<PAGE>   1

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------

                       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

                 For the fiscal year ended DECEMBER 31, 2000 OR

[ ]  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
         SECURITIES EXCHANGE ACT OF 1934

              For the transition period from ________ to ________

                         Commission file number 1-7320

                              ANR PIPELINE COMPANY
             (Exact name of registrant as specified in its charter)

<TABLE>
<S>                                            <C>
                  DELAWARE                                      38-1281775
       (State or other jurisdiction of             (I.R.S. Employer Identification No.)
       incorporation or organization)
              EL PASO BUILDING
            1001 LOUISIANA STREET
               HOUSTON, TEXAS                                      77002
  (Address of principal executive offices)                      (Zip Code)
</TABLE>

       Registrant's telephone number, including area code: (713) 420-2131

          Securities registered pursuant to Section 12(b) of the Act:

<TABLE>
<CAPTION>
                                               NAME OF EACH EXCHANGE
         TITLE OF EACH CLASS                    ON WHICH REGISTERED
         -------------------                   ---------------------
<S>                                    <C>    <C>
9 5/8% Debentures, due 2021            H
7 3/8% Debentures, due 2024                   New York Stock Exchange
 7% Debentures, due 2025
</TABLE>

     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]

     Common Stock, par value $100 per share. Shares outstanding on March 19,
2001: 1,000

     ANR PIPELINE COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION I(1)(a)
AND (b) TO FORM 10-K AND IS, THEREFORE, FILING THIS REPORT WITH A REDUCED
DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.

                   DOCUMENTS INCORPORATED BY REFERENCE: NONE

--------------------------------------------------------------------------------
--------------------------------------------------------------------------------
<PAGE>   2

                              ANR PIPELINE COMPANY

                               TABLE OF CONTENTS

                                    CAPTION

<TABLE>
<CAPTION>
                                                                           PAGE
                                                                           ----
  <S>        <C>                                                           <C>
                                     PART I

  Item  1.   Business....................................................    1
  Item  2.   Properties..................................................    3
  Item  3.   Legal Proceedings...........................................    3
  Item  4.   Submission of Matters to a Vote of Security Holders.........    *

                                     PART II

  Item  5.   Market for the Registrant's Common Equity and Related
             Stockholder Matters.........................................    4
  Item  6.   Selected Financial Data.....................................    *
  Item  7.   Management's Discussion and Analysis of Financial Condition
             and Results of Operations...................................    4
  Item  7A.  Quantitative and Qualitative Disclosures About Market
             Risk........................................................    6
  Item  8.   Financial Statements and Supplementary Data.................    7
  Item  9.   Changes in and Disagreements with Accountants on Accounting
             and Financial Disclosure....................................   20

                                    PART III

  Item 10.   Directors and Executive Officers of the Registrant..........    *
  Item 11.   Executive Compensation......................................    *
  Item 12.   Security Ownership of Certain Beneficial Owners and
             Management..................................................    *
  Item 13.   Certain Relationships and Related Transactions..............    *

                                     PART IV

  Item 14.   Exhibits, Financial Statement Schedules and Reports on Form
             8-K.........................................................   20

             Signatures..................................................   21
</TABLE>

---------------

* We have not included a response to this item in this document since no
  response is required pursuant to the reduced disclosure format permitted by
  General Instruction I to Form 10-K.

     Below is a list of terms that are common to our industry and used
throughout this document:

<TABLE>
<S>     <C>
/d      - per day
Bcf     - billion cubic feet
Mcf     - thousand cubic feet
MMcf    - million cubic feet
MMcfe   - million cubic feet of gas equivalents
</TABLE>

     When we refer to cubic feet measurements, all measurements are at 14.73
pounds per square inch.

                                       (i)
<PAGE>   3

                                     PART I

ITEM 1. BUSINESS

                                  INTRODUCTION

     In January 2001, we became a wholly owned subsidiary of El Paso Corporation
through the merger of a wholly owned El Paso subsidiary with The Coastal
Corporation. In the merger, each share of Coastal common stock, and Class A
common stock was converted on a tax-free basis into 1.23 shares of El Paso
common stock. The outstanding convertible preferred stock of Coastal was
exchanged tax free for El Paso common stock on the same basis as if the
preferred stock had been converted into Coastal common stock immediately prior
to the merger. El Paso issued a total of approximately 271 million shares of El
Paso common stock, including approximately 4 million shares issued in exchange
for outstanding Coastal stock options.

     We are a Delaware corporation organized in 1945. All of our outstanding
common stock is owned by American Natural Resources Company. American Natural
Resources is a direct, wholly owned subsidiary of Coastal Natural Gas Company,
and an indirect subsidiary of El Paso CGP Company (formerly Coastal). We own and
operate an interstate natural gas pipeline system.

                               NATURAL GAS SYSTEM

OPERATIONS

     We are involved in the open access transportation, storage and gathering of
natural gas owned by third parties. Our two interconnected, large-diameter
multiple pipeline systems transport natural gas from gas-producing fields in
Texas, Oklahoma, Louisiana, the Gulf of Mexico, and Canada to markets in the
Midwest and Northeast regions of the United States, including the metropolitan
areas of Detroit, Chicago, and Milwaukee.

     Our system consists of 10,600 miles of pipeline and 74 compressor stations,
with a design peak capacity of approximately 6.6 Bcf/d. During 2000, we
transported natural gas volumes averaging approximately 71 percent of our
capacity. Along our system, we also have approximately 202 Bcf of underground
working gas storage capacity, with a maximum daily delivery capacity of 3 Bcf.
Working gas storage capacity operated by us of 126.3 Bcf is available from five
owned and five leased underground storage facilities in Michigan. We also have
the contracted rights for 75.4 Bcf of working gas storage capacity, of which
45.4 Bcf is provided by Blue Lake Gas Storage Company and 30 Bcf is provided by
ANR Storage.

     We own a 50 percent indirect interest in the East Breaks, High Island
Offshore, Stingray and U-T Offshore systems, all of which are located in the
Gulf of Mexico. We also own an indirect 16 percent interest in the Iroquois
pipeline system that transports gas from Canada to the northeastern U.S. As a
result of the El Paso merger, we were required, under a Federal Trade Commission
consent order, to dispose of our interests in the U-T Offshore and Stingray
systems. These sales were completed in February 2001. Under that same order, we
will dispose of our 16 percent interest in the Iroquois Gas Transmission System.
The sale of our interest in the Iroquois system is expected to be completed in
the first half of 2001.

     Deliveries on our system for the years 2000, 1999 and 1998 were as follows:

<TABLE>
<CAPTION>
                       TOTAL SYSTEM     DAILY AVERAGE
YEAR                    DELIVERIES    SYSTEM DELIVERIES
----                   ------------   -----------------
                          (BCF)            (MMCF)
<S>                    <C>            <C>
2000                      1,352             3,694
1999                      1,362             3,732
1998                      1,354             3,710
</TABLE>

     In January 2001, we placed in service an expansion of our Wisconsin system
that provides an efficient means for customers to gain access to increased
supplies of natural gas at the Joliet Market Hub. This expansion added 20,000
horsepower of compression and provides 109 MMcf/d of additional capacity.

                                        1
<PAGE>   4

REGULATORY ENVIRONMENT

     Our interstate systems and those of our investee pipelines are regulated by
the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act of
1938 and the Natural Gas Policy Act of 1978. Our systems operate under FERC
approved tariffs that establish rates, terms, and conditions under which each
system provides services to its customers. Generally, FERC's authority extends
to:

     - transportation and storage of natural gas, rates and charges;

     - certification and construction of new facilities;

     - extension or abandonment of services and facilities;

     - maintenance of accounts and records;

     - regulatory accounting policies;

     - acquisition and disposition of facilities;

     - initiation and discontinuation of services; and

     - various other matters.

     Tariffs for our and our investee pipeline systems have been established
through filings with FERC and have a variety of terms and conditions, each of
which affects the pipelines' operations and their ability to recover fees for
the services they provide. By and large, changes to these fees or terms can only
be implemented upon approval by FERC.

     We are also subject to the Natural Gas Pipeline Safety Act of 1968 that
establishes pipeline and liquefied natural gas plant safety requirements. We are
also subject to environmental legislation and regulations. Our systems have a
continuing program of inspection designed to keep all of our facilities in
compliance with pollution control and pipeline safety requirements. We believe
that our systems are in substantial compliance with the applicable requirements.

     We are also subject to regulation with respect to safety requirements in
the design, construction, operation and maintenance of our interstate natural
gas transmission and storage facilities by the U.S. Department of
Transportation. Operations on United States government land are regulated by the
U.S. Department of the Interior.

     For further discussion of our regulatory matters, see Item 8, Financial
Statements and Supplementary Data, Note 4.

MARKETS AND COMPETITION

     In our historical market areas of Wisconsin and Michigan, we compete with
other interstate and intrastate pipeline companies and local distribution
companies in the transportation and storage of natural gas. We have been
successful in restructuring the service portfolios of a number of our major
Wisconsin customers. This restructuring has enabled us to extend contracts that
were set to expire in 2003, with the restructured

                                        2
<PAGE>   5

contracts providing for a combined winter maximum daily quantity of 674 MMcf/d
that will expire in 2008 and 2010. We continue to work with our largest
customer, Wisconsin Gas Company, to restructure and extend contracts that are
set to expire in 2003. However, Wisconsin Gas is a sponsor of the proposed
Guardian Pipeline, which received a FERC certificate on March 14, 2001, and that
pipeline will directly compete for a portion of this expiring capacity. We also
have 900 MMcf/d of capacity under contract with Michigan Consolidated Gas
Company. Of that amount, 110 MMcf/d is due to expire in March 2002, another 175
MMcf/d will expire in 2003, and the remainder of the capacity will expire
between 2006 and 2011. Extensions of these contracts are under negotiation.

     We also face competition in the Northeast markets from other interstate
pipelines serving electric generation and local distribution companies.

                                 ENVIRONMENTAL

     A description of our environmental activities is included in Item 8,
Financial Statements and Supplementary Data, Note 4, and is incorporated herein
by reference.

                                   EMPLOYEES

     At January 31, 2001, we had 981 employees engaged in the operation of ANR,
including the employees engaged in the operation of ANR Storage Company and
Empire State Pipeline. None of our employees are subject to collective
bargaining agreements.

ITEM 2. PROPERTIES

     A description of our properties is included in Item 1, Business and is
incorporated herein by reference.

     We are of the opinion that we have satisfactory title to the properties
owned and used in our businesses, subject to liens for current taxes, liens
incident to minor encumbrances, and easements and restrictions that do not
materially detract from the value of such property or the interests therein or
the use of such properties in our businesses. We believe that our physical
properties are adequate and suitable for the conduct of our business in the
future.

ITEM 3. LEGAL PROCEEDINGS

     See Item 8, Financial Statements and Supplementary Data, Note 4, which is
incorporated herein by reference.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

     Item 4, Submission of Matters to a Vote of Security Holders, has been
omitted from this report pursuant to the reduced disclosure format permitted by
General Instruction I to Form 10-K.

                                        3
<PAGE>   6

                                    PART II

ITEM 5. MARKET FOR THE REGISTRANT'S COMMON EQUITY AND RELATED STOCKHOLDER
        MATTERS

     All of our common stock, par value $100 per share, is owned by American
Natural Resources, and accordingly, there is no public trading market for our
securities. American Natural Resources is an indirect subsidiary of Coastal. On
January 29, 2001, Coastal became a wholly owned subsidiary of El Paso.

     We pay dividends on our common stock from time to time from legally
available funds that have been approved for payment by our Board of Directors.
We paid cash dividends of $74 million, $127 million and $161 million to our
parent in 2000, 1999 and 1998.

ITEM 6. SELECTED FINANCIAL DATA

     Item 6, Selected Financial Data, has been omitted from this report pursuant
to the reduced disclosure format permitted by General Instruction I to Form
10-K.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
        OF OPERATIONS

     The information required by this Item is presented in a reduced disclosure
format permitted by General Instruction I to Form 10-K. The Notes to
Consolidated Financial Statements contain information that is pertinent to the
following analysis.

     In January 2001, we became a wholly owned subsidiary of El Paso through the
merger of a wholly owned El Paso subsidiary with Coastal. In the merger, El Paso
issued a total of approximately 271 million shares of its common stock,
including approximately 4 million shares issued in exchange for outstanding
Coastal stock options.

     In September 2000, it was announced that our headquarters would be
relocated from Detroit, Michigan to Houston, Texas following the merger. We
expect to incur charges associated with relocations of our employees and assets,
and charges for asset and contract terminations that will occur as our
operations are consolidated. We anticipate a majority of these charges will
occur in the first half of 2001.

     On January 30, 2001, we completed an employee restructuring that resulted
in the reduction of approximately 900 full time positions through a combination
of early retirements and terminations. These reductions will result in severance
and termination charges, retention payments to employees retained on a
transition basis following the merger, and the acceleration of employee benefit
payments under existing benefit plans and employment contracts. We expect a
majority of these charges to occur in the first quarter of 2001.

     As a result of the merger, we were required, under a Federal Trade
Commission consent order, to dispose of our 50 percent indirect interests in the
U-T Offshore and Stingray systems. These sales were completed in February 2001.
Under that same order, we will dispose of our 16 percent interest in the
Iroquois Gas Transmission System. The sale of our interest in the Iroquois
system is expected to be completed in the first half 2001.

     The final cost of the merger-related activities and the charges we will
incur as we continue to integrate our activities with El Paso are not fully
known at this time. However, we expect that most of these charges will be
recorded in 2001.

                                        4
<PAGE>   7

                             RESULTS OF OPERATIONS

     Operating results and an analysis of those results for the years ended
December 31, 2000 and 1999 are as follows:

<TABLE>
<CAPTION>
                                                               2000     1999
                                                              ------   ------
                                                               (IN MILLIONS)
<S>                                                           <C>      <C>
Operating revenues..........................................  $  592   $  601
Operating expenses..........................................     397      362
Other income................................................      58       51
Earnings before interest and income taxes...................     253      290
Total throughput volume (MMcf/d)............................   3,694    3,732
</TABLE>

YEAR ENDED DECEMBER 31, 2000 COMPARED TO YEAR ENDED DECEMBER 31, 1999

     Operating revenues decreased by $9 million in 2000 as compared to 1999.
This decrease was primarily due to lower storage and transportation revenues
resulting from lower average rates charged to customers. We expect the trend in
lower average rates to continue in the near term, as there currently exists
excess pipeline capacity for deliveries of natural gas in the Midwest region of
the United States. Also contributing to the decrease was a continuing decline in
surcharge revenues related to FERC Order 636 transition costs. The decrease in
lower storage and transportation revenues was partially offset by an increase in
other revenues primarily due to higher Dakota gas sales revenues resulting from
natural gas price increases.

     Operating expenses increased by $35 million in 2000 as compared to 1999.
This increase was largely due to higher prices impacting Dakota gas purchases
and accruals for the replacement of system balancing gas. Also contributing to
the increase was a $15 million benefit recorded in the first quarter of 1999
related to revisions of various gas costs, gas transportation costs and
environmental cleanup cost accruals.

     Other income increased by $7 million in 2000 as compared to 1999. The
increase is primarily due to higher equity in earnings from pipeline
partnerships.

     Income taxes decreased by $18 million in 2000 as compared to 1999 primarily
due to lower pre-tax income. The effective tax rate was 35 percent and 37
percent for 2000 and 1999.

CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
                    SECURITIES LITIGATION REFORM ACT OF 1995

     This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and to be made in
good faith, assumed facts or bases almost always vary from the actual results,
and the differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, that expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements.

                                        5
<PAGE>   8

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

     The following table presents hypothetical changes in fair values in our
debt obligations at December 31, 2000 and 1999. The modeling technique used
measures the change in fair values arising from selected changes in interest
rates. Market changes reflect immediate hypothetical changes in interest rates
at December 31. Fair values are calculated as the net present value of the
expected cash flows of the financial instrument.

<TABLE>
<CAPTION>
                                                             10% INCREASE         10% DECREASE
                                                          ------------------   ------------------
                                                FAIR      FAIR     INCREASE    FAIR     INCREASE
                                                VALUE     VALUE   (DECREASE)   VALUE   (DECREASE)
                                              ---------   -----   ----------   -----   ----------
                                                                 (IN MILLIONS)
<S>                                           <C>         <C>     <C>          <C>     <C>
Impact of changes in market rates of
  interest on
  Long-term debt subject to fixed interest
     rates
     2000...................................    $555      $527       $(28)     $585       $30
     1999...................................     539       507        (32)      575        36
</TABLE>

     We have a note receivable from a related party with a carrying value of
$128 million and $136 million at December 31, 2000 and 1999. The note earns
interest at a variable rate tied to market rates of interest, and therefore, the
carrying amount is a reasonable estimate of its fair value. A 10 percent change
in interest rates from December 31 levels would not have a material impact on
our income.

                                        6
<PAGE>   9

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

                     ANR PIPELINE COMPANY AND SUBSIDIARIES

                       CONSOLIDATED STATEMENTS OF INCOME
                                 (IN MILLIONS)

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              ------------------------
                                                               2000     1999     1998
                                                              ------   ------   ------
<S>                                                           <C>      <C>      <C>
Operating revenues
  Storage and transportation
     Third parties..........................................   $507     $544     $613
     Related parties........................................     34       23        7
  Other.....................................................     51       35       58
                                                               ----     ----     ----
                                                                592      601      678
                                                               ----     ----     ----
Operating expenses
  Operation and maintenance
     Third parties..........................................    278      240      266
     Related parties........................................     63       63       70
  Depreciation and amortization.............................     39       38       37
  Taxes, other than income taxes............................     17       21       26
                                                               ----     ----     ----
                                                                397      362      399
                                                               ----     ----     ----
Operating income............................................    195      239      279
                                                               ----     ----     ----

Other income
  Third parties.............................................     45       41       39
  Related parties...........................................     13       10       17
                                                               ----     ----     ----
                                                                 58       51       56
                                                               ----     ----     ----

Income before interest and income taxes.....................    253      290      335
                                                               ----     ----     ----

Other expenses
  Interest expense..........................................     46       47       46
  Interest income from a related party......................     (8)     (10)     (13)
  Income taxes..............................................     76       94       98
                                                               ----     ----     ----
                                                                114      131      131
                                                               ----     ----     ----

Net Income..................................................   $139     $159     $204
                                                               ====     ====     ====
</TABLE>

                            See accompanying notes.

                                        7
<PAGE>   10

                     ANR PIPELINE COMPANY AND SUBSIDIARIES

                          CONSOLIDATED BALANCE SHEETS
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
                                                               DECEMBER 31,
                                                              ---------------
                                                               2000     1999
                                                              ------   ------
<S>                                                           <C>      <C>
                           ASSETS
Current Assets
  Cash and cash equivalents.................................  $    1   $    3
  Notes receivable from a related party.....................     128      136
  Accounts receivable
     Third parties..........................................     118       20
     Related parties........................................      33       45
  Materials and supplies, at average cost...................      29       28
  Current deferred income taxes.............................      16       21
                                                              ------   ------
          Total current assets..............................     325      253
                                                              ------   ------
Property, plant and equipment, at cost......................   3,468    3,463
  Less -- Accumulated depreciation..........................   2,196    2,168
                                                              ------   ------
          Total property, plant, and equipment, net.........   1,272    1,295
                                                              ------   ------
Other Assets
  Investments in related parties
     Pipeline partnerships..................................      52       68
     Other..................................................      61       65
  Deferred charges and other................................       5       14
                                                              ------   ------
          Total other assets................................     118      147
                                                              ------   ------
          Total assets......................................  $1,715   $1,695
                                                              ======   ======
</TABLE>

<TABLE>
<S>                                                           <C>      <C>
            LIABILITIES AND STOCKHOLDER'S EQUITY
Current Liabilities
  Accounts payable
     Third parties..........................................  $   73   $   94
     Related parties........................................       4        8
  Income taxes payable......................................      26       32
  Other taxes...............................................      18       24
  Other.....................................................      32       40
                                                              ------   ------
          Total current liabilities.........................     153      198
                                                              ------   ------
Long-Term Debt..............................................     498      498
                                                              ------   ------
Deferred Credits and Other
  Deferred income taxes.....................................     230      200
  Other deferred credits....................................      34       64
                                                              ------   ------
          Total deferred credits and other..................     264      264
                                                              ------   ------
Stockholder's Equity
  Common stock, $100 par value, authorized, issued and
     outstanding 1,000 shares...............................      --       --
  Additional paid-in capital................................     466      466
  Retained earnings.........................................     334      269
                                                              ------   ------
          Total stockholder's equity........................     800      735
                                                              ------   ------
          Total liabilities and stockholder's equity........  $1,715   $1,695
                                                              ======   ======
</TABLE>

                            See accompanying notes.

                                        8
<PAGE>   11

                     ANR PIPELINE COMPANY AND SUBSIDIARIES

                     CONSOLIDATED STATEMENTS OF CASH FLOWS
                                 (IN MILLIONS)

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              2000     1999     1998
                                                              -----   ------   ------
<S>                                                           <C>     <C>      <C>
Cash flows from operating activities
  Net income................................................  $139    $ 159    $ 204
  Adjustments to reconcile net income to net cash from
     operating activities
     Depreciation and amortization..........................    39       38       37
     Deferred income tax expense............................    35       29       45
     Provision for regulatory matters.......................    --       --     (181)
     Undistributed equity in earnings of pipeline
      partnerships..........................................   (13)     (10)     (17)
  Changes in other assets and liabilities affecting
     operating activities
     (Increase) decrease in accounts receivable
       Third parties........................................   (98)       4        2
       Related parties......................................    12      (18)      (2)
     Increase (decrease) in accounts payable and other
      accruals
       Third parties........................................   (31)     (13)      41
       Related parties......................................    (4)      (3)       2
     Net (increase) decrease in other assets/liabilities....    83       (7)     (13)
                                                              ----    -----    -----
       Net cash provided by operating activities............   162      179      118
                                                              ----    -----    -----
Cash flows from investing activities
  Capital expenditures......................................   (99)     (83)     (77)
  Investment in pipeline partnerships.......................    --      (28)      --
  Decrease in notes receivable from related party...........     8       20      110
  Investment in related parties.............................     4        4        6
  Proceeds from sale of plant to related party..............    (1)      38        4
                                                              ----    -----    -----
       Net cash (used in) provided by investing
        activities..........................................   (88)     (49)      43
                                                              ----    -----    -----
Cash flows from financing activities
  Common stock dividends paid...............................   (74)    (127)    (161)
  Other.....................................................    (2)      (3)      (2)
                                                              ----    -----    -----
       Net cash used in financing activities................   (76)    (130)    (163)
                                                              ----    -----    -----
Net decrease in cash and cash equivalents...................    (2)      --       (2)
Cash and cash equivalents
  Beginning of period.......................................     3        3        5
                                                              ----    -----    -----
  End of period.............................................  $  1    $   3    $   3
                                                              ====    =====    =====
</TABLE>

                            See accompanying notes.

                                        9
<PAGE>   12

                     ANR PIPELINE COMPANY AND SUBSIDIARIES

                CONSOLIDATED STATEMENTS OF STOCKHOLDER'S EQUITY
                      (IN MILLIONS, EXCEPT SHARE AMOUNTS)

<TABLE>
<CAPTION>
                                                              YEAR ENDED DECEMBER 31,
                                                              -----------------------
                                                              2000     1999     1998
                                                              -----   ------   ------
<S>                                                           <C>     <C>      <C>
Common stock, par value $100 per share, authorized, issued
  and outstanding 1,000 shares..............................  $ --    $  --    $  --

Additional paid-in capital..................................   466      466      466
Retained earnings
  Beginning balance.........................................   269      237      194
  Net income................................................   139      159      204
  Dividends on common stock.................................   (74)    (127)    (161)
                                                              ----    -----    -----
  Ending balance............................................   334      269      237
                                                              ----    -----    -----
          Total.............................................  $800    $ 735    $ 703
                                                              ====    =====    =====
</TABLE>

                            See accompanying notes.

                                        10
<PAGE>   13

                     ANR PIPELINE COMPANY AND SUBSIDIARIES

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

  Basis of Presentation

     We are a wholly owned subsidiary of American Natural Resources Company,
which is an indirect subsidiary of El Paso CGP Company (formerly Coastal). In
connection with Coastal's merger with a wholly owned subsidiary of El Paso in
January 2001, Coastal became a subsidiary of El Paso. Coastal then changed its
name to El Paso CGP Company. We were originally acquired by Coastal in 1985. Our
financial statements are presented on a historical cost basis and do not reflect
the cost basis to Coastal when they acquired us. The preparation of these
financial statements, in conformity with generally accepted accounting
principles, requires us to make estimates and assumptions that affect the
reported amounts of assets, liabilities, revenues and expenses. Our actual
results are likely to differ from those estimates and assumptions used.

  Principles of Consolidation

     Our consolidated financial statements include accounts of all wholly owned
subsidiaries, after eliminating all significant intercompany transactions. The
equity method of accounting is used for investments in which we are able to
exert significant influence, but not control over operating and financial
policies. Other investments where we are unable to exert significant influence
are accounted for by the cost method.

  Natural Gas Imbalances

     Natural gas imbalances result from differences in gas volumes received from
and delivered to our transportation and storage customers and arise when a
customer delivers more or less gas into our pipeline than they take out. We
value these gas imbalances due to or from shippers and operators at an
appropriate index price. Natural gas imbalances are settled in cash or made up
in-kind, subject to the pipelines' various terms.

  Property, Plant and Equipment

     Property additions include capitalized interest costs allocable to
construction. Such costs amounted to $2 million in both 2000 and 1999 and $3
million in 1998.

     Our 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 was approximately 1.2 percent for 2000,
1999 and 1998.

     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.

  Income Taxes

     We are a member of a consolidated group which files a consolidated federal
income tax return. Members of the consolidated group with taxable income 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. We follow the liability
method of accounting for deferred income taxes as required by the provisions of
Statement of Financial Accounting Standards (SFAS) No. 109, Accounting for
Income Taxes.

  Cash and Cash Equivalents

     Cash equivalents include time deposits, certificates of deposit and all
highly liquid instruments with original maturities of three months or less. We
made cash payments for interest, net of amounts capitalized, of $46 million, $47
million and $61 million in 2000, 1999 and 1998. Cash payments for income taxes
amounted to $48 million, $71 million and $54 million in 2000, 1999 and 1998.
                                        11
<PAGE>   14

  Price Risk Management Activities

     We periodically enter into swaps, futures and other contracts to hedge the
price risk of natural gas anticipated to be sold. We defer the impact of changes
in the market value of these contracts until such time as the hedged transaction
is completed. At that time, the impact of the changes in fair market value of
these contracts is recognized in income.

  Nature of Operations and Concentrations of Credit Risk

     We are involved in the transportation, storage and gathering of natural gas
primarily for markets in the Midwest and Northeast regions of the United States.
We operate under arrangements with other companies including distributors,
intrastate and interstate pipelines, producers, brokers, marketers and
end-users. As a result, we have a concentration of receivables due from these
customers. This may affect our 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, we analyze customers'
credit positions prior to extending credit.

  Reclassifications

     Minor reclassifications of prior period statements have been made to
conform with current reporting practices. The effect of these reclassifications
was not material to our financial position, operating results or cash flows.

  Accounting for Derivative Instruments and Hedging Activities

     In June of 1998, the Financial Accounting Standards Board (FASB) issued
SFAS No. 133, Accounting for Derivative Instruments and Hedging Activities. In
June of 1999, the FASB extended the adoption date of SFAS No. 133 through the
issuance of SFAS No. 137, Deferral of the Effective Date of SFAS 133. In June
2000, the FASB issued SFAS No. 138, Accounting for Certain Derivative
Instruments and Certain Hedging Activities, which also amended SFAS No. 133.
SFAS No. 133, and its amendments and interpretations, establishes accounting and
reporting standards for derivative instruments, including derivative instruments
embedded in other contracts, and derivative instruments used for hedging
activities. It requires that we measure all derivative instruments at their fair
value, and classify them as either assets or liabilities on our balance sheet,
with a corresponding offset to income or other comprehensive income depending on
their designation, their intended use, or their ability to qualify as hedges
under the standard.

     We adopted SFAS No. 133 on January 1, 2001. The adoption of SFAS No. 133
had no impact on our financial position, operating results or cash flows.

2. LONG-TERM DEBT

     Our long-term debt outstanding consisted of the following at December 31:

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Debentures
  9 5/8% series, due 2021...................................  $300    $300
  7 3/8% series, due 2024...................................   125     125
  7% series, due 2025.......................................    75      75
Unamortized discount related to outstanding debt, net of
  premium...................................................    (2)     (2)
                                                              ----    ----
                                                              $498    $498
                                                              ====    ====
</TABLE>

                                        12
<PAGE>   15

3. FAIR VALUE OF FINANCIAL INSTRUMENTS

     We have estimated the fair value amounts of our financial instruments,
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 we could
realize in a current market exchange. The carrying amounts and estimated fair
values of our financial instruments at December 31 are as follows:

<TABLE>
<CAPTION>
                                                            2000                1999
                                                      -----------------   -----------------
                                                      CARRYING    FAIR    CARRYING    FAIR
                                                       AMOUNT     VALUE    AMOUNT     VALUE
                                                      --------    -----   --------    -----
                                                                   (IN MILLIONS)
<S>                                                   <C>         <C>     <C>         <C>
  Financial assets
     Cash and cash equivalents......................    $  1      $  1      $  3      $  3
     Note receivable from a related party...........     128       128       136       136
  Financial liabilities
     Long-term debt.................................     498       555       498       539
</TABLE>

     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 our long-term debt are based on interest
rates at December 31, 2000 and 1999 for new issues with similar remaining
maturities.

4. COMMITMENTS AND CONTINGENCIES

  Legal Proceedings

     In 1997, we and a number of our affiliates were served as defendants in
actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege an industry-wide conspiracy
to under report the heating value as well as the volumes of the natural gas
produced from federal and Native American lands, which deprived the U.S.
Government of royalties. These matters have been consolidated for pretrial
purposes. (In re: Natural Gas Royalties Qui Tam Litigation, U.S. District Court
for the District of Wyoming.)

     We and a number of our affiliates were served as defendants in an action
styled Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors,
et al, filed in 1999 in the District Court of Stevens County, Kansas. This class
action complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
Quinque complaint, once transferred to the same court handling the Grynberg
complaint, has been sent back to the Kansas State Court for further proceedings.

     We are also a named defendant in other lawsuits arising in the ordinary
course of our business.

     While the outcome of the matters discussed above cannot be predicted with
certainty, we do not expect the ultimate resolution of these matters will have a
material adverse effect on our financial position, operating results or cash
flows.

  Environmental

     Our operations are subject to extensive and evolving federal, state and
local environmental laws and regulations. Compliance with these laws and
regulations can be costly. Additionally, governmental authorities may enforce
the laws and regulations with a variety of civil and criminal enforcement
measures, including monetary penalties and remediation requirements.

     We spent approximately $5 million in 2000 on environmental capital projects
and anticipate capital expenditures of approximately $6 to $8 million per year
over the next several years aimed at maintaining compliance with these laws and
regulations.

     The Comprehensive Environmental Response, Compensation and Liability Act
(CERCLA) imposes liability for the release of a hazardous substance into the
environment. CERCLA liability is imposed without

                                        13
<PAGE>   16

regard to fault and even if the waste disposal was in compliance with the then
current laws and regulations. With the joint and several liability imposed under
CERCLA, a potentially responsible party may be required to pay more than its
proportional share of such costs. We have been named as a potentially
responsible party in three CERCLA waste disposal sites. At these sites, there is
sufficient information to estimate total cleanup costs of approximately $52
million, and we estimate our pro-rata exposure, to be paid over a period of
several years, is approximately $1 million and have made appropriate provisions.

     In Michigan, where we have extensive operations, the Environmental Response
Act requires individuals, including corporations, who have caused contamination
to remediate the contamination to regulatory standards. Owners or operators of
contaminated property who did not cause the contamination are not required to
remediate the contamination, but must exercise due care in their use of the
property so that the contamination is not exacerbated and the property does not
pose a threat to human health. We estimate that our costs to comply with the
Michigan regulations will be approximately $8 million, which will be expended
over a period of several years and for which appropriate provisions have been
made.

     In October 1998, the EPA announced a Finding of Significant Contribution
and Rulemaking for Certain States in the Ozone Transport Assessment Group Region
for Purposes of Reducing Regional Transport of Ozone (NOx SIP Call), which
required the submission of state implementation plans by 22 states, including
eight states in which we operate, and the District of Columbia. The NOx SIP Call
is the subject of legal proceedings instituted by nine of the affected states
and numerous affected industries. In a May 1999 order, the U.S. District Court,
District of Columbia stayed, until further order, compliance with the NOx SIP
Call. As a result of the gas industry's success in the litigation, the EPA
released, on January 5, 2001, its Rulemaking for Purposes of Reducing Interstate
Ozone Transport: Response to March 3, 2000, Decision of the U.S. Court of
Appeals for the District of Columbia Circuit (Remand Proposal). In the Remand
Proposal, the EPA intends to require nitric oxide controls on all engines
emitting more than one ton per day of nitric oxide during the 1995 "ozone
season." We have approximately 18 engines that would require nitric oxide
controls, if the Remand Proposal is adopted without change. We will not be able
to estimate the amount of any obligation resulting from the NOx SIP Call until
the states have submitted compliant state implementation plans.

     It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations, and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe that compliance
with all applicable laws and regulations will not have a material adverse impact
on our financial position, operating results or cash flows.

  Regulatory Matters

     Several regulatory issues remain unresolved among us, our customers and
FERC. We have made provisions that represent our assessment of the ultimate
resolution of these issues. While we cannot predict with certainty the final
outcome or the timing of the resolution of all our regulatory matters, we
believe the ultimate resolution of these issues will not have a material adverse
effect on our financial position, operating results or cash flows.

  Lease Commitments

     Operating lease rentals included in operating expenses amounted to $20
million for each of 2000 and 1999 and $12 million for 1998. Aggregate minimum
lease payments under existing noncapitalized, long-term leases are estimated to
be $17 million for each of the years 2001 and 2002, $25 million for 2003 through
2005 and $249 million thereafter.

                                        14
<PAGE>   17

5. INCOME TAXES

     The following table reflects the components of income tax expense for the
years ended December 31:

<TABLE>
<CAPTION>
                                                              2000    1999    1998
                                                              ----    ----    ----
                                                                 (IN MILLIONS)
<S>                                                           <C>     <C>     <C>
Current
  Federal...................................................  $43     $61     $47
  State and city............................................   (2)      4       6
                                                              ---     ---     ---
                                                               41      65      53
                                                              ---     ---     ---
Deferred
  Federal...................................................   33      27      40
  State and city............................................    2       2       5
                                                              ---     ---     ---
                                                               35      29      45
                                                              ---     ---     ---
          Total tax expense.................................  $76     $94     $98
                                                              ===     ===     ===
</TABLE>

     El Paso CGP and the Internal Revenue Service Appeals Office have concluded
a tentative settlement of the adjustments proposed to El Paso CGP's federal
income tax returns filed for the years 1988 through 1994. Examination of El Paso
CGP's federal income tax returns filed for the years 1995, 1996 and 1997 began
in 1999 and is ongoing. We believe that adequate provisions for federal income
taxes have been reflected in our consolidated financial statements.

     Our income tax expense differs from the amount computed by applying the
statutory federal income tax rate of 35 percent for the following reasons at
December 31:

<TABLE>
<CAPTION>
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Tax expense at the statutory federal rate of 35%............  $75    $89    $106
Increase (decrease):
  State and city income taxes, net of federal income tax
     benefit................................................   --      4       7
  Other.....................................................    1      1     (15)
                                                              ---    ---    ----
     Income tax expense.....................................  $76    $94    $ 98
                                                              ===    ===    ====
     Effective tax rate.....................................  35%    37%     32%
                                                              ===    ===    ====
</TABLE>

     The following are the components of our net deferred tax liability at
December 31:

<TABLE>
<CAPTION>
                                                              2000    1999
                                                              -----   -----
                                                              (IN MILLIONS)
<S>                                                           <C>     <C>
Deferred tax liabilities
  Depreciation..............................................  $239    $223
  Other.....................................................    21      14
                                                              ----    ----
     Total deferred tax liabilities.........................   260     237
                                                              ----    ----
Deferred tax assets
  Inventory capitalization..................................     2       2
  Purchased gas and other recoverable costs.................    --       5
  Benefit plans and accrued expenses........................    23      24
  Environmental costs.......................................     3       3
  Lease costs...............................................     6       5
  Other.....................................................    12      19
                                                              ----    ----
     Total deferred tax assets..............................    46      58
                                                              ----    ----
     Net deferred tax liability.............................  $214    $179
                                                              ====    ====
</TABLE>

                                        15
<PAGE>   18

6. BENEFIT PLANS

     We participate in the non-contributory pension plan of El Paso CGP which
covers substantially all of our employees. The pension plan provides benefits
based on final average monthly compensation and years of service, subject to
maximum limitations as defined in the plans. As of December 31, 2000, the
pension plan did not have an unfunded accumulated benefit obligation. We made no
contributions to the pension plan for 2000, 1999 or 1998. Assets of the pension
plan are not segregated or restricted by participating employers, and pension
obligations for our employees would remain the obligation of the pension plan if
we were to withdraw.

     We also make contributions to a thrift plan, which is a trusteed, voluntary
and contributory plan for our eligible employees. We match 100 percent of
participant basic contributions up to 8 percent, with the matching contribution
being made in common stock of Coastal. Our contributions, which are based on
matching employee contributions, amounted to $6 million for each of the years
2000, 1999 and 1998.

     We provide health care and life insurance benefits for substantially all of
our employees. The estimated costs of retiree benefit payments are accrued
during the years the employee provides services.

     In conjunction with the El Paso merger, some of our benefit plans will be
merged into comparable El Paso benefit plans, while other benefit plans will be
terminated.

     The following table sets forth the changes in benefit obligation, change in
plan assets, reconciliation of funded status, and components of net periodic
benefit cost for postretirement benefits.

<TABLE>
<CAPTION>
                                                              2000     1999
                                                              -----    -----
                                                              (IN MILLIONS)
<S>                                                           <C>      <C>
Change in postretirement benefit obligation
  Benefit obligation at beginning of period.................  $ 48     $ 51
  Service cost..............................................     1        1
  Interest cost.............................................     4        3
  Participant contributions.................................     1        1
  Actuarial loss (gain).....................................     1       (3)
  Benefits paid.............................................    (5)      (5)
                                                              ----     ----
  Postretirement benefit obligation at end of period........  $ 50     $ 48
                                                              ====     ====
Change in plan assets
  Fair value of plan assets at beginning of period..........  $ 20     $ 15
  Actual return on plan assets..............................     1        1
  Employer contributions....................................     9        9
  Administrative expenses...................................    --       (1)
  Benefits paid.............................................    (5)      (4)
                                                              ----     ----
  Fair value of plan assets at end of period................  $ 25     $ 20
                                                              ====     ====
Reconciliation of funded status
  Funded status at end of period............................  $(25)    $(28)
  Unrecognized transition obligation........................    34       37
  Unrecognized net gain.....................................   (11)     (14)
                                                              ----     ----
  Accrued postretirement benefit obligation at December
     31.....................................................  $ (2)    $ (5)
                                                              ====     ====
</TABLE>

                                        16
<PAGE>   19

     Postretirement benefit obligations are based upon actuarial estimates as
described below.

<TABLE>
<CAPTION>
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Postretirement benefit obligations include the following
  components
  Service cost..............................................  $ 1    $ 1    $ 1
  Interest cost.............................................    4      3      3
  Expected return on assets.................................   (1)    (1)    --
  Amortization of transition obligation.....................    3      3      3
  Amortization of net gain..................................   (1)    (1)    (1)
                                                              ---    ---    ---
  Net postretirement benefit cost...........................  $ 6    $ 5    $ 6
                                                              ===    ===    ===
</TABLE>

     The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 7.8 percent in 2000, declining gradually
to 6.0 percent by the year 2004. The assumed health care cost trend rate used in
measuring the accumulated postretirement benefit obligation was 8.4 percent and
9.0 percent in 1999 and 1998. 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, 2000 by approximately 5.69
percent and the net postretirement health care cost by approximately 5.01
percent. A one percentage point decrease in the assumed health care cost trend
rate for each year would decrease the accumulated postretirement benefit
obligation as of December 31, 2000 by approximately 5.63 percent and the net
postretirement health care cost by approximately 5.13 percent. The assumed
discount rate used in determining the accumulated postretirement benefit
obligation was 7.75 percent in 2000 and 8.0 percent in 1999, and the expected
long-term rate of return on assets was 4.3 percent in 2000 and 1999.

7. TRANSACTIONS WITH MAJOR CUSTOMERS AND RELATED PARTIES

  Major Customers:

     The Consolidated Statements of Income include revenues from major customers
amounting to 10 percent or more of our consolidated operating revenues as
follows:

<TABLE>
<CAPTION>
                                          2000                1999                1998
                                    -----------------   -----------------   -----------------
                                             PERCENT             PERCENT             PERCENT
                                    AMOUNT   OF TOTAL   AMOUNT   OF TOTAL   AMOUNT   OF TOTAL
                                    ------   --------   ------   --------   ------   --------
                                                          (IN MILLIONS)
<S>                                 <C>      <C>        <C>      <C>        <C>      <C>
Wisconsin Gas Company.............   $68       12.6%     $71       12.5%     $68       11.0%
</TABLE>

     Revenues from any other single customer did not amount to 10 percent or
more of our consolidated operating revenues for the years ended December 31,
2000, 1999 and 1998.

  Related Parties:

     Operation and maintenance expenses within the Consolidated Statements of
Income includes affiliate and other related party transactions as follows:

<TABLE>
<CAPTION>
                                                              2000   1999   1998
                                                              ----   ----   ----
                                                                (IN MILLIONS)
<S>                                                           <C>    <C>    <C>
Storage and transportation expense -- affiliates............  $12    $12    $12
Storage and transportation expense -- other related
  parties...................................................   24     23     24
Services provided at cost -- affiliates.....................   22     22     22
Facilities rental expense -- affiliates.....................    5      6     13
</TABLE>

                                        17
<PAGE>   20

     Services provided by us at cost for affiliated companies were $12 million
for both of 2000 and 1999 and $13 million for 1998. The services we provide to
affiliates, and provided by affiliates to us, primarily reflect the allocation
of costs relating to the sharing of facilities and administrative functions,
characteristic of group operations. Costs are allocated based on several factors
including revenues, property and payroll.

     We have lease agreements with El Paso CGP and its affiliates for the rental
of office space, natural gas storage fields and several pipeline facilities. Our
investment in an affiliate, Coastal Medical Services, Inc., was $61 million at
December 31, 2000 and $65 million at December 31, 1999. The affiliate has
assumed the responsibility for facilitating the management of a portion of our
medical obligations and the medical obligations of several other El Paso CGP
subsidiaries. At December 31, 1999, our Accounts receivable -- Related parties
balance includes $21 million of costs incurred for the proposed Gulfstream
System, which was divested in conjunction with the merger of El Paso and
Coastal. In 2000, these costs were reimbursed by an affiliate that held the
investment in this project. In 1999, we sold several storage facilities and
related base gas to an affiliate for net book value of $38 million.

     We participate in a program that matches short-term cash excesses and
requirements of participating affiliates, thus minimizing borrowings from
outside sources. We had advanced to an associated company at a market rate of
interest, $128 million at December 31, 2000 and $136 million at December 31,
1999. Such amounts are repayable on demand.

8. MERGER-RELATED EMPLOYEE RESTRUCTURING

     In September 2000, it was announced that our headquarters would be
relocated from Detroit, Michigan to Houston, Texas following the merger. On
January 30, 2001, we completed an employee restructuring that resulted in the
reduction of approximately 900 full time positions through a combination of
early retirements and terminations. These reductions will result in severance
and termination charges, retention payments to employees retained on a
transition basis following the merger, and the acceleration of employee benefit
payments under existing benefit plans and employment contracts.

9. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)

     Financial information by quarter is summarized below. In the opinion of
management, all adjustments necessary for a fair presentation have been made.

<TABLE>
<CAPTION>
                                                              2000 QUARTER ENDED
                                                  -------------------------------------------
                                                  MARCH 31,   JUNE 30,   SEPT. 30,   DEC. 31,
                                                  ---------   --------   ---------   --------
                                                                 (IN MILLIONS)
<S>                                               <C>         <C>        <C>         <C>
Revenues........................................    $185        $149       $147        $178
Costs and expenses..............................     137         126        129         128
                                                    ----        ----       ----        ----
     Net income.................................    $ 48        $ 23       $ 18        $ 50
                                                    ====        ====       ====        ====
</TABLE>

<TABLE>
<CAPTION>
                                                              1999 QUARTER ENDED
                                                  -------------------------------------------
                                                  MARCH 31,   JUNE 30,   SEPT. 30,   DEC. 31,
                                                  ---------   --------   ---------   --------
                                                                 (IN MILLIONS)
<S>                                               <C>         <C>        <C>         <C>
Revenues........................................    $191        $148       $153        $170
Costs and expenses..............................     127         121        125         130
                                                    ----        ----       ----        ----
     Net income.................................    $ 64        $ 27       $ 28        $ 40
                                                    ====        ====       ====        ====
</TABLE>

                                        18
<PAGE>   21

                          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 El Paso CGP Company,
formerly The Coastal Corporation) and subsidiaries as of December 31, 2000 and
1999, and the related consolidated statements of income, retained earnings and
cash flows for each of the three years in the period ended December 31, 2000.
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 auditing standards generally
accepted in the United States of America. 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, 2000 and 1999, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America.

DELOITTE & TOUCHE LLP

Detroit, Michigan
March 19, 2001

                                        19
<PAGE>   22

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE

     None.

                                    PART III

     Item 10, "Directors and Executive Officers of the Registrant;" Item 11,
"Executive Compensation;" Item 12, "Security Ownership of Certain Beneficial
Owners and Management;" and Item 13, "Certain Relationships and Related
Transactions," have been omitted from this report pursuant to the reduced
disclosure format permitted by General Instruction I to Form 10-K.

                                    PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

     (a) The following documents are filed as part of this report:

        1. Financial Statements.

             The following Consolidated Financial Statements are included in
        Part II, Item 8, of this report:

<TABLE>
<CAPTION>
PAGE
----
<S>                                                            <C>
Consolidated Statements of Income...........................     7
Consolidated Balance Sheets.................................     8
Consolidated Statements of Cash Flows.......................     9
Consolidated Statements of Stockholder's Equity.............    10
Notes to Consolidated Financial Statements..................    11
Independent Auditors' Report................................    19
</TABLE>

        2. Financial Statement Schedules.

             Schedules are omitted because they are not applicable.

        3. Exhibits.

<TABLE>
<CAPTION>
      EXHIBIT NO.                                DESCRIPTION
      -----------                                -----------
<C>                      <S>
          3.A            -- Certificate of Incorporation of ANR, as amended.
          3.B            -- By-Laws of ANR effective as of September 21, 1994.
          4.1            -- Indenture dated as of February 15, 1994 and First
                            Supplemental Indenture dated as of February 15, 1994
                            including the form of 7 3/8% Debentures
</TABLE>

     (b) Reports on Form 8-K:

          We filed a Current Report on Form 8-K dated February 2, 2001,
     announcing that we became an indirect subsidiary of El Paso Corporation as
     a result of the merger of a wholly owned subsidiary of El Paso with The
     Coastal Corporation.

                                        20
<PAGE>   23

                                   SIGNATURES

     Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, as amended, ANR Pipeline Company has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized
on the 29th day of March 2001.

                                                ANR PIPELINE COMPANY

                                                By:    /s/ E. J. HOLM
                                                --------------------------------
                                                           E. J. Holm
                                                    Chief Executive Officer

     Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, this report has been signed below by the following persons on behalf of
ANR Pipeline Company and in the capacities and on the dates indicated:

<TABLE>
<CAPTION>
                      SIGNATURE                                     TITLE                    DATE
                      ---------                                     -----                    ----
<C>                                                    <S>                              <C>

                   /s/ E. J. HOLM                      Chief Executive Officer          March 29, 2001
-----------------------------------------------------
                    (E. J. Holm)

             /s/ JOHN W. SOMERHALDER II                Chairman of the Board and        March 29, 2001
-----------------------------------------------------    Director
              (John W. Somerhalder II)

                 /s/ GREG G. GRUBER                    Senior Vice President and Chief  March 29, 2001
-----------------------------------------------------    Financial Officer
                  (Greg G. Gruber)

                /s/ JEFFREY I. BEASON                  Senior Vice President and        March 29, 2001
-----------------------------------------------------    Controller
                 (Jeffrey I. Beason)                     (Principal Accounting
                                                         Officer)

                 /s/ H. BRENT AUSTIN                   Executive Vice President and     March 29, 2001
-----------------------------------------------------    Director
                  (H. Brent Austin)

                 /s/ WILLIAM A. WISE                   Director                         March 29, 2001
-----------------------------------------------------
                  (William A. Wise)
</TABLE>

                                        21
<PAGE>   24

                                 EXHIBIT INDEX

<TABLE>
<CAPTION>
        EXHIBIT
         NUMBER                                    DOCUMENT
        -------                                    --------
<C>                      <S>
         *3.A            -- Certificate of Incorporation of ANR, as amended.
         *3.B            -- By-Laws of ANR effective as of September 21, 1994.
          4.A            -- 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. (Exhibit 4.4 to ANR's 1993 Form 10-K)
</TABLE>