1
Other costs and expenses................................ 155.5 127.8 144.2 138.3
--------- --------- -------- ---------
Net earnings......................................... $ 48.6 $ 43.3 $ 26.4 $ 33.8
========= ========= ======== =========
* The quarter ended September 30, 1994, has been restated to exclude
transportation imbalance activity in the amount of $33.1 million from both
"Revenues" and "Cost of gas." Such activity is now accounted for on a net
basis.
F-21
EXHIBIT INDEX
Exhibit
Number Document
- ------ ----------
(3.1)+ Composite Certificate of Incorporation of ANR Pipeline effective
as of December 31, 1987 (Filed as Module ANRCertIncorp on March
29, 1994).
(3.2)+ Amended By-laws of ANR Pipeline effective as of September 21,
1994. (Filed as Exhibit 3.2 to ANR Pipeline's Annual Report on
Form 10-K for the fiscal year ended December 31, 1994.)
(4) With respect to instruments defining the rights of holders of
long-term debt, the Company will furnish to the Securities and
Exchange Commission any such document on request.
(4.1)+ Board Resolution dated September 22, 1975 establishing the $2.675
Series of Cumulative Preferred Stock (Filed as Module
BoardRes_092275 on March 29, 1994).
(4.2)+ Board Resolution dated October 26, 1976 establishing the $2.12
Series of Cumulative Preferred Stock (Filed as Module
BoardRes_102676 on March 29, 1994).
(4.3)+ Board Resolution dated May 12, 1980 establishing the $12.00
Series of Cumulative Preferred Stock (Filed as Module
BoardRes_051280 on March 29, 1994).
(4.4)+ Indenture dated as of February 15, 1994 and First Supplemental
Indenture dated as of February 15, 1994 for the $125 million of
7-3/8% Debentures due February 15, 2024. (Filed as Exhibit 4.4 to
ANR Pipeline's Annual Report on Form 10-K for the fiscal year
ended December 31, 1993.)
(10.1)+ Form of Employment Agreement between ANR Pipeline and certain of
its executive officers (Filed as a Module ANREmployAgree on March
29, 1994).
(10.2)+ Form of Employment Agreement between Coastal and certain Company
executive officers (Filed as Module TCCEmployAgree on March 29,
1994).
(10.3)* Agreement for Consulting Services between ANR Pipeline and Harold
Burrow, dated as of January 1, 1996.
(21)* Subsidiaries of the Company.
(24)* Power of Attorney (included on signature pages herein).
(27)* Financial Data Schedule.
- ----------------------
Note:
+ Indicates documents incorporated by reference from the prior filings
indicated.
* Indicates documents filed herewith.