1
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 8-K
CURRENT REPORT
Pursuant to Section 13 or 15(d) of
the Securities Exchange Act of 1934
February 16, 2001
(Date of earliest event reported)
KINDER MORGAN, INC.
(Exact name of registrant as specified in its charter)
KANSAS 1-6446 48-0290000
(State or other jurisdiction (Commission (I.R.S. Employer
of incorporation) File Number) Identification No.)
500 Dallas, Suite 1000
Houston, Texas 77002
(Address of principal executive offices, including zip code)
713-369-9000
(Registrant's telephone number, including area code)
2
Item 5. Other Events.
The following financial information of Kinder Morgan, Inc., a Kansas
corporation, is included herein commencing on page F-1:
(1) Financial statements as of December 31, 2000 and 1999, and for the
years ended December 31, 2000, 1999 and 1998;
(2) Quarterly financial information (unaudited) for 2000 and 1999:
(3) Selected financial data for each of the five years in the period ended
December 31, 2000;
(4) Management's discussion and analysis of financial condition and
results of operation;
(5) Quantitative and qualitative disclosures about market risk; and
(6) Schedule II - Valuation and Qualifying Accounts.
The consolidated financial statements and related notes of Kinder Morgan Energy
Partners, L.P. (an equity method investee of Kinder Morgan, Inc.) included as
exhibit 99.1 in its Form 8-K filing dated February 16, 2001 are filed herewith
as exhibit 99.1 and are incorporated herein by reference.
Item 7. Financial Statements and Exhibits
23.1 Consent of PricewaterhouseCoopers LLP
23.2 Consent of Arthur Andersen LLP
99.1 Form 8-K of Kinder Morgan Energy Partners, L.P. dated February 16,
2001, including the consolidated financial statements of Kinder Morgan
Energy Partners, L.P.
3
REPORT OF INDEPENDENT ACCOUNTANTS
To the Board of Directors
and Stockholders of Kinder Morgan, Inc.
In our opinion, the accompanying consolidated balance sheets and the related
consolidated statements of income, of comprehensive income, of stockholders'
equity and of cash flows present fairly, in all material respects, the financial
position of Kinder Morgan, Inc. (formerly K N Energy, Inc.) and its subsidiaries
at December 31, 2000 and 1999, and the results of their operations and their
cash flows for the years then ended in conformity with accounting principles
generally accepted in the United States of America. In addition, in our opinion,
the financial statement schedule listed in the index appearing under Item 5 of
this Form 8-K presents fairly, in all material respects, the information set
forth therein when read in conjunction with the related consolidated financial
statements. 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 of these statements in
accordance with auditing standards generally accepted in the United States of
America, which 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, assessing the
accounting principles used and significant estimates made by management, and
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
We also audited the adjustments described in Note 2 that were applied to restate
the 1998 consolidated financial statements. In our opinion, such adjustments are
appropriate and have been properly applied.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
February 14, 2001
F-1
4
REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS
To Kinder Morgan, Inc.:
We have audited the accompanying consolidated statements of income,
comprehensive income, stockholders' equity, and cash flows of Kinder Morgan,
Inc. (formerly K N Energy, Inc. and a Kansas corporation) and subsidiaries for
the year ended December 31, 1998 prior to the restatement (and, therefore, are
not presented herein) for the retroactive application of the equity method of
accounting for an investment as described in Note 2 to the restated financial
statements. 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 audit.
We conducted our audit in accordance with auditing standards generally accepted
in the United States. 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 audit provides a reasonable basis for our
opinion.
In our opinion, the consolidated financial statements referred to above present
fairly, in all material respects, the results of operations and cash flows of
Kinder Morgan, Inc. and subsidiaries for the year ended December 31, 1998, in
conformity with accounting principles generally accepted in the United States.
/s/ Arthur Andersen LLP
Denver, Colorado
February 2, 1999 (except with respect to the matters discussed in Note 6, as to
which the dates are March 16, 2000 and February 14, 2001)
F-2
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CONSOLIDATED STATEMENTS OF INCOME
KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
---------------------------------------------
RESTATED - SEE NOTE 2
----------------------------
2000 1999 1998
----------- ----------- -----------
(In Thousands Except Per Share Amounts)
OPERATING REVENUES:
Natural Gas Sales $ 1,999,648 $ 1,004,097 $ 955,254
Natural Gas Transportation and Storage 596,774 745,179 640,906
Other 117,315 87,092 64,099
----------- ----------- -----------
Total Operating Revenues 2,713,737 1,836,368 1,660,259
----------- ----------- -----------
OPERATING COSTS AND EXPENSES:
Gas Purchases and Other Costs of Sales 1,960,083 1,050,250 836,614
Operations and Maintenance 164,286 184,888 170,035
General and Administrative 58,087 85,591 68,502
Depreciation and Amortization 108,165 147,933 155,363
Taxes, Other Than Income Taxes 27,973 34,561 28,290
Merger-related and Severance Costs -- 37,443 5,763
----------- ----------- -----------
Total Operating Costs and Expenses 2,318,594 1,540,666 1,264,567
----------- ----------- -----------
OPERATING INCOME 395,143 295,702 395,692
----------- ----------- -----------
OTHER INCOME AND (EXPENSES):
Kinder Morgan Energy Partners:
Equity in Earnings 140,913 15,733 --
Amortization of Excess Investment (28,317) (7,335) --
Equity in Earnings (Losses) of Other Equity Investments (6,586) 24,651 31,141
Interest Expense, Net (243,155) (251,920) (205,840)
Minority Interests (24,121) (24,845) (19,483)
Other, Net 72,565 194,405 21,395
----------- ----------- -----------
Total Other Income and (Expenses) (88,701) (49,311) (172,787)
----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES 306,442 246,391 222,905
Income Taxes 122,727 90,733 82,710
----------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS 183,715 155,658 140,195
----------- ----------- -----------
DISCONTINUED OPERATIONS, NET OF TAX:
Loss from Discontinued Operations -- (50,941) (77,984)
Loss on Disposal of Discontinued Operations (31,734) (344,378) --
----------- ----------- -----------
Total Loss From Discontinued Operations (31,734) (395,319) (77,984)
----------- ----------- -----------
NET INCOME (LOSS) 151,981 (239,661) 62,211
Less - Preferred Dividends -- 129 350
Less - Premium Paid on Preferred Stock Redemption -- 350 --
----------- ----------- -----------
EARNINGS (LOSS) AVAILABLE FOR COMMON STOCK $ 151,981 $ (240,140) $ 61,861
=========== =========== ===========
Number of Shares Used in Computing Basic
Earnings Per Common Share (Thousands) 114,063 80,284 64,021
=========== =========== ===========
BASIC EARNINGS (LOSS) PER COMMON SHARE:
Continuing Operations $ 1.61 $ 1.93 $ 2.19
Loss from Discontinued Operations -- (0.63) (1.22)
Loss on Disposal of Discontinued Operations (0.28) (4.29) --
----------- ----------- -----------
Total Basic Earnings (Loss) Per Common Share $ 1.33 $ (2.99) $ 0.97
=========== =========== ===========
Number of Shares Used in Computing Diluted
Earnings Per Common Share (Thousands) 115,030 80,358 64,636
=========== =========== ===========
DILUTED EARNINGS (LOSS) PER COMMON SHARE:
Continuing Operations 1.60 1.93 2.17
Loss from Discontinued Operations -- (0.63) (1.21)
Loss on Disposal of Discontinued Operations (0.28) (4.29) --
----------- ----------- -----------
Total Diluted Earnings (Loss) Per Common Share $ 1.32 $ (2.99) $ 0.96
=========== =========== ===========
DIVIDENDS PER COMMON SHARE $ 0.20 $ 0.65 $ 0.76
=========== =========== ===========
The accompanying notes are an integral part of these statements.
F-3
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CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
--------------------------------------
RESTATED - SEE NOTE 2
------------------------
2000 1999 1998
--------- --------- ---------
(In Thousands)
NET INCOME (LOSS) 151,981 (239,661) 62,211
Realized Gain on Equity Securities, Net of Tax 1,602 852 --
Unrealized Loss on Equity Securities, Net of Tax -- -- (6,697)
--------- --------- ---------
COMPREHENSIVE INCOME (LOSS) $ 153,583 $(238,809) $ 55,514
========= ========= =========
The accompanying notes are an integral part of these statements.
F-4
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CONSOLIDATED BALANCE SHEETS
KINDER MORGAN, INC. AND SUBSIDIARIES
DECEMBER 31,
----------------------------
RESTATED
SEE NOTE 2
-----------
2000 1999
----------- -----------
(In Thousands)
ASSETS
CURRENT ASSETS:
Cash and Cash Equivalents $ 141,923 $ 26,378
Restricted Deposits 14,063 51
Customer Accounts Receivable, Net 104,209 298,805
Receivable From Kinder Morgan Energy Partners -- 330,000
Other Receivables 64,309 7,646
Inventories 19,600 50,328
Gas Imbalances 40,838 51,024
Other 48,700 19,154
Net Current Assets of Discontinued Operations -- 58,991
----------- -----------
433,642 842,377
----------- -----------
INVESTMENTS:
Kinder Morgan Energy Partners 1,850,397 1,791,768
Other 143,698 132,971
----------- -----------
1,994,095 1,924,739
----------- -----------
PROPERTY, PLANT AND EQUIPMENT, NET 5,724,617 5,789,564
----------- -----------
DEFERRED CHARGES AND OTHER ASSETS 265,751 209,758
----------- -----------
NET NON-CURRENT ASSETS OF DISCONTINUED OPERATIONS -- 659,236
----------- -----------
TOTAL ASSETS $ 8,418,105 $ 9,425,674
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current Maturities of Long-term Debt $ 808,167 $ 7,167
Notes Payable 100,000 574,400
Accounts Payable 126,267 224,625
Accounts Payable - Kinder Morgan Energy Partners 13,534 --
Accrued Interest 72,222 73,000
Accrued Taxes 26,584 36,075
Gas Imbalances 39,496 74,992
Payable for Purchase of Thermo Companies 15,000 44,320
Reserve for Loss on Disposal of Discontinued Operations 23,694 535,630
Other 143,761 133,620
----------- -----------
1,368,725 1,703,829
----------- -----------
OTHER LIABILITIES AND DEFERRED CREDITS:
Deferred Income Taxes 2,284,496 2,231,224
Other 208,570 242,926
----------- -----------
2,493,066 2,474,150
----------- -----------
LONG-TERM DEBT 2,478,983 3,293,326
----------- -----------
KINDER MORGAN-OBLIGATED MANDATORILY REDEEMABLE PREFERRED CAPITAL TRUST
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY DEBENTURES OF KINDER MORGAN 275,000 275,000
----------- -----------
MINORITY INTERESTS IN EQUITY OF SUBSIDIARIES 4,910 9,523
----------- -----------
COMMITMENTS AND CONTINGENT LIABILITIES (NOTES 9 AND 17)
STOCKHOLDERS' EQUITY:
Preferred Stock (Note 13) -- --
Common Stock-
Authorized - 150,000,000 Shares, Par Value $5 Per Share
Outstanding - 114,578,800 and 112,838,379 Shares,
Before Deducting 96,140 and 172,402 Shares Held in Treasury 572,894 564,192
Additional Paid-in Capital 1,189,270 1,203,008
Retained Earnings (Deficit) 37,584 (91,610)
Other, Including Shares Held in Treasury (2,327) (5,744)
----------- -----------
Total Stockholders' Equity 1,797,421 1,669,846
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY $ 8,418,105 $ 9,425,674
=========== ===========
The accompanying notes are an integral part of these statements.
F-5
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CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
KINDER MORGAN, INC. AND SUBSIDIARIES
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------
2000 1999 1998
------------------------- ------------------------- -------------------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
----------- ----------- ----------- ----------- ----------- -----------
(Dollars In Thousands)
PREFERRED STOCK:
Beginning Balance -- $ -- 70,000 $ 7,000 70,000 $ 7,000
Redemption of Preferred Stock -- -- (70,000) (7,000) -- --
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance -- -- -- -- 70,000 7,000
----------- ----------- ----------- ----------- ----------- -----------
COMMON STOCK:
Beginning Balance 112,838,379 564,192 68,645,906 343,230 32,024,557 160,123
Sale of Common Stock, Net -- -- -- -- 12,500,000 62,500
Acquisition of Kinder Morgan Delaware -- -- 41,683,323 208,417 -- --
Acquisitions/Sales of Other Businesses 946,207 4,731 2,065,909 10,330 689,810 3,449
Employee and Executive Benefit Plans 794,214 3,971 443,241 2,215 549,570 2,758
Common Stock Split -- -- -- -- 22,881,969 114,400
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance 114,578,800 572,894 112,838,379 564,192 68,645,906 343,230
----------- ----------- ----------- ----------- ----------- -----------
ADDITIONAL PAID-IN CAPITAL:
Beginning Balance 1,203,008 694,223 266,435
Sale of Common Stock, Net -- -- 558,053
Costs Related to PEPS Offering (1,151) (514) (62,150)
Revaluation of KMEP Investment (Note 5) (51,074) -- --
Acquisition of Kinder Morgan Delaware -- 470,831 --
Acquisition of Other Businesses 23,824 34,670 30,985
Employee and Executive Benefit Plans 14,663 3,798 15,371
Common Stock Split -- -- (114,471)
----------- ----------- -----------
Ending Balance 1,189,270 1,203,008 694,223
----------- ----------- -----------
RETAINED EARNINGS (DEFICIT):
Beginning Balance - as Previously
Reported (95,615) 193,925 185,658
Restatement (Note 2) 4,005 2,222 --
----------- ----------- -----------
Beginning Balance - As Restated (91,610) 196,147 185,658
Net Income (Loss) - as Previously
Reported 151,981 (241,444) 59,989
Restatement (Note 2) -- 1,783 2,222
Cash Dividends:
Common (22,787) (47,967) (51,372)
Preferred -- (129) (350)
----------- ----------- -----------
Ending Balance 37,584 (91,610) 196,147
----------- ----------- -----------
OTHER:
DEFERRED COMPENSATION:
Beginning Balance -- (10,686) (9,203)
Executive Benefit Plans -- 10,686 (1,483)
----------- ----------- -----------
Ending Balance -- -- (10,686)
----------- ----------- -----------
TREASURY STOCK, AT COST:
Beginning Balance (172,402) (4,142) (48,598) (1,417) (28,482) (1,124)
Treasury Stock Acquired (1,743) (62) (135,510) (2,956) (60,994) (2,834)
Treasury Stock Issued 78,005 1,877 -- -- -- --
Acquisition of Businesses -- -- -- -- 39,970 1,801
Dividend Reinvestment Plan -- -- 11,706 231 17,135 740
Common Stock Split -- -- -- -- (16,227) --
----------- ----------- ----------- ----------- ----------- -----------
Ending Balance (96,140) (2,327) (172,402) (4,142) (48,598) (1,417)
----------- ----------- ----------- ----------- ----------- -----------
ACCUMULATED OTHER COMPREHENSIVE
INCOME (NET OF TAX):
Beginning Balance (1,602) (2,454) 4,243
Sale of Tom Brown, Inc. Common Stock 1,602 -- --
Unrealized Gain (Loss) on Equity Securities -- 852 (6,697)
----------- ----------- -----------
Ending Balance -- (1,602) (2,454)
----------- ----------- -----------
TOTAL OTHER (96,140) (2,327) (172,402) (5,744) (48,598) (14,557)
----------- ----------- ----------- ----------- ----------- -----------
TOTAL STOCKHOLDERS' EQUITY 114,482,660 $ 1,797,421 112,665,977 $ 1,669,846 68,597,308 $ 1,226,043
=========== =========== =========== =========== =========== ===========
The accompanying notes are an integral part of these statements.
F-6
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CONSOLIDATED STATEMENTS OF CASH FLOWS
KINDER MORGAN, INC. AND SUBSIDIARIES
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS YEAR ENDED DECEMBER 31,
---------------------------------------------
2000 1999 1998
----------- ----------- -----------
(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net Income (Loss) $ 151,981 $ (239,661) $ 62,211
Adjustments to Reconcile Net Income (Loss) to
Net Cash Flows from Operating Activities:
Loss from Discontinued Operations, Net of Tax 31,734 395,319 77,984
Depreciation and Amortization 108,165 147,933 155,363
Deferred Income Taxes 105,424 57,609 24,516
Equity in Earnings of Kinder Morgan Energy Partners (112,596) -- --
Distributions from Kinder Morgan Energy Partners 121,323 15,000 --
Deferred Purchased Gas Costs 2,685 6,646 468
Net Gains on Sales of Facilities (61,684) (189,778) (19,552)
Proceeds from Buyout of Contractual Gas Obligations -- -- 27,500
Changes in Other Working Capital Items [Note 1(M)] (48,466) 36,119 (40,506)
Changes in Deferred Revenues (4,457) (15,641) 6,300
Other, Net (16,622) 13,142 (7,242)
----------- ----------- -----------
Net Cash Flows Provided by Continuing Operations 277,487 226,688 287,042
Net Cash Flows Provided by (Used in) Discontinued Operations (110,399) 94,488 (191,773)
----------- ----------- -----------
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES 167,088 321,176 95,269
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital Expenditures (137,477) (97,644) (120,881)
Proceeds from Sales to Kinder Morgan Energy Partners 500,302 -- --
Cash Paid for Acquisition of MidCon Corp., Net of Cash Acquired -- -- (2,191,555)
Other Acquisitions (19,412) (34,565) 1,086
Investments (28,688) (10,044) (9,179)
Proceeds from Sale of Tom Brown, Inc. Stock 14,823 28,650 --
Sale of U.S. Government Securities -- 1,092,415 1,062,453
Purchase of U.S. Government Securities -- -- (2,154,868)
Proceeds from Sales of Other Assets 14,998 87,949 38,634
----------- ----------- -----------
Net Cash Flows Provided By (Used In) Continuing Investing Activities 344,546 1,066,761 (3,374,310)
Net Cash Flows Provided By (Used In) Discontinued Investing Activities 154,176 (46,568) (119,100)
----------- ----------- -----------
NET CASH FLOWS PROVIDED BY (USED IN) INVESTING ACTIVITIES 498,722 1,020,193 (3,493,410)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Short-Term Debt, Net (474,400) (1,117,446) (32,687)
Long-Term Debt - Issued -- -- 2,750,000
Long-Term Debt - Retired (14,055) (158,934) (35,787)
Common Stock Issued in Public Offering -- -- 650,000
Other Common Stock Issued 17,773 8,323 13,437
Other Financing, Net (45,239) -- --
Mandatorily Redeemable Trust Securities Issued -- -- 175,000
Preferred Stock Redeemed -- (7,350) --
Treasury Stock, Issued 1,877 231 740
Treasury Stock, Acquired (62) (2,956) (2,834)
Cash Dividends, Common and Preferred (22,787) (48,096) (51,722)
Minority Interests, Net (2,436) 379 9,697
Premium Equity Participating Securities Contract Fee and Securities
Issuance Costs (10,936) (11,097) (78,219)
----------- ----------- -----------
NET CASH FLOWS (USED IN) PROVIDED BY FINANCING ACTIVITIES (550,265) (1,336,946) 3,397,625
----------- ----------- -----------
Net Increase (Decrease) in Cash and Cash Equivalents 115,545 4,423 (516)
Cash and Cash Equivalents at Beginning of Year 26,378 21,955 22,471
----------- ----------- -----------
Cash and Cash Equivalents at End of Year $ 141,923 $ 26,378 $ 21,955
=========== =========== ===========
The accompanying notes are an integral part of these statements.
F-7
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
1. NATURE OF OPERATIONS AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(A) Nature of Operations
Kinder Morgan, Inc. is one of the largest midstream energy companies in America,
operating more than 30,000 miles of natural gas and products pipelines. Our
common stock is traded on the New York Stock Exchange under the ticker symbol
"KMI." We are an energy services provider and have operations in 16 states in
the Rocky Mountain and mid-continent regions, with principal operations in
Arkansas, Colorado, Illinois, Iowa, Kansas, Nebraska, Oklahoma, Texas and
Wyoming. Energy services we offer include: storing, transporting and selling
natural gas, providing retail natural gas distribution services, and generating
and selling electricity. We have both regulated and nonregulated operations.
During 1999, we made significant acquisitions, including Kinder Morgan Delaware.
As a result, through our general partner interest, we operate Kinder Morgan
Energy Partners, L.P., a publicly traded pipeline master limited partnership,
referred to in these Notes as "Energy Partners," and receive a substantial
portion of our earnings from returns on this investment.
In October 1999, K N Energy, Inc., (as we were then named) a Kansas corporation,
acquired Kinder Morgan, Inc., a Delaware corporation, referred to in these Notes
as "Kinder Morgan Delaware." We then changed our name to Kinder Morgan, Inc.
Unless the context requires otherwise, references to "we," "us," "our," or the
"Company" are intended to mean Kinder Morgan, Inc. (a Kansas corporation and
formerly known as K N Energy, Inc.) and its consolidated subsidiaries. During
the third and fourth quarters of 1999, we adopted and implemented plans to
discontinue our businesses involved in (i) wholesale marketing of natural gas
and natural gas liquids, (ii) gathering and processing of natural gas, including
field services and short-haul intrastate pipelines, (iii) direct marketing of
non-energy products and services and (iv) international operations. During the
fourth quarter of 2000, we decided that, due to the start-up nature of these
operations and the unwillingness of buyers to pay for the value created to date,
it was not in the best interests of the Company to dispose of our international
operations and, accordingly, we decided to retain them. Additional information
concerning these discontinued operations is contained in Note 6.
(B) Basis of Presentation
The preparation of financial statements in conformity with generally accepted
accounting principles requires management to make estimates and assumptions.
These estimates and assumptions affect the reported amounts of assets and
liabilities, the disclosure of contingent assets and liabilities, and the
reported amounts of revenues and expenses. Actual results could differ from
these estimates.
The consolidated financial statements include the accounts of Kinder Morgan,
Inc. and its majority-owned subsidiaries. Investments in jointly owned
operations in which we have the ability to exercise significant influence over
their operating and financial policies are accounted for under the equity
method, as is our investment in Energy Partners, which is further described in
Note 2. All material intercompany transactions and balances have been
eliminated. Certain prior year amounts have been reclassified to conform to the
current presentation.
(C) Accounting for Regulatory Activities
Our regulated public utilities are accounted for in accordance with the
provisions of Statement of Financial Accounting Standards ("SFAS") No. 71,
"Accounting for the Effects of Certain Types of Regulation," which prescribes
the circumstances in which the application of generally accepted accounting
principles is affected by the economic effects of regulation.
F-8
11
Regulatory assets and liabilities represent probable future revenues or expenses
associated with certain charges and credits that will be recovered from or
refunded to customers through the ratemaking process. The following regulatory
assets and liabilities are reflected in the accompanying Consolidated Balance
Sheets:
DECEMBER 31,
---------------------
2000 1999
-------- --------
(In Thousands)
REGULATORY ASSETS:
Employee Benefit Costs $ 6,576 $ 6,909
Debt Refinancing Costs 1,664 1,992
Deferred Income Taxes 16,801 16,853
Purchased Gas Costs 23,470 27,043
Plant Acquisition Adjustments 454 454
Rate Regulation and Application Costs 3,040 3,095
-------- --------
Total Regulatory Assets 52,005 56,346
-------- --------
REGULATORY LIABILITIES:
Employee Benefit Costs 5,967 5,967
Deferred Income Taxes 28,930 31,235
Purchased Gas Costs 14,415 25,926
-------- --------
Total Regulatory Liabilities 49,312 63,128
-------- --------
NET REGULATORY ASSETS (LIABILITIES) $ 2,693 $ (6,782)
======== ========
As of December 31, 2000, $45.0 million of our regulatory assets and $43.3
million of our regulatory liabilities were being recovered from or refunded to
customers through rates over periods ranging from 1 to 13 years.
(D) Revenue Recognition Policies
We recognize revenues as services are rendered or goods are delivered and, if
applicable, title has passed. Our rate-regulated retail natural gas distribution
business bills customers on a monthly cycle billing basis. Revenues are recorded
on an accrual basis, including an estimate at the end of each accounting period
for gas delivered and, if applicable, title has passed but for which bills have
not yet been rendered. With respect to our construction activities, we utilize
the percentage of completion method whereby revenues and associated expenses are
recognized over the construction period based on work performed in relation to
the total expected for the entire project.
(E) Earnings Per Share
Basic earnings per share is computed based on the monthly weighted-average
number of common shares outstanding during each period. Diluted earnings per
share is computed based on the monthly weighted-average number of common shares
outstanding during the periods, increased by the assumed exercise or conversion
of securities (stock options and premium equity participating security units)
convertible into common stock for which the effect of conversion or exercise
using the treasury stock method would be dilutive. Dilutive securities assumed
to have been converted or exercised totaled 967,700 for 2000, 73,800 for 1999
and 614,500 for 1998. Remaining stock options outstanding totaling 307,100 for
2000, 3,824,000 for 1999 and 785,000 for 1998 were not included in the earnings
per share calculation because to do so would have been antidilutive. Note 12(B)
contains more information regarding premium equity participating security units,
while Note 16 contains more information regarding stock options.
F-9
12
(F) Restricted Deposits
Restricted Deposits consist of monies on deposit with brokers that are
restricted to meet exchange trading requirements; see Note 14.
(G) Inventories
DECEMBER 31,
-------------------
2000 1999
------- -------
(In Thousands)
Gas in Underground Storage (Current) $ 5,145 $38,499
Materials and Supplies 14,455 11,829
------- -------
$19,600 $50,328
======= =======
Inventories are accounted for using the following methods, with the percent of
the total dollars at December 31, 2000 shown in parentheses: average cost
(85.32%), last-in, first-out (10.26%) and first-in, first-out (4.42%). All
non-utility inventories held for resale are valued at the lower of cost or
market. We also maintain gas in our underground storage facilities on behalf of
certain third parties. We receive a fee from our storage service customers but
do not reflect the value of their gas stored in our facilities in the
accompanying Consolidated Balance Sheets.
(H) Other Investments
DECEMBER 31,
---------------------
2000 1999
-------- --------
(In Thousands)
Thermo Companies $ 72,457 $ 63,528
TransColorado Pipeline Company 34,824 31,160
Tom Brown, Inc. Common Stock (Note 5) -- 12,283
Other 36,417 26,000
-------- --------
$143,698 $132,971
======== ========
Investments consist primarily of equity method investments in unconsolidated
subsidiaries and joint ventures, and include ownership interests in net profits
and net cash flows. At December 31, 2000, "Other" included a $13.5 million
investment in Wrightsville Development, LLC, a $6.0 million investment in
Igasamex USA, Ltd, a $5.3 million investment in Front Range Holding, LLC, and
approximately $4.5 million in assets held for deferred employee compensation,
among other individually insignificant items. At December 31, 1999, "Other"
included a $10.4 million investment in Front Range Holding, LLC, a $6.3 million
investment in Igasamex USA, Ltd, and approximately $4.9 million in assets held
for deferred employee compensation, among other individually insignificant
items.
(I) Property, Plant and Equipment
Property, plant and equipment is stated at historical cost, which for
constructed plant includes indirect costs such as payroll taxes, fringe
benefits, administrative and general costs. Expenditures that increase
capacities, improve efficiencies or extend useful lives are capitalized. Routine
maintenance, repairs and renewal costs are expensed as incurred. The cost of
normal retirements of depreciable utility property, plant and equipment, plus
the cost of removal less salvage, is recorded in accumulated depreciation with
no effect on current period earnings. Gains or losses are recognized upon
retirement of non-utility property, plant and equipment, and utility property,
plant and equipment constituting an operating unit or system, when sold or
abandoned.
F-10
13
In accordance with the provisions of SFAS 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," we review the
carrying values of our long-lived assets whenever events or changes in
circumstances indicate that such carrying values may not be recoverable. As yet,
no asset or group of assets has been identified for which the sum of expected
future cash flows (undiscounted and without interest charges) is less than the
carrying amount of the asset(s) and, accordingly, no impairment losses have been
recorded. However, currently unforeseen events and changes in circumstances
could require the recognition of impairment losses at some future date.
(J) Depreciation and Amortization
Depreciation is computed based on the straight-line method over the estimated
useful lives of assets. The range of estimated useful lives used in depreciating
assets for each property type are as follows:
PROPERTY TYPE RANGE OF ESTIMATED USEFUL LIVES OF ASSETS
------------- -----------------------------------------
(In Years)
Natural Gas Pipelines 24 to 68 (Transmission assets: average 56)
Retail Natural Gas Distribution 33
Power Generation 10 to 30
General and Other 3 to 56
(K) Interest Expense, Net
"Interest Expense, Net" as presented in the accompanying Consolidated Statements
of Income is net of (i) the debt component of the allowance for funds used
during construction ("AFUDC - Interest"), (ii) in 1999, interest income related
to government securities associated with the acquisition of MidCon Corp. and
(iii) in 2000, interest income attributable to (i) our note receivable from
Energy Partners associated with the sale of certain interests (see Note 5) and
(ii) interest income associated with settlement of our net cash position with
ONEOK, Inc.; see (N).
YEAR ENDED DECEMBER 31,
-------------------------------
2000 1999 1998
------- ------- -------
(In Millions)
AFUDC - Interest $ 2.6 $ 1.9 $ 2.3
Interest Income $ 2.6 $ 0.5 $ 46.4
As discussed in Note 2, in conjunction with the January 30, 1998, acquisition of
MidCon Corp., we were required by the definitive stock purchase agreement to
assume the Substitute Note for $1.4 billion and to collateralize the Substitute
Note with bank letters of credit, a portfolio of government securities or a
combination of the two. As a result, we had a significant amount of interest
income during 1998 associated with the issuance of the Substitute Note, which
has been reported together with the related interest expense as described above.
In conjunction with our sale of certain assets to ONEOK as discussed in Note 6,
we agreed to continue managing cash for these assets for a period of months,
following which an audit was conducted to affirm the assignment of specific
amounts to the two parties based on the timing of the underlying business
transactions. We reported the interest income attributable to our net receivable
resulting from this transaction together with the related interest expense as
described above.
(L) Other, Net
"Other, Net" as presented in the accompanying Consolidated Statements of Income
includes $61.7 million, $189.8 million and $19.6 million in 2000, 1999 and 1998,
respectively, attributable to gains from sales of assets. These transactions are
discussed in Note 5.
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14
(M) Cash Flow Information
We consider all highly liquid investments purchased with an original maturity of
three months or less to be cash equivalents. "Other, Net," presented as a
component of "Net Cash Flows From Operating Activities" in the accompanying
Consolidated Statements of Cash Flows includes, among other things,
undistributed equity in earnings of unconsolidated subsidiaries and joint
ventures (other than Energy Partners) and other non-cash charges and credits to
income.
ADDITIONAL CASH FLOW INFORMATION:
CHANGES IN OTHER WORKING CAPITAL ITEMS:
(NET OF EFFECTS OF ACQUISITIONS AND SALES)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS
YEAR ENDED DECEMBER 31,
---------------------------------------
2000 1999 1998
--------- --------- ---------
(In Thousands)
Accounts Receivable $(172,781) $ (16,483) $ (19,626)
Material and Supplies Inventory (2,626) 2,894 (962)
Gas in Underground Storage - Current 32,453 (17,626) 6,598
Other Current Assets (27,737) 114 3,329
Accounts Payable 114,908 37,506 (68,774)
Other Current Liabilities 7,317 29,714 38,929
--------- --------- ---------
$ (48,466) $ 36,119 $ (40,506)
========= ========= =========
SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:
YEAR ENDED DECEMBER 31,
--------------------------------------
2000 1999 1998
--------- --------- ---------
(In Thousands)
CASH PAID FOR:
Interest (Net of Amount Capitalized) $ 248,177 $ 284,762 $ 189,929
========= ========= =========
Distributions on Preferred Capital Trust Securities $ 21,913 $ 21,913 $ 14,754
========= ========= =========
Income Taxes Paid (Received) $ 7,674 $ (10,883) $ 39,756
========= ========= =========
In April 2000, we made the final scheduled payment for our third-quarter 1998
acquisition of interests in the Thermo Companies using 961,153 shares of our
common stock, approximately $30 million of value. For our December 31, 2000 sale
of assets to Energy Partners, we received both cash and non-cash consideration;
see Note 5. In October 1999, we acquired Kinder Morgan Delaware in a non-cash
transaction. During 1998, we acquired MidCon Corp. and interests in assets from
the Thermo Companies in transactions that included both cash and non-cash
components. For additional information on these transactions, see Note 2.
(N) Accounts Receivable
The caption "Customer Accounts Receivable, Net" in the accompanying Consolidated
Balance Sheets is presented net of allowances for doubtful accounts of $2.3
million and $1.7 million at December 31, 2000 and 1999, respectively. The
caption "Other Receivables" principally consists of a receivable from ONEOK
due to cash management services provided to them during 2000 in conjunction
with their purchase of certain of our assets as discussed in Note 6.
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15
(O) Stock-Based Compensation
SFAS 123, "Accounting for Stock-Based Compensation," encourages, but does not
require, entities to adopt the fair value method of accounting for stock-based
compensation plans. As allowed under SFAS 123, we continue to apply Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees."
Accordingly, compensation expense is not recognized for stock options unless the
options are granted at an exercise price lower than the market price on the
grant date.
(P) Accounting for Certain Equity Transactions by Affiliates
We account for our investment in Energy Partners (among other entities) under
the equity method of accounting. In each accounting period, we record our share
of these investees' earnings, and amortize any "excess" investment. We adjust
the amount of our excess investment when an equity method investee or a
consolidated subsidiary issues additional equity (or reacquires equity shares)
in any manner that alters our ownership percentage. Differences between the per
unit sales proceeds from these equity issuances (or reacquisitions) and our
underlying book basis, as well as the pro rata portion of the excess investment
(including associated deferred taxes), are recorded directly to paid-in capital
rather than being recognized as gains or losses. Two such transactions are
described in Note 5.
(Q) Accounting for Risk Management Activities
We utilize energy derivatives for the purpose of mitigating our risk resulting
from fluctuations in the market price of natural gas and associated
transportation. Prior to December 31, 2000, our accounting policy for these
activities was based on a number of authoritative pronouncements including SFAS
No. 80, "Accounting for Futures Contracts." This policy is described in detail
in Note 14, as is our new policy, which is based on the accounting standard
which became effective for us on January 1, 2001, SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities."
(R) Income Taxes
Deferred income tax assets and liabilities are recognized for temporary
differences between the basis of assets and liabilities for financial reporting
and tax purposes. Changes in tax legislation are included in the relevant
computations in the period in which such changes are effective. Deferred tax
assets are reduced by a valuation allowance for the amount of any tax benefit we
do not expect to be realized.
2. BUSINESS COMBINATIONS
On October 7, 1999, we completed the acquisition of Kinder Morgan Delaware, the
sole stockholder of the general partner of Energy Partners. Energy Partners is
the nation's largest pipeline master limited partnership. It owns and operates
one of the largest product pipeline systems in the United States, delivering
gasoline, diesel and jet fuel to customers through more than 10,000 miles of
pipeline and over 20 associated terminals. Additional assets include 10,000
miles of natural gas transportation pipelines; natural gas gathering and storage
facilities; 28 bulk terminal facilities, which transload more than 40 million
tons of coal, petroleum coke and other products annually; and Kinder Morgan CO2
Company, L.P.
To effect the business combination, we issued approximately 41.5 million shares
of our common stock in exchange for all of the outstanding shares of Kinder
Morgan Delaware. Upon closing of the transaction, Richard D. Kinder, Chairman
and Chief Executive Officer of Kinder Morgan Delaware, was named our Chairman
and Chief Executive Officer, and we were renamed Kinder Morgan, Inc. In
addition, we issued 200,000 shares of our common stock to Petrie Parkman & Co.,
Inc. in consideration for Petrie Parkman's
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16
advisory services rendered in connection with the acquisition of Kinder Morgan
Delaware. The issuance of these shares was exempt from registration under
Section 4(2) of the Securities Act of 1933, as amended.
This acquisition was accounted for as a purchase for accounting purposes and,
accordingly, the assets acquired and liabilities assumed were recorded at their
respective estimated fair market values as of the acquisition date. The
allocation of the purchase price resulted in an excess of the purchase price
over Kinder Morgan Delaware's share of the underlying equity in the net assets
of Energy Partners totaling $1.3 billion. This excess has been fully allocated
to the Kinder Morgan Delaware investment in Energy Partners and reflects the
estimated fair market value of this investment at the date of acquisition. This
excess investment is being amortized over 44 years, approximately the estimated
remaining useful life of Energy Partners' assets, and is shown in the
accompanying Consolidated Income Statements as "Amortization of Excess
Investment" under the sub-heading "Kinder Morgan Energy Partners" within "Other
Income and (Expenses)." The assets, liabilities and results of operations of
Kinder Morgan Delaware are included with those of Kinder Morgan beginning with
the October 7, 1999 acquisition date.
The following pro forma information gives effect to our acquisition of Kinder
Morgan Delaware as if the business combination had occurred January 1 of each
year presented. This unaudited pro forma information should be read in
conjunction with the accompanying consolidated financial statements. This pro
forma information does not necessarily indicate the financial results that would
have occurred if this acquisition had taken place on the dates indicated, nor
should it necessarily be viewed as an indicator of future financial results.
UNAUDITED PRO FORMA FINANCIAL INFORMATION
YEAR ENDED DECEMBER 31,
---------------------------------------------
1999 1998
----------- -----------
(Dollars in Millions Except Per Share Amounts)
Operating Revenues $ 1,745.5 $ 1,660.9
Net Income (Loss) $ (233.9) $ 62.5
Diluted Earnings (Loss) Per Common Share $ (2.09) $ 0.58
Number of Shares Used in Computing Diluted Earnings Per
Common Share (In Thousands) 112,334 106,319
During the third quarter of 1998, we completed our acquisition of interests in
four independent power plants in Colorado from the Denver-based Thermo
Companies, representing approximately 380 megawatts of electric generation
capacity and access to approximately 130 Bcf of natural gas reserves. These
generating facilities are located in Ft. Lupton, Colorado (272 megawatts) and
Greeley, Colorado (108 megawatts) and sell their power output to Public Service
Company of Colorado under long-term agreements. Payments for the Thermo
interests were made over a two-year period, with the initial payment of
1,034,715 shares of our common stock having been made on October 21, 1998.
Additional payments were made on January 4, 1999, consisting of 833,623 shares
of our common stock and $15 million in cash, on April 20, 1999, consisting of
1,232,286 shares of our common stock and $20 million in cash and on April 20,
2000, with 961,153 shares of our common stock. This transaction was accounted
for as a purchase. Under the purchase agreement, we were entitled, as soon as
the consent of the other partner was obtained, to become a partner in a 50/50
joint venture in which Thermo had previously been a partner and, in the interim,
to receive cash distributions from Thermo's former owners in lieu of our share
of the joint venture's earnings. In the fourth quarter of 2000, we obtained the
consent, became a partner in the venture and adopted the equity method of
accounting for this investment. We restated all prior periods to reflect the
equity method of accounting as required by the authoritative accounting
guidelines. This restatement had the effect of decreasing operating revenues by
$7.4 million and $4.9 million, increasing equity in earnings of unconsolidated
subsidiaries by $10.5 million and $8.7 million, and increasing income from
continuing operations by $1.8 million and $2.2 million, in each case for 1999
and 1998, respectively.
F-14
17
On January 30, 1998, we acquired all of the outstanding shares of capital stock
of MidCon Corp. from Occidental Petroleum Corporation for $2.1 billion in cash
and the assumption of a $1.4 billion short-term note (which was repaid in
January, 1999), at which time MidCon Corp. became our wholly owned subsidiary.
MidCon was an energy company engaged in the purchase, gathering, processing,
transmission and storage of natural gas and whose principal asset was Natural
Gas Pipeline Company of America (referred to as "Natural" in these notes). The
assets, liabilities and results of operations of MidCon are included with those
of Kinder Morgan beginning with the January 30, 1998 acquisition date. The
acquisition was initially financed through a combination of credit agreements;
see Note 12.
The acquisition was accounted for as a purchase for accounting purposes and,
accordingly, the MidCon assets acquired and liabilities assumed were recorded at
their fair market values as of the acquisition date. The allocation of purchase
price resulted in the recognition of a gas plant acquisition adjustment of
approximately $4.0 billion, principally representing the excess of the assigned
fair market value of the assets of Natural over the historical cost for
ratemaking purposes. This gas plant acquisition adjustment, none of which is
currently being recognized for rate-making purposes, is being amortized over 55
years (see Note 4), approximately the estimated remaining useful life of
Natural's interstate pipeline system. For the years ended December 31, 2000,
1999 and 1998, $73.3 million, $96.0 million and $97.9 million of such
amortization, respectively, was charged to expense; see Note 4.
The following pro forma information gives effect to our acquisition of MidCon
Corp. as if the business combination had occurred at January 1, 1998. This
unaudited pro forma information should be read in conjunction with the
accompanying consolidated financial statements. This pro forma information does
not necessarily indicate the financial results that would have occurred if this
acquisition had taken place on the date indicated, nor is it necessarily
comparable to subsequent financial results nor should it necessarily be viewed
as an indicator of future financial results.
UNAUDITED PRO FORMA FINANCIAL INFORMATION
(Dollars in Millions Except Per Share Amounts)
YEAR ENDED
DECEMBER 31,
1998
------------
Operating Revenues $ 4,655.9
Net Income $ 65.6
Diluted Earnings Per Common Share $ 1.01
Number of Shares Used in Computing Diluted Earnings Per Common Share (In Thousands) 64,636
On February 22, 1999, Sempra Energy and we announced that our respective boards
of directors had unanimously approved a definitive agreement under which Sempra
and we would combine in a stock-and-cash transaction valued in the aggregate at
$6.0 billion. On June 21, 1999, Sempra and we announced that we had mutually
agreed to terminate the merger agreement. Sempra reimbursed us $5.95 million for
expenses incurred in connection with the proposed merger.
3. MERGER-RELATED AND SEVERANCE COSTS
In anticipation of the completion of the transaction with Kinder Morgan
Delaware, during the third quarter of 1999, a number of our officers terminated
their employment with us, as did certain other employees. In addition, we
terminated the employment of a number of additional employees during the fourth
quarter of 1999 and in early 2000 as a result of cost saving initiatives
implemented following the closing of the Kinder Morgan Delaware transaction. In
total, approximately 150 employees were severed. In conjunction with these
terminations, we agreed to provide severance benefits and incurred certain legal
and other associated costs. Also in conjunction with the Kinder Morgan Delaware
transaction, we elected to discontinue certain projects,
F-15
18
consolidate certain facilities and relocate certain employees. The $37.4 million
pre-tax expense ($23.6 million after tax or $0.29 per diluted share) associated
with these matters (included in the accompanying Consolidated Income Statement
for 1999 under the caption "Merger-related and Severance Costs") was composed of
the following: (i) severance and relocation, including restricted stock -- $22.7
million, (ii) facilities costs, including moving expenses -- $5.3 million, (iii)
write-down/write-off of project costs -- $8.0 million and (iv) other -- $1.4
million. Of this total, approximately $9.4 million remained as an accrual at
December 31, 1999, all of which was expended during the first half of 2000. The
$5.8 million pre-tax expense ($3.6 million after tax or $0.06 per diluted share)
included under the same caption for the year ended December 31, 1998 represents
costs associated with our January 30, 1998 acquisition of MidCon Corp. For
additional information on these business combinations, see Note 2.
4. CHANGE IN ACCOUNTING ESTIMATE
Pursuant to a revised study of the useful lives of the underlying assets by an
independent third party, in July 1999, we changed the depreciation rates
associated with the gas plant acquisition adjustment recorded in conjunction
with the acquisition of MidCon Corp. Relative to the amounts which would have
been recorded utilizing the previous depreciation rates, this change had the
effect of decreasing "Depreciation and Amortization" by approximately $19.3
million for the year ended December 31, 1999. Consequently, "Income from
Continuing Operations" and "Net Income" were increased by approximately $12.1
million for the year ended December 31, 1999 ($0.15 per diluted common share).
5. INVESTMENTS AND SALES
See Note 6 for information regarding sales of assets and businesses included in
discontinued operations.
In December 2000, we sold approximately $300 million of assets to Energy
Partners effective December 31, 2000. The largest asset we sold was our wholly
owned subsidiary Kinder Morgan Texas Pipeline, Inc. and certain associated
entities (a major intrastate natural gas pipeline system). We also sold the
Douglas and Casper gas processing facilities and associated natural gas
gathering systems, our 50 percent interest in Coyote Gas Treating, LLC and our
25 percent interest in Thunder Creek Gas Services, L.L.C. As consideration for
the sale, we received approximately $150 million in cash (with an additional
cash payment for working capital), 0.6 million Energy Partners' common limited
partner units and 2.7 million Class-B Energy Partners' common limited partner
units. We recorded a pre-tax gain of $61.6 million (approximately $37.0 million
after tax or $0.32 per diluted share) in conjunction with this sale.
In August 2000, Kinder Morgan Power Company, one of our wholly owned
subsidiaries, announced plans to build a 550-megawatt electric power plant in
Jackson, Michigan. All necessary regulatory permits and approvals have been
obtained, and construction on the $250 million natural gas-fired plant has
begun. The plant is expected to begin producing power in June 2002. In May 2000,
Kinder Morgan Power announced another 550-megawatt facility that is currently
being constructed near Little Rock, Arkansas.
In April 2000, Energy Partners issued 4.5 million limited partnership units in a
public offering at a price of $39.75 per unit, receiving total net proceeds
(after underwriting discount) of $171.3 million. We did not acquire any of these
units. This transaction reduced our percentage ownership of Energy Partners from
approximately 19.9% to approximately 18.6% and had the associated effects of
increasing our investment in the net assets of Energy Partners by $6.1 million
and reducing (i) our excess investment in Energy Partners by $81.1 million, (ii)
associated accumulated deferred income taxes by $30.0 million, (iii) paid-in
capital by $45.0 million and (iv) the monthly amortization of the excess
investment by approximately $176 thousand. In February 2000, Energy Partners
issued approximately 0.6 million common units as consideration for acquiring all
the capital stock of Milwaukee Bulk Terminals, Inc. and Dakota Bulk Terminals,
Inc. This transaction
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19
reduced our percentage ownership of Energy Partners and had the associated
effects of increasing our investment in the net assets of Energy Partners by
$1.1 million and reducing (i) our excess investment in Energy Partners by $11.3
million, (ii) associated accumulated deferred income taxes by $4.1 million,
(iii) paid-in capital by $6.1 million and (iv) the monthly amortization of the
excess investment by approximately $21 thousand; see Notes 1(P) and 2.
In March 2000, we sold the 918,367 shares of Tom Brown, Inc. Common Stock we had
held since early 1996 (see the discussion of the sale of Tom Brown Preferred
Stock following). We recorded a pre-tax gain of $1.4 million ($0.8 million after
tax or approximately $0.01 per diluted share).
On December 30, 1999, we entered into an agreement with several of our wholly
owned subsidiaries and Energy Partners. As a result, effective as of December
31, 1999, we sold all of our interests in the following to Energy Partners: (i)
our wholly owned subsidiary, Kinder Morgan Interstate Gas Transmission LLC
(formerly K N Interstate Gas Transmission Co.), (ii) our wholly owned
subsidiary, Kinder Morgan Trailblazer LLC (formerly NGPL-Trailblazer, Inc.),
which owns a one-third interest in Trailblazer Pipeline Company and (iii) our
49% interest in Red Cedar Gathering Company. In exchange, Energy Partners issued
to us 9,810,000 common units representing limited partnership interest in Energy
Partners. In addition, Energy Partners paid us $330 million in cash in early
2000. We recorded a pre-tax gain of $158.8 million (approximately $100.9 million
after tax or $1.25 per diluted share) in conjunction with the sale of
interests.
On September 30, 1999, we sold (to an unaffiliated party) our interests in
Stingray Pipeline Company, L.L.C., an offshore pipeline that gathers natural
gas, and West Cameron Dehydration Company, L.L.C., which dehydrates natural gas
for shippers on the Stingray Pipeline. On June 30, 1999, we sold our interests
in the HIOS and UTOS offshore pipeline systems and related laterals to Leviathan
Gas Pipeline Partners, L. P. These two sales yielded total cash proceeds of
approximately $75.1 million, resulted in a total pretax gain of approximately
$28.9 million (approximately $17.6 million after tax or $0.25 per diluted
share), and substantially eliminated our investment in offshore assets.
On September 3, 1999, we sold 1,000,000 shares of preferred stock of Tom Brown,
Inc. for approximately $29 million in cash, realizing a gain of $2.2 million
(approximately $1.3 million after tax or $0.02 per diluted share).
In May 1999, we announced plans to build the Horizon Pipeline, which, through
our wholly owned subsidiary Natural, we planned to own jointly with one or more
other partners. An open season closed in June 1999 with service requests from
shippers of more than 800 MMcf of natural gas per day, including 300 MMcf per
day from Nicor Gas. In February 2000, Nicor, Inc. announced that it had signed
an agreement to become an equal partner in the planned Horizon Pipeline with
Natural. The Horizon Pipeline is a $75 million natural gas pipeline that will
originate in Joliet, Illinois and extend 74 miles into northern Illinois,
connecting the emerging supply hub at Joliet with Nicor Gas' distribution system
and an existing Natural pipeline.
On March 31, 1999, the TransColorado Gas Transmission Company ("TransColorado"),
an enterprise we jointly own with Questar Corp., placed in service a
280-mile-long natural gas pipeline. This pipeline includes two compressor
stations and extends from near Rangely, Colorado, to its southern terminus at
the Blanco Hub near Aztec, New Mexico. The pipeline has a design transmission
capacity of approximately 300 million cubic feet of natural gas per day. On
October 14, 1998, TransColorado entered into a $200 million revolving credit
agreement with a group of commercial banks. We provide a corporate guarantee for
one-half of all amounts borrowed under the agreement. Beginning 24 months after
the in-service date, Questar has the right, for a 12-month period, to require
that we purchase Questar's ownership interest in TransColorado for $121 million.
This right has been stayed; see Note 9.
In September 1998, we sold some of our microwave towers and associated land and
equipment to American Tower Corp., recognizing a pre-tax gain of $10.9 million
($6.7 million after tax or $0.10 per diluted share). In
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20
March 1998, we sold our Kansas retail natural gas distribution properties to
Midwest Energy, Inc., recognizing a pre-tax gain of $8.5 million ($5.2 million
after tax or $0.08 per diluted share). Concurrently with the sale, we received
$27.5 million in cash in exchange for release of the purchaser from certain
contractual gas purchase obligations, which amount is being amortized as an
offset to gas purchases over a period of years as the associated volumes are
sold.
6. DISCONTINUED OPERATIONS
Prior to mid-1999, we had major business operations in the upstream (gathering
and processing), midstream (natural gas pipelines) and downstream (wholesale and
retail marketing) portions of the natural gas industry and, in addition, had (i)
non-energy retail marketing operations in the form of a joint venture called
en*able and (ii) limited international operations. During the third quarter of
1999, we adopted a plan to discontinue the direct marketing of non-energy
products and services (principally under the "Simple Choice" brand). During the
fourth quarter of 1999 and following our merger with Kinder Morgan Delaware, we
adopted and implemented plans to discontinue the following lines of business:
(i) gathering and processing natural gas, including short-haul intrastate
pipelines and providing field services to natural gas producers, (ii) wholesale
marketing of natural gas and natural gas liquids, and (iii) international
operations. During the fourth quarter of 2000, we decided that, due to the
start-up nature of these operations and the unwillingness of buyers to pay for
the value created to date, it was not in the best interests of the Company to
dispose of our international operations, which consist principally of a natural
gas distribution system under development in Hermosillo, Mexico. Consequently,
results from our international operations have been reclassified to continuing
operations for all periods presented. The $3.9 million estimated after-tax loss
on disposal recorded in 1999, consisting principally of a write down to
estimated net realizable value including estimated costs of disposal, was
reversed in 2000 and is included under the caption "Loss on Disposal of
Discontinued Operations" in the accompanying Consolidated Statements of Income.
The following table contains additional information concerning our international
operations.
INTERNATIONAL OPERATIONS
YEAR ENDED DECEMBER 31,
----------------------------
2000 1999 1998
------ ------ ------
(Thousands of dollars)
Total Assets (at December 31) $32,347 $25,325 $12,838
Total Liabilities (at December 31) $ 3,984 $ 29 $ 779
Operating Revenues $ 5,699 $ 1,129 $ 4,249
Operating Loss $ 2,071 $ 2,523 $ 631
In accordance with the provisions of Accounting Principles Board Opinion No. 30,
"Reporting the Results of Operations - Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions" ("APB 30"), our consolidated financial statements have
been restated to present these businesses as discontinued operations.
Accordingly, the revenues, costs and expenses, assets and liabilities and cash
flows of these discontinued operations have been excluded from the respective
captions in the accompanying Consolidated Statements of Income, Consolidated
Balance Sheets and Consolidated Statements of Cash Flows, and have been reported
in the various statements under the captions "Loss from Discontinued Operations,
Net of Tax"; "Loss on Disposal of Discontinued Operations, Net of Tax"; "Net
Current Assets of Discontinued Operations"; "Net Non-current Assets of
Discontinued Operations"; "Net Cash Flows Provided by (Used in) Discontinued
Operations" and "Net Cash Flows Provided By (Used In) Discontinued Investing
Activities" for all relevant periods. In addition, certain of these Notes have
been restated for all relevant periods to reflect the discontinuance of these
operations.
F-18
21
Summarized financial data of discontinued operations are as follows:
YEAR ENDED DECEMBER 31,
---------------------------------------------
2000 1999 1998
----------- ----------- -----------
(In Thousands)
Income Statement Data
Operating Revenues:
Wholesale Natural Gas and Liquids Marketing $ 580,159 $ 3,550,568 $ 2,580,459
Gathering and Processing, Including Field Services and Short-haul
Intrastate Pipelines $ 436,979 $ 630,005 $ 640,623
Loss From Discontinued Operations, Net of Tax:
Wholesale Marketing, Net of Tax Benefits of $9,300 and $7,869 $ (15,046) $ (14,837)
Gathering and Processing, Net of Tax Benefits of $18,177 and $30,733 $ (29,404) $ (57,949)
en*able/Orcom, Net of Tax Benefits of $4,150 and $2,757 $ (6,491) $ (5,198)
Loss on Disposal of Discontinued Operations, Net of Tax:
Wholesale Marketing, Net of Tax Benefits of $2,013 and $34,588 $ (3,013) $ (55,780)
Gathering and Processing, Net of Tax Benefits of $21,617 and $169,413 $ (32,638) $ (273,202)
en*able/Orcom, Net of Tax Benefits of $7,340 $ (11,479)
International Operations, Net of $2,430 of Tax and $2,430 of Tax Benefits $ 3,917 $ (3,917)
With the exception of our international operations, which, as discussed above,
we decided to retain, we completed the divestiture of our discontinued
operations by December 31, 2000. In the fourth quarter of 2000, we recorded an
incremental loss on disposal of discontinued operations of $31.7 million,
representing the impact of the final disposition transactions and adjustment of
previously recorded estimates. We had a remaining liability of approximately
$23.7 million at December 31, 2000 associated with these discontinued
operations, principally consisting of (i) indemnification obligations under the
various sale agreements and (ii) retained liabilities, which were settled in
cash in early 2001. Following is additional information concerning the various
disposition transactions.
We completed the disposition of our investment in en*able and sold our
businesses involved in providing field services to natural gas producers (K N
Field Services, Inc. and Compressor Pump and Engine, Inc.) and MidCon Gas
Products of New Mexico Corp., a wholly owned subsidiary providing natural gas
gathering and processing services, prior to the end of 1999. We received $23.3
million in cash as consideration for these sales.
Effective March 1, 2000, ONEOK purchased our gathering and processing businesses
in Oklahoma, Kansas and West Texas. In addition, ONEOK purchased our marketing
and trading business, as well as certain storage and transmission pipelines in
the Mid-continent region. As consideration, ONEOK paid us approximately $108
million plus approximately $56 million for estimated net working capital at
closing (subject to post-closing adjustment). In addition, ONEOK assumed (i) the
operating lease associated with the Bushton, Kansas processing plant and (ii)
long-term throughput capacity commitments on Natural and Kinder Morgan
Interstate.
During the second quarter of 2000, we completed the sale of three natural gas
gathering systems and a natural gas processing facility to WBI Holdings, Inc.,
the natural gas pipeline unit of MDU Resources Group, Inc. for approximately $21
million. Gathering systems included in the sale were the Bowdoin System located
in north-central Montana, the Niobrara System located in northeastern Colorado
and northwestern Kansas, and the Yenter System located in northeastern Colorado
and western Nebraska. The natural gas processing facility included in the sale
was the Yenter Plant, located northwest of Sterling, Colorado.
During the fourth quarter of 2000, Wildhorse Energy Partners, LLC distributed
all of its assets to the members and was dissolved. Formed in 1996, Wildhorse
was owned 55 percent by us and 45 percent by Tom Brown. All the Wildhorse
gathering and processing assets were distributed to Tom Brown and we received
the Wolf
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Creek storage facility (which will be utilized in our natural gas distribution
business) and cash. Also during the fourth quarter of 2000, our Douglas and
Casper gas processing facilities and associated natural gas gathering systems,
our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent interest
in Thunder Creek Gas Services, L.L.C. were included as part of a larger
transaction with Energy Partners; see Note 5.
7. ACCOUNTS RECEIVABLE SALES FACILITY
In September 1999, certain of our wholly owned subsidiaries entered into a
five-year agreement to sell all of their accounts receivable, on a revolving
basis, to K N Receivables Corporation, our wholly owned subsidiary. K N
Receivables was formed prior to the execution of that receivables agreement for
the purpose of buying and selling accounts receivable and was determined to be
bankruptcy remote. Also in September 1999, K N Receivables entered into a
five-year agreement with a financial institution whereby K N Receivables could
sell, on a revolving basis, an undivided percentage ownership interest in
certain eligible accounts receivable, as defined, up to a maximum of $150
million. This transaction was accounted for as a sale of receivables in
accordance with SFAS No. 125, "Accounting for Transfer and Servicing of
Financial Assets and Extinguishment of Liabilities." Accordingly, our
accompanying Consolidated Balance Sheet at December 31, 1999, reflects the
portion of receivables transferred to the financial institution as a reduction
of Accounts Receivable. Losses from the sale of these receivables are included
in "Other, Net" in the accompanying Consolidated Statements of Income during the
periods in which the facility was utilized. We received compensation for
servicing that was approximately equal to the amount an independent servicer
would receive. Accordingly, no servicing assets or liabilities were recorded.
The full amount of the allowance for possible losses was retained by K N
Receivables. The fair value of this recourse liability approximated the
allocated allowance for doubtful accounts given the short-term nature of the
transferred receivables.
We received $150 million in proceeds from the sale of receivables on September
30, 1999. The proceeds were subsequently used to retire notes payable of Kinder
Morgan Delaware that were outstanding when we acquired it. Cash flows associated
with this program are included with "Accounts Receivable" under "Cash Flows from
Operating Activities" in the accompanying Statements of Consolidated Cash Flows.
In February 2000, we reduced our participation in this receivables sale program
by approximately $120 million, principally as a result of our then pending
disposition of our wholesale gas marketing business. On April 25, 2000, we
repaid the residual balance and terminated this agreement.
8. REGULATORY MATTERS
On July 17, 2000, Natural filed its Compliance Plan, including pro forma tariff
sheets, pursuant to FERC's Order Nos. 637 and 637-A. The FERC directed all
interstate pipelines to file pro forma tariff sheets to comply with new
regulatory requirements in the Orders regarding scheduling procedures, capacity
segmentation, imbalance management services and penalty credits, or in the
alternative, to explain why no changes to existing tariff provisions are
necessary. Natural's filing is currently pending FERC action and any changes to
its tariff provisions are not expected to take effect until after the entire
Order 637 process is finished for all interstate pipelines.
On May 10, 2000, Chesapeake Panhandle Limited Partnership filed a complaint with
the FERC against Natural, MidCon Gas Products Corp., MidCon Gas Services Corp.,
K N Energy, Inc. and us. The complaint alleges that Natural collected an
unlawful gathering rate from Chesapeake for the period March 1998 through
December 1999. Chesapeake is seeking a refund totaling $5.2 million. We have
responded and denied the allegations. On July 27, 2000, the FERC issued an order
commencing a preliminary non-public investigation into the complaint. We believe
that we have meritorious defenses to the claim.
On January 23, 1998, Kinder Morgan Interstate filed a general rate case with the
FERC, requesting a $30.2 million increase in annual revenues. As a result of the
FERC's action, Kinder Morgan Interstate was allowed to
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place its rates into effect on August 1, 1998, subject to refund, and provisions
for refund were recorded based on expected ultimate resolution. On November 3,
1999, Kinder Morgan Interstate filed a comprehensive Stipulation and Agreement
to resolve all issues in this proceeding. The FERC approved the Stipulation and
Agreement on December 22, 1999, and the settlement rates have been placed in
effect. Kinder Morgan Interstate was sold to Energy Partners effective December
31, 1999; see Note 5.
In November 1997, we announced a plan to give residential and small commercial
customers in Nebraska a choice of natural gas suppliers. This program, the
Nebraska Choice Gas program, became effective June 1, 1998. This program
separates, or "unbundles," the consumer's natural gas purchases from other
utility services. As of December 31, 2000, the plan had been approved by 178 of
the 181 Nebraska municipalities we serve, representing approximately 91,000
customers served by us in Nebraska.
9. ENVIRONMENTAL AND LEGAL MATTERS
(A) Environmental Matters
On December 20, 1999, the U.S. Department of Justice filed a Complaint against
Natural on behalf of the U.S. Environmental Protection Agency in the Federal
District Court of Colorado, Civil Action 99-S-2419. The Complaint alleged that
Natural failed to obtain all of the necessary air quality permits in 1979 when
it constructed the Akron Compressor Station, which consisted of three compressor
engines in Weld County, Colorado. Natural and the Environmental Protection
Agency, through the Department of Justice, have settled this issue. The
Environmental Protection Agency has agreed to dismiss all allegations and claims
upon completion of the terms of the settlement.
On December 17, 1999, the State of Colorado notified us of air quality permit
compliance issues for several Kinder Morgan facilities. On September 21, 2000,
we entered into a consent order with the State of Colorado to resolve the
outstanding issues.
In 1998, the Environmental Protection Agency published a final rule addressing
transport of ground level ozone. The rule affected 22 Eastern and Midwestern
states, including Illinois and Missouri, in which we operate gas compression
facilities. The rule required reductions in emissions of nitrogen oxide, a
precursor to ozone formation, from various emission sources, including utility
and non-utility sources. The rule required that the affected states prepare and
submit State Implementation Plans to the Environmental Protection Agency by
September 1999, reflecting how the required emissions reductions would be
achieved. Emission controls are required to be installed by May 1, 2003. The
State Implementation Plans which will effectuate this rule have yet to be
proposed or promulgated, and will require detailed analysis before their final
economic impact can be ascertained. On March 3, 2000, the Washington D.C.
Circuit Court issued a decision regarding the rule. The Circuit Court remanded
certain issues back to the Environmental Protection Agency. On January 5, 2001,
the Environmental Protection Agency proposed regulations concerning the remanded
issues. The final regulations are expected to be promulgated later this year.
While additional capital costs are likely to result from this rule, based on
currently available information, we do not believe that these costs will have a
material adverse effect on our business, cash flows, financial position or
results of operations.
On June 17, 1999, the Environmental Protection Agency published a final rule
creating a standard to limit emissions of hazardous air pollutants from oil and
natural gas production as well as from natural gas transmission and storage
facilities. The standard requires that the affected facilities reduce emissions
of hazardous air pollutants by 95 percent. This standard will require us to
achieve this reduction either by process modifications or by installing new
emissions control technology. The standard will affect our competitors and us in
a like manner. The rule allows affected sources three years from the publication
date to come into compliance. We have conducted a detailed analysis of the final
rule to determine its overall effect. While
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additional capital costs are likely to result from this rule, the rule will not
have a material adverse effect on our business, cash flows, financial position
or results of operations.
We have an established environmental reserve of approximately $19 million to
address remediation issues associated with 38 projects. Based on current
information and taking into account reserves established for environmental
matters, we do not believe that compliance with federal, state and local
environmental laws and regulations will have a material adverse effect on our
business, cash flows, financial position or results of operations. In addition,
the clean-up programs in which we are engaged are not expected to interrupt or
diminish our operational ability to gather or transport natural gas. However,
there can be no assurances that future events, such as changes in existing laws,
the promulgation of new laws, or the development of new facts or conditions will
not cause us to incur significant costs.
(B) Litigation Matters
"K N TransColorado, Inc. v. TransColorado Gas Transmission Company, et. al,"
Case No. 00-CV-129, District Court, County of Garfield, State of Colorado. On
June 15, 2000, K N TransColorado filed suit against Questar TransColorado and
several of its affiliated Questar entities, asserting claims for breach of
fiduciary duties, breach of contract, constructive trust, rescission of the
partnership agreement, breach of good faith and fair dealing, tortuous
concealment, misrepresentation, aiding and abetting a breach of fiduciary duty,
dissolution of the TransColorado partnership, and seeking a declaratory
judgment, among other claims. The TransColorado partnership has been made a
defendant for purposes of an accounting. The lawsuit stems from Questar's
failure to support the TransColorado partnership, together with its decision to
seek regulatory approval for a project that competes with the Partnership, in
breach of its fiduciary duties as a partner. K N TransColorado seeks to recover
damages in excess of $152 million due to Questar's breaches and, in addition,
seeks punitive damages. In response to the complaint, on July 28, 2000, the
Questar entities filed a counterclaim and third party claims against certain of
our entities and us for claims arising out of the construction and operation of
the TransColorado pipeline project. The claims allege, among other things, that
the Kinder Morgan entities interfered with and delayed construction of the
pipeline and made misrepresentations about marketing of capacity. The Questar
entities seek to recover damages in excess of $185 million for an alleged breach
of fiduciary duty and other claims. On December 15, 2000, the parties agreed to
stay the exercise of a contractual provision purportedly requiring K N
TransColorado to purchase Questar's interest in the pipeline and to investigate
the appointment of an independent operator for the pipeline during the
litigation. On January 31, 2001, the Court dismissed Questar's counterclaims for
breach of duty of good faith and fair dealing and for indemnity and contribution
and dismissed Questar's Third Party Complaint. Discovery has commenced.
"Jack J. Grynberg v. K N Energy, Inc., Rocky Mountain Natural Gas Company, and
GASCO, Inc.," Civil Action No. 92-N-2000. On October 9, 1992, Jack J. Grynberg
filed suit in the United States District Court for the District of Colorado
against us, Rocky Mountain Natural Gas Company and GASCO, Inc. alleging that
these entities, the K N Entities, as well as K N Production Company and K N Gas
Gathering, Inc., have violated federal and state antitrust laws. In essence,
Grynberg asserts that the companies have engaged in an illegal exercise of
monopoly power, have illegally denied him economically feasible access to
essential facilities to store, transport and distribute gas, and illegally have
attempted to monopolize or to enhance or maintain an existing monopoly. Grynberg
also asserts certain state causes of action relating to a gas purchase contract.
In February 1999, the Federal District Court granted summary judgment for the K
N Entities as to some of Grynberg's antitrust and state law claims, while
allowing other claims to proceed to trial. Grynberg has previously claimed
damages in excess of $50 million. In addition to monetary damages, Grynberg has
requested that the K N Entities be ordered to divest all interests in natural
gas exploration, development and production properties, all interests in
distribution and marketing operations, and all interests in natural gas storage
facilities, in order to separate these interests from our natural gas gathering
and transportation system in northwest Colorado. No trial date has been set.
However, recent settlement conferences have occurred and the parties are
continuing to provide information related to a Court ordered mediation.
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"Jack J. Grynberg, individually and as general partner for the Greater Green
River Basin Drilling Program: 72-73 v. Rocky Mountain Natural Gas Company and
K N Energy, Inc.," Case No. 90-CV-3686. On June 5, 1990, Jack J. Grynberg filed
suit, which is presently pending in Jefferson County District Court for
Colorado, against Rocky Mountain Natural Gas Company and us alleging breach of
contract and fraud. In essence, Grynberg asserts claims that the named companies
failed to pay Grynberg the proper price, impeded the flow of gas, mismeasured
gas, delayed his development of gas reserves, and other claims arising out of a
contract to purchase gas from a field in northwest Colorado. On February 13,
1997, the trial judge entered partial summary judgment for Mr. Grynberg on his
contract claim that he failed to receive the proper price for his gas. This
ruling followed an appellate decision that was adverse to us on the contract
interpretation of the price issue, but which did not address the question of
whether Grynberg could legally receive the price he claimed or whether he had
illegally diverted gas from a prior purchase. Grynberg has previously claimed
damages in excess of $30 million. On August 29, 1997, the trial judge stayed the
summary judgment pending resolution of a proceeding at the FERC to determine if
Grynberg was entitled to administrative relief from an earlier dedication of the
same gas to interstate commerce. The background of that proceeding is described
in the immediately following paragraph. On March 15, 1999, an Administrative Law
Judge for the FERC ruled, after an evidentiary hearing, that Mr. Grynberg had
illegally diverted the gas when he entered the contract with the named companies
and was not entitled to relief. Grynberg filed exceptions to this ruling. In
late March 2000, the FERC issued an order affirming in part and denying in part
the motions for rehearing of its Initial Decision. On November 21, 2000, the
FERC upheld the Administrative Law Judge's factual findings and denial of
retroactive abandonment. Grynberg recently filed a Notice of Appeal of the
FERC's decision to the D.C. Circuit Court of Appeals. The action in Colorado
remains stayed pending final resolution of these proceedings.
"Jack J. Grynberg v. Rocky Mountain Natural Gas Company," Docket No. GP91-8-008.
"Rocky Mountain Natural Gas Company v. Jack J. Grynberg," Docket No.
GP91-10-008. On May 8, 1991, Grynberg filed a petition for declaratory order
with the FERC seeking a determination whether he was entitled to the price he
seeks in the Jefferson County District Court proceeding referred to in the
immediately preceding paragraph. While Grynberg initially received a favorable
decision from the FERC, that decision was reversed by the Court of Appeals for
the District of Columbia Circuit on June 6, 1997. This matter has been remanded
to the FERC for subsequent proceedings. The matter was set for an expedited
evidentiary hearing, and an Initial Decision favorable to Rocky Mountain was
issued on March 15, 1999. That decision determined that Grynberg had
intentionally diverted gas from an earlier dedication to interstate commerce in
violation of the Natural Gas Act and denied him equitable administrative relief.
On November 21, 2000, the FERC upheld the Administrative Law Judge's factual
findings and denial of retroactive abandonment. Grynberg recently filed a Notice
of Appeal of the FERC's decision to the D.C. Circuit Court of Appeals. Grynberg
filed exceptions to this Initial Decision. In late March 2000, the FERC issued
an order affirming in part and denying in part the motions for rehearing of its
Initial Decision. In April 2000, we, together with the other parties, filed for
rehearing.
"United States of America, ex rel., Jack J. Grynberg v. K N Energy," Civil
Action No. 97-D-1233, filed in the U.S. District Court, District of Colorado.
This action was filed pursuant to the federal False Claim Act and involves
allegations of mismeasurement of natural gas produced from federal and Indian
lands. The Department of Justice has decided not to intervene in support of the
action. The complaint is part of a larger series of similar complaints filed by
Mr. Grynberg against 77 natural gas pipelines (approximately 330 other
defendants). An earlier single action making substantially similar allegations
against the pipeline industry was dismissed by Judge Hogan of the U.S. District
Court for the District of Columbia on grounds of improper joinder and lack of
jurisdiction. As a result, Mr. Grynberg filed individual complaints in various
courts throughout the country. These cases were recently consolidated by the
Judicial Panel for Multidistrict Litigation, and transferred to the District of
Wyoming. Motions to Dismiss were filed on November 19, 1999. Plaintiff filed his
response on January 14, 2000 and defendants filed their Reply Brief on February
14, 2000. An oral argument on the Motion to Dismiss occurred on March 17, 2000.
On July 20, 2000 the United States of
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America filed a motion to dismiss those claims by Grynberg that deal with the
manner in which defendants valued gas produced from federal leases.
"Quinque Operating Company, et. al. v. Gas Pipelines, et. al.," Cause No.
99-1390-CM, United States District Court for the District of Kansas. This action
was originally filed in Kansas state court in Stevens County, Kansas as a class
action against approximately 245 pipeline companies and their affiliates,
including certain Kinder Morgan entities. The plaintiffs in the case purport to
represent a class of natural gas producers and fee royalty owners who allege
that they have been subject to systematic gas mismeasurement by the defendants
for more than 25 years. Subsequently, one of the defendants removed the action
to Kansas Federal District Court. Thereafter, we filed a motion with the
Judicial Panel for Multidistrict Litigation to consolidate this action for
pretrial purposes with the Grynberg False Claim Act cases referred to above,
because of common factual questions. On April 10, 2000, the MDL Panel ordered
that this case be consolidated with the Grynberg federal False Claims Act cases.
On January 12, 2001, the Federal District Court of Wyoming issued an oral ruling
remanding the case back to the State Court in Stevens County, Kansas. A Motion
to Reconsider the remand was filed and is currently pending.
"Dirt Hogs, Inc. v. Natural Gas Pipeline Company of America, et al." There have
been several related cases with Dirt Hogs, Inc. with allegations of breach of
contract, false representations, improper requests for kickbacks and other
improprieties. Essentially, the plaintiff claims that it should have been
awarded extensive pipeline reclamation work without having to qualify or bid as
a qualifying contractor. Case No. Civ-98-231-R, is a case which was dismissed in
the U.S. District Court for the Western District of Oklahoma because of pleading
deficiencies and is now on appeal to the 10th Circuit (Case No. 99-6-026). On
April 10, 2000, the 10th Circuit upheld the dismissal of this action. Another
case, arising out of the same factual allegations, was filed by Dirt Hogs in the
District Court, Caddo County, Oklahoma (Case No. CJ-99-92), on March 29, 1999.
By agreement of all parties, this action is currently stayed. A third related
case, styled "Natural Gas Pipeline Company of America, et al. v. Dirt Hogs,
Inc." (Case No. 99-360-R), resulted in a default judgment against Dirt Hogs.
After initially appealing the default judgment, Dirt Hogs dismissed their appeal
on September 1, 1999.
"K N Energy, Inc., et al. v. James P. Rode and Patrick R. McDonald," Case No.
99CV1239, filed in the District Court, Jefferson County, Division 8, Colorado.
Defendants counterclaimed and filed third party claims against several of our
former officers and/or directors. Messrs. Rode and McDonald are former principal
shareholders of Interenergy Corporation. We acquired Interenergy on December 19,
1997 pursuant to a Merger Agreement dated August 25, 1997. Rode and McDonald
allege that K N Energy committed securities fraud, common law fraud and
negligent misrepresentation as well as breach in contract. Plaintiffs are
seeking an unspecified amount of compensatory damages, greater than $2 million,
plus unspecified exemplary or punitive damages, attorney's fees and their costs.
We filed a motion to dismiss, and on April 21, 2000, the Jefferson County
District Court Judge dismissed the case against the individuals and us with
prejudice. Defendants also filed a federal securities fraud action in the United
States District Court for the District of Colorado on January 27, 2000 titled:
"James P. Rode and Patrick R. McDonald v. K N Energy, Inc., et al.," Civil
Action No. 00-N-190. This case initially raised the identical state law claims
contained in the counterclaim and third party complaint in state court. Rode and
McDonald filed an amended Complaint, which dropped the state-law claims. This
Complaint is now the subject of a motion to dismiss filed by defendants. The
case has been stayed pending the outcome of these motions. A third related class
action case styled, "Adams vs. Kinder Morgan, Inc., et. al.," Civil Action No.
00-M-516, in the United States District Court for the District of Colorado was
served on us on April 10, 2000. As of this date no class has been certified. We
have filed a motion to dismiss this case. Oral argument on the Motions to
Dismiss in the Rode/McDonald and Adams actions is scheduled for February 23,
2001. The cases remain stayed pending the resolution of these motions.
We believe that we have meritorious defenses to all lawsuits and legal
proceedings in which we are defendants and will vigorously defend against them.
Based on our evaluation of the above matters, and after consideration
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of reserves established, we believe that the resolution of such matters will not
have a material adverse effect on our business, financial position or results of
operations.
10. PROPERTY, PLANT AND EQUIPMENT
Investments in property, plant and equipment ("PP&E"), at cost, and accumulated
depreciation and amortization ("Accumulated D&A") are as follows:
DECEMBER 31, 2000
------------------------------------------------
PROPERTY, PLANT AND ACCUMULATED
EQUIPMENT D&A NET
------------------- ----------- ---------
(In Thousands)
Natural Gas Pipelines $5,662,880 $262,073 $5,400,807
Retail Natural Gas Distribution 251,660 90,966 160,694
Electric Power Generation 79,696 2,608 77,088
General and Other 142,773 56,745 86,028
---------- --------- ----------
PP&E Related to Continuing Operations $6,137,009 $412,392 $5,724,617
========== ========= ==========
DECEMBER 31, 1999
------------------------------------------------
PROPERTY, PLANT AND ACCUMULATED
EQUIPMENT D&A NET
------------------- ----------- ---------
(In Thousands)
Natural Gas Pipelines $5,768,566 $240,949 $5,527,617
Retail Natural Gas Distribution 248,998 83,010 165,988
Electric Power Generation 27,873 1,915 25,958
General and Other 121,814 51,813 70,001
---------- --------- ----------
PP&E Related to Continuing Operations $6,167,251 $377,687 $5,789,564
========== ========= ==========
11. INCOME TAXES
Components of the income tax provision applicable to continuing operations for
federal and state income taxes are as follows:
YEAR ENDED DECEMBER 31,
-------------------------------------------
2000 1999 1998
-------- -------- --------
(Dollars in thousands)
TAXES CURRENTLY PAYABLE:
Federal $ 3,212 $ 19,340 $ 49,630
State 14,091 13,784 8,564
-------- -------- --------
Total 17,303 33,124 58,194
-------- -------- --------
TAXES DEFERRED:
Federal 94,435 64,086 25,068
State 10,989 (6,477) (552)
-------- -------- --------
Total 105,424 57,609 24,516
-------- -------- --------
TOTAL TAX PROVISION $122,727 $ 90,733 $ 82,710
======== ======== ========
EFFECTIVE TAX RATE 40.0% 36.8% 37.1%
======== ======== ========
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The difference between the statutory federal income tax rate and our effective
income tax rate is summarized as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------
2000 1999 1998
------ ------ ------
FEDERAL INCOME TAX RATE 35.0% 35.0% 35.0%
INCREASE (DECREASE) AS A RESULT OF:
State Income Tax, Net of Federal Benefit 5.6% 1.9% 2.1%
Other (0.6)% (0.1)% --
------ ------ ------
EFFECTIVE TAX RATE 40.0% 36.8% 37.1%
====== ====== ======
Deferred tax assets and liabilities result from the following:
DECEMBER 31,
----------------------------
2000 1999
---------- ----------
(Dollars In Thousands)
DEFERRED TAX ASSETS:
Post-retirement Benefits $ 14,776 $ 28,299
Gas Supply Realignment Deferred Receipts 17,101 15,847
State Taxes 138,976 112,049
Book Accruals 39,505 29,186
Alternative Minimum Tax Credits 9,098 8,222
Net Operating Loss Carryforwards 107,033 112,080
Discontinued Operations 9,584 208,317
Capital Loss Carryforwards 42,914 --
Other 4,269 6,765
---------- ----------
TOTAL DEFERRED TAX ASSETS 383,256 520,765
---------- ----------
DEFERRED TAX LIABILITIES:
Property, Plant and Equipment 2,009,086 2,087,109
Investments 654,263 656,781
Other 4,403 8,099
---------- ----------
TOTAL DEFERRED TAX LIABILITIES 2,667,752 2,751,989
---------- ----------
NET DEFERRED TAX LIABILITIES $2,284,496 $2,231,224
========== ==========
For tax purposes we had available, at December 31, 2000, net operating loss
carryforwards for regular federal income tax purposes of approximately $306
million which will expire as follows: $66 million in the year 2018, $211 million
in the year 2019 and $29 million in the year 2020. We also had available, at
December 31, 2000, capital loss carryforwards of $122 million which will expire
in the year 2005. We believe it is more likely than not that all of the net
operating loss carryforwards and capital loss carryforwards will be utilized
prior to their expiration; therefore no valuation allowance is necessary. We
also had available, at December 31, 2000, approximately $9 million of
alternative minimum tax credit carryforwards which are available indefinitely.
12. FINANCING
(A) Notes Payable
At December 31, 2000, we had available a $500 million 364-day facility dated
October 25, 2000, and a $400 million amended and restated five-year revolving
credit agreement dated January 30, 1998. These bank facilities can be used for
general corporate purposes, including backup for our commercial paper program,
and include covenants that are common in such arrangements. For example, the
$500 million facility requires consolidated debt to be less than 68% of
consolidated capitalization. The $400 million facility requires that upon
issuance of common stock to the holders of the premium equity participating
security units at the maturity of the security units (November 2001),
consolidated debt must be less than 67% of consolidated total
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capitalization. Both of the bank facilities require the debt of consolidated
subsidiaries to be less than 10% of our consolidated debt and require the
consolidated debt of each material subsidiary to be less than 65% of our
consolidated total capitalization. The $400 million facility requires our
consolidated net worth (inclusive of trust preferred securities) be at least
$1.236 billion plus 50 percent of consolidated net income earned for each fiscal
quarter beginning with the last quarter of 1998. The $500 million facility
requires our consolidated net worth (inclusive of trust preferred securities) be
at least $1.236 billion plus 50 percent of consolidated net income earned for
each fiscal quarter beginning with the last quarter of 1999. Under the bank
facilities, we are required to pay a facility fee based on the total commitment,
at a rate that varies based on our senior debt rating. Facility fees paid in
2000 and 1999 were $1.6 million and $1.9 million, respectively. At December 31,
2000 and 1999, $100 million and $300 million, respectively, was outstanding
under the bank facilities.
Commercial paper issued by us and supported by the bank facilities are unsecured
short-term notes with maturities not to exceed 270 days from the date of issue.
During 2000, all commercial paper was redeemed within 52 days, with interest
rates ranging from 5.60 percent to 7.50 percent. No commercial paper was
outstanding at December 31, 2000. Commercial paper outstanding at December 31,
1999 was $274.4 million. The weighted-average interest rate on short-term
borrowings outstanding at December 31, 1999 was 7.00 percent. Average short-term
borrowings outstanding during 2000 and 1999 were $310.6 million and $620.9
million, respectively. During 2000 and 1999, the weighted-average interest rates
on short-term borrowings outstanding were 6.52 percent and 5.56 percent
(excluding the Substitute Note as described below), respectively.
Our short-term debt of $908.2 million at December 31, 2000 consisted of (i) $100
million of borrowings under our revolving credit facilities, (ii) the $400
million of Reset Put Securities that are scheduled to be either remarketed or
retired as of March 1, 2001, (iii) the $400 million of 6.45% Senior Notes, due
November 2001 and (iv) $8.2 million of miscellaneous current maturities of
long-term debt. We expect to retire the Reset Put Securities at March 1, 2001
utilizing a combination of cash on hand and incremental short-term borrowings,
which will result in an extraordinary loss on early extinguishments of debt
expected to total approximately $15 million. We expect that the $400 million of
6.45% Senior Notes will be retired at maturity with a portion of the $460
million of cash to be received from the issuance of common stock upon maturity
of the Premium Equity Participating Securities, which occurs concurrently as
discussed following. Apart from these items, our current assets and current
liabilities are approximately equal. Given our expected cash flows from
operations and our unused debt capacity, including our 5-year revolving credit
facility, we do not expect any liquidity issues in the foreseeable future.
Effective with the acquisition of MidCon Corp. on January 30, 1998, we entered
into a $4.5 billion credit facility consisting of (i) a $1.4 billion 364-day
credit facility to support the note issued to Occidental Petroleum Corporation
in conjunction with the purchase of MidCon Corp., (ii) a $2.1 billion 364-day
revolving facility, (iii) the $400 million facility, providing for loans and
letters of credit, of which the letter of credit usage may not exceed $100
million and (iv) a 364-day $600 million revolving credit facility. The $1.4
billion and $2.1 billion facilities could be used only in conjunction with the
acquisition of MidCon Corp. In addition to the working capital and acquisition
components of the $4.5 billion facility, we assumed a short-term note for $1.4
billion payable to Occidental referred to as the "Substitute Note," which was
initially collateralized by letters of credit issued under the $1.4 billion
facility. In March 1998, we received net proceeds of approximately $2.34 billion
from the public offerings of senior debt securities of varying maturities with
principal totaling $2.35 billion. The net proceeds from these offerings were
used to refinance borrowings under the $4.5 billion facility and to purchase
U.S. government securities to replace a portion of the letters of credit that
collateralized the Substitute Note. The $2.1 billion facility was repaid in its
entirety and cancelled on March 10, 1998. The Substitute Note was repaid on
January 4, 1999. On January 5, 1999, we cancelled the remaining letters of
credit used to collateralize the Substitute Note. On January 8, 1999, the $600
million facility was replaced with a new $600 million 364-day facility, which
was essentially the same as the previous agreement. On November 18, 1999, we
replaced our then-existing $600 million 364-day facility with a new $550 million
364-day facility, which has subsequently been replaced with a new $500 million
364-day facility dated October 25, 2000 as discussed above.
F-27
30
(B) Long-term Debt and Premium Equity Participating Security Units
DECEMBER 31,
-------------------------------
2000 1999
----------- -----------
(In Thousands)
DEBENTURES:
6.50% Series, Due 2013 $ 50,000 $ 50,000
7.85% Series, Due 2022 24,943 25,731
8.75% Series, Due 2024 75,000 75,000
7.35% Series, Due 2026 125,000 125,000
6.67% Series, Due 2027 150,000 150,000
7.25% Series, Due 2028 493,000 500,000
7.45% Series, Due 2098 150,000 150,000
SINKING FUND DEBENTURES:
9.95% Series, Due 2020 20,000 20,000
9.625% Series, Due 2021 45,000 45,000
8.35% Series, Due 2022 35,000 35,000
SENIOR NOTES:
6.45% Series, Due 2001 400,000 400,000
7.27% Series, Due 2002 10,000 15,000
6.45% Series, Due 2003 500,000 500,000
6.65% Series, Due 2005 500,000 500,000
6.80% Series, Due 2008 300,000 300,000
Reset Put Securities, 6.30%, Due 2021 400,000 400,000
Other 13,617 14,883
Unamortized Debt Discount (4,410) (5,121)
Current Maturities of Long-term Debt (808,167) (7,167)
---------- ----------
TOTAL LONG-TERM DEBT $2,478,983 $3,293,326
========== ==========
Maturities of long-term debt (in thousands) for the five years ending December
31, 2005 are $808,167, $10,417, $507,167, $7,167 and $507,167, respectively.
The 2013 Debentures and the 2001, 2003 and 2005 Senior Notes are not redeemable
prior to maturity. The 2022, 2028 and 2098 Debentures, the 2020 Sinking Fund
Debentures and the 2002 and 2008 Senior Notes are redeemable in whole or in
part, at our option at any time, at redemption prices defined in the associated
prospectus supplements. The 2024, 2026 and 2027 Debentures are redeemable in
whole or in part, at our option after October 15, 2002, August 1, 2006, and
November 1, 2004, respectively, at redemption prices defined in the associated
prospectus supplements. The 2021 and 2022 Sinking Fund Debentures are redeemable
in whole or in part, at our option after August 1, 2001 and September 15, 2002,
respectively, at redemption prices defined in the associated prospectus
supplements.
In November 1998 we sold $460 million principal amount of premium equity
participating security units in an underwritten public offering. The net cash
proceeds from the sale of the security units, together with additional funds we
provided, were used to purchase U.S. Treasury Notes on behalf of the security
unit holders. The Treasury Notes are the property of the security unit holders
and are pledged to the collateral agent, for our benefit, to secure the
obligation of the security unit holders to purchase our common stock. These
security units obligate the holders to purchase a certain amount of our common
stock, depending on the market price at November 30, 2001 (unless earlier
terminated or settled at the option of the holders of the security units), and
provide for the holders to receive interest at the rate of 8.25 percent per year
during the three-year period. The interest is paid by the agent, which receives
part of the necessary funds from the collateral agent, which holds 5.875% U.S.
Treasury Notes purchased with the proceeds of the initial investment by the
security unit holders. We pay the remaining 2.375 percent. We may defer the
payment of all or any part of our portion of the contract fees until no later
than the end of the three-year period. Any portion so deferred will accrue
interest at the annual rate of 8.25 percent until paid.
F-28
31
The face value of the security units is not recorded in the accompanying
Consolidated Balance Sheets. The $29.4 million present value of the contract fee
payable to the security unit holders has been recorded as a liability and as a
reduction to paid-in capital. During the period in which the 2.375 percent
contract fees are payable, accretion of the $3.4 million of discount initially
recorded will increase the liability and further decrease paid-in capital. In
addition, paid-in capital has been reduced for the issuance costs associated
with the security units and the premium paid upon purchase of the Treasury Notes
pledged to the collateral agent, which amounts total approximately $32.8
million.
The $400 million of Reset Put Securities due March 1, 2021 are subject to
mandatory redemption from the then-existing holders on March 1, 2001, either (i)
through the exercise of a call option by Morgan Stanley & Co. International
Limited or (ii) in the event Morgan Stanley does not exercise the call option,
the automatic exercise of a mandatory put by First Trust National Association on
behalf of the holders. The $12 million of proceeds we received from Morgan
Stanley as consideration for the call option are being amortized as an
adjustment to the effective interest rate on the Reset Put Securities. We
currently expect that these securities will not be remarketed but, instead, will
be retired utilizing a combination of cash and incremental short-term
borrowings. This retirement is expected to result in an extraordinary loss, net
of tax, of approximately $15 million.
At December 31, 2000 and 1999, the carrying amount of our long-term debt was
$3.3 billion and $3.3 billion, respectively. The estimated fair values of our
long-term debt at December 31, 2000 and 1999 are shown in Note 18.
(C) Capital Securities
In April 1998, we sold $175 million of 7.63% Capital Trust Securities maturing
on April 15, 2028, and in April 1997, we sold $100 million of 8.56% Capital
Trust Securities maturing on April 15, 2027, each in an underwritten public
offering. We created wholly owned business trusts, K N Capital Trust I and K N
Capital Trust III, to make the sales. The transactions and balances of K N
Capital Trust I and K N Capital Trust III are included in our consolidated
financial statements, with the Capital Securities treated as a minority
interest, shown in our Consolidated Balance Sheets under the caption "Kinder
Morgan-Obligated Mandatorily Redeemable Preferred Capital Trust Securities of
Subsidiary Trust Holding Solely Debentures of Kinder Morgan." Periodic payments
made to the holders of these securities are classified under "Minority
Interests" in the accompanying Consolidated Statements of Income. See Note 18
for the fair value of these securities.
(D) Common Stock
On November 17, 1999, our Board of Directors approved a reduction in the
quarterly dividend from $0.20 per share to $0.05 per share.
On November 9, 1998, our Board of Directors approved a three-for-two split of
our common stock. The stock split was distributed on December 31, 1998, to
shareholders of record at the close of business on December 15, 1998. The par
value of the stock did not change.
In March 1998, we received net proceeds of approximately $624.6 million from a
public offering of 12.5 million shares (18.75 million shares after adjustment
for the December 1998 three-for-two stock split) of our common stock. The net
proceeds from this offering were used to refinance borrowings under the $4.5
billion Facility and to purchase U.S. government securities to replace a portion
of the letters of credit that collateralized the Substitute Note.
F-29
32
13. PREFERRED STOCK
We have authorized 200,000 shares of Class A and 2,000,000 shares of Class B
preferred stock, all without par value.
(A) Class A $5.00 Cumulative Preferred Stock
On April 13, 1999, we sent notices to holders of our Class A $5.00 Cumulative
Preferred Stock of our intent to redeem these shares on May 14, 1999. Holders of
70,000 preferred shares were advised that on April 13, 1999, funds were
deposited with the First National Bank of Chicago to pay the redemption price of
$105 per share plus accrued but unpaid dividends. Under the terms of our
Articles of Incorporation, upon deposit of funds to pay the redemption price,
all rights of the preferred stockholders ceased and terminated except the right
to receive the redemption price upon surrender of their stock certificates.
At December 31, 2000 and 1999, we did not have any outstanding shares of Class A
$5.00 Cumulative Series Preferred Stock. At December 31, 1998, we had 70,000
shares of Class A $5.00 Cumulative Series Preferred Stock outstanding.
(B) Class B Preferred Stock
We did not have any outstanding shares of Class B Preferred Stock at December
31, 2000, 1999 or 1998.
14. RISK MANAGEMENT
We use energy financial instruments to reduce our risk of price changes in the
spot and fixed price natural gas markets as discussed following. We are exposed
to credit-related losses in the event of nonperformance by counterparties to
these financial instruments but, given their existing credit ratings, do not
expect any counterparties to fail to meet their obligations. The fair value of
these risk management instruments reflects the estimated amounts that we would
receive or pay to terminate the contracts at the reporting date, thereby taking
into account the current unrealized gains or losses on open contracts. Market
quotes are available for substantially all financial instruments we use.
Energy risk management products we use include commodity futures and options
contracts, fixed-price swaps and basis swaps. Pursuant to our Board of
Director's approved policy, we are to engage in these activities only as a
hedging mechanism against price volatility associated with pre-existing or
anticipated physical gas sales, gas purchases, system use and storage in order
to protect profit margins, and are prohibited from engaging in speculative
trading. Commodity-related activities of the risk management group are monitored
by our Risk Management Committee, which is charged with the review and
enforcement of the Board of Director's risk management policy. Gains and losses
on hedging positions are deferred and recognized as gas purchases expense in the
periods in which the underlying physical transactions occur.
Purchases or sales of commodity contracts require a dollar amount to be placed
in margin accounts. In addition, we are required to post margins with certain
over-the-counter swap partners. These margin requirements are determined based
upon credit limits and mark-to-market positions. At December 31, 2000, we had
$10.0 million in margin deposits associated with commodity contract positions
and $4.0 million in margin deposits associated with over-the-counter swaps.
These amounts are shown as "Restricted Deposits" in the accompanying
Consolidated Balance Sheets.
The differences between the current market value and the original physical
contracts value, associated with hedging activities, are reflected, depending on
maturity, as deferred charges or credits and other current assets or liabilities
in the accompanying Consolidated Balance Sheets but, in 2001, will be included
with "Other
F-30
33
Comprehensive Income" as discussed following. In the event energy financial
instruments are terminated prior to the period of physical delivery of the items
being hedged, the gains and losses on the energy financial instruments at the
time of termination remain deferred until the period of physical delivery.
Given our portfolio of businesses as of December 31, 2000, our principal uses of
derivative financial instruments will be to mitigate the risk associated with
market movements in the price of natural gas associated with (i) the sale of
in-kind fuel recoveries in excess of fuel used on Natural's pipeline system and
(ii) the purchase of natural gas by Retail to serve its customers in the Choice
Gas program. The "short" and "long" positions shown in the table that follows
are principally associated with the activities described under (i) and (ii),
respectively.
Following is selected information concerning our risk management activities:
DECEMBER 31, 2000
---------------------------------------------
COMMODITY OVER-THE-COUNTER
CONTRACTS SWAPS AND OPTIONS TOTAL
--------- ----------------- ---------
(In contracts and thousands of dollars)
Deferred Net (Loss) Gain $ 14,036 $ (28,466) $ (14,430)
Contract Amounts - Gross $ 65,730 $ 163,991 $ 229,721
Contract Amounts - Net $ 540 $ (93,283) $ (92,743)
Credit Exposure of Loss $ 2,514 $ 2,514
Notional Volumetric Positions: Long 419 1,296
Notional Volumetric Positions: Short (500) (2,913)
Net Notional Totals To Occur in 2001 (81) (1,459)
Net Notional Totals To Occur in 2002 -- (158)
In June 1998, the Financial Accounting Standards Board issued SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (the
"Statement"). The Statement establishes accounting and reporting standards
requiring that every derivative instrument (including certain derivative
instruments embedded in other contracts) be recorded in the balance sheet as
either an asset or liability measured at its fair value. The Statement requires
that changes in the derivatives fair value be recognized currently in earnings
unless specific hedge accounting criteria are met. If the derivatives meet these
criteria, the Statement allows a derivative's gains and losses to offset related
results on the hedged item in the income statement, and requires that a company
formally designate a derivative as a hedge and document and assess the
effectiveness of derivatives associated with transactions that receive hedge
accounting.
The Statement, after amendment by SFAS 137 and SFAS 138, is effective for all
quarters of all fiscal years beginning after June 15, 2000. The Statement cannot
be applied retroactively. As discussed preceding, our principal use of
derivative financial instruments is to mitigate the market price risk associated
with anticipated transactions for the purchase and sale of natural gas. The
Statement allows these transactions to continue to be treated as hedges for
accounting purposes, although the changes in the market value of these
instruments will affect comprehensive income in the period in which they occur
and any ineffectiveness in the risk mitigation performance of the hedge will
affect net income currently, although we do not expect the amount of such
inefficiency to be material. The change in the market value of these instruments
representing effective hedge operation will continue to affect net income in the
period in which the associated physical transactions are consummated. Adoption
of the Statement has resulted in the $14.4 million deferred net loss shown in
the preceding table being reported as part of other comprehensive income, as
well as subsequent changes in the market value of these derivatives prior to
consummation of the transaction being hedged.
F-31
34
15. EMPLOYEE BENEFITS
(A) Retirement Plans
We have defined benefit pension plans covering eligible full-time employees.
These plans provide pension benefits that are based on the employees'
compensation during the period of employment, age and years of service. These
plans are tax-qualified subject to the minimum funding requirements of the
"Employee Retirement Income Security Act of 1974." Our funding policy is to
contribute annually the recommended contribution using the actuarial cost method
and assumptions used for determining annual funding requirements. Plan assets
consist primarily of pooled fixed income, equity, bond and money market funds.
Plan assets included our common stock valued at $11.5 million and $5.1 million
as of December 31, 2000 and 1999, respectively.
Net periodic pension cost includes the following components:
YEAR ENDED DECEMBER 31,
------------------------------------------
2000 1999 1998
-------- -------- --------
(In Thousands)
Service Cost $ 7,306 $ 9,977 $ 4,859
Interest Cost 8,600 8,170 7,537
Expected Return on Assets (14,034) (13,381) (11,812)
Net Amortization and Deferral (1,257) (210) (864)
Recognition of Curtailment Gain -- (9) --
-------- -------- --------
Net Periodic Pension (Benefit) Cost $ 615 $ 4,547 $ (280)
======== ======== ========
The following table sets forth the reconciliation of the beginning and ending
balances of the pension benefit obligation:
2000 1999
--------- ---------
(In Thousands)
Benefit Obligation at Beginning of Year $(118,038) $(121,076)
Service Cost (7,306) (9,977)
Interest Cost (8,600) (8,170)
Actuarial Gain 3,922 14,602
Benefits Paid 6,915 6,421
Curtailment Gain -- 162
--------- ---------
Benefit Obligation at End of Year $(123,107) $(118,038)
========= =========
F-32
35
The following table sets forth the reconciliation of the beginning and ending
balances of the fair value of the plans' assets, the plans' funded status and
prepaid pension cost amounts recognized under the caption "Other Current Assets"
in our Consolidated Balance Sheets:
DECEMBER 31,
---------------------------
2000 1999
--------- ---------
(In Thousands)
Fair Value of Plan Assets at Beginning of Year $ 150,900 $ 143,983
Actual Return on Plan Assets During the Year 17,294 13,338
Benefits Paid During the Year (6,915) (6,421)
--------- ---------
Fair Value of Plan Assets at End of Year 161,279 150,900
Benefit Obligation at End of Year (123,107) (118,038)
--------- ---------
Plan Assets in Excess of Projected Benefit Obligation 38,172 32,862
Unrecognized Net Gain (33,134) (27,080)
Prior Service Cost Not Yet Recognized in Net Periodic Pension Costs 88 105
Unrecognized Net Asset at Transition (696) (842)
--------- ---------
Prepaid Pension Cost $ 4,430 $ 5,045
========= =========
The rate of increase in future compensation was 3.5 percent for 2000, 1999 and
1998. The expected long-term rate of return on plan assets was 9.5 percent for
2000 and 1999, and 8.5 percent for 1998. The weighted-average discount rate used
in determining the actuarial present value of the projected benefit obligation
was 7.75 percent for 2000 and 1999, and 6.75 percent for 1998.
Effective January 1, 2001, we added a cash balance plan to our retirement plan.
Certain collectively bargained employees and "grandfathered" employees will
continue to accrue benefits through the defined pension benefit plan described
above. All other employees will accrue benefits through a personal retirement
account in the new cash balance plan. All employees converting to the cash
balance plan will be credited with the current fair value of any benefits they
have previously accrued through the defined benefit plan. We will then begin
contributions on behalf of these employees equal to 3% of eligible compensation
every pay period. In addition, we may make discretionary contributions to the
plan based on our performance. Interest will be credited to the personal
retirement accounts at the 30-year U.S. Treasury bond rate in effect each year.
Employees will be fully vested in the plan after five years, and they may take a
lump sum distribution upon termination or retirement.
In 2000, we merged the Kinder Morgan Bulk Terminals Retirement Savings Plan and
the Kinder Morgan Retirement Savings Plan with the Kinder Morgan Profit Sharing
and Savings Plan, a defined contribution plan. The merged plan was renamed the
Kinder Morgan, Inc. Savings Plan. On July 2, 2000, we began making regular
contributions to the Plan. Contributions are made each pay period in an amount
equal to 4% of compensation on behalf of each eligible employee. All
contributions are in the form of Company stock, which is immediately convertible
into other available investment vehicles at the employee's discretion. On July
25, 2000, our Board of Directors authorized an additional 6 million shares to be
issued through the Plan, for a total of 6.7 million shares available. In
addition to the above contributions, we may make annual discretionary
contributions based on our performance. These contributions are made in the year
following the year for which the contribution amount is calculated. The total
amount contributed for 2000 was $3.7 million. No contribution was made to the
profit sharing plan for 1999 or 1998. In January 1998, we acquired the MidCon
Retirement Plan as part of our acquisition of MidCon Corp. (See Note 2.) The
MidCon plan was a defined contribution plan. Contributions to the plan were
based on age and earnings. Effective January 1, 1999, the MidCon plan was merged
into the Profit Sharing Plan and all eligible MidCon employees joined our
defined benefit pension plans. In 1999 and 1998, we contributed $0.7 million and
$4.6 million, respectively, to the MidCon plan.
F-33
36
(B) Other Postretirement Employee Benefits
We have a defined benefit postretirement plan providing medical and life
insurance benefits upon retirement for eligible employees and their eligible
dependents, including former MidCon employees who met the eligibility
requirements on the date of acquisition of MidCon Corp. (see Note 2). The MidCon
postretirement medical and life insurance plans were "grandfathered" as of the
acquisition date and no new employees have or will be added to the MidCon plans
subsequent to the acquisition date. We fund the future expected postretirement
benefit cost under the plan by making payments to Voluntary Employee Benefit
Association trusts. Plan assets consist primarily of pooled fixed income funds.
Net periodic postretirement benefit cost includes the following components:
YEAR ENDED DECEMBER 31,
---------------------------------------
2000 1999 1998
------- ------- -------
(In Thousands)
Service Cost $ 413 $ 450 $ 592
Interest Cost 7,159 6,655 6,425
Expected Return on Assets (4,790) (3,720) (2,854)
Net Amortization and Deferral 992 908 919
Curtailment Gain -- -- (1,569)
------- ------- -------
Net Periodic Postretirement Benefit Cost $ 3,774 $ 4,293 $ 3,513
======= ======= =======
The following table sets forth the reconciliation of the beginning and ending
balances of the accumulated postretirement benefit obligation:
2000 1999
--------- ---------
(In Thousands)
Benefit Obligation at Beginning of Year $ (93,080) $(101,988)
Service Cost (413) (450)
Interest Cost (7,159) (6,655)
Actuarial Gain (Loss) (8,191) 3,278
Benefits Paid 15,918 15,330
Retiree Contributions (2,253) (2,595)
--------- ---------
Benefit Obligation at End of Year $ (95,178) $ (93,080)
========= =========
F-34
37
The following table sets forth the reconciliation of the beginning and ending
balances of the fair value of plan assets; the plan's funded status and the
amounts included under the caption "Other" in the category "Other Liabilities
and Deferred Credits" in our Consolidated Balance Sheets:
DECEMBER 31,
-------------------------
2000 1999
-------- --------
(In Thousands)
Fair Value of Plan Assets at Beginning of Year $ 52,572 $ 45,364
Actual Return on Plan Assets (2,175) 4,320
Contributions by Employer 1,500 2,771
Retiree Contributions 1,726 2,246
Benefits Paid (2,467) (2,129)
-------- --------
Fair Value of Plan Assets at End of Year 51,156 52,572
Benefit Obligation at End of Year (95,178) (93,080)
-------- --------
Excess of Projected Benefit Obligation Over Plan Assets (44,022) (40,508)
Unrecognized Net (Gain) Loss 12,779 (2,313)
Unrecognized Net Obligations at Transition 11,149 12,078
-------- --------
Accrued Expense $(20,094) $(30,743)
======== ========
The weighted-average discount rate used in determining the actuarial present
value of the accumulated postretirement benefit obligation was 7.75 percent for
2000 and 1999, and 6.75 percent for 1998. The expected long-term rate of return
on plan assets was 9.5 percent for 2000 and 1999, and 8.5 percent for 1998. The
assumed health care cost trend rate was 7 percent per year for 1999 and beyond
(3 percent per year for 1999 and beyond for the MidCon plans). A
one-percentage-point increase (decrease) in the assumed health care cost trend
rate for each future year would have increased (decreased) the aggregate of the
service and interest cost components of the 2000 net periodic postretirement
benefit cost by approximately $23,332 ($22,163) and would have increased
(decreased) the accumulated postretirement benefit obligation as of December 31,
2000 by approximately $205,055 ($214,589).
16. COMMON STOCK OPTION AND PURCHASE PLANS
We have the following stock option plans: The 1982 Incentive Stock Option Plan,
the 1982 Stock Option Plan for Non-Employee Directors, the 1986 Incentive Stock
Option Plan, the 1988 Incentive Stock Option Plan, the 1992 Stock Option Plan
for Non-Employee Directors, the 1994 Kinder Morgan, Inc. Long-term Incentive
Plan (which also provides for the issuance of restricted stock), the American
Oil and Gas Corporation Stock Incentive Plan and the Kinder Morgan, Inc. Amended
and Restated 1999 Stock Option Plan. We also have an employee stock purchase
plan. All per share amounts and shares outstanding or exercisable presented in
this note have been restated to reflect the impact of the December 31, 1998,
three-for-two common stock split as discussed in Note 12(D).
On October 8, 1999, our Board of Directors approved the creation of the 1999
stock option plan, a broadly based non-qualified stock option plan. Under the
plan, options may be granted to individuals who are regular full-time employees,
including officers and directors who are employees. The aggregate number of
shares of stock that may be issued under the plan is 5.5 million. Options under
the plan vest in 25 percent increments on the anniversary of the grant over a
four-year period from the date of grant. All options granted under the plan have
a 10-year life, and must be granted at not less than the fair market value of
Kinder Morgan, Inc. common stock at the close of trading on the date of grant.
On January 17, 2001, our Board of Directors approved an additional 5 million
shares for future grants to participants in the 1999 Stock Option Plan, which
brings the aggregate number of shares subject to the plan to 10.5 million. The
Board also approved an additional 0.5 million shares for future grants to
participants in the 1992 Directors' Plan, which will be available subject to
shareholder approval.
F-35
38
Under all plans, except the Long-term Incentive Plan and the AOG Plan, options
are granted at not less than 100 percent of the market value of the stock at the
date of grant. Under the Long-term Incentive Plan options may be granted at less
than 100 percent of the market value of the stock at the date of grant. Certain
restricted stock awards include provisions accelerating the lapsing of
restrictions in the event certain operating goals are met. Compensation expense
was recorded totaling $0, $8.6 million, and $3.1 million for 2000, 1999, and
1998, respectively, relating to restricted stock grants awarded under the plans.
OPTION SHARES
SHARES SUBJECT GRANTED THROUGH VESTING EXPIRATION
PLAN NAME TO THE PLAN 12/31/00 PERIOD PERIOD
--------- -------------- --------------- ------- ---------
1982 Plan 1,332,788 1,332,788 Immediate 10 Years
1982 Directors' Plan 186,590 186,590 3 Years 10 Years
1986 Plan 618,750 618,750 Immediate 10 Years
1988 Plan 618,750 618,750 Immediate 10 Years
1992 Directors' Plan 525,000 386,875 0 - 6 Months 10 Years
Long-term Incentive Plan 5,700,000 2,754,839 0 - 5 Years 5 - 10 Years
AOG Plan 775,500 775,500 3 Years 10 Years
1999 Plan 5,500,000 4,974,475 4 Years 10 Years
A summary of the status of our stock option plans at December 31, 2000, 1999 and
1998, and changes during the years then ended is presented in the table and
narrative below:
2000 1999 1998
-------------------------- ------------------------ -------------------------
WTD. AVG. WTD. AVG. WTD. AVG.
EXERCISE EXERCISE EXERCISE
SHARES PRICE SHARES PRICE SHARES PRICE
---------- --------- --------- -------- --------- ----------
OUTSTANDING AT BEGINNING OF YEAR 7,542,898 $ 24.92 4,218,191 $ 24.38 3,220,065 $ 19.19
Granted 1,364,500 $ 30.42 4,837,656 $ 23.81 1,781,761 $ 31.40
Exercised (537,400) $ 19.26 (602,928) $ 8.00 (662,274) $ 16.46
Forfeited (2,276,179) $ 25.69 (910,021) $ 27.79 (121,361) $ 27.35
---------- --------- ---------
OUTSTANDING AT END OF YEAR 6,093,819 $ 26.05 7,542,898 $ 24.92 4,218,191 $ 24.38
========== ======== ========= ======== ========= ========
EXERCISABLE AT END OF YEAR 2,056,771 $ 27.03 1,918,868 $ 26.54 1,794,112 $ 25.11
========== ======== ========= ======== ========= ========
WEIGHTED-AVERAGE FAIR VALUE
OF OPTIONS GRANTED $ 10.51 $ 5.83 $ 12.08
======== ======== ========
The weighted-average fair value of each option grant is estimated on the date of
grant using the Black-Scholes option pricing model with the following
assumptions:
YEAR ENDED DECEMBER 31,
---------------------------------------------
2000 1999 1998
---------- --------- ----------
RISK-FREE INTEREST RATE (%) 4.97 5.5 5.5
EXPECTED WEIGHTED-AVERAGE LIFE 4.5 years 4.0 years 4.0 years
VOLATILITY 0.34 0.31 0.25
EXPECTED DIVIDEND YIELD (%) 0.38 3.2 3.5
We account for these plans under Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees." Had compensation cost for these
plans been determined consistent with SFAS No. 123, "Accounting for Stock-Based
Compensation" ("SFAS 123"), net income and diluted earnings per share would have
been reduced to the pro forma amounts shown in the table below. Because the SFAS
123 method of accounting has not been applied to options granted prior to
January 1, 1995, the resulting pro forma compensation cost may not be
representative of that to be expected in future years. Additionally, the pro
forma amounts include $0.5
F-36
39
million, $0.6 million and $0.6 million related to the purchase discount offered
under the ESP Plan for 2000, 1999 and 1998, respectively.
YEAR ENDED DECEMBER 31,
--------------------------------------------------
2000 1999 1998
----------- ----------- -----------
(In Thousands, Except Per Share Amounts)
NET INCOME (LOSS):
As Reported $ 151,981 $ (239,661) $ 62,211
=========== =========== ===========
Pro Forma $ 144,526 $ (244,513) $ 58,109
=========== =========== ===========
EARNINGS (LOSS) PER DILUTED SHARE:
As Reported $ 1.32 $ (2.99) $ 0.96
=========== =========== ===========
Pro Forma $ 1.26 $ (3.05) $ 0.90
=========== =========== ===========
The following table sets forth our December 31, 2000, common stock options
outstanding, weighted-average exercise prices, weighted-average remaining
contractual lives, common stock options exercisable and the exercisable
weighted-average exercise price:
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
------------------------------------------------------------------------------------- -------------------------
WTD. AVG. WTD. AVG.
NUMBER EXERCISE WTD. AVG. REMAINING NUMBER EXERCISE
PRICE RANGE OUTSTANDING PRICE CONTRACTUAL LIFE EXERCISABLE PRICE
----------- ----------- --------- ------------------- ----------- ---------
$00.00 - $23.72 166,228 $ 20.50 5.90 years 162,986 $ 20.44
$23.81 - $23.81 3,920,421 $ 23.81 8.77 years 1,018,417 $ 23.81
$24.04 - $39.38 2,007,170 $ 30.87 8.55 years 875,368 $ 32.00
----------- ----------
6,093,819 $ 26.05 8.61 years 2,056,771 $ 27.03
=========== ==========
Under the employee stock purchase plan, we may sell up to 2,400,000 shares of
common stock to eligible employees. Employees purchase shares through voluntary
payroll deductions. Prior to the 2000 plan year, shares were purchased annually
at a 15 percent discount from the market value of the common stock, as defined
in the plan, and issued in the month following the end of the plan year.
Beginning with the 2000 plan year, shares are purchased quarterly at a 15
percent discount from the closing price of the common stock on the last trading
day of each calendar quarter. Employees purchased 86,630 shares, 187,567 shares
and 163,799 shares for plan years 2000, 1999 and 1998, respectively. Using the
Black-Scholes model to assign value to the option inherent in the right to
purchase stock under the provisions of the employee stock purchase plan, the
weighted-average fair value per share of purchase rights granted in 2000, 1999
and 1998 was $6.60, $6.41 and $5.94, respectively.
F-37
40
17. COMMITMENTS AND CONTINGENT LIABILITIES
(A) Leases
Expenses incurred under operating leases were $47.1 million in 2000, $57.8
million in 1999, and $56.9 million in 1998. Future minimum commitments under
major operating leases as of December 31, 2000 are as follows:
YEAR AMOUNT
---- ------
(In Thousands)
2001 $ 11,886
2002 8,376
2003 7,813
2004 7,563
2005 7,716
Thereafter 21,605
----------
Total $ 64,959
==========
(B) Guarantees of Unconsolidated Subsidiaries' Debt
We have executed a guarantee of the revolving credit agreement of an
unconsolidated subsidiary, TransColorado, in the amount of $100 million. As of
December 31, 2000, $100 million had been borrowed with a maturity date of
October 13, 2001.
(C) Capital Expenditures Budget
Approximately $5.5 million of our consolidated capital expenditure budget for
2001 had been committed for the purchase of plant and equipment at December 31,
2000.
(D) Commitment to Sell or Purchase Assets
We announced on November 30, 1999, that we entered into agreements with HS
Resources, Inc. for the sale of certain assets in the Wattenberg field area of
the Denver-Julesberg Basin. Under the terms of the agreements, HS Resources,
Inc. commenced operating these assets. We are receiving cash payments from HS
Resources, Inc. during 2000 and 2001, with the legal transfer of ownership
expected to occur on or before December 15, 2001. We were committed, during a
specified period, to purchase, at the option of the other party, an incremental
50% interest in a joint venture pipeline, although the ability of the other
party to cause the purchase is currently stayed; see Notes 5 and 9.
F-38
41
18. FAIR VALUE
The following fair values of Investments, Long-term Debt, Capital Securities and
Kinder Morgan Preferred Stock were estimated based on an evaluation made by an
independent securities analyst. Fair values of "Energy Financial Instruments,
Net" reflect the estimated amounts that we would receive or pay to terminate the
contracts at the reporting date, thereby taking into account the current
unrealized gains or losses on open contracts. Market quotes are available for
substantially all instruments we use.
DECEMBER 31,
----------------------------------------------------------
2000 1999
------------------------- ---------------------------
CARRYING CARRYING
VALUE FAIR VALUE VALUE FAIR VALUE
-------- ---------- --------- -----------
(In Millions)
FINANCIAL ASSETS:
Tom Brown, Inc. Common Stock (1) $ -- $ -- $ 12.3 $ 12.3
FINANCIAL LIABILITIES:
Long-term Debt $3,291.6 $3,253.4 $3,305.6 $3,146.1
Capital Securities $ 275.0 $ 278.7 $ 275.0 $ 265.4
Energy Financial Instruments, Net $ 14.4 $ 14.4 $ 16.1 $ 16.1
(1) See Note 5 regarding the sale of this stock.
19. BUSINESS SEGMENT INFORMATION
In accordance with the manner in which we manage our businesses, including the
allocation of capital and evaluation of business unit performance, we report our
operations in the following segments: (1) Natural Gas Pipeline Company of
America and certain associated entities, referred to as Natural, a major
interstate natural gas pipeline and storage system; (2) Retail, the regulated
sale of natural gas to residential commercial and industrial customers and
non-utility sales of natural gas to certain utility customers under the Choice
Gas Program and (3) Power and Other, the construction and operation of natural
gas fired electric generation facilities, together with various other activities
not constituting separately managed or reportable business segments. In previous
periods, we owned and operated other lines of business that we discontinued
during 1999. In addition, our direct investment in the natural gas transmission
and storage business has significantly decreased as a result of (i) the December
2000 sale of Kinder Morgan Texas Pipeline, Inc. to Energy Partners and (ii) the
December 31, 1999 sale of Kinder Morgan Interstate Gas Transmission LLC to
Energy Partners. The results of operations of these two businesses are included
in our financial statements until their disposition, which is discussed in Note
5.
The accounting policies applied in the generation of business unit information
are generally the same as those described in Note 1 to the accompanying
Consolidated Financial Statements, except that items below the "Operating
Income" line are either not allocated to business units or are not considered by
Management in its evaluation of business unit performance. An exception to this
is that Power, which routinely conducts its business activities in the form of
joint operations with other parties that are accounted for under the equity
method of accounting, includes its equity in earnings of these investees in its
operating results. These equity-method earnings are included in "Other Income
and (Expenses)" in our consolidated income statement. In addition, certain items
included in consolidated operating income (such as merger-related and severance
costs and general and administrative expenses) are not allocated to individual
business units. With adjustment for these items, we currently evaluate business
unit performance primarily based on operating income in relation to the level of
assets employed. Sales between business units are accounted for at market
prices. For comparative purposes, prior period results and balances have been
reclassified as necessary to conform to the current presentation.
F-39
42
Natural's principal delivery market area encompasses the states of Illinois,
Indiana, Iowa and portions of Wisconsin, Nebraska, Kansas, Missouri and
Arkansas. Natural is the largest transporter of natural gas to the Chicago,
Illinois area, its largest market. During 2000, approximately 50% of Natural's
transportation represented deliveries to this market. Natural's storage capacity
is largely located near its transportation delivery markets, effectively serving
the same customer base. Natural has a number of individually significant
customers, including local gas distribution companies in the greater Chicago
area and major natural gas marketers and, during 2000, approximately 50% of its
operating revenues were attributable to its nine largest customers. Retail's
markets are represented by residential, commercial and industrial customers
located in Colorado, Nebraska and Wyoming. These markets represent varied types
of customers in many industries, but a significant amount of Retail's load is
represented by the use of natural gas for space heating, grain drying and
irrigation. The latter two groups of customers are concentrated in the
agricultural industry and all markets are affected by the weather. Power's
current principal market is represented by the local electric utilities in
Colorado, which purchase the power output from its generation facilities. Its
market will expand geographically as a result of power generation facilities
planned or under construction and it is expected that future customers may
include wholesale power marketers.
During 2000 and 1999, we had revenues from a single customer of $740.5 million
and $ 389.4 million, respectively, amounts in excess of 10 percent of
consolidated operating revenues for each year. Both Natural and Kinder Morgan
Texas made sales to this customer. With the transfer of Kinder Morgan Texas to
Energy Partners as of December 31, 2000, sales to this customer are not expected
to exceed 10% of consolidated operating revenues in the future, although certain
of Natural's customers may meet this threshold.
F-40
43
BUSINESS SEGMENT INFORMATION
DECEMBER 31,
YEAR ENDED DECEMBER 31, 2000 2000
--------------------------------------------------------------------------- ------------
INCOME FROM REVENUES FROM DEPRECIATION
CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT
OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS
----------- ------------- ------------ ------------- ------------ -----------
(In Thousands)
Natural $ 342,887 $ 656,035 $ (18) $ 84,975 $ 38,555 $5,478,183
Kinder Morgan Interstate -- -- -- -- -- --
Retail 49,732 229,510 -- 11,776 10,730 350,042
Kinder Morgan Texas 29,318 1,747,499 -- 2,211 16,734 --
Power and Other(3) 31,293 80,693 4 9,203 71,458 2,589,880(1)
Discontinued Operations -- -- -- -- 3,185 --
---------- ---------- ---------- ---------- ---------- ----------
Consolidated 453,230 $2,713,737 $ (14) $ 108,165 $ 140,662 $8,418,105
========== ========== ========== ========== ==========
General and Administrative Expenses 58,087
Merger Related Costs --
----------
Operating Income 395,143
Other Income and (Expenses) (88,701)
----------
Income from Continuing Operations
Before Income Taxes $ 306,442
==========
DECEMBER 31,
YEAR ENDED DECEMBER 31, 1999 1999
--------------------------------------------------------------------------- ------------
INCOME FROM REVENUES FROM DEPRECIATION
CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT
OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS
----------- ------------- ------------ ------------- ------------ -----------
(In Thousands)
Natural $ 306,507 $ 625,705 $ 1,182 $ 109,346 $ 41,716 $5,469,050
Kinder Morgan Interstate 53,924 96,531 16,676 16,985 20,743 --
Retail 20,104 182,861 51 11,382 11,749 332,618
Kinder Morgan Texas 16,554 872,161 -- 2,466 4,567 255,200
Power and Other(3) 21,647 59,110 194 7,754 18,869 2,650,579(1)
Discontinued Operations -- -- -- -- 28,363 718,227
---------- ---------- ---------- ---------- ---------- ----------
Consolidated 418,736 $1,836,368 $ 18,103 $ 147,933 $ 126,007 $9,425,674
========== ========== ========== ========== ==========
General and Administrative Expenses 85,591
Merger Related Costs 37,443
----------
Operating Income 295,702
Other Income and (Expenses) (49,311)
----------
Income from Continuing Operations
Before Income Taxes $ 246,391
==========
DECEMBER 31,
YEAR ENDED DECEMBER 31, 1998 1998
--------------------------------------------------------------------------- ------------
INCOME FROM REVENUES FROM DEPRECIATION
CONTINUING EXTERNAL INTERSEGMENT AND CAPITAL SEGMENT
OPERATIONS CUSTOMERS REVENUES AMORTIZATION EXPENDITURES ASSETS
----------- ------------- ------------ ------------- ------------ -----------
(In Thousands)
Natural $ 336,825 $ 556,662 $ 299 $ 121,008 $ 40,855 $5,421,029
Kinder Morgan Interstate 58,006 88,244 17,333 19,474 49,044 581,089
Retail 56,214 234,307 -- 11,014 17,405 362,289
Kinder Morgan Texas 2,129 739,201 -- 1,615 8,037 198,347
Power and Other(3) 16,783 41,845 5,535 2,252 5,539 1,519,510(2)
Discontinued Operations -- -- -- -- 135,634 1,541,515
---------- ---------- ---------- ---------- ---------- ----------
Consolidated 469,957 $1,660,259 $ 23,167 $ 155,363 $ 256,514 $9,623,779
========== ========== ========== ========== ==========
General and Administrative Expenses 68,502
Merger Related Costs 5,763
----------
Operating Income 395,692
Other Income and (Expenses) (172,787)
----------
Income from Continuing Operations
Before Income Taxes $ 222,905
==========
(1) Principally the investment in Energy Partners and corporate cash and
receivables
(2) Principally government securities held as collateral for the Substitute
Note
(3) Restated, see Note 2.
GEOGRAPHIC INFORMATION
All but an insignificant amount of Kinder Morgan's assets and operations are
located in the continental United States.
F-41
44
QUARTERLY FINANCIAL INFORMATION (UNAUDITED)
KINDER MORGAN, INC. AND SUBSIDIARIES
QUARTERLY OPERATING RESULTS FOR 2000 AND 1999
2000 - THREE MONTHS ENDED
----------------------------------------------------------------
MARCH 31(1) JUNE 30(1) SEPTEMBER 30(1) DECEMBER 31
----------- ---------- --------------- -----------
(In Thousands Except Per Share Amounts)
Operating Revenues $ 480,481 $ 551,088 $ 750,465 $ 931,703
Gas Purchases and Other Costs of Sales 277,911 381,607 577,478 723,087
--------- --------- --------- ---------
Gross Margin 202,570 169,481 172,987 208,616
Other Operating Expenses 89,881 87,819 87,517 93,294
--------- --------- --------- ---------
Operating Income 112,689 81,662 85,470 115,322
Other Income and (Expenses) (35,477) (40,581) (40,624) 27,981(2)
--------- --------- --------- ---------
Income From Continuing Operations
Before Income Taxes 77,212 41,081 44,846 143,303
Income Taxes 30,887 16,968 18,138 56,734
--------- --------- --------- ---------
Income From Continuing Operations 46,325 24,113 26,708 86,569
Loss on Disposal of Discontinued
Operations, Net of Tax(3) -- -- -- (31,734)
--------- --------- --------- ---------
Net Income $ 46,325 $ 24,113 $ 26,708 $ 54,835
========= ========= ========= =========
Number of Shares Used in Computing
Basic Earnings Per Share 113,058 114,196 114,461 114,535
Number of Shares Used in Computing
Diluted Earnings Per Share 113,456 114,981 116,177 118,594
BASIC EARNINGS PER COMMON SHARE:
Continuing Operations $ 0.41 $ 0.21 $ 0.23 $ 0.76
Loss on Disposal of Discontinued Operations -- -- -- (0.28)
--------- --------- --------- ---------
Total Basic Earnings Per Common Share $ 0.41 $ 0.21 $ 0.23 $ 0.48
========= ========= ========= =========
DILUTED EARNINGS PER COMMON SHARE:
Continuing Operations $ 0.41 $ 0.21 $ 0.23 $ 0.73
Loss on Disposal of Discontinued Operations -- -- -- (0.27)
--------- --------- --------- ---------
Total Diluted Earnings Per Common Share $ 0.41 $ 0.21 $ 0.23 $ 0.46
========= ========= ========= =========
(1) Restated for a change to the equity method of accounting for an investment
and reflects the reclassification of International's operating results to
continuing operations. See Notes 2 and 6 of the accompanying Consolidated
Financial Statements and the table presented below.
(2) Includes the $62 million pre-tax gain from the contribution of certain
assets to Energy Partners; see Note 5 of the accompanying Notes to
Consolidated Financial Statements.
(3) See Note 6 of the accompanying Notes to Consolidated Financial Statements.
2000 - THREE MONTHS ENDED
----------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30
-------- ------- ------------
(In Thousands)
Income From Continuing
Operations as Previously Reported $ 46,084 $ 24,827 $ 26,628
Power Restatement:
Operating Revenues (1,072) (598) (97)
Other Income and (Expenses) 1,892 1,618 1,092
Income Taxes (328) (408) (398)
Reclassification of International Operations (251) (1,326) (517)
-------- -------- --------
Income From Continuing
Operations as Restated $ 46,325 $ 24,113 $ 26,708
======== ======== ========
F-42
45
1999 - THREE MONTHS ENDED(1)
----------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- --------- ------------ -----------
(In Thousands Except Per Share Amounts)
Operating Revenues $ 425,696 $ 429,331 $ 495,906 $ 485,435
Gas Purchases and Other Costs of Sales 206,158 248,449 318,386 277,257
--------- --------- --------- ---------
Gross Margin 219,538 180,882 177,520 208,178
Other Operating Expenses 118,593 119,292 107,361 107,727
Merger-Related and Severance Costs 2,916 (2,916) 10,962 26,481
--------- --------- --------- ---------
Operating Income 98,029 64,506 59,197 73,970
Other Income and (Expenses) (58,162) (44,145) (48,729) 101,725(2)
--------- --------- --------- ---------
Income From Continuing Operations
Before Income Taxes 39,867 20,361 10,468 175,695
Income Taxes 15,582 8,056 4,465 62,630
--------- --------- --------- ---------
Income From Continuing Operations 24,285 12,305 6,003 113,065
--------- --------- --------- ---------
Discontinued Operations, Net of Tax(3):
Loss From Discontinued Operations (16,720) (14,500) (7,989) (11,732)
Loss on Disposal of Discontinued Operations -- -- (11,479) (332,899)
--------- --------- --------- ---------
Total Loss From Discontinued Operations (16,720) (14,500) (19,468) (344,631)
--------- --------- --------- ---------
Net Income (Loss) 7,565 (2,195) (13,465) (231,566)
Less-Preferred Dividends 88 41 -- --
Less-Premium Paid on Preferred Stock Redemption -- 350 -- --
--------- --------- --------- ---------
Earnings (Loss) Available for Common Stock $ 7,477 $ (2,586) $ (13,465) $(231,566)
========= ========= ========= =========
Number of Shares Used in Computing
Basic Earnings Per Share 69,486 70,689 70,914 110,047
Number of Shares Used in Computing
Diluted Earnings Per Share 69,578 70,761 70,986 110,105
BASIC EARNINGS (LOSS) PER COMMON SHARE:
Continuing Operations $ 0.35 $ 0.17 $ 0.08 $ 1.03
Discontinued Operations (0.24) (0.21) (0.11) (0.11)
Loss on Disposal of Discontinued Operations -- -- (0.16) (3.02)
--------- --------- --------- ---------
Total Basic Earnings (Loss) Per Common Share $ 0.11 $ (0.04) $ (0.19) $ (2.10)
========= ========= ========= =========
DILUTED EARNINGS (LOSS) PER COMMON SHARE:
Continuing Operations $ 0.35 $ 0.17 $ 0.08 $ 1.03
Discontinued Operations (0.24) (0.21) (0.11) (0.11)
Loss on Disposal of Discontinued Operations -- -- (0.16) (3.02)
--------- --------- --------- ---------
Total Diluted Earnings (Loss) Per Common Share $ 0.11 $ (0.04) $ (0.19) $ (2.10)
========= ========= ========= =========
(1) Restated for a change to the equity method of accounting for an investment
and reflects the reclassification of International's operating results to
continuing operations. See Notes 2 and 6 of the accompanying Consolidated
Financial Statements and the table presented below.
(2) Includes the $158 million pre-tax gain from the contribution of certain
assets to Energy Partners; see Note 5 of the accompanying Notes to
Consolidated Financial Statements.
(3) See Note 6 of the accompanying Notes to Consolidated Financial Statements.
F-43
46
1999 - THREE MONTHS ENDED
----------------------------------------------------------------
MARCH 31 JUNE 30 SEPTEMBER 30 DECEMBER 31
--------- --------- ------------ -----------
(In Thousands)
Income From Continuing
Operations as Previously Reported $ 23,908 $ 12,380 $ 5,886 $ 112,478
Power Restatement:
Operating Revenues (2,058) (2,580) (1,201) (1,595)
Other Income and (Expenses) 2,797 2,934 2,955 1,720
Income Taxes (296) (141) (702) (50)
Reclassification of International Operations (66) (288) (935) 512
--------- --------- --------- ---------
Income From Continuing
Operations as Restated $ 24,285 $ 12,305 $ 6,003 $ 113,065
========= ========= ========= =========
F-44
47
SELECTED FINANCIAL DATA
FIVE-YEAR REVIEW
KINDER MORGAN, INC. AND SUBSIDIARIES
(In Thousands, Except Per Share Amounts)
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------------
2000 1999(1,3) 1998(1,4) 1997 1996
---------- ---------- ---------- --------- ---------
Operating Revenues $2,713,737 $1,836,368 $1,660,259 $ 340,685 $ 299,608
Gas Purchases and Other Costs of
Sales 1,960,083 1,050,250 836,614 134,476 102,725
---------- ---------- ---------- --------- ---------
Gross Margin 753,654 786,118 823,645 206,209 196,883
Other Operating Expenses 358,511 490,416 427,953 128,059 128,895
---------- ---------- ---------- --------- ---------
OPERATING INCOME 395,143 295,702 395,692 78,150 67,988
Other Income and (Expenses) (88,701) (49,311) (172,787) (21,039) (14,798)
---------- ---------- ---------- --------- ---------
Income From Continuing Operations
Before Income Taxes 306,442 246,391 222,905 57,111 53,190
Income Taxes 122,727 90,733 82,710 12,777 17,304
---------- ---------- ---------- --------- ---------
INCOME FROM CONTINUING OPERATIONS 183,715 155,658 140,195 44,334 35,886
Gain (Loss) From Discontinued
Operations, Net of Tax (31,734) (395,319) (77,984) 33,163 27,933
---------- ---------- ---------- --------- ---------
NET INCOME (LOSS) 151,981 (239,661) 62,211 77,497 63,819
Less-Preferred Dividends -- 129 350 350 398
Less-Premium Paid on Preferred Stock
Redemption -- 350 -- -- --
---------- ---------- ---------- --------- ---------
EARNINGS (LOSS) AVAILABLE FOR
COMMON STOCK $ 151,981 $ (240,140) $ 61,861 $ 77,147 $ 63,421
========== ========== ========== ========= =========
Number of Shares Used in Computing
Diluted Earnings Per Common Share 115,030 80,358 64,636 47,307 44,436
========== ========== ========== ========== ==========
DILUTED EARNINGS (LOSS) PER
COMMON SHARE:
Continuing Operations $ 1.60 $ 1.93 $ 2.17 $ 0.93 $ 0.80
Discontinued Operations (0.28) (4.92) (1.21) 0.70 0.63
---------- ---------- ---------- ---------- ----------
Total Diluted Earnings (Loss)
Per Common Share $ 1.32 $ (2.99) $ 0.96 $ 1.63 $ 1.43
========== ========== ========== ========== ==========
DIVIDENDS PER COMMON SHARE $ 0.20 $ 0.65 $ 0.76 $ 0.73 $ 0.70
========== ========== ========== ========== ==========
CAPITAL EXPENDITURES(2) $ 137,477 $ 97,644 $ 120,881 $ 230,814 $ 88,755
========== ========== ========== ========== ==========
TOTAL ASSETS(5) $8,418,105 $9,425,674 $9,623,779 $2,305,805 $1,629,720
========== ========== ========== ========== ==========
CAPITALIZATION(5):
Common Stockholders' Equity $1,797,421 40% $1,669,846 32% $1,219,043 25% $ 606,132 48% $ 519,794 55%
Preferred Stock -- -- -- -- 7,000 -- 7,000 -- 7,000 1%
Preferred Capital Trust Securities 275,000 6% 275,000 5% 275,000 6% 100,000 8% -- --
Long-Term Debt 2,478,983 54% 3,293,326 63% 3,300,025 69% 553,816 44% 423,676 44%
---------- --- ---------- --- ---------- --- ---------- --- ---------- ---
Total Capitalization $4,551,404 100% $5,238,172 100% $4,801,068 100% $1,266,948 100% $ 950,470 100%
========== === ========== === ========== === ========== === ========== ===
BOOK VALUE PER
COMMON SHARE(5) $ 15.70 $ 14.82 $ 17.77 $ 12.63 $ 11.44
========== ========== ========== ========== ==========
(1) Restated, see Note 2 of the accompanying Notes to Consolidated Financial
Statements.
(2) Capital Expenditures shown are for continuing operations only.
(3) Reflects the acquisition of Kinder Morgan Delaware on October 7, 1999. See
Note 2 of the accompanying Notes to Consolidated Financial Statements.
(4) Reflects the acquisition of MidCon Corp. on January 30, 1998. See Note 2 of
the accompanying Notes to Consolidated Financial Statements.
(5) At December 31 of each respective year
F-45
48
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS
GENERAL
In this report, unless the context requires otherwise, references to "we," "us,"
"our," or the "Company" are intended to mean Kinder Morgan, Inc. (a Kansas
corporation and formerly known as K N Energy, Inc.) and its consolidated
subsidiaries. The following discussion should be read in conjunction with the
accompanying Consolidated Financial Statements and related Notes. Specifically,
as discussed in Notes 2, 5 and 6 of the accompanying Notes to Consolidated
Financial Statements, we have engaged in acquisitions (including the October
1999 acquisition of Kinder Morgan (Delaware), Inc., a Delaware corporation and
the indirect owner of the general partner interest in Kinder Morgan Energy
Partners, L.P., a publicly-traded master limited partnership, referred to in
this report as "Energy Partners"), and divestitures (including the
discontinuance of certain lines of business and the transfer of certain assets
to Energy Partners), which may affect comparisons of financial position and
results of operations between periods.
Certain information contained in this report may include "forward-looking
statements" within the meaning of the Private Securities Litigation Reform Act
of 1995. These statements are subject to risks and uncertainties and are based
on the beliefs and assumptions of our management, based on information currently
available to our management. When words such as "believes," "expects,"
"anticipates," "intends," "plans," "estimates," "should" or similar expressions
are used, we are making forward-looking statements.
Forward-looking statements are not guarantees of performance. They involve
risks, uncertainties and assumptions. Our future results and stockholder values
may differ materially from those expressed in these forward-looking statements.
Many of the factors that will determine these results and values are beyond our
ability to control or predict. These statements are necessarily based upon
various assumptions involving judgments with respect to the future including,
among others, the ability to achieve cost savings and revenue growth, national,
international, regional and local economic, competitive and regulatory
conditions and developments, technological developments, capital market
conditions, inflation rates, interest rates, the political and economic
stability of oil producing nations, energy markets, weather conditions, business
and regulatory or legal decisions, the pace of deregulation of retail natural
gas and electricity, the timing and extent of changes in commodity prices for
oil, natural gas, natural gas liquids, electricity and certain agricultural
products, the timing and success of business development efforts, and other
uncertainties, all of which are difficult to predict and many of which are
beyond our control. Readers are cautioned not to put undue reliance on any
forward-looking statements. For those statements, we claim the protection of the
safe harbor for forward-looking statements contained in the Private Securities
Litigation Reform Act of 1995.
Business Strategy
On October 7, 1999, we completed the merger of Kinder Morgan, Inc. and Kinder
Morgan Delaware, the owner of the general partner interest in Energy Partners.
Under the terms of the merger agreement, we issued approximately 41.5 million
shares of our common stock in exchange for all of the outstanding shares of
Kinder Morgan Delaware. Upon closing of the transaction, Richard D. Kinder was
named Chairman of the combined company, which was renamed Kinder Morgan, Inc.
In accordance with previously announced plans, we implemented and have continued
to pursue our "Back to Basics" strategy. This strategy includes the following
key aspects: (i) divest non-core assets and use the proceeds to reduce debt,
(ii) sell certain core assets for fair market value to Energy Partners, (iii)
focus on the efficiency and profitability of our remaining core assets, (iv)
reduce corporate overhead costs, (v) align employee and shareholder incentives,
(vi) reduce the shareholder dividend and (vii) seek accretive acquisitions and
business expansions.
F-46
49
During 1999, we implemented plans to dispose of our non-core businesses and as
of December 31, 2000, we have effectively completed the disposition of these
assets and operations, all as more fully described in Note 6 of the accompanying
Notes to Consolidated Financial Statements. The cash proceeds from these
dispositions were largely used to retire debt, contributing to the reduction in
leverage experienced during this period.
In addition to sales of non-core assets to third parties, we made significant
transfers of assets to Energy Partners at the end of 1999 and the end of 2000,
which, in total, represent over $1 billion of fair market value. By contributing
assets to Energy Partners that are accretive to its earnings and cash flow, we
can receive fair market value in the contribution transaction, while still
maintaining an indirect interest in the earnings and cash flows of the assets
through our limited and general partner interests in Energy Partners. As of
December 31, 2000, we owned approximately 14.0 million limited partner units of
Energy Partners, representing approximately 20.7% of the total units
outstanding. As a result of our general and limited partner interests in Energy
Partners, at the current level of distribution including incentive distributions
to the general partner, we currently are entitled to receive approximately 49%
of all distributions from Energy Partners. The actual level of distributions
received by us in the future will vary with the level of distributable cash
determined by Energy Partners' partnership agreement. By increasing our stake in
Energy Partners, we expect to receive additional future cash distributions from
Energy Partners through incremental general partner incentive distributions as
well as increased limited partner distributions due to our ownership of
additional common units received as compensation in the transfers.
After the dispositions discussed above, our primary source of operating income
is Natural Gas Pipeline Company of America, referred to in this report as
"Natural," a major interstate natural gas pipeline system that runs from natural
gas producing areas in West Texas and the Gulf of Mexico to its principal market
area of Chicago, Illinois. In accordance with our strategy to increase
operational focus on core assets, we have worked toward agreements to fully
utilize the transportation and storage capacity of Natural with the result that
Natural sold out its capacity through the year 2000-2001 winter season. Natural
continues to pursue opportunities to connect its system to power generation
facilities and, in addition, has announced plans to extend its system into the
metropolitan east area of St. Louis anchored by a contract with Dynegy Marketing
and Trade. Additional information on Natural's business is included under
"Natural" in a subsequent section of this report.
Our other remaining core operations consist of the retail distribution of
natural gas to approximately 250,000 customers in several Western and Midwestern
states and the construction and operation of electric power generation
facilities. Our natural gas distribution properties are located, in part, in
areas where significant growth is occurring and we expect to participate in that
growth through increased natural gas demand. The nation's demand for additional
electric power generation is significant and immediate. Our power generation
business has a beneficial master turbine purchase agreement that it plans to
utilize in constructing a number of gas-fired electric generation facilities to
help meet this need. These power projects, in addition to generating income in
their own right, are expected to increase Natural's throughput as described
above.
Even though we have made significant progress to date, we believe that
opportunities remain for increasing shareholder value through cost reductions
and other efficiency improvements with respect to both existing assets and
future acquisitions. One measure intended to increase shareholder value is the
All Employee Stock Option Plan implemented in October 1999. Through this plan,
virtually all employees, with the exception of Richard D. Kinder and William V.
Morgan (each of whom is currently a major shareholder), have received options to
purchase shares of our common stock. By aligning employee incentives with
shareholder value, we expect to increase employee productivity, retention and
satisfaction. We believe these factors ultimately contribute to increased
earnings and overall shareholder value. To reduce debt and provide funds for
future growth, we reduced the regular quarterly common dividend from $0.20 per
share to $0.05 per share in the fourth quarter of 1999 and have maintained it at
that level.
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50
The final aspect of our strategy is seeking out accretive acquisitions and
business expansions. Energy Partners has a multi-year history of making
accretive acquisitions, which benefit us through our limited and general partner
interests. This acquisitive strategy is expected to continue, with the
population of potential acquisition candidates being driven by consolidation in
the energy industry, as well as rationalization of asset portfolios by major
corporations. In addition, we expect to, within strict guidelines as to rate of
return and risk and timing of cash flows, expand Natural's pipeline system,
acquire natural gas distribution properties that fit well with the current
profile and build and acquire incremental power generation facilities.
CONSOLIDATED FINANCIAL RESULTS
YEAR ENDED DECEMBER 31,
---------------------------------------------------
2000 1999 1998
----------- ----------- -----------
(In Thousands Except Per Share Amounts)
Operating Revenues $ 2,713,737 $ 1,836,368 $ 1,660,259
=========== =========== ===========
Gross Margin(1) $ 753,654 $ 786,118 $ 823,645
=========== =========== ===========
Operating Income:
Before Merger-related and Severance Costs $ 395,143 $ 333,145 $ 401,455
Merger-related and Severance Costs -- (37,443) (5,763)
----------- ----------- -----------
Consolidated Operating Income $ 395,143 $ 295,702 $ 395,692
=========== =========== ===========
Income from Continuing Operations:
Before Merger-related and Severance Costs
and Gains from Sales of Assets $ 146,735 $ 58,848 $ 131,416
Merger-related and Severance Costs, Net of Tax -- (23,327) (3,518)
Gains from Sales of Assets, Net of Tax 36,980 120,137 12,297
----------- ----------- -----------
Income from Continuing Operations 183,715 155,658 140,195
----------- ----------- -----------
Discontinued Operations, Net of Tax:
Loss from Discontinued Operations -- (50,941) (77,984)
Loss on Disposal of Discontinued Operations (31,734) (344,378) --
----------- ----------- -----------
(31,734) (395,319) (77,984)
----------- ----------- -----------
Net Income (Loss) $ 151,981 $ (239,661) $ 62,211
=========== =========== ===========
Diluted Earnings (Loss) Per Share:
From Continuing Operations Before Merger-related
and Severance Costs and Gain from Sales of Assets $ 1.28 $ 0.73 $ 2.03
Merger-related and Severance Costs -- (0.29) (0.05)
Gain from Sales of Assets 0.32 1.49 0.19
Loss from Discontinued Operations -- (0.63) (1.21)
Loss on Disposal of Discontinued Operations (0.28) (4.29) --
----------- ----------- -----------
Diluted Earnings (Loss) Per Share $ 1.32 $ (2.99) $ 0.96
=========== =========== ===========
Number of Shares Used in Computing Diluted Earnings
Per Common Share 115,030 80,358 64,636
=========== =========== ===========
(1) Gross margin equals total operating revenues less gas purchases and other
costs of sales.
Our results for 2000, in comparison to 1999, reflect an increase of $877.4
million in operating revenues, a decrease of $32.5 million in gross margin and
an increase of $62.0 million in operating income before merger-related and
severance costs. The increase in operating revenues is principally due to (i)
increased natural gas sales volumes and prices on the Kinder Morgan Texas
Pipeline, (ii) weather-related increases in natural gas sales and transportation
volumes from Retail Natural Gas Distribution and (iii) increased storage service
revenues and operational gas sales from Natural Gas Pipeline Company of America,
partially offset by the fact that 2000 results do not include the operations of
Kinder Morgan Interstate Gas Transmission. Kinder Morgan Interstate Gas
Transmission was contributed to Energy Partners at December 31, 1999, while
Kinder Morgan Texas Pipeline was contributed to Energy Partners at December 31,
2000. These transactions are described in Note 5 of the accompanying Notes to
Consolidated Financial Statements. The decrease in gross margin that
F-48
51
occurred from 1999 to 2000, despite the increased operating revenues, was
principally due to the fact that 2000 results do not include the results of
Kinder Morgan Interstate Gas Transmission. Results for 1999 and 1998 included
merger-related and severance costs as further discussed in Note 3 of the
accompanying Notes to Consolidated Financial Statements. The individual business
unit sections that follow contain more details concerning the comparison of
these results down to the level of operating income.
Below the operating income line, results for 2000, 1999 and 1998 included
significant gains from the sale of assets. Results for 2000 and 1999 included
equity in earnings (and associated amortization of excess investment) associated
with our October 1999 acquisition of Kinder Morgan Delaware. Interest expense
increased significantly in 1999 due, in large part, to the January 1998
acquisition of MidCon Corp., and declined in 2000 largely due to reduced
short-term borrowing levels as a result of applying cash received from asset
sales. Additional information on these non-operating income and expense items is
included under "Other Income and (Expenses)" following, and information
concerning the acquisitions and asset sales is contained in Notes 2 and 5 of the
accompanying Notes to Consolidated Financial Statements.
Diluted earnings per common share from continuing operations before
merger-related and severance costs and gains from sales of assets increased from
$0.73 per share in 1999 to $1.28 per share in 2000. In addition to the operating
and financing factors described preceding, this increase also reflects an
increase of 34.7 million (43.1%) in average diluted shares outstanding, largely
due to shares issued in conjunction with the acquisition of Kinder Morgan
Delaware discussed above. Diluted earnings per common share increased from a
loss of $2.99 per common share in 1999 to earnings of $1.32 per common share in
2000, reflecting, in addition to the factors discussed preceding, the impact of
discontinued operations, including losses on disposal of discontinued
operations, in each period. See "Discontinued Operations" following and Note 6
of the accompanying Notes to Consolidated Financial Statements.
F-49
52
RESULTS OF OPERATIONS
We manage our various businesses by, among other things, allocating capital and
monitoring operating performance. This management process includes dividing the
overall Company into business units so that performance can be effectively
monitored and reported for a limited number of discrete businesses. Currently,
we manage and report our operations in the following business units:
BUSINESS UNIT BUSINESS CONDUCTED REFERRED TO AS:
------------- ------------------ ---------------
Natural Gas Pipeline Company of Major interstate natural gas pipeline and Natural
America and certain affiliates storage system
Retail Natural Gas Distribution The regulated sale of natural gas to Retail
residential, commercial and industrial
customers and non-utility sales of natural
gas to certain utility customers under the
Choice Gas Program
Power Generation and Other The construction and operation of natural gas Power and Other
fired electric generation facilities,
together with various other activities not
constituting separately managed or reportable
business segments
In previous periods, we owned and operated other lines of business, which we
discontinued during 1999. In addition, our direct investment in the natural gas
transmission and storage business has significantly decreased as a result of (i)
the December 31, 1999 sale of Kinder Morgan Interstate Gas Transmission LLC,
referred to in this report as "Kinder Morgan Interstate," to Energy Partners and
(ii) the December 2000 sale of Kinder Morgan Texas Pipeline, Inc., referred to
in this report as "Kinder Morgan Texas," to Energy Partners. The results of
operations of these two businesses are included in our financial statements
until their disposition, which is discussed under "General" in this portion of
the Form 10-K and in Note 5 of the accompanying Notes to Consolidated Financial
Statements.
The accounting policies applied in the generation of business unit information
are generally the same as those described in Note 1 to the accompanying
Consolidated Financial Statements, except that items below the "Operating
Income" line are either not allocated to business units or are not considered by
Management in its evaluation of business unit performance. An exception to this
is that Power, which routinely conducts its business activities in the form of
joint operations with other parties that are accounted for under the equity
method of accounting, includes its equity in earnings of these investees in its
business unit operating results. These equity-method earnings are included in
"Other Income and (Expenses)" in our consolidated income statement. In addition,
certain items included in consolidated operating income (such as merger-related
and severance costs and general and administrative expenses) are not allocated
to individual business units. With adjustment for these items, we currently
evaluate business unit performance primarily based on operating income in
relation to the level of assets employed. Sales between business units are
accounted for at market prices. For comparative purposes, prior period results
and balances have been reclassified as necessary to conform to the current
presentation.
Following are operating results by individual business unit (before intersegment
eliminations), including explanations of significant variances between the
periods presented.
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53
NATURAL
YEAR ENDED DECEMBER 31,
----------------------------------------
2000 1999 1998
-------- -------- --------
(In Thousands Except Systems Throughput)
Operating Revenues $656,017 $626,888 $556,961
-------- -------- --------
Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales 145,431 115,481 24,273
Operations and Maintenance 62,582 72,979 59,055
Depreciation and Amortization 84,975 109,346 121,008
Taxes, Other Than Income Taxes 20,142 22,575 15,800
-------- -------- --------
313,130 320,381 220,136
-------- -------- --------
Operating Income Before Corporate Costs $342,887 $306,507 $336,825
======== ======== ========
Systems Throughput (Trillion Btus) 1,459.3 1,449.9 1,296.6
======== ======== ========
Operating results for Natural are included in our consolidated results beginning
with the January 30, 1998 acquisition of MidCon Corp. See Note 2 of the
accompanying Notes to Consolidated Financial Statements for more information
regarding this acquisition.
Natural's operating income before corporate costs increased by $36.4 million
(11.9%) from 1999 to 2000. Operating results for 2000 were positively affected,
relative to 1999, by (i) increased operational efficiency and the associated
favorable impact of increased gas prices on Natural's operational gas sales in
2000, (ii) increased storage service revenues, (iii) a reduction in amortization
resulting from the July 1999 change in amortization rates (see Note 4 of the
accompanying Notes to Consolidated Financial Statements), (iv) reduced 2000
operations and maintenance expenses due to successful cost control measures and
to the sales of certain gathering assets and offshore laterals and (v) reduced
ad valorem taxes. These positive effects were partially offset by (i) reduced
2000 revenues due to the sales of certain gathering assets and offshore
laterals, (ii) decreased 2000 unit revenues largely attributable to both
existing and planned competing pipeline capacity (with the attendant reduced
value of transportation) in the upper Midwest, Natural's principal market area,
and reduced transport revenue due to the sale of a marketing affiliate during
2000. Note 5 of the accompanying Notes to Consolidated Financial Statements
contains additional information concerning asset sales.
Natural's operating income before corporate costs decreased by $30.3 million
(9.0%) from 1998 to 1999. Natural was negatively impacted in 1999, relative to
1998, by (i) a decrease in the margin per MMBtu of throughput from $0.41 in 1998
to $0.34 in 1999 resulting from (1) two recent mild winters, including the
impact of the resultant high levels of gas in underground storage and (2)
increased competitive pressures in Midwest markets due to actual or projected
supply increases and (ii) increased operations and maintenance expenses and
property taxes. These negative impacts were partially offset by (i) an increase
in average monthly throughput volumes from 118 trillion Btus in 1998 to 126
trillion Btus in 1999 (although, in general, interstate pipelines receive the
majority of their transportation revenues from demand charges, which are not
affected by the level of throughput), (ii) reduced amortization expense in 1999
resulting from a change in the estimated useful life of Natural's assets (see
Note 4 of the accompanying Notes to Consolidated Financial Statements) and (iii)
the fact that our 1999 results included 12 months of the operations of Natural,
while our 1998 results included only 11 months.
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54
KINDER MORGAN INTERSTATE
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 1998
-------- --------
(In Thousands Except Systems Throughput)
Operating Revenues:
Transportation and Storage $112,732 $105,160
Other 475 417
-------- --------
113,207 105,577
-------- --------
Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales 13,954 3,763
Operations and Maintenance 23,737 20,026
Depreciation and Amortization 16,985 19,474
Taxes, Other Than Income Taxes 4,607 4,308
-------- --------
59,283 47,571
-------- --------
Operating Income Before Corporate Costs $ 53,924 $ 58,006
======== ========
Systems Throughput (Trillion Btus) 203.1 216.6
======== ========
Effective December 31, 1999, we sold Kinder Morgan Interstate to Energy
Partners. See Note 5 of the accompanying Notes to Consolidated Financial
Statements for more information regarding this transaction.
Kinder Morgan Interstate's operating income before corporate costs decreased by
$4.1 million (7.0%) from 1998 to 1999. This business unit was negatively
impacted in 1999, relative to 1998, by (i) the 1999 write-off of approximately
$5.8 million of deferred fuel tracker costs that had accumulated since the
initial implementation of FERC Order No. 636 and were deemed unrecoverable due
to the settlement of the general rate case; (see Note 8 of the accompanying
Notes to Consolidated Financial Statements for more information regarding Kinder
Morgan Interstate's general rate case), (ii) a decrease in shipper supplied fuel
requirements under the terms of Kinder Morgan Interstate's general rate case
which, in conjunction with normal system fuel and loss requirements, caused
Kinder Morgan Interstate to purchase additional system fuel supplies and (iii)
increased operations and maintenance expenses, primarily related to the Pony
Express Pipeline. These negative impacts were partially offset by (i) increased
revenues in 1999 due to higher transportation rates under the terms of the
general rate case and (ii) reduced depreciation expense in 1999 resulting from
the assets of Kinder Morgan Interstate being classified as assets held for sale
effective November 1, 1999, at which time further depreciation of these assets
was suspended in accordance with the provisions of SFAS No. 121, "Accounting for
the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed
Of."
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55
RETAIL
YEAR ENDED DECEMBER 31,
----------------------------------------
2000 1999 1998
-------- -------- --------
(In Thousands Except Systems Throughput)
Operating Revenues:
Gas Sales $171,696 $134,208 $186,527
Transportation 41,371 34,919 27,309
Other 16,442 13,785 20,470
-------- -------- --------
229,509 182,912 234,306
-------- -------- --------
Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales 128,811 107,264 123,099
Operations and Maintenance 36,627 40,807 41,093
Depreciation and Amortization 11,776 11,382 11,014
Taxes, Other Than Income Taxes 2,563 3,355 2,886
-------- -------- --------
179,777 162,808 178,092
-------- -------- --------
Operating Income Before Corporate Costs $ 49,732 $ 20,104 $ 56,214
======== ======== ========
Systems Throughput (Trillion Btus) 72.6 56.6 61.7
======== ======== ========
Retail's operating income before corporate costs increased by $29.6 million
(147.4%) from 1999 to 2000. Operating results for 2000 were positively impacted,
relative to 1999, by (i) increased system throughput in 2000, although a portion
of this increase represents volumes transported for relatively low margins, (ii)
increased service revenues in 2000 and (iii) reduced 2000 operating expenses.
The increase in gross margins (operating revenues minus gas purchases and other
costs of sales) which resulted from increased throughput volumes was principally
due to increased irrigation demand in the third quarter of 2000 and increased
space heating demand in the fourth quarter. Weather-related demand in Retail's
service territory was affected by colder than normal weather in the fourth
quarter of 2000, compared with warmer than normal weather in the fourth quarter
of 1999. The reduced 2000 operating expenses resulted from (i) a reduction in
advertising and marketing expenses for the Choice Gas program (unregulated sales
of natural gas made to certain of Retail's utility customers), (ii) continued
focus on efficient operations, (iii) reduced ad valorem and use taxes in 2000
and (iv) reduced costs for certain administrative functions due to renegotiation
of a contract with a third-party service provider.
Retail's operating income before corporate costs decreased by $36.1 million
(64.2%) from 1998 to 1999. This business unit was negatively impacted in 1999,
relative to 1998, by (i) the fact that 1998 results include three months of the
operations of distribution assets in Kansas that were sold in March 1998 (see
Note 5 of the accompanying Notes to Consolidated Financial Statements) and (ii)
reduced margins from sales and transportation due primarily to (1)
weather-related reductions in 1999 irrigation demand and (2) reduced margins
related to the Nebraska Choice Gas program.
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56
KINDER MORGAN TEXAS
YEAR ENDED DECEMBER 31,
----------------------------------------------
2000 1999 1998
---------- ---------- ----------
(In Thousands Except Systems Throughput)
Operating Revenues:
Gas Sales $1,675,206 $ 815,557 $ 704,190
Transportation 25,468 23,971 19,192
Other 46,825 32,633 15,819
---------- ---------- ----------
1,747,499 872,161 739,201
---------- ---------- ----------
Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales 1,666,169 804,674 680,766
Operations and Maintenance 45,401 45,778 51,067
Depreciation and Amortization 2,211 2,466 1,615
Taxes, Other Than Income Taxes 4,400 2,689 3,624
---------- ---------- ----------
1,718,181 855,607 737,072
---------- ---------- ----------
Operating Income Before Corporate Costs $ 29,318 $ 16,554 $ 2,129
========== ========== ==========
Systems Throughput (Trillion Btus) 654.4 575.3 581.6
========== ========== ==========
Operating results for Kinder Morgan Texas are included in our consolidated
results beginning with the January 30, 1998 acquisition of MidCon Corp. See Note
2 of the accompanying Notes to Consolidated Financial Statements for more
information regarding this acquisition. Effective December 31, 2000, we
contributed Kinder Morgan Texas to Energy Partners. See Note 5 of the
accompanying Notes to Consolidated Financial Statements for more information
regarding this transaction.
Operating revenues for Kinder Morgan Texas increased by $875.3 million (100.4%)
from 1999 to 2000. The $859.6 million (105.4%) increase in natural gas sales
reflected a 75% increase in the average sales price during 2000, together with a
17% increase in sales volumes. The $14.2 million increase in other revenues was
principally due to a 55% increase in the average sales price of natural gas
liquids during 2000. Gross margin (operating revenues minus gas purchases and
other costs of sales) increased by $13.8 million (20.5%) from 1999 to 2000, as
the increased operating revenues were offset approximately proportionally by the
increased cost of natural gas purchased. Operating income before corporate costs
increased by $12.8 million (77.1%) from 1999 to 2000 as the increase in gross
margin discussed preceding was partially offset by increased ad valorem taxes.
Kinder Morgan Texas' operating income before corporate costs increased by $14.4
million from 1998 to 1999. This business unit was positively impacted in 1999,
relative to 1998, by (i) the fact that 1999 results include 12 months of the
operations of Kinder Morgan Texas, while 1998 results include only 11 months,
(ii) increased per unit margins from sales and transportation in 1999, (iii)
increased 1999 margins from natural gas liquids sales due to an improved pricing
environment, (iv) reduced 1999 operations and maintenance expenses and (v)
reduced 1999 ad valorem taxes. These positive impacts were partially offset by
(i) reduced 1999 overall systems throughput volumes and (ii) increased 1999
depreciation expense reflecting the cumulative impact of capital expenditures
made in 1998 and 1999.
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57
POWER AND OTHER
YEAR ENDED DECEMBER 31,
-------------------------------------
2000 1999 1998
------- ------- -------
(In Thousands)
Operating Revenues $80,697 $59,305 $47,380
Equity in Earnings of Equity Investments 3,669 10,511 8,675
------- ------- -------
84,366 69,816 56,055
------- ------- -------
Operating Costs and Expenses:
Gas Purchases and Other Costs of Sales 19,653 12,921 19,441
Operations and Maintenance 19,680 15,648 7,232
Depreciation and Amortization 9,203 7,754 2,252
Taxes, Other Than Income Taxes 868 1,335 1,672
------- ------- -------
49,404 37,658 30,597
------- ------- -------
Income Before Corporate Costs $34,962 $32,158 $25,458
======= ======= =======
Results of power generation operations are included in Power and Other beginning
with the acquisition of interests in power plants from the Denver-based Thermo
Companies, which acquisition was completed in the third quarter of 1998. See
Note 2 of the accompanying Notes to Consolidated Financial Statements for more
information concerning this acquisition.
Income before corporate costs from Power and Other increased $2.8 million (8.7%)
from 1999 to 2000. Operating results for 2000 were positively impacted, relative
to 1999, by profits from development of a 550-megawatt electric generating plant
currently being constructed by Power near Little Rock, Arkansas. The positive
impact related to development profits was partially offset by (i) a decrease in
earnings from equity investments largely attributable to increased fuel (natural
gas) costs related to electricity generation and (ii) increased operating
expenses associated with other operations, principally our agreement with HS
Resources, Inc. and certain telecommunications assets used primarily by internal
business units. As we announced on November 30, 1999, we have entered into
agreements with HS Resources, Inc. for the sale of certain assets in the
Wattenberg field area of the Denver-Julesberg Basin. Under the terms of the
agreements, HS Resources, Inc. commenced operating these assets. We are
receiving payments from HS Resources, Inc. during 2000 and 2001, with the legal
transfer of ownership expected to occur on or before December 15, 2001. Loss
before Corporate Costs for our international activities, included in this
business unit, was $1.9 million, $1.9 million and $0.4 million in 2000, 1999 and
1998, respectively.
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58
Income before corporate costs from Power and Other increased $6.7 million
(26.3%) from 1998 to 1999. Operating results for 1999 were positively impacted,
relative to 1998, by (i) 1999 results include a full year of power generation
activities, while 1998 includes only partial year results and (ii) increased
1999 operating income from our agreement with HS Resources, as described above.
OTHER INCOME AND (EXPENSES)
YEAR ENDED DECEMBER 31,
---------------------------------------------
2000 1999 1998
--------- --------- ---------
(In Thousands)
Interest Expense, Net $(243,155) $(251,920) $(205,840)
--------- --------- ---------
Equity in Earnings:
Energy Partners - Earnings 140,913 15,733 --
Energy Partners - Amortization (28,317) (7,335) --
Power Segment(1) 3,669 10,511 8,675
Other (10,255) 14,140 22,466
--------- --------- ---------
Total Equity in Earnings 106,010 33,049 31,141
--------- --------- ---------
Minority Interests (24,121) (24,845) (19,483)
Gains from Sales of Assets 61,684 189,778 19,552
Other, Net 10,881 4,627 1,843
--------- --------- ---------
$ (88,701) $ (49,311) $(172,787)
========= ========= =========
(1) See discussion under the heading "Power and Other."
The increase of $39.4 million (79.9%) in net expense under "Other Income and
(Expenses)" from 1999 to 2000 is principally due to decreased gains from sales
of assets and reduced other equity in earnings in 2000, partially offset by
higher 2000 equity in earnings of Energy Partners and increased "Other, Net."
The decrease in gains from sales of assets in 2000 reflects the fact that 1999
results include (i) a gain of $158.8 million from the sale of Kinder Morgan
Interstate and interests in two equity method investments and (ii) a gain of
$31.0 million from the sale of two offshore pipeline assets, while 2000 results
include a gain of $61.6 million from the sale of Kinder Morgan Texas Pipeline.
The equity in earnings of Energy Partners and associated amortization during
2000 and 1999 result from our October 1999 acquisition of interests in Energy
Partners and, thus, 1999 includes only one quarter of earnings on this
investment while 2000 reflects earnings for the full year. Energy Partners' Form
10-K for the year ended December 31, 2000 contains additional information about
its results of operations. The decrease in other equity in earnings from 1999 to
2000 is principally due to the sale of various equity method investments. In
addition, 2000 results reflect increased equity in losses of the TransColorado
pipeline joint venture, which was placed in service March 31, 1999. The expense
associated with "Minority Interests" in each period principally represents the
costs associated with our two series of Capital Trust Securities. These
securities are described in Note 12 of the accompanying Notes to Consolidated
Financial Statements. The increase in "Other, Net" from 1999 to 2000 reflects
the fact that, while each period includes miscellaneous items of income and
expense, 2000 results also include (i) $4.1 million due to the recovery of note
receivable proceeds in excess of its carrying value and (ii) $3.9 million due to
the settlement of a regulatory matter for an amount less than that previously
reserved.
The decrease of $123.5 million in net expense reported under "Other Income and
(Expenses)" from 1998 to 1999 is principally due to increased 1999 gains from
the sale of assets, partially offset by increased interest expense. The
decreased 1999 gains from the sale of assets reflects the fact that 1999
includes the gain from the sale of Kinder Morgan Gas Transmission and other
assets as discussed above, while 1998 includes (i) a gain of $10.9 million from
the sale of certain microwave towers and (ii) a gain of $8.5 million from the
sale of Kansas natural gas distribution properties. The increase of $46.1
million (22.4%) in "Interest Expense, Net" from 1998 to 1999 is principally due
the incremental debt outstanding as a result of the January 1998 acquisition of
MidCon and decreased capitalized interest in 1999 due to the reduced level of
capital spending (see "Net Cash Flows from Investing Activities").
F-56
59
INCOME TAXES - CONTINUING OPERATIONS
YEAR ENDED DECEMBER 31,
---------------------------------------------
2000 1999 1998
--------- --------- ---------
(Dollars In Thousands)
Income Tax Provision $ 122,727 $ 90,733 $ 82,710
========= ========= =========
Effective Tax Rate 40.0% 36.8% 37.1%
========= ========= =========
The increase of $32.0 million in the income tax provision from 1999 to 2000 is
composed of (i) an increase of $22.1 million due to an increase in pretax income
and (ii) an increase of $9.9 million due to an increase in the effective tax
rate in 2000. The increased effective tax rate for 2000 is principally due to an
increased effective rate associated with state income taxes. The increase of
$8.0 million in income tax expense from 1998 to 1999 reflected an increase of
$8.7 million due to an increase in 1999 pre-tax income, partially offset by a
decrease of $0.7 million due to a decrease in the 1999 effective tax rate. The
decrease in the 1999 effective tax rate was principally due to the impact of
asset sales and dispositions of certain lines of business.
DISCONTINUED OPERATIONS
YEAR ENDED DECEMBER 31,
----------------------------------------------
2000 1999 1998
---------- --------- ---------
(In Thousands)
Income (Loss) from Discontinued Operations, Net of Tax $ -- $ (50,941) $ (77,984)
========== ========= =========
Loss on Disposal of Discontinued Operations, Net of Tax $ (31,734) $(344,378) $ --
========== ========= =========
During the third quarter of 1999, we adopted and implemented a plan to
discontinue the direct marketing of non-energy products and services
(principally under the "Simple Choice" brand), which activities had been carried
on largely through our en*able joint venture with PacifiCorp. During the fourth
quarter of 1999, we adopted and implemented plans to discontinue the following
lines of business: (i) gathering and processing of natural gas, including
short-haul intrastate pipelines and providing field services to natural gas
producers, (ii) wholesale marketing of natural gas and natural gas liquids and
(iii) international operations. We recorded a loss of $344.4 million,
representing the estimated loss to be recognized upon final disposal of these
businesses, including estimated operating losses prior to disposal. During 2000,
we completed the disposition of these businesses, with the exception of
international operations (principally consisting of a natural gas distribution
system under construction in Hermosillo, Mexico), which, in the fourth quarter
of 2000, we decided to retain. Neither the decision to dispose of our
international operations nor our subsequent decision to retain them had any
material effect on our results of operations, commitments and contingencies,
known trends or capital resources. In the fourth quarter of 2000, we recorded an
incremental loss on disposal of discontinued operations of $31.7 million,
representing the impact of the final disposition transactions and adjustment of
previously recorded estimates. We had a remaining liability of approximately
$23.7 million at December 31, 2000 associated with these discontinued
operations, principally consisting of (i) indemnification obligations under the
various sale agreements and (ii) retained liabilities, which were settled in
cash in early 2001. We do not expect significant additional financial impacts
associated with these matters. Note 6 of the accompanying Notes to Consolidated
Financial Statements contains certain additional financial information with
respect to these discontinued operations.
Losses from discontinued operations, net of tax benefits of $29.7 million and
$46.0 million in 1999 and 1998, respectively, decreased by $27.1 million from
1998 to 1999. Operating results were positively impacted in 1999, relative to
1998, by (i) improvement in the natural gas liquids pricing environment in 1999
and (ii) the fact that 1998 operating results included (1) $6.4 million of
adjustments to write down certain natural gas due from third parties and in
underground storage to their current market values, (2) $3.7 million of
increased provision for uncollectible accounts receivable, (3) natural gas
liquids storage inventory write-downs and (4) operating losses associated with
gas processing facilities that were sold in the fourth quarter of 1998. These
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factors serving to create a favorable period to period variance were partially
offset by the fact that 1998 results included $6.0 million in margin from sales
of storage gas.
LIQUIDITY AND CAPITAL RESOURCES
The following table illustrates the sources of our invested capital. The
balances at December 31, 1999 reflect the impacts associated with the
acquisition of Kinder Morgan Delaware and the sale of certain assets to Energy
Partners, while the balances at December 31, 2000 also reflect the impact of the
sale of additional assets to Energy Partners effective as of that date. Notes 2
and 5 of the accompanying Notes to Consolidated Financial Statements contain
additional information on these transactions, while Note 12 contains information
concerning our outstanding debt securities, short-term borrowing facilities and
financing activities.
DECEMBER 31,
------------------------------------------------
2000 1999 1998
---------- ---------- ----------
(Dollars In Thousands)
Long-term Debt $2,478,983 $3,293,326 $3,300,025
Common Equity 1,797,421 1,669,846 1,219,043
Preferred Stock -- -- 7,000
Capital Trust Securities 275,000 275,000 275,000
---------- ---------- ----------
Capitalization 4,551,404 5,238,172 4,801,068
Short-term Debt 908,167 581,567 1,702,013(1)
---------- ---------- ----------
Invested Capital $5,459,571 $5,819,739 $6,503,081
========== ========== ==========
Capitalization:
Long-term Debt 54.5% 62.9% 68.7%
Common Equity 39.5% 31.9% 25.4%
Preferred Stock -- -- 0.2%
Capital Trust Securities 6.0% 5.2% 5.7%
Invested Capital(3):
Total Debt 62.0% 66.6% 76.9%(2)
Equity, Including Capital Trust Securities 38.0% 33.4% 23.1%
(1) Includes the $1,394,846 Substitute Note assumed in conjunction with the
acquisition of MidCon Corp. This note was repaid on January 4, 1999.
(2) If the government securities then held as collateral were offset against
the related debt, the ratio of total debt to invested capital at December
31, 1998, would have been 72.3 percent.
(3) As adjusted to reflect the November 2001 maturity of the Premium Equity
Participating Units (see "Net Cash Flows from Financing Activities") and
the associated $460 million increase in equity and decrease in debt, the
ratios would be: Debt - 53.6%, Equity - 46.4%.
CASH FLOWS
The following discussion of cash flows should be read in conjunction with the
accompanying Consolidated Statements of Cash Flows and related supplemental
disclosures. All highly liquid investments purchased with an original maturity
of three months or less are considered to be cash equivalents.
Net Cash Flows from Operating Activities
"Net Cash Flows Provided by Operating Activities" decreased from $321.2 million
in 1999 to $167.1 million in 2000, a decline of $154.1 million (48%). This
decline is primarily due to an increase in cash flows used for discontinued
operations, which increased from a source of $94.5 million in 1999 to a use of
$110.4 million in 2000, a $204.9 million increased use of cash reflecting (i)
$124.7 million of cash outflow in 2000 attributable to the termination of our
receivable sale program and (ii) 124.7 million of cash inflow in 1999
attributable to the receivable sale program (see "Net Cash Flows from Financing
Activities" following). The decline in "Net Cash Flows Provided by Operating
Activities" for discontinued operations was partially offset by an increase in
cash flows provided by continuing operations, which increased from a source of
$226.7 million in 1999 to a source
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of $277.5 million in 2000. This $50.8 million of increased cash flow is
primarily due to (i) $121.3 million of cash distributions received in 2000
attributable to our interest in Energy Partners (see Note 2 of the accompanying
Notes to Consolidated Financial Statements and the discussion following) and
(ii) a decrease in cash used in 2000 to make interest payments reflecting the
decreased average debt balance outstanding. Partially offsetting this increase
were (i) an increase in cash used for working capital of $84.6 million and (ii)
January 2000 payments associated with December 1999 gas supply purchases.
"Net Cash Flows from Operating Activities" increased from $95.3 million in 1998
to $321.2 million in 1999, an increase of $225.9 million or 237 percent. This
increase was principally attributable to (i) cash provided by reductions in
working capital for continuing operations in 1999 and (ii) increased 1999
operating cash flows associated with discontinued operations reflecting, among
other things, improved operating results and the sale of accounts receivable,
partially offset by (i) reduced 1999 earnings from continuing operations before
asset sales and (ii) the inclusion in 1998 results of $27.5 million of proceeds
from the buyout of certain contractual gas obligations.
In general, distributions from Energy Partners are declared in the month
following the end of the quarter to which they apply and are paid in the month
following the month of declaration to the general partner and unit holders of
record as of the end of the declaration month. Therefore, the accompanying
Statement of Consolidated Cash Flows for 2000 reflects the receipt of a total of
$121.3 million of cash distributions from Energy Partners for the fourth quarter
of 1999 and the first nine months of 2000. The cash distributions attributable
to our interest for the three months and twelve months ended December 31, 2000
total $44.5 million and $149.9 million, respectively. The increase in
distributions during 2000 reflects, among other factors, the December 31, 1999
transfer of certain properties from us to Energy Partners (see Note 5 of the
accompanying Notes to Consolidated Financial Statements).
Net Cash Flows from Investing Activities
"Net Cash Flows Provided by Investing Activities" decreased from $1.0 billion in
1999 to $498.7 million in 2000, a decline of $521.5 million principally due to
the sale of approximately $1.1 billion of government securities during 1999,
with the proceeds utilized to repay the Substitute Note assumed in conjunction
with the January 1998 acquisition of MidCon Corp. Partially offsetting this
decrease was (i) $500.3 million of cash received during 2000 from the sale of
certain interests and assets to Energy Partners and (ii) cash flows of
discontinued investing activities increasing from a use of $46.6 million in 1999
to a source of $154.2 million in 2000, which was principally a result of the
$163.9 million of proceeds received from ONEOK for the sale of gathering and
processing businesses in Oklahoma, Kansas and West Texas.
"Net Cash Flows from Investing Activities" increased from a net outflow of $3.5
billion in 1998 to a net inflow of $1.0 billion in 1999. This increase was
principally attributable to the net impact of (i) a net cash outflow of $2.2
billion in 1998 for the purchase of MidCon Corp., (ii) net purchases of U.S.
Government securities of $1.1 billion in 1998, principally to act as collateral
for the Substitute Note assumed in the acquisition of MidCon Corp., (iii) net
sales of U.S. government securities of $1.1 billion in 1999, which proceeds were
used, together with proceeds of additional short-term borrowings, to repay the
Substitute Note, (iv) additional cash used in 1999 for other acquisitions,
principally the cash portion of consideration paid for the Thermo acquisition,
(v) the 1999 receipt of $28.7 million of proceeds from the sale of Tom Brown,
Inc. preferred stock, (vi) increased proceeds from sales of assets in 1999 and
(vi) decreased net cash outflows for investing activities of discontinued
operations in 1999.
During the year 2000, major asset sales included (i) Kinder Morgan Texas
Pipeline, Inc., the Casper and Douglas Natural Gas Gathering and Processing
Systems, our 50 percent interest in Coyote Gas Treating, LLC and our 25 percent
interest in Thunder Creek Gas Services, L.L.C. to Energy Partners, (ii)
gathering and processing businesses in Oklahoma, Kansas and West Texas as well
as our marketing and trading business to
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ONEOK, (iii) three natural gas gathering systems and a natural gas processing
facility to WBI Holdings, Inc. and (iv) Wildhorse Energy Partners, LLC to Tom
Brown, Inc. Total proceeds received in 2000 from asset sales were $730.6 million
of which $330 million represented proceeds from the 1999 transfer of assets to
Energy Partners.
Major asset sales during 1999 included (i) Kinder Morgan Interstate, Kinder
Morgan Trailblazer LLC and our interest in Red Cedar Gathering Company to Energy
Partners, (ii) all of our major offshore assets in the Gulf of Mexico area,
including our interests in Stingray Pipeline Company L.L.C. and West Cameron
Dehydration Company L.L.C., and the HIOS and UTOS offshore pipeline systems and
(iii) MidCon Gas Products of New Mexico Corp. Total proceeds received in 1999
from asset sales were $111.1 million.
Notes 2, 5 and 6 of the accompanying Notes to Consolidated Financial Statements
and "Net Cash Flows from Financing Activities" following contain more
information concerning these investments and sales.
Net Cash Flows from Financing Activities
"Net Cash Flows Used in Financing Activities" decreased from approximately $1.3
billion in 1999 to $550.3 million in 2000, a decline of approximately $786.7
million. This decrease was principally due to the first-quarter 1999 repayment
of the $1.39 billion Substitute Note as discussed preceding, partially offset by
increased short-term borrowings during the same period, as well as reduced cash
payments for dividends in 2000.
"Net Cash Flows from Financing Activities" decreased from a net inflow of $3.4
billion in 1998 to a net outflow of $1.3 billion in 1999. This decrease was
principally the result of the 1998 financings associated with the acquisition of
MidCon Corp. and the repayment of the Substitute Note in 1999, in each case as
described following. In addition, we retired $158.9 million of long-term debt in
1999, compared to $35.8 million in 1998. The long-term debt retired in 1999
included $148.6 million of debt assumed in conjunction with the acquisition of
Kinder Morgan Delaware.
Our principal sources of short-term liquidity are our revolving bank facilities.
As of December 31, 2000, we had available a $500 million 364-day facility dated
October 25, 2000, and a $400 million amended and restated five-year revolving
credit agreement dated January 30, 1998. These bank facilities can be used for
general corporate purposes, including backup for our commercial paper program.
At December 31, 2000, we had $100 million of bank borrowings and commercial
paper (which is backed by the bank facilities) issued and outstanding. The
corresponding amount outstanding was $50 million at February 9, 2001. After
inclusion of applicable letters of credit, the remaining available borrowing
capacity under the bank facilities was $796.7 million and $846.7 million at
December 31, 2000 and February 9, 2001, respectively. The bank facilities
include covenants that are common in such arrangements. For example, the $500
million facility requires consolidated debt to be less than 68% of consolidated
total capitalization. The $400 million facility requires that upon issuance of
common stock to the holders of the premium equity participating security units
at the maturity of the security units (November 2001), consolidated debt must be
less than 67% of consolidated total capitalization. Both of the bank facilities
require the debt of consolidated subsidiaries to be less than 10% of our
consolidated debt and require the consolidated debt of each material subsidiary
to be less than 65% of our consolidated total capitalization. The $400 million
facility requires our consolidated net worth (inclusive of trust preferred
securities) be at least $1.236 billion plus 50 percent of consolidated net
income earned for each fiscal quarter beginning with the last quarter of 1998.
The $500 million facility requires our consolidated net worth (inclusive of
trust preferred securities) be at least $1.236 billion plus 50 percent of
consolidated net income earned for each fiscal quarter beginning with the last
quarter of 1999.
Our short-term debt of $908.2 million at December 31, 2000 consisted of (i) $100
million of borrowings under our revolving credit facilities, (ii) the $400
million of Reset Put Securities that are scheduled to be either remarketed or
retired as of March 1, 2001, (iii) the $400 million of 6.45% Senior Notes, due
November 2001
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and (iv) $8.2 million of miscellaneous current maturities of long-term debt. We
expect to retire the Reset Put Securities at March 1, 2001 utilizing a
combination of cash on hand and incremental short-term borrowings, which will
result in an extraordinary loss on early extinguishments of debt expected to
total approximately $15 million. We expect that the $400 million of 6.45% Senior
Notes will be retired at maturity with a portion of the $460 million of cash to
be received from the issuance of common stock upon maturity of the Premium
Equity Participating Securities, which occurs concurrently as discussed
following. Apart from these items, our current assets and current liabilities
are approximately equal. Given our expected cash flows from operations and our
unused debt capacity, including our 5-year revolving credit facility, we do not
expect any liquidity issues in the foreseeable future.
In September 1999, we established an accounts receivable sales facility that
provided up to $150 million of additional liquidity. In accordance with this
agreement, we received proceeds of $150 million on September 30, 1999. Cash
flows associated with this facility are included with "Cash flows from Operating
Activities" in the accompanying Consolidated Statements of Cash Flows. In
February 2000, we reduced our participation in this receivables sales program by
$124.9 million, principally as a result of our then-pending disposition of our
wholesale gas marketing business. On April 25, 2000, we repaid the residual
balance and terminated the agreement.
In November 1998, we sold $460 million principal amount of premium equity
participating securities in a public offering. The proceeds from the security
units offering was used to purchase U.S. Treasury Notes on behalf of the
security unit holders, which notes are the property of the security unit holders
and will be held as collateral to fund the obligation of the security unit
holders to purchase our common stock at the end of a three-year period. In
November 2001, the maturity of these securities will result in our receipt of
$460 million in cash as discussed above and, based on the market price of our
common stock as of November 30, 2001, the issuance of approximately 13.4 million
shares of common stock. The cash proceeds are expected to be used to retire the
$400 million of 6.45% Senior Notes that mature concurrently with the premium
equity participating securities and to repay a portion of short-term borrowings
then outstanding.
In March 1998, we issued 12.5 million shares (18.75 million shares after
adjustment for the December 1998 three-for-two stock split) of common stock in
an underwritten public offering, receiving net proceeds of approximately $624.6
million. Also in March 1998, we issued $2.35 billion principal amount of debt
securities of varying maturities and interest rates in an underwritten public
offering, receiving net proceeds of approximately $2.34 billion. The net
proceeds from these two offerings were used to refinance borrowings under the
MidCon Corp. acquisition financing arrangements and to purchase U.S. government
securities to collateralize a portion of the Substitute Note (assumed in
conjunction with the acquisition). In April 1998, we sold $175 million of 7.63%
Capital Securities due April 15, 2028, in an underwritten offering, with the net
proceeds of $173.1 million used to purchase U.S. government securities to
further collateralize the Substitute Note. In November 1998, we completed the
underwritten public offering of $400 million of 3-year senior notes concurrently
with the $460 million principal amount of premium equity participating security
units discussed above. The $397.4 million of net proceeds from the senior notes
offering were used to retire a portion of our then-outstanding short-term
borrowings. For additional information on each of these financings, including
terms of the specific securities and the associated accounting treatment, see
Note 12 of the accompanying Notes to Consolidated Financial Statements.
On January 4, 1999, we repaid the $1.4 billion Substitute Note payable to
Occidental Petroleum as part of the MidCon Corp. acquisition. The note was
repaid using the proceeds of approximately $1.1 billion from the sale of U.S.
government securities that had been held as collateral, with the balance of the
funds provided by an increase in short-term borrowings.
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Capital Expenditures and Commitments
Capital expenditures in 2000 were $137.5 million and $3.2 million for continuing
operations and discontinued operations, respectively. The 2001 capital
expenditure budget totals approximately $197 million. We expect that funding for
the budget will be provided from internal sources and, if necessary, incremental
borrowings. Approximately $5.5 million of this amount had been committed for the
purchase of plant and equipment at December 31, 2000. Additional information on
commitments is contained in Note 17 of the accompanying Notes to Consolidated
Financial Statements.
LITIGATION AND ENVIRONMENTAL
Our anticipated environmental capital costs and expenses for 2001, including
expected costs for remediation efforts, are approximately $7 million, compared
to $5.8 million of such costs and expenses incurred in 2000. A substantial
portion of our environmental costs are either recoverable through insurance and
indemnification provisions or have previously recorded liabilities associated
with them.
Refer to Notes 9(A) and 9(B) to the accompanying Consolidated Financial
Statements for additional information on our pending litigation and
environmental matters. We believe we have established adequate reserves such
that the resolution of pending litigation and environmental matters will not
have a material adverse impact on our business, cash flows, financial position
or results of operations.
REGULATION
See Note 8 of the accompanying Notes to Consolidated Financial Statements for
information regarding regulatory matters.
RISK MANAGEMENT
The following discussion should be read in conjunction with Note 14 of the
accompanying Notes to Consolidated Financial Statements, which contains
additional information on our risk management activities.
To minimize the risk of price changes in the natural gas and associated
transportation markets, we use certain financial instruments for hedging
purposes. These instruments include energy products traded on the New York
Mercantile Exchange, the Kansas City Board of Trade and over-the-counter markets
including, but not limited to, futures and options contracts and fixed-price
swaps. We are exposed to credit-related losses in the event of nonperformance by
counterparties to these financial instruments but, given their existing credit
ratings, we do not expect any counterparties to fail to meet their obligations.
Pursuant to a policy approved by our Board of Directors, we are to engage in
these activities only as a hedging mechanism against price volatility associated
with (i) pre-existing or anticipated physical gas sales, (ii) physical gas
purchases and (iii) system use and storage in order to protect profit margins,
and not to engage in speculative trading. Commodity-related activities of the
risk management group are monitored by our Risk Management Committee, which is
charged with the review and enforcement of the Board of Directors' risk
management policy. The Risk Management Committee reviews the types of hedging
instruments used, contract limits and approval levels and may review the pricing
and hedging of any or all commodity transactions. All energy futures, swaps and
options are recorded at fair value. The fair value of these risk management
instruments reflects the estimated amounts that we would receive or pay to
terminate the contracts at the reporting date, thereby taking into account the
current unrealized gains or losses on open contracts. Market quotes are
available for substantially all financial instruments we use.
Through December 31, 2000, gains and losses on hedging positions have been
deferred and recognized as gas purchases expense in the periods in which the
underlying physical transactions occur. On January 1, 2001, we began accounting
for derivative instruments under SFAS No. 133,
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"Accounting for Derivative Instruments and Hedging Activities," (after amendment
by SFAS 137 and SFAS 138, the "Statement"). As discussed preceding, our
principal use of derivative financial instruments is to mitigate the market
price risk associated with anticipated transactions for the purchase and sale of
natural gas. The Statement allows these transactions to continue to be treated
as hedges for accounting purposes, although the changes in the market value of
these instruments will affect comprehensive income in the period in which they
occur and any ineffectiveness in the risk mitigation performance of the hedge
will affect net income currently. The change in the market value of these
instruments representing effective hedge operation will continue to affect net
income in the period in which the associated physical transactions are
consummated. Adoption of the Statement has resulted in $14.4 million of deferred
net loss as of January 1, 2001, being reported as part of other comprehensive
income in 2001, as well as subsequent changes in the market value of these
derivatives prior to consummation of the transaction being hedged.
We measure the risk of price changes in the natural gas and natural gas liquids
markets utilizing a Value-at-Risk model. Value-at-Risk is a statistical measure
of how much the marked-to-market value of a portfolio could change during a
period of time, within a certain level of statistical confidence. We utilize a
closed form model to evaluate risk on a daily basis. The Value-at-Risk
computations utilize a confidence level of 97.7 percent for the resultant price
movement and a holding period of one day chosen for the calculation. The
confidence level used means that there is a 97.7 percent probability that the
mark-to-market losses for a single day will not exceed the Value-at-Risk number
presented. Instruments evaluated by the model include forward physical gas,
storage and transportation contracts and financial products including commodity
futures and options contracts, fixed price swaps, basis swaps and
over-the-counter options. During 2000, Value-at-Risk reached a high of $5.4
million and a low of $1.5 million. Value-at-Risk at December 31, 2000, was $5.3
million and averaged $4.5 million for 2000.
Our calculated Value-at-Risk exposure represents an estimate of the reasonably
possible net losses that would be recognized on our portfolio of derivatives
assuming hypothetical movements in future market rates, and is not necessarily
indicative of actual results that may occur. It does not represent the maximum
possible loss or any expected loss that may occur, since actual future gains and
losses will differ from those estimated. Actual gains and losses may differ from
estimates due to actual fluctuations in market rates, operating exposures and
the timing thereof, as well as changes in our portfolio of derivatives during
the year.
As a result of our recent divestiture of certain lines of business, including
our wholesale natural gas and liquids marketing and natural gas gathering,
processing and associated businesses, we expect that our portfolio of financial
instruments held for the purposes of hedging, and corresponding exposure to loss
from such instruments, will be smaller in the future. Given our portfolio of
businesses as of December 31, 2000, our principal uses of derivative financial
instruments will be to mitigate the risk associated with market movements in the
price of natural gas associated with (i) the sale of in-kind fuel recoveries in
excess of fuel used on Natural's pipeline system and (ii) the purchase of
natural gas by Retail to serve its customers in the Choice Gas program.
From time to time, our treasury department manages interest rate exposure
utilizing interest rate swaps, caps or similar derivatives within
Board-established policy. None of these interest rate derivatives is leveraged.
We are currently not hedging our interest rate exposure resulting from
short-term borrowings. The market risk related to short-term borrowings from a
one percent change in interest rates would result in a $0.5 million annual
impact on pre-tax income, based on short-term borrowing levels as of February 9,
2001.
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Significant Operating Variables
Our principal exposure to market variability is related to the variation in
natural gas prices and basis differentials, which can affect gross margins in
our Natural and Retail segments. "Basis differential" is a term that refers to
the difference in natural gas prices between two locations or two points in
time. These price differences can be affected by, among other things, natural
gas supply and demand, available transportation capacity, storage inventories
and deliverability, prices of alternative fuels and weather conditions. In
recent periods, additional competitive pressures have been generated in Midwest
natural gas markets due to the introduction and planned introduction of
additional supplies into the Chicago market area, although incremental "take
away" capacity has also been constructed. We have attempted to reduce our
exposure to this form of market variability by pursuing long-term, fixed-rate
type contract agreements for capacity on Natural. In addition, as discussed
under "Risk Management" elsewhere in this document and in Note 14 of the
accompanying Notes to Consolidated Financial Statements, we utilize a
comprehensive risk management program to mitigate our exposure to changes in the
market price of natural gas and associated transportation.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Information required by this item is in Item 7 under the heading "Risk
Management."
KINDER MORGAN, INC. AND SUBSIDIARIES
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS
YEAR ENDED DECEMBER 31, 2000
-----------------------------------------------------------------------------------------
DEDUCTIONS
BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED
BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END
PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
------------ --------------- ------------- ------------ --------------
(In Millions)
Allowance for Doubtful Accounts $ 1.7 $ 9.9 $ (9.3) $ -- $ 2.3
YEAR ENDED DECEMBER 31, 1999
-----------------------------------------------------------------------------------------
DEDUCTIONS
BALANCE AT ADDITIONS WRITE-OFF OF DISCONTINUED
BEGINNING OF CHARGED TO COST UNCOLLECTIBLE OPERATIONS BALANCE AT END
PERIOD AND EXPENSES ACCOUNTS DEDUCTIONS OF PERIOD
------------ --------------- ------------- ------------ --------------
(In Millions)
Allowance for Doubtful Accounts $ 10.8 $ 3.6 $ (0.6) $ (12.1) $ 1.7
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SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934,
the registrant has duly caused this report to be signed on its behalf by the
undersigned hereunto duly authorized.
KINDER MORGAN, INC.
Dated: February 16, 2001 By: /s/ JOSEPH LISTENGART
-------------------------------
Joseph Listengart
Vice President and General Counsel
68
EXHIBIT INDEX
EXHIBIT
NUMBER DESCRIPTION
------ -----------
23.1 Consent of PricewaterhouseCoopers LLP
23.2 Consent of Arthur Andersen LLP
99.1 Form 8-K Kinder Morgan Energy Partners, L.P. dated
February 16, 2001, including the consolidated financial
statements of Kinder Morgan Energy Partners, L.P.