<PAGE> 1
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UNITED STATES
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
Date of Report: March 10, 2000
(Date of earliest event reported: January 17, 2000)
EL PASO ENERGY CORPORATION
(Exact name of registrant as specified in the charter)
DELAWARE 1-14365 76-0568816
(State or other jurisdiction (Commission File Number) (I.R.S. Employer
of incorporation) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)
Registrant's telephone number, including area code (713) 420-2131
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<PAGE> 2
ITEM 5. OTHER EVENTS
On January 17, 2000, we entered into an Agreement and Plan of Merger
with The Coastal Corporation pursuant to which Coastal will merge into
a wholly owned subsidiary of El Paso Energy. In the merger, we will issue to
Coastal stockholders: 1.23 shares of El Paso Energy common stock for each
outstanding share of Coastal's common stock and each outstanding share of
Coastal's Class A common stock; 9.133 shares of El Paso common stock for each
outstanding share of Coastal's Series A and Series B convertible preferred
stock; and 17.98 shares of El Paso Energy common stock for each outstanding
share of Coastal's Series C convertible preferred stock. Our respective
obligations to complete the merger are subject to a number of conditions. These
include:
o Coastal stockholders approving and adopting the merger agreement;
o El Paso Energy stockholders approving the issuance of shares of El Paso
Energy common stock in connection with the merger;
o the expiration or termination of the waiting period under the
Hart-Scott-Rodino Antitrust Improvements Act of 1976, or the HSR Act,
applicable to the merger;
o all other regulatory approvals, including approval of the Federal
Energy Regulatory Commission, or FERC, having been obtained without the
imposition of conditions that would be materially adverse to El Paso
Energy's and Coastal's combined businesses, financial condition or
results of operations;
o our respective independent public accountants concurring that the
merger will qualify for pooling of interests accounting treatment; and
o our receiving legal opinions from our respective counsel that the
merger will qualify as a reorganization under the Internal Revenue
Code.
Even if these conditions are satisfied, we cannot assure you that we will
complete this merger.
We expect to complete the merger on an all common stock basis and
expect to account for the merger using the pooling of interests method of
accounting in accordance with United States generally accepted accounting
principles. Therefore, the unaudited pro forma condensed combined financial
statements provided under Item 7(b) reflect the merger using the pooling of
interests method of accounting.
ITEM 7. FINANCIAL STATEMENTS AND EXHIBITS
(a) Financial statements of business acquired.
<PAGE> 3
INDEPENDENT AUDITORS' REPORT
Board of Directors and Stockholders
The Coastal Corporation
Houston, Texas
We have audited the accompanying consolidated balance sheets of The
Coastal Corporation and subsidiaries as of December 31, 1999 and 1998, and the
related consolidated statements of operations, common stock and other
stockholders' equity and cash flows for each of the three years in the period
ended December 31, 1999. These financial statements are the responsibility of
the Company's management. Our responsibility is to express an opinion on these
financial statements based on our audits.
We conducted our audits in accordance with generally accepted auditing
standards. Those standards require that we plan and perform the audit to obtain
reasonable assurance about whether the financial statements are free of material
misstatement. An audit includes examining, on a test basis, evidence supporting
the amounts and disclosures in the financial statements. An audit also includes
assessing the accounting principles used and significant estimates made by
management, as well as evaluating the overall financial statement presentation.
We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the consolidated financial position of The Coastal
Corporation and subsidiaries as of December 31, 1999 and 1998, and the results
of their operations and their cash flows for each of the three years in the
period ended December 31, 1999, in conformity with generally accepted accounting
principles.
DELOITTE & TOUCHE LLP
Houston, Texas
February 8, 2000
2
<PAGE> 4
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED OPERATIONS
(Millions of Dollars Except Per Share)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING REVENUES.............................................. $ 8,197.2 $ 7,368.2 $ 9,730.1
----------- ----------- -----------
OPERATING COSTS AND EXPENSES
Purchases.................................................... 5,148.7 4,376.8 6,863.5
Operating and general expenses............................... 1,687.2 1,674.9 1,700.4
Depreciation, depletion and amortization..................... 479.6 443.2 433.5
----------- ----------- -----------
7,315.5 6,494.9 8,997.4
----------- ----------- -----------
OTHER INCOME - NET.............................................. 114.4 71.2 111.8
----------- ----------- -----------
EARNINGS BEFORE INTEREST AND INCOME TAXES....................... 996.1 944.5 844.5
----------- ----------- -----------
OTHER EXPENSES
Interest and debt expense.................................... 323.3 294.9 307.5
Taxes on income.............................................. 173.9 166.7 138.3
----------- ----------- -----------
EARNINGS FROM CONTINUING OPERATIONS
BEFORE EXTRAORDINARY ITEM.................................... 498.9 482.9 398.7
DISCONTINUED OPERATIONS - NET OF INCOME TAXES
Loss from operations......................................... - (3.5) (6.6)
Estimated loss on disposal................................... - (35.0) -
----------- ----------- -----------
EARNINGS BEFORE EXTRAORDINARY ITEM.............................. 498.9 444.4 392.1
EXTRAORDINARY ITEM - NET OF INCOME TAXES
Loss on early extinguishment of debt......................... - - (90.6)
----------- ----------- -----------
NET EARNINGS.................................................... 498.9 444.4 301.5
DIVIDENDS ON PREFERRED STOCK.................................... .3 6.0 17.4
----------- ----------- -----------
NET EARNINGS AVAILABLE TO COMMON
STOCKHOLDERS................................................. $ 498.6 $ 438.4 $ 284.1
=========== =========== ===========
BASIC EARNINGS PER SHARE
From continuing operations before extraordinary item......... $ 2.34 $ 2.24 $ 1.80
Discontinued operations...................................... - (.18) (.03)
Extraordinary item........................................... - - (.43)
----------- ----------- -----------
NET BASIC EARNINGS PER SHARE................................. $ 2.34 $ 2.06 $ 1.34
=========== =========== ===========
DILUTED EARNINGS PER SHARE
From continuing operations before extraordinary item......... $ 2.30 $ 2.21 $ 1.77
Discontinued operations...................................... - (.18) (.03)
Extraordinary item........................................... - - (.42)
----------- ----------- -----------
NET DILUTED EARNINGS PER SHARE............................... $ 2.30 $ 2.03 $ 1.32
=========== =========== ===========
</TABLE>
See Notes to Consolidated Financial Statements.
3
<PAGE> 5
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
----------- ----------
ASSETS
- ------
<S> <C> <C>
CURRENT ASSETS
Cash and cash equivalents..................................................... $ 44.4 $ 106.9
Receivables, less allowance for doubtful accounts $17.4 million (1999)
and $15.9 million (1998)................................................... 1,932.5 1,142.8
Inventories................................................................... 732.7 499.5
Prepaid expenses and other.................................................... 213.9 220.6
----------- ----------
Total current assets....................................................... 2,923.5 1,969.8
----------- ----------
PROPERTY, PLANT AND EQUIPMENT - AT COST
Natural gas systems........................................................... 6,328.7 6,069.2
Refining, crude oil and chemical facilities................................... 2,555.0 2,424.2
Gas and oil properties - at full-cost......................................... 3,832.0 2,870.8
Other......................................................................... 581.5 366.6
----------- ----------
13,297.2 11,730.8
Accumulated depreciation, depletion and amortization.......................... 3,959.8 3,706.9
----------- ----------
9,337.4 8,023.9
----------- ----------
OTHER ASSETS
Goodwill...................................................................... 451.8 470.8
Investments - equity method .................................................. 1,434.9 970.8
Other......................................................................... 975.4 868.8
----------- ----------
2,862.1 2,310.4
----------- ----------
$ 15,123.0 $ 12,304.1
=========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
4
<PAGE> 6
THE COASTAL CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEET
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
----------- ----------
<S> <C> <C>
LIABILITIES AND STOCKHOLDERS' EQUITY
- ------------------------------------
CURRENT LIABILITIES
Notes payable ................................................................ $ 105.9 $ 87.0
Accounts payable.............................................................. 2,350.1 1,488.0
Accrued expenses.............................................................. 420.0 305.0
Current maturities on long-term debt.......................................... 161.6 126.5
----------- ----------
Total current liabilities.................................................. 3,037.6 2,006.5
----------- ----------
DEBT
Long-term debt, excluding current maturities.................................. 4,798.2 3,999.3
----------- ----------
DEFERRED CREDITS AND OTHER
Deferred income taxes......................................................... 1,814.2 1,717.7
Other deferred credits ....................................................... 785.2 704.8
----------- ----------
2,599.4 2,422.5
----------- ----------
SECURITIES OF SUBSIDIARIES
Company-obligated mandatory redemption preferred securities of a
consolidated trust......................................................... 300.0 300.0
Preferred stock issued by subsidiaries........................................ 165.0 100.0
Consolidated joint venture.................................................... 285.9 -
----------- ----------
750.9 400.0
----------- ----------
COMMON STOCK AND OTHER STOCKHOLDERS' EQUITY
Cumulative preferred stock (with aggregate liquidation preference
of $7.3 million) .......................................................... - -
Class A common stock - Issued (1999 - 345,019 shares;
1998 - 354,058 shares)..................................................... .1 .1
Common stock - Issued (1999 - 217,705,249 shares;
1998 - 216,764,580 shares)................................................. 72.5 72.2
Additional paid-in capital.................................................... 1,031.7 1,016.2
Retained earnings............................................................. 2,965.1 2,519.8
----------- ----------
4,069.4 3,608.3
Less common stock in treasury - at cost (1999 - 4,395,950 shares;
1998 - 4,395,654 shares).................................................. 132.5 132.5
----------- ----------
3,936.9 3,475.8
----------- ----------
$ 15,123.0 $ 12,304.1
=========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
5
<PAGE> 7
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
NET CASH FLOW FROM OPERATING ACTIVITIES
Earnings from continuing operations
before extraordinary item................................. $ 498.9 $ 482.9 $ 398.7
Add (subtract) items not requiring (providing) cash:
Depreciation, depletion and amortization ................. 483.3 449.4 436.6
Deferred income taxes..................................... 112.1 151.7 73.9
Undistributed earnings from equity investments............ (39.3) (41.2) (43.0)
Working capital and other changes, excluding changes
relating to cash and non-operating activities:
Accounts receivable....................................... (809.2) 395.2 248.5
Inventories............................................... (119.5) 185.1 418.2
Prepaid expenses and other................................ 18.3 31.0 12.3
Accounts payable.......................................... 661.2 (573.4) (350.1)
Accrued expenses.......................................... 111.0 30.9 (56.6)
Other..................................................... 127.0 34.7 (161.6)
----------- ----------- ----------
1,043.8 1,146.3 976.9
----------- ----------- ----------
CASH FLOW FROM INVESTING ACTIVITIES
Purchases of property, plant and equipment................... (1,780.6) (1,404.0) (996.7)
Proceeds from sale of property, plant and equipment.......... 37.7 98.5 84.1
Additions to investments..................................... (379.4) (255.4) (193.8)
Proceeds from investments.................................... 9.8 59.9 71.5
Net from discontinued operations............................. (3.0) 9.3 (16.0)
----------- ----------- ----------
(2,115.5) (1,491.7) (1,050.9)
----------- ----------- ----------
CASH FLOW FROM FINANCING ACTIVITIES
Increase in short-term notes................................. 93.9 123.0 259.0
Redemption of preferred stock................................ - (200.0) -
Proceeds from issuing common stock........................... 14.7 5.5 7.3
Proceeds from long-term debt issues.......................... 1,090.8 432.2 943.4
Proceeds from issuing Company-obligated mandatory
redemption preferred securities of a consolidated trust... - 300.0 -
Proceeds from sale of interest in joint venture.............. 285.0 - -
Proceeds from issuing stock of subsidiaries.................. 65.0 - -
Payments to retire long-term debt............................ (486.6) (172.4) (1,161.8)
Dividends paid............................................... (53.6) (56.5) (59.7)
----------- ----------- ----------
1,009.2 431.8 (11.8)
----------- ----------- -----------
NET INCREASE (DECREASE) IN CASH
AND CASH EQUIVALENTS ........................................ (62.5) 86.4 (85.8)
Cash and cash equivalents at beginning of year............... 106.9 20.5 106.3
----------- ----------- ----------
Cash and cash equivalents at end of year..................... $ 44.4 $ 106.9 $ 20.5
=========== =========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
6
<PAGE> 8
THE COASTAL CORPORATION AND SUBSIDIARIES
STATEMENT OF CONSOLIDATED COMMON STOCK AND
OTHER STOCKHOLDERS' EQUITY
(Thousands of Shares and Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------------
1999 1998 1997
------------------- -------------------- --------------------
Shares Amount Shares Amount Shares Amount
-------- -------- -------- -------- -------- ---------
<S> <C> <C> <C> <C> <C> <C>
PREFERRED STOCK, PAR VALUE 33-1/3(cent)
PER SHARE, AUTHORIZED 50,000,000
SHARES CUMULATIVE CONVERTIBLE
PREFERRED:
$1.19, Series A: Beginning balance. 56 $ - 58 $ - 60 $ -
Converted to common................ (3) - (2) - (2) -
-------- --------- ------- -------- ------- --------
Ending balance................... 53 - 56 - 58 -
======== --------- ======= -------- ======= --------
$1.83, Series B: Beginning balance. 61 - 68 - 74 -
Converted to common................ (3) - (7) - (6) -
-------- --------- ------- -------- ------- --------
Ending balance................... 58 - 61 - 68 -
======== --------- ======= -------- ======= --------
$5.00, Series C: Beginning balance. 28 - 30 - 32 -
Converted to common................ (1) - (2) - (2) -
-------- --------- ------- -------- ------- --------
Ending balance................... 27 - 28 - 30 -
======== --------- ======= -------- ======= --------
CUMULATIVE PREFERRED:
$2.125, Series H, liquidation amount
of $25 per share:
Beginning balance.................. - - 8,000 2.6 8,000 2.6
Redeemed........................... - - (8,000) (2.6) - -
-------- --------- ------- ------- ------- --------
Ending balance..................... - - - - 8,000 2.6
======== --------- ======= -------- ======= --------
CLASS A COMMON STOCK, PAR VALUE
33-1/3(cent) PER SHARE, AUTHORIZED
2,700,000 SHARES
Beginning balance.................. 354 .1 366 .1 382 .1
Converted to common................ (12) - (13) - (17) -
Conversion of preferred stock and
exercise of stock options.......... 3 - 1 - 1 -
-------- --------- ------- -------- ------- --------
Ending balance................... 345 .1 354 .1 366 .1
======== --------- ======= -------- ======= --------
COMMON STOCK, PAR VALUE 33-1/3(cent)
PER SHARE, AUTHORIZED 500,000,000
SHARES
Beginning balance.................. 216,765 72.2 110,117 36.7 109,756 36.6
Conversion of preferred stock...... 65 - 63 - 47 -
Conversion of Class A common stock. 12 - 13 - 17 -
Two-for-one stock split............ - - 106,274 35.4 - -
Exercise of stock options.......... 863 .3 298 .1 297 .1
-------- --------- ------- -------- ------- --------
Ending balance................... 217,705 72.5 216,765 72.2 110,117 36.7
======== --------- ======= -------- ======= --------
ADDITIONAL PAID-IN CAPITAL
Beginning balance.................. 1,016.2 1,243.6 1,239.6
Exercise of stock options.......... 9.0 5.4 4.0
Two-for-one stock split............ - (35.4) -
Redemption of Series H preferred
stock............................ - (197.4) -
Issuance of FELINE PRIDES(SM)...... 6.5 - -
--------- -------- --------
Ending balance................... 1,031.7 1,016.2 1,243.6
--------- -------- --------
RETAINED EARNINGS
Beginning balance ................. 2,519.8 2,131.9 1,890.1
Net earnings for period............ 498.9 444.4 301.5
Cash dividends on preferred stock.. (.3) (6.0) (17.4)
Cash dividends on Class A common
stock, 22.5(cents) (1999),
21.38(cents) (1998) and 18(cents)
(1997) per share................. (.1) (.1) (.1)
Cash dividends on common stock,
25(cents) (1999), 23.75(cents)
(1998) and 20(cents) (1997)
per share........................ (53.2) (50.4) (42.2)
-------- ------- -------
Ending balance................... 2,965.1 2,519.8 2,131.9
--------- -------- --------
LESS TREASURY STOCK - AT COST........... 4,396 132.5 4,396 132.5 4,396 132.5
======== --------- ======= -------- ======= --------
TOTAL................................... $ 3,936.9 $3,475.8 $3,282.4
========= ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.
7
<PAGE> 9
THE COASTAL CORPORATION AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
PRINCIPLES OF CONSOLIDATION. The consolidated financial statements include
accounts of the Company and its wholly owned subsidiaries, after eliminating all
significant intercompany transactions. The equity method of accounting is used
for investments in which the Company has a 20% to 50% voting interest and
exercises significant influence. The equity method is also used for investments
in limited partnerships in which the Company has an interest of more than 5%.
Other investments in which the Company has less than a 20% voting interest are
accounted for by the cost method.
STATEMENT OF CASH FLOWS. For purposes of this statement, cash equivalents
include time deposits, certificates of deposit and all highly liquid instruments
with original maturities of three months or less. Cash flows of a hedging
instrument that is accounted for as a hedge of an identifiable transaction are
classified in the same category as the cash flows from the item being hedged.
The Company made cash payments for interest and financing fees (net of amounts
capitalized) of $306.6 million, $291.6 million and $275.7 million in 1999, 1998
and 1997, respectively. Cash payments for income taxes amounted to $9.7 million,
$42.4 million and $63.6 million for 1999, 1998 and 1997, respectively.
USE OF ESTIMATES. The preparation of financial statements in conformity
with generally accepted accounting principles requires the Company to make
estimates and assumptions that affect the reported amounts of assets,
liabilities, revenues and expenses. Actual results could differ from the
estimates and assumptions used.
INVENTORIES. Inventories of refined products and crude oil are accounted
for by the first-in, first-out cost method or market, if lower. Inventories of
natural gas are accounted for at average cost. Inventories of coal are accounted
for at average cost, or market, if lower. Inventories of materials and supplies
are accounted for at average cost.
HEDGES. The Company frequently enters into swaps, futures and other
contracts to hedge the price risks associated with inventories, commitments and
certain anticipated transactions. The Company defers the impact of changes in
the market value of these contracts until such time as the hedged transaction is
completed. At that time, the impact of the changes in the fair value of these
contracts is recognized in income. The Company also enters into interest rate
and foreign currency swaps to manage interest rates and foreign currency
exchange risk. Income and expense related to interest rate swaps is accrued as
interest rates change and is recognized in income over the life of the
agreement. Such gains and losses are essentially offset by gains or losses on
the related debt.
To qualify as a hedge, the item to be hedged must expose the Company to
price, interest rate or foreign currency exchange rate risk and the hedging
instrument must reduce that exposure. Any contracts held or issued that did not
meet the requirements of a hedge would be recorded at fair value in the balance
sheet and any changes in that fair value recognized in income. If a contract
designated as a hedge of price risk or foreign currency exchange risk is
terminated, the associated gain or loss is deferred and recognized in income in
the same manner as the hedged item. Also, a contract designated as a hedge of an
anticipated transaction that is no longer likely to occur would be recorded at
fair value and the associated changes in fair value recognized in income. The
gain or loss associated with a terminated interest rate swap that has been
designated as a hedge of interest rate risk will continue to be recognized in
interest and debt expense over the life of the agreement.
PROPERTY, PLANT AND EQUIPMENT. Property additions include acquisition
costs, administrative costs and, where appropriate, capitalized interest
allocable to construction. Capitalized interest amounted to $41.3 million, $26.9
million and $15.5 million in 1999, 1998 and 1997, respectively. All costs
incurred in the acquisition, exploration and development of gas and oil
properties, including unproductive wells, are capitalized under the full-cost
method of accounting. Such costs include the costs of all unproved properties
and internal costs directly related to acquisition and exploration activities.
All other general and administrative costs, as well as production costs, are
expensed as incurred.
Depreciation, depletion and amortization ("DD&A") of gas and oil
properties are provided on the unit-of- production basis whereby the unit rate
for DD&A is determined by dividing the total unrecovered carrying value of gas
and oil properties plus estimated future development costs by the estimated
proved reserves included therein, as
8
<PAGE> 10
estimated by Company engineers and reviewed by independent engineers. The
average amortization rate per equivalent unit of a thousand cubic feet of gas
production for oil and gas operations was $.87 for 1999, $.89 for 1998 and $.91
for 1997. Unamortized costs of proved properties are subject to a ceiling which
limits such costs to the estimated future net cash flows from proved gas and oil
properties, net of related income tax effects, discounted at 10 percent. If the
unamortized costs are greater than this ceiling, any excess will be charged to
DD&A expense. No such charge was required in the periods presented. Provisions
for depletion of coal properties, including exploration and development costs,
are based upon estimates of recoverable reserves using the unit-of-production
method. Provision for depreciation of other property is primarily on a
straight-line basis over the estimated useful life of the properties. The annual
rates of depreciation are as follows:
<TABLE>
<S> <C> <C> <C>
Refining, crude oil and chemical facilities...... 3.0% - 20.0%
Gas systems...................................... 1.2% - 10.0%
Coal facilities.................................. 5.0% - 33.3%
Power facilities ................................ 2.9% - 33.3%
Transportation equipment......................... 4.5% - 33.3%
Office and miscellaneous equipment............... 3.0% - 33.3%
Buildings and improvements....................... 1.3% - 20.0%
</TABLE>
Costs of minor property units (or components thereof) retired or abandoned
are charged or credited, net of salvage, to accumulated depreciation, depletion
and amortization. Gain or loss on sales of major property units is credited or
charged to income.
The Company reexamined the useful lives of certain assets of its
interstate natural gas pipelines and certain storage subsidiaries. During 1997,
the depreciation rates associated with these assets were revised, which had the
effect of increasing "Earnings from continuing operations before extraordinary
item" and "Net earnings" by $19.0 million ($.09 per share) in 1998 and $13.4
million ($.06 per share) in 1997.
GOODWILL. Goodwill, which primarily relates to the acquisitions of
American Natural Resources Company ("ANR") and Colorado Interstate Gas Company
("CIG"), amounted to $451.8 million at December 31, 1999, and is being amortized
on a straight-line basis over a 40-year period. Amortization expense charged to
operations was approximately $19.0 million for 1999, 1998 and 1997,
respectively. As warranted by facts and circumstances, the Company periodically
assesses the recoverability of the cost of goodwill from future operating
income.
INCOME TAXES. The Company follows the liability method of accounting for
deferred income taxes as required by the provisions of Statement of Financial
Accounting Standards No. 109, "Accounting for Income Taxes."
REVENUE RECOGNITION. The Company's subsidiaries recognize revenues for the
sale of their respective products in the period of delivery. Revenues for
services are recognized in the period the services are provided.
CURRENCY TRANSLATION. The U.S. dollar is the functional currency for
substantially all the Company's foreign operations. For those operations, all
gains and losses from currency translations are included in income currently.
EARNINGS PER SHARE. Basic earnings per common share amounts are calculated
using the average number of common and Class A common shares outstanding during
each period. Diluted earnings per share assumes conversion of dilutive
convertible preferred stocks and exercise of all stock options having exercise
prices less than the average market price of the common stock using the treasury
stock method.
Basic and diluted earnings per share amounts and average shares entering
into the computation for 1998 and 1997 reflect the two-for-one stock split of
the Company's common stock declared on May 7, 1998.
EMERGING ISSUES TASK FORCE ISSUE NO. 98-10. The Company adopted Financial
Accounting Standards Board ("FASB") Emerging Issues Task Force Issue No. 98-10,
"Accounting for Contracts in Energy Trading and Risk Management Activities," in
1999. The application of Issue 98-10 did not have a material effect on the
Company's consolidated financial statements.
9
<PAGE> 11
STATEMENT OF POSITION 98-5 ("SOP 98-5"). The Company adopted the
Accounting Standards Executive Committee of the American Institute of Certified
Public Accountants' SOP 98-5, "Reporting on the Costs of Start-Up Activities,"
in 1999. The application of SOP 98-5 did not have a material effect on the
Company's consolidated financial statements.
STATEMENT OF FINANCIAL ACCOUNTING STANDARDS NO. 133, "ACCOUNTING FOR
DERIVATIVE INSTRUMENTS AND HEDGING ACTIVITIES" ("FAS 133"). The FASB has issued
FAS 133, as amended by Statement of Financial Accounting Standards No. 137, to
be effective for all fiscal quarters of fiscal years beginning after June 15,
2000. FAS 133 requires that an entity recognize all derivatives as either assets
or liabilities in the statement of financial position and measure those
instruments at fair value. The accounting for changes in the fair value of a
derivative will depend on the intended use of the derivative and the resulting
designation. The Company is currently evaluating the impact of FAS 133.
EURO CONVERSION. In January 1999, certain countries of the European Union
adopted the Euro as their legal common currency. This conversion to the Euro did
not have a material effect on the Company's consolidated results of operations,
financial position or cash flows as the Company does not have significant
European operations.
RECLASSIFICATION OF PRIOR PERIOD STATEMENTS. Certain minor
reclassifications have been made to conform with current reporting practices.
The effect of the reclassifications was not material to the Company's
consolidated results of operations, financial position or cash flows.
NOTE 2. INVENTORIES
Inventories at December 31 were (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998
----------- ----------
<S> <C> <C>
Refined products, crude oil and chemicals.................................. $ 576.2 $ 306.9
Natural gas in underground storage......................................... - 32.0
Coal, materials and supplies............................................... 156.5 160.6
----------- ----------
$ 732.7 $ 499.5
=========== ==========
</TABLE>
Elements included in inventory cost are material, labor and manufacturing
expenses.
NOTE 3. INVESTMENTS
The Company has interests in corporations and partnerships which are
accounted for on an equity basis. These investments, included in Other Assets,
are Great Lakes Gas Transmission Limited Partnership (50% interest), which
operates an interstate pipeline system; Engage Energy US, L.P. and Engage Energy
Canada, L.P. ("Engage") (50% interest), which market natural gas and
electricity; Iroquois Gas Pipeline System, L.P. (16% interest), which operates a
natural gas pipeline; Empire State Pipeline (50% interest), which operates a
natural gas pipeline; Javelina Company (40% interest), which operates a gas
processing plant in Corpus Christi, Texas; Eagle Point Cogeneration Partnership
(50% interest), which operates a cogeneration facility in New Jersey; Alliance
Pipeline Limited Partnership (14.4% interest), which is constructing a 1,900
mile pipeline; Midland Cogeneration Venture (43.5% interest), which operates a
cogeneration plant in Michigan; and several pipeline, power and other ventures.
The Company's investment in these entities, including advances, amounted to
$1,434.9 million and $970.8 million at December 31, 1999 and 1998, respectively.
The Company's equity in income of the investments, included in Other Income-Net,
was $190.4 million, $124.3 million and $137.5 million in 1999, 1998 and 1997,
respectively, while dividends and partnership distributions received amounted to
$151.1 million, $83.1 million and $94.5 million in 1999, 1998 and 1997,
respectively.
10
<PAGE> 12
Summarized financial information of these entities is as follows (Millions
of Dollars):
<TABLE>
<CAPTION>
December 31,
---------------------------
1999 1998
----------- ----------
<S> <C> <C>
Current assets............................................................. $ 2,095.3 $ 1,388.2
Noncurrent assets.......................................................... 7,338.7 5,948.8
----------- ----------
$ 9,434.0 $ 7,337.0
=========== ==========
Current liabilities........................................................ $ 1,673.1 $ 1,093.1
Noncurrent liabilities..................................................... 4,088.8 3,348.2
Deferred credits........................................................... 456.1 225.0
Equity..................................................................... 3,216.0 2,670.7
----------- ----------
$ 9,434.0 $ 7,337.0
=========== ==========
</TABLE>
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Revenues ................................................ $ 7,271.4 $ 7,631.4 $ 5,302.1
Operating income.......................................... 661.1 563.2 627.5
Net income................................................ 494.8 306.5 353.4
</TABLE>
11
<PAGE> 13
NOTE 4. DEBT
LONG-TERM DEBT - Balances at December 31 were (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998
----------- ----------
<S> <C> <C>
The Coastal Corporation:
Notes payable (revolving credit agreements)................................ $ 50.0 $ 125.0
Senior notes:
10.375%, due 2000....................................................... 121.3 121.3
10%, due 2001........................................................... 84.0 84.0
8.75%, due 1999......................................................... - 150.0
8.125%, due 2002........................................................ 249.8 249.7
6.2%, due 2004.......................................................... 199.8 -
6.5%, due 2006.......................................................... 199.6 -
Senior debentures:
10.25%, due 2004........................................................ 37.7 37.7
10.75%, due 2010........................................................ 56.5 56.4
9.75%, due 2003......................................................... 102.1 102.1
9.625%, due 2012........................................................ 149.4 149.3
7.75%, due 2035......................................................... 149.9 149.9
7.42%, due 2037......................................................... 200.0 200.0
6.7%, due 2027.......................................................... 200.0 200.0
6.5%, due 2008.......................................................... 199.8 199.8
6.95%, due 2028......................................................... 199.4 199.4
6.375%, due 2009........................................................ 199.5 -
6.625% with FELINE PRIDES(SM), due 2004................................. 454.0 -
----------- ----------
2,852.8 2,024.6
----------- ----------
Subsidiary companies:
Notes payable (term credit facilities)..................................... 354.7 184.3
Notes payable (revolving credit agreements)................................ 379.0 609.0
Notes payable (project financings), due 2006-2011.......................... 53.8 59.6
Debentures, 6.85% to 10%, due 2005-2037.................................... 777.5 777.5
Other, due 2003-2028....................................................... 67.0 70.8
----------- ----------
1,632.0 1,701.2
----------- ----------
Amount reclassified from short-term debt................................... 475.0 400.0
----------- ----------
Total long-term debt....................................................... 4,959.8 4,125.8
Less current maturities.................................................... 161.6 126.5
----------- ----------
$ 4,798.2 $ 3,999.3
=========== ==========
</TABLE>
At December 31, 1999, amounts available under long-term credit agreements
with banks totaled $2,018.4 million, including $85.0 million available to The
Coastal Corporation. Loans under these agreements bear interest at money
market-related rates (weighted average 6.46% at December 31, 1999). Annual
commitment fees range up to .30% payable on the unused portion of the applicable
facility. At December 31, 1999, $783.7 million was outstanding and $496.3
million of the unused amount was dedicated to specific uses.
The subsidiary project financing notes bear interest at money
market-related rates.
In February 1999, the Company completed a public offering of $200 million
of 6.375% senior debentures due 2009. The net proceeds from the sale were used
to repay floating rate indebtedness of a subsidiary under a revolving credit
facility.
12
<PAGE> 14
In May 1999, the Company issued $200 million of 6.2% senior notes due in
2004 and $200 million of 6.5% senior notes due in 2006. The net proceeds from
the sale of the notes were used to retire $150 million of 8.75% senior notes due
May 15, 1999 and to repay floating rate indebtedness, including indebtedness of
a subsidiary under a revolving credit facility, and for general corporate
purposes.
In August 1999, the Company issued a total of 18,400,000 FELINE PRIDES(SM)
consisting of 17,000,000 Income PRIDES with a stated value of $25 and 1,400,000
Growth PRIDES with a stated value of $25, and also issued $35 million of 6.625%
Senior Debentures, having a principal amount of $25 and due August 16, 2004 (the
"Senior Debentures"). The Income PRIDES consist of a unit comprised of a Senior
Debenture and a purchase contract under which the holder will purchase from the
Company by no later than August 16, 2002 for $25 (the stated price) a number of
shares of the Company's common stock. The Growth PRIDES consist of a unit
comprised of a purchase contract under which the holder will purchase from the
Company by no later than August 16, 2002 for $25 (the stated price) a number of
shares of the Company's common stock and a 2.5% undivided beneficial interest in
a three-year Treasury security having a principal amount at maturity equal to
$1,000. The interest rate on the Senior Debentures is to be reset, subject to
certain limitations, effective August 16, 2002. Under the terms of the purchase
contracts, the Company will issue shares of the Company's common stock in a
number ranging from a minimum of approximately 9.9 million shares up to a
maximum of approximately 12.1 million shares, depending on the market price,
upon settlement of the purchase contracts. If the market price of Coastal's
common stock is less than or equal to $38.0625, the number of shares to be
delivered will be calculated by dividing the stated price by $38.0625. If the
market price of Coastal's common stock is greater than $46.4363, the number of
shares to be delivered will be calculated by dividing the stated price by
$46.4363. If the market price is between $38.0625 and $46.4363, the number of
shares to be delivered will be calculated by dividing the stated price by the
market price. The Company received total gross proceeds of approximately $460
million before applicable expenses. The proceeds from the issuance of the FELINE
PRIDES(SM) and the Senior Debentures were used to repay indebtedness, including
indebtedness of subsidiaries.
Various agreements contain restrictive covenants which, among other
things, limit dividends by certain subsidiaries and additional indebtedness of
certain subsidiaries. At December 31, 1999, net assets of consolidated
subsidiaries amounted to approximately $8.4 billion, of which $766.9 million was
restricted by such provisions.
MATURITIES. The aggregate amounts of long-term debt maturities for the
five years following 1999 are (Millions of Dollars):
<TABLE>
<S> <C> <C> <C>
2000 $161.6 2003 $123.4
2001 $596.9 2004 $705.6
2002 $469.6
</TABLE>
NOTES PAYABLE. At December 31, 1999, Coastal and its subsidiaries had
$580.9 million of outstanding indebtedness under the Company's commercial paper
program and indebtedness to banks under short-term lines of credit, compared to
$487.0 million at December 31, 1998. As of December 31, 1999, the Company's
financial statements reflected $475.0 million of short-term borrowings which had
been reclassified as long-term, based on the availability of committed credit
lines with maturities in excess of one year and the Company's intent to maintain
such amounts as long-term borrowings. There was a similar reclassification of
$400.0 million as of December 31, 1998. The weighted average interest rates were
6.63% and 6.07% at December 31, 1999 and 1998, respectively. As of December 31,
1999, $1,031.4 million was available to be drawn under short-term credit lines.
RESTRICTIONS ON PAYMENT OF DIVIDENDS. Under the terms of the most
restrictive of the Company's financing agreements, approximately $781.4 million
of retained earnings was available at December 31, 1999, for payment of
dividends on the Company's common and preferred stocks.
GUARANTEES. Coastal and certain subsidiaries have guaranteed specific
obligations of several unconsolidated affiliates. Affiliates are generally not
required to collateralize their contingent liabilities to the Company. At
December 31, 1999, the Company had guaranteed a construction financing of a
partially owned partnership. The Company's proportionate share of the
outstanding principal balance under this guarantee was $92.5 million at December
31, 1999. This loan is expected to be refinanced on a non-recourse basis. The
Company and a partner have issued a number of guarantees related to the
operations of Engage. Pursuant to an equalization agreement with the partner,
each party has
13
<PAGE> 15
agreed to reimburse the other in the event there are disproportionate payments
under their respective guarantees. As of December 31, 1999, the Company's share
of such guarantees was $668.6 million; the actual liabilities related to these
guarantees was $144.8 million. Other guarantees and indemnities related to
obligations of unconsolidated affiliates amounted to approximately $104.4
million as of December 31, 1999. The Company is of the opinion that its
unconsolidated affiliates will be able to perform under their respective
financings and other obligations and that no payments will be required and no
losses will be incurred under such guarantees and indemnities.
NOTE 5. LEASES AND COMMITMENTS
The Company leases property, plant and equipment under various operating
leases, certain of which contain renewal and purchase options and residual value
guarantees. Such residual value guarantees amount to approximately $517.3
million. Rental expense amounted to approximately $120.3 million, $86.0 million
and $95.3 million in 1999, 1998 and 1997, respectively, excluding leases
covering natural resources. Aggregate minimum lease payments under existing
noncapitalized long-term leases are estimated to be $124.4 million, $114.9
million, $100.1 million, $99.5 million, and $98.6 million for the years
2000-2004, respectively, and $677.5 million thereafter.
NOTE 6. SECURITIES OF SUBSIDIARIES
COMPANY-OBLIGATED MANDATORY REDEMPTION PREFERRED SECURITIES OF A
CONSOLIDATED TRUST. On May 13, 1998, Coastal completed a public offering of
12,000,000 Coastal-obligated mandatory redemption preferred securities through
an affiliate, Coastal Finance I, a business trust (the "Trust"), for $300
million in cash. The Trust holds debt securities of Coastal purchased with the
proceeds of the preferred securities offering. Cumulative quarterly
distributions are being paid on the preferred securities at an annual rate of
8.375% of the liquidation amount of $25 per preferred security. The preferred
securities are mandatorily redeemable on the maturity date, May 13, 2038, and
may be redeemed at the Company's option on or after May 13, 2003, or earlier if
certain events occur. The redemption price to be paid is $25 per preferred
security, plus accrued and unpaid distributions to the date of redemption.
PREFERRED STOCK OF SUBSIDIARIES. Coastal Securities Company Limited
("Coastal Securities"), a wholly owned subsidiary, issued 4,000,000 shares of
preferred stock in 1996 for $100 million in cash. Quarterly cash dividends are
being paid on the preferred stock at a rate based on the London Interbank
Offered Rate ("LIBOR"). The preferred shareholders are also entitled to
participating dividends based on certain refining margins. Coastal Securities
may redeem the preferred stock on or after December 31, 1999 for cash. Also, on
or after December 31, 1999 but prior to December 31, 2000, Coastal Securities
may elect to redeem the preferred stock by issuing unsecured convertible
debentures.
In 1999, Coastal Oil and Gas Resources, Inc. ("COGR"), a wholly owned
subsidiary, issued 50,000 shares of preferred stock for $50 million in cash. The
preferred shareholders are entitled to quarterly cash dividends at a rate based
on LIBOR. The dividend rate is subject to renegotiation in 2004 and on each
fifth anniversary thereafter. In the event COGR and the preferred shareholders
are unable to agree to a new rate, COGR must redeem the shares at $1,000 per
share plus any accrued and unpaid dividends, or cause the preferred stock to be
registered with the Securities and Exchange Commission and remarketed. COGR also
has the option to redeem all shares on any dividend rate reset date for $1,000
per share plus any accrued and unpaid preferred dividends.
In 1999, Coastal Limited Ventures, Inc. ("CLVI"), a wholly owned
subsidiary, issued 150,000 shares of preferred stock for $15 million in cash.
The preferred shareholders are entitled to quarterly cash dividends at an annual
rate of 6%. The dividend rate is subject to renegotiation in 2004 and on each
fifth anniversary thereafter. In the event CLVI and the preferred shareholders
are unable to agree to a new rate, the preferred shareholders may call for
redemption of all of the preferred shares. The redemption price is $100 per
share plus any accrued and unpaid preferred dividends thereon. CLVI also has the
option to redeem all shares on any rate reset date for $100 per share plus any
accrued and unpaid preferred dividends.
CONSOLIDATED JOINT VENTURE. In December 1999, CLVI contributed certain
assets to a limited partnership in exchange for a controlling general
partnership interest. Limited interests in the partnership were issued to
unaffiliated investors for $285 million in cash. The limited partners are
entitled to a cumulative priority return based on LIBOR. The return is subject
to renegotiation in 2004 and on each fifth anniversary thereafter. The
partnership has a maximum life of 20 years, but may be terminated sooner subject
to certain conditions, including failure to agree to a new rate. CLVI
14
<PAGE> 16
may terminate the partnership at any time by repayment of the limited partners'
outstanding capital plus any unpaid priority returns.
NOTE 7. FINANCIAL INSTRUMENTS AND RISK MANAGEMENT
The Company's operations involve managing market risks related to changes
in interest rates, foreign exchange rates and commodity prices. Derivative
financial instruments, specifically swaps and other contracts, are used to
reduce and manage those risks. The Company does not currently hold or issue
financial instruments for trading purposes.
INTEREST RATE SWAPS. The Company has entered into a number of interest
rate swap agreements designated as a partial hedge of the Company's portfolio of
variable rate debt. The purpose of these swaps is to fix interest rates on
variable rate debt and reduce certain exposures to interest rate fluctuations.
At December 31, 1999, the Company had interest rate swaps with a notional amount
of $18.2 million, and a portfolio of variable rate debt outstanding in the
amount of $1,469.2 million. Under these agreements, Coastal will pay the
counterparties interest at a weighted average fixed rate of 6.78%, and the
counterparties will pay Coastal interest at a variable rate equal to LIBOR or
other market rates. The weighted average rate applicable to these agreements was
5.29% at December 31, 1999. The notional amounts do not represent amounts
exchanged by the parties, and thus are not a measure of exposure of the Company.
The amounts exchanged are normally based on the notional amounts and other terms
of the swaps. The weighted average variable rates are subject to change over
time as market rates fluctuate. Terms expire at various dates through the year
2011.
Neither the Company nor the counterparties, which are prominent bank
institutions, are required to collateralize their respective obligations under
these swaps. Coastal is exposed to loss if one or more of the counterparties
default. At December 31, 1999, Coastal had no exposure to credit loss on
interest rate swaps. The Company does not believe that any reasonably likely
change in interest rates would have a material adverse effect on the financial
position, the results of operations or cash flows of the Company. All interest
rate and currency swaps are reviewed with, and when necessary, are approved by
the Company's Board of Directors.
OTHER DERIVATIVES. The Company and its subsidiaries also frequently enter
into swaps and other contracts to hedge the price risks associated with
inventories, commitments and certain anticipated transactions. The swaps and
other contracts are with established energy companies and major financial
institutions. The Company believes its credit risk is minimal on these
transactions, as the counterparties are required to meet stringent credit
standards. There is continuous day-to-day involvement by senior management in
the hedging decisions, operating under resolutions adopted by each subsidiary's
board of directors.
15
<PAGE> 17
FAIR VALUE OF FINANCIAL INSTRUMENTS. The estimated fair value amounts of
the Company's financial instruments have been determined by the Company, using
appropriate market information and valuation methodologies. Considerable
judgment is required to develop the estimates of fair value, thus, the estimates
provided herein are not necessarily indicative of the amounts that the Company
could realize in a current market exchange.
<TABLE>
<CAPTION>
(Millions of Dollars)
------------------------------------------------------------
Dec. 31, 1999 Dec. 31, 1998
---------------------------- -----------------------------
Carrying Fair Carrying Fair
Amount Value Amount Value
---------- ----------- ----------- ------------
<S> <C> <C> <C> <C>
Nonderivatives:
Financial assets:
Cash and cash equivalents..................... $ 44.4 $ 44.4 $ 106.9 $ 106.9
Notes receivable.............................. 259.0 270.6 248.1 271.3
Investments................................... 68.0 68.0 64.0 64.0
Financial liabilities:
Short-term debt............................... 105.9 105.9 87.0 87.0
Long-term debt ............................... 4,959.8 4,907.0 4,125.8 4,423.0
Company-obligated mandatory redemption
preferred securities of a consolidated trust.. 300.0 276.0 300.0 295.6
Preferred stock - issued by subsidiaries........ 165.0 166.3 100.0 100.0
Limited partnership interests in consolidated
joint venture................................. 285.9 285.9 - -
Derivatives relating to:
Commodity swaps gain (loss)..................... - (4.8) - 6.4
Interest rate swaps gain (loss) ................ - .4 - (1.7)
</TABLE>
The estimated values of the Company's notes receivable, long-term debt,
Company-obligated mandatory redemption preferred securities of a consolidated
trust, preferred stock - issued by subsidiaries and limited partnership
interests in consolidated joint venture are based on interest rates at December
31, 1999 and 1998, respectively, for new issues with similar remaining
maturities. The fair value of investments are based on market prices at December
31, 1999 and 1998, respectively. The fair value of the derivatives related to
commodity swaps are derived from quoted market prices at December 31, 1999 and
1998, respectively. The fair market value of the Company's interest rate swaps
is based on the estimated termination values at December 31, 1999 and 1998,
respectively.
NOTE 8. COMMON AND PREFERRED STOCK
On April 15, 1998, the Company redeemed all 8,000,000 outstanding shares
of its $2.125 Cumulative Preferred Stock, Series H. Redemption price for the
Series H stock was $25 per share plus accrued dividends of $.182986 to April 15,
1998.
Executives, directors and other key employees have been granted options to
purchase common shares under stock option plans adopted in 1990, 1994, 1996,
1997 and 1998. Under each plan, the option price equals the fair market value of
the common shares on the date of grant. Options vest cumulatively at rates
ranging from 15% to 33 1/3% of the option shares on each anniversary date of the
date of grant beginning with the first or second anniversary. The options, which
expire either five years or ten years from the grant date, do not carry any
stock appreciation rights.
16
<PAGE> 18
The following table presents a summary of stock options transactions for
the three years ended December 31, 1999:
<TABLE>
<CAPTION>
Class A Average
Common Common Option Price
Shares Shares Per Share
------------ ----------- --------------
<S> <C> <C> <C>
December 31, 1996........................................... 4,469,050 2,280 $ 15.49
Granted.................................................. 1,567,112 - 23.60
Exercised................................................ (589,930) - 13.72
Revoked or expired....................................... (235,202) - 16.26
------------ ----------- --------------
December 31, 1997........................................... 5,211,030 2,280 18.12
Granted.................................................. 2,080,349 - 32.72
Exercised................................................ (466,812) - 16.15
Revoked or expired....................................... (222,230) - 23.84
----------- ----------- --------------
December 31, 1998........................................... 6,602,337 2,280 22.64
Granted.................................................. 1,809,068 - 32.93
Exercised................................................ (863,408) (2,280) 17.23
Revoked or expired....................................... (434,288) - 26.52
----------- ----------- --------------
December 31, 1999........................................... 7,113,709 - $ 25.68
=========== =========== ==============
</TABLE>
In accordance with the provisions of Statement of Financial Accounting
Standards No. 123, "Accounting for Stock-Based Compensation" ("FAS 123"), the
Company applies APB Opinion 25 in accounting for its stock option plans and,
accordingly, does not recognize compensation cost for options granted to
executives and other key employees. If the Company had elected to recognize
compensation cost based on the fair value of the options granted at grant date
as prescribed by FAS 123, earnings from continuing operations before
extraordinary item, net earnings and earnings per share would have been reduced
to the pro forma amounts shown in the table below (in Millions Except Per Share
Amounts):
<TABLE>
<CAPTION>
Year Ended December 31,
-------------------------------------------
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Earnings from continuing operations before
extraordinary item..................................... $ 486.8 $ 473.8 $ 394.4
Net earnings.............................................. 486.8 435.3 297.2
Basic earnings per share
From continuing operations before
extraordinary item................................... $ 2.28 $ 2.20 $ 1.78
Discontinued operations................................ - (.18) (.03)
Extraordinary item..................................... - - (.43)
----------- ----------- ----------
Net basic earnings per share........................... $ 2.28 $ 2.02 $ 1.32
=========== =========== ==========
Diluted earnings per share
From continuing operations before
extraordinary item................................... $ 2.24 $ 2.17 $ 1.75
Discontinued operations................................ - (.18) (.03)
Extraordinary item..................................... - - (.42)
----------- ----------- ----------
Net diluted earnings per share......................... $ 2.24 $ 1.99 $ 1.30
=========== =========== ==========
</TABLE>
The effects of applying FAS 123 in this pro forma disclosure are not
indicative of future amounts.
17
<PAGE> 19
The fair value of each option grant is estimated on the date of grant
using the Black-Scholes option-pricing model with the following assumptions used
for grants in 1999, 1998 and 1997:
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- ----------
<S> <C> <C> <C>
Risk free interest rate................................... 5.17% 5.57% 6.90%
Expected life (years)..................................... 8 8 8
Expected dividend yield................................... .81% .611% .85%
Expected volatility....................................... .3583 .2241 .2205
Weighted average fair value of options granted (per share) $ 15.22 $ 12.77 $ 9.75
</TABLE>
Stock options available for future grants amounted to 5,478,587;
6,856,789; and 493,642 at December 31, 1999, 1998 and 1997, respectively.
Exercisable stock options amounted to 1,983,595; 1,706,453; and 1,353,198, at
December 31, 1999, 1998 and 1997, respectively.
The following table summarizes information about stock options outstanding
and exercisable at December 31, 1999:
<TABLE>
<CAPTION>
Outstanding Exercisable
------------------------------------- -----------------------
Average Average
Exercise Average Exercise Exercise
Price Range Shares Life (*) Price Shares Price
----------- ----------- ----------- ----------- ----------- -----------
<S> <C> <C> <C> <C> <C>
$10.46 - $18.28........................ 2,338,018 4.9 $ 15.93 1,337,138 $ 15.20
23.53 - 29.82........................ 1,236,058 7.1 23.63 384,336 23.69
30.74 - 43.34........................ 3,539,633 8.6 32.84 262,121 32.88
----------- -----------
7,113,709 1,983,595
=========== ===========
</TABLE>
* Average life remaining in years.
NOTE 9. SEGMENT AND GEOGRAPHIC REPORTING
The Company operates principally in the following lines of business:
natural gas; refining, marketing and chemicals; exploration and production;
power; and coal. Separate management of each segment is required because each
line of business is subject to different production, marketing and technology
strategies.
Natural gas operations involve the production, purchase, gathering,
storage, transportation, marketing and sale of natural gas, principally to
utilities, industrial customers and other pipelines, and include the operation
of natural gas liquids extraction plants. Sales are primarily made to pipeline
and distribution companies in most major areas of the United States.
Refining, marketing and chemicals operations involve the purchase,
transportation and sale of refined products, crude oil, condensate and natural
gas liquids; the operation of refineries and chemical plants; the sale at retail
of gasoline, petroleum products and convenience items; petroleum product
terminaling and marketing of crude oil and refined petroleum products. Products
from this segment are sold to customers worldwide.
Exploration and production operations involve the exploration, development
and production of natural gas, crude oil, condensate and natural gas liquids.
Sales are made to affiliated companies, industrial users, interstate pipelines
and distribution companies in the Rocky Mountain, central and southwest areas of
the United States and offshore Gulf of Mexico.
Power operations involve the ownership of, participation in and operation
of power projects in the United States and internationally. Power is sold to
customers in the Northeast and Midwest United States and internationally in Asia
and Latin America.
18
<PAGE> 20
Coal operations include the mining, processing and marketing of coal from
Company-owned reserves and from other sources, and the brokering of coal for
others. Sales are made to utilities and industrial customers in the United
States and to export markets in Canada.
Corporate and other operations include real estate activities and
corporate income and expense not allocated to the operating segments.
The Company's operating revenues from external customers; intersegment
revenues; earnings (loss) before interest and income taxes; depreciation
depletion and amortization; equity income (loss) from investments; and capital
expenditures for the years ended December 31, 1999, 1998 and 1997 are shown as
follows (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING REVENUES FROM EXTERNAL CUSTOMERS
Natural gas............................................... $ 1,243.5 $ 1,356.8 $ 2,125.5
Refining, marketing and chemicals......................... 6,005.9 5,200.4 6,870.9
Exploration and production................................ 556.3 436.6 383.4
Power..................................................... 127.6 121.1 103.8
Coal...................................................... 257.6 241.7 226.8
Corporate and other ...................................... 6.3 11.6 19.7
----------- ----------- -----------
Consolidated totals.................................... $ 8,197.2 $ 7,368.2 $ 9,730.1
=========== =========== ===========
INTERSEGMENT REVENUES
Natural gas............................................... $ 3.4 $ 1.6 $ 40.7
Refining, marketing and chemicals......................... 2.2 2.3 6.2
Exploration and production................................ 27.7 26.4 106.8
Power..................................................... - - -
Coal...................................................... - - -
Corporate and other ...................................... 8.8 11.4 9.7
----------- ----------- -----------
Consolidated totals.................................... $ 42.1 $ 41.7 $ 163.4
=========== =========== ===========
EARNINGS (LOSS) BEFORE INTEREST AND INCOME TAXES
Natural gas............................................... $ 573.8 $ 594.3 $ 583.0
Refining, marketing and chemicals......................... 228.5 243.9 95.6
Exploration and production................................ 185.9 109.8 167.6
Power..................................................... 89.0 67.8 43.4
Coal...................................................... 15.8 17.4 25.3
Corporate and other....................................... (96.9) (88.7) (70.4)
----------- ----------- -----------
Consolidated totals.................................... $ 996.1 $ 944.5 $ 844.5
=========== =========== ===========
DEPRECIATION, DEPLETION AND AMORTIZATION (EXCLUDING
AMORTIZATION OF GOODWILL)
Natural gas............................................... $ 129.2 $ 118.3 $ 136.5
Refining, marketing and chemicals......................... 74.3 78.3 74.6
Exploration and production................................ 231.9 209.2 185.5
Power..................................................... 8.5 3.2 3.1
Coal...................................................... 16.8 14.6 14.1
Corporate and other....................................... 3.6 7.0 4.1
----------- ----------- -----------
Consolidated totals.................................... $ 464.3 $ 430.6 $ 417.9
=========== =========== ===========
</TABLE>
19
<PAGE> 21
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
EQUITY INCOME (LOSS) FROM INVESTMENTS
Natural gas............................................... $ 95.7 $ 80.4 $ 92.6
Refining, marketing and chemicals......................... 20.7 1.0 8.7
Exploration and production................................ - - -
Power..................................................... 74.4 43.0 36.2
Coal...................................................... - - -
Corporate and other....................................... (.4) (0.1) -
----------- ----------- -----------
Consolidated totals.................................... $ 190.4 $ 124.3 $ 137.5
=========== =========== ===========
CAPITAL EXPENDITURES
Natural gas............................................... $ 307.3 $ 192.2 $ 224.7
Refining, marketing and chemicals......................... 162.8 229.1 167.6
Exploration and production................................ 1,079.6 934.8 574.4
Power..................................................... 153.1 2.0 2.2
Coal...................................................... 65.4 34.7 18.8
Corporate and other....................................... 12.4 11.2 9.0
----------- ----------- -----------
Consolidated totals.................................... $ 1,780.6 $ 1,404.0 $ 996.7
=========== =========== ===========
</TABLE>
The Company's assets and amount of investment in equity method investees
by segment as of December 31, 1999, 1998 and 1997 are as follows (Millions of
Dollars):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
ASSETS
Natural gas............................................... $ 5,801.3 $ 5,379.5 $ 5,262.0
Refining, marketing and chemicals......................... 4,464.2 3,351.2 3,795.4
Exploration and production................................ 3,029.5 2,161.6 1,484.0
Power..................................................... 765.3 449.8 258.1
Coal...................................................... 307.1 269.6 252.7
Corporate and other....................................... 755.6 692.4 587.5
----------- ----------- -----------
Consolidated totals.................................... $ 15,123.0 $ 12,304.1 $ 11,639.7
=========== =========== ===========
EQUITY METHOD INVESTMENTS
Natural gas............................................... $ 851.3 $ 608.9 $ 521.7
Refining, marketing and chemicals......................... 98.8 68.2 64.6
Exploration and production................................ - - -
Power..................................................... 486.4 295.0 167.5
Coal...................................................... .5 .5 .5
Corporate and other....................................... (2.1) (1.8) (1.7)
----------- ----------- -----------
Consolidated totals.................................... $ 1,434.9 $ 970.8 $ 752.6
=========== =========== ===========
</TABLE>
Intersegment sales are accounted for on the basis of contract, current
market or internally established transfer prices.
In September 1996, Coastal and Westcoast Energy Inc. ("Westcoast") jointly
announced plans to form one of North America's largest marketers of natural gas
and electricity through the combination of the operations of the two companies'
related marketing and service subsidiaries. Agreements were concluded in
February 1997, which created Engage in which Coastal and Westcoast indirectly
own 50% each. Natural gas operating revenues for the first two months of 1997
include the revenues of Coastal's natural gas marketing operations ($833.5
million). Subsequent to the combination, Engage's revenues are not included in
Coastal's operating revenues; however, Coastal's share of Engage's net earnings
is included in Other Income-Net. As part of the combination, Coastal received an
equalization payment of $42 million which is included in the Natural Gas
earnings before interest and income taxes in 1997.
20
<PAGE> 22
In June 1998, the power purchase agreement associated with the Company's
Fulton Power Plant ("Plant") was restructured. In connection with the
restructuring, a net gain of $17.2 million was recorded in the Power segment.
The net gain reflects a $23 million reduction in the Plant's carrying value (to
estimated fair value following the restructuring) and deferral of certain
proceeds to cover estimated future costs.
In October 1998, the Company sold certain non-core natural gas processing
and gathering assets. Revenues and earnings before interest and income taxes for
the Natural Gas segment include a gain of $58.6 million from the sale.
Refining, marketing and chemicals revenues include gross profit arising
from the selling, trading and exchanging of third-party products. Approximate
amounts from these transactions included in revenues and the impact on earnings,
exclusive of interest costs, were (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Revenues.................................................. $ 52.5 $ 34.8 $ 26.3
Impact on earnings........................................ 34.1 22.6 17.1
</TABLE>
The number and magnitude of such transactions may vary significantly from
year to year, particularly in view of conditions in world petroleum markets.
The Company's operating revenues for the years ended December 31, 1999,
1998 and 1997 and property, plant and equipment as of December 31, 1999, 1998
and 1997, by geographic area, are shown as follows (Millions of Dollars):
<TABLE>
<CAPTION>
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
OPERATING REVENUES
United States............................................. $ 6,865.4 $ 6,381.7 $ 8,059.6
Foreign, Aruba............................................ 1,045.1 743.4 1,251.4
Foreign, Other............................................ 286.7 243.1 419.1
----------- ----------- -----------
Consolidated totals.................................... $ 8,197.2 $ 7,368.2 $ 9,730.1
=========== =========== ===========
PROPERTY, PLANT AND EQUIPMENT
United States............................................. $ 8,608.7 $ 7,344.9 $ 6,551.0
Foreign, Aruba............................................ 589.2 564.0 478.8
Foreign, Other............................................ 139.5 115.0 91.8
----------- ----------- -----------
Consolidated totals.................................... $ 9,337.4 $ 8,023.9 $ 7,121.6
=========== =========== ===========
</TABLE>
Revenues from sales to any single customer during 1999, 1998 or 1997 did
not amount to 10% or more of the Company's consolidated revenues. Revenues by
geographic area are attributed to countries based on the location of Company
subsidiaries making the sales.
21
<PAGE> 23
NOTE 10. BENEFIT PLANS
The Company has non-contributory pension plans covering substantially all
U.S. employees. These plans provide benefits based on final average monthly
compensation and years of service. The Company's funding policy is to contribute
the amount necessary for the plan to maintain its qualified status under the
Employment Retirement Income Security Act of 1974, as amended. The following
tables provide a reconciliation of the changes in the pension plans' benefit
obligations and fair value of assets over each of the years ended December 31,
1999 and 1998 and a statement of the funded status as of December 31, 1999 and
1998 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year.................................... $ 757.9 $ 729.3
Service cost............................................................... 21.4 19.6
Interest cost.............................................................. 51.5 49.0
Plan amendment ............................................................ - 3.8
Actuarial (gain) loss...................................................... (11.4) (1.5)
Benefit payments........................................................... (42.9) (42.3)
----------- -----------
Benefit obligation at end of year.......................................... $ 776.5 $ 757.9
=========== ===========
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year............................. $ 1,481.8 $ 1,298.7
Actual return on plan assets............................................... 222.4 224.9
Employer contributions..................................................... .7 .5
Benefit payments........................................................... (42.9) (42.3)
----------- -----------
Fair value of plan assets at end of year................................... $ 1,662.0 $ 1,481.8
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
FUNDED STATUS
Funded status at year end.................................................. $ 885.5 $ 723.9
Unrecognized transition obligation (asset)................................. (20.3) (28.5)
Unrecognized prior service cost............................................ 5.0 5.9
Unrecognized net (gain) loss............................................... (368.4) (293.1)
----------- -----------
Prepaid pension cost....................................................... $ 501.8 $ 408.2
=========== ===========
</TABLE>
Plan assets include common stock and Class A common stock of the Company
amounting to a total of 7.2 million shares at December 31, 1999 and 1998,
respectively.
22
<PAGE> 24
The following table provides the components of the net periodic pension
benefit for 1999, 1998 and 1997 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Service cost.............................................. $ 21.4 $ 19.6 $ 17.2
Interest cost............................................. 51.5 49.0 47.5
Expected return on assets................................. (145.1) (126.4) (105.7)
Amortization of transition obligation (asset)............. (8.2) (8.6) (8.6)
Amortization of prior service cost........................ .8 .8 .4
Amortization of net (gain) loss........................... (13.4) (7.6) (3.1)
----------- ----------- -----------
Net periodic pension benefit ............................. $ (93.0) $ (73.2) $ (52.3)
=========== =========== ===========
</TABLE>
The discount rate used in determining the actuarial present value of the
projected benefit obligation was 8% in 1999 and 7% in 1998 and 1997. The
expected increase in future compensation levels was 4% in 1999, 1998 and 1997
and the expected long-term rate of return on assets was 10% in 1999, 1998 and
1997.
The Company also participates in several multi-employer pension plans for
the benefit of its employees who are union members. Company contributions to
these plans were not material for 1999, 1998 or 1997.
The Company also makes contributions to a thrift plan, which is a
trusteed, voluntary and contributory plan for eligible employees of the Company.
The Company's contributions, which are based on matching employee contributions,
amounted to $20.2 million, $19.4 million and $18.9 million in 1999, 1998 and
1997, respectively.
The Company provides certain health care and life insurance benefits for
retired employees. Substantially all U.S. employees are provided these benefits.
The estimated costs of retiree benefit payments are accrued during the years the
employee provides services.
23
<PAGE> 25
The following tables provide a reconciliation of the changes in the
postretirement benefit obligation and the fair value of plan assets over each of
the years ended December 31, 1999 and 1998, and a statement of the funded status
as of December 31, 1999 and 1998 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
CHANGE IN BENEFIT OBLIGATION
Benefit obligation at beginning of year.................................... $ 108.1 $ 108.0
Service cost............................................................... 2.7 2.3
Interest cost.............................................................. 6.8 6.9
Participant contributions.................................................. 2.4 2.8
Actuarial gain (loss)...................................................... (2.7) (.8)
Benefit payments........................................................... (9.6) (10.2)
Curtailment (gain) loss.................................................... - (.9)
----------- -----------
Benefit obligation at end of year.......................................... $ 107.7 $ 108.1
=========== ===========
CHANGE IN PLAN ASSETS
Fair value of plan assets at beginning of year............................. $ 24.4 $ 24.1
Actual return on plan assets............................................... 1.4 .1
Employer contributions..................................................... 10.4 5.5
Administrative expenses.................................................... (2.3) (.1)
Benefit payments........................................................... (4.5) (5.2)
----------- -----------
Fair value of plan assets at end of year................................... $ 29.4 $ 24.4
=========== ===========
</TABLE>
<TABLE>
<CAPTION>
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
FUNDED STATUS
Funded status at year end.................................................. $ (78.3) $ (83.7)
Unrecognized transition obligation ........................................ 77.2 83.2
Unrecognized prior service cost............................................ 3.0 3.5
Unrecognized net (gain) loss............................................... (38.6) (34.1)
----------- -----------
Accrued postretirement benefit obligation.................................. $ (36.7) $ (31.1)
=========== ===========
</TABLE>
The following table provides the components of net periodic postretirement
benefit cost for 1999, 1998 and 1997 (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Service cost.............................................. $ 2.7 $ 2.3 $ 2.3
Interest cost............................................. 6.8 6.9 7.0
Expected return on assets................................. (.7) (.7) (.8)
Amortization of transition obligation .................... 5.9 6.0 6.0
Amortization of prior service cost........................ .4 .4 .4
Amortization of net (gain) loss........................... (2.4) (2.6) (2.6)
Deferred regulatory amounts............................... - - 3.5
----------- ----------- -----------
Net periodic postretirement benefit cost.................. $ 12.7 $ 12.3 $ 15.8
=========== =========== ===========
</TABLE>
The assumed health care cost trend rate used in measuring the accumulated
postretirement benefit obligation was 8.40% in 1999, declining gradually to 6.0%
by the year 2004. The assumed health care cost trend rate used in measuring
the accumulated postretirement benefit obligation was 9.0% in 1998 and 9.7% in
1997. A one percentage point increase in the assumed health care cost trend rate
for each year would increase the accumulated postretirement benefit obligation
24
<PAGE> 26
as of December 31, 1999 by approximately 4.63% and the net postretirement health
care cost by approximately 3.75%. A one percentage point decrease in the assumed
health care cost trend rate for each year would decrease the accumulated
postretirement benefit obligation as of December 31, 1999 by approximately 4.61%
and the net postretirement health care cost by approximately 4.58%.The assumed
discount rate used in determining the accumulated postretirement benefit
obligation was 8.0% in 1999, 7.0% in 1998 and 7.25% in 1997 and the expected
long-term rate of return on assets was 4.3% in 1999, 1998 and 1997.
NOTE 11. TAXES ON INCOME
Pretax earnings from continuing operations before extraordinary item are
composed of the following (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
United States............................................. $ 554.3 $ 502.8 $ 458.2
Foreign .................................................. 118.5 146.8 78.8
----------- ----------- -----------
$ 672.8 $ 649.6 $ 537.0
=========== =========== ===========
</TABLE>
Provisions for income taxes from continuing operations before
extraordinary item are composed of the following (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Current income taxes:
Federal................................................... $ 45.0 $ 5.0 $ 50.7
Foreign................................................... 7.8 5.5 5.3
State..................................................... 9.0 4.5 8.4
----------- ----------- -----------
61.8 15.0 64.4
----------- ----------- -----------
Deferred income taxes:
Federal................................................... 111.7 140.9 69.5
Foreign................................................... 3.4 3.4 3.3
State..................................................... (3.0) 7.4 1.1
----------- ----------- -----------
112.1 151.7 73.9
----------- ----------- -----------
Taxes on Income................................................. $ 173.9 $ 166.7 $ 138.3
=========== =========== ===========
</TABLE>
The Company and the Internal Revenue Service ("IRS") Appeals Office have
concluded a final settlement of adjustments originally proposed to federal
income tax returns filed for the years 1985 through 1987 and have concluded a
tentative settlement of the additional adjustments proposed by the IRS to those
returns. The Company and the IRS Appeals Office have also concluded a tentative
settlement of the adjustments proposed to the Company's federal income tax
returns filed for the years 1988 through 1990. The Company has received notice
of proposed adjustments to the Company's federal income tax returns filed for
the years 1991 through 1994, and the Company is currently contesting certain of
these adjustments before the IRS Appeals Office. Examination of the Company's
federal income tax returns filed for the years 1995, 1996 and 1997 began in
1999. It is the opinion of management that adequate provisions for federal
income taxes have been reflected in the consolidated financial statements.
25
<PAGE> 27
Provisions for income taxes were different than the amount computed by
applying the statutory U.S. federal income tax rate to earnings before tax. The
reasons for these differences are (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------------------
1999 1998 1997
----------- ----------- -----------
<S> <C> <C> <C>
Tax expense by applying the U.S. federal income tax
rate of 35%............................................ $ 235.5 $ 227.4 $ 187.9
Increases (reductions) in taxes resulting from:
Tight sands gas credit................................. (6.0) (7.9) (6.5)
State income tax cost ................................. 3.9 7.7 6.2
Goodwill............................................... 6.4 6.4 6.4
Exclusion for foreign investments and certain
domestic joint ventures.............................. (51.5) (50.3) (50.6)
Depletion and depreciation............................. (16.4) (1.2) (1.4)
Other.................................................. 2.0 (15.4) (3.7)
----------- ----------- -----------
Taxes on income................................................. $ 173.9 $ 166.7 $ 138.3
=========== =========== ===========
</TABLE>
Deferred tax liabilities (assets) which are recognized for the estimated
future tax effects attributable to temporary differences and carryforwards are
(Millions of Dollars):
<TABLE>
<CAPTION>
December 31,
----------------------------
1999 1998
----------- -----------
<S> <C> <C>
Excess of book basis over tax basis of property, plant and equipment ...... $ 1,646.2 $ 1,637.4
Pensions and benefit costs................................................. 129.4 109.8
Other...................................................................... 130.0 67.2
----------- -----------
Deferred tax liabilities................................................... 1,905.6 1,814.4
----------- -----------
Purchase gas and other recoverable costs................................... (4.9) (14.0)
Alternative minimum tax credit carryforward................................ (189.7) (195.4)
----------- -----------
Deferred tax assets........................................................ (194.6) (209.4)
----------- -----------
Deferred income taxes...................................................... $ 1,711.0 $ 1,605.0
=========== ===========
</TABLE>
U.S. income taxes have been provided for earnings of foreign subsidiaries
that are expected to be distributed to the U.S. parent company. Foreign
subsidiaries' cumulative undistributed earnings of $389.3 million are considered
to be indefinitely reinvested outside the U.S. and, accordingly, no U.S. income
taxes have been provided on those earnings. The determination of the
hypothetical amount of unrecognized deferred U.S. taxes on undistributed
earnings of foreign subsidiaries is not practicable.
NOTE 12. DISCONTINUED OPERATIONS
The Company is pursuing the disposition of its 50% ownership of ANR
Advance Transportation Company, Inc. ("ANR Advance"), a trucking operation. ANR
Advance is being liquidated in cooperation with other owners. Accordingly, the
trucking operations are being reported as a discontinued operation.
The net assets (liabilities) being disposed of have been classified in the
accompanying consolidated balance sheet in Other Assets at December 31, 1999 and
1998. The net assets (liabilities) of the discontinued operations amounted to
$2.5 million and $(.5) million at December 31, 1999 and 1998, respectively.
Operating results of the discontinued operations are shown separately in
the accompanying statement of consolidated operations. The loss from operations
shown on the statement of consolidated operations is net of income tax benefits
of $1.9 million and $3.5 million in 1998 and 1997, respectively. The estimated
loss on disposal of the discontinued operations of $35.0 million is net of
income tax benefits of $18.8 million.
26
<PAGE> 28
NOTE 13. EXTRAORDINARY ITEM
EARLY EXTINGUISHMENT OF DEBT. In February 1997, the Company purchased and
retired $798.0 million of notes and debentures with interest rates ranging from
9-3/4% to 10-3/4%. None of the issues were eligible for redemption and the
purchase included payment of a premium. The Company incurred an after-tax
extraordinary charge of $90.6 million ($.43 per share-basic or $.42 per
share-diluted), net of income taxes of $48.7 million, in connection with the
repurchase of these debt securities.
NOTE 14. EARNINGS PER SHARE
Earnings per share are calculated following Statement of Financial
Accounting Standards No. 128. The following data shows the amounts used in
computing basic earnings per share and the effects on income and the weighted
average number of shares of dilutive securities.
<TABLE>
<CAPTION>
For the Year Ended December 31, 1999
-----------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ----------- -----------
<S> <C> <C> <C>
Earnings from continuing operations
before extraordinary item............................ $ 498.9
Less preferred stock dividends.......................... .3
--------------
Basic earnings per share
Income available to common stockholders.............. 498.6 213,283 $ 2.34
===========
Effect of dilutive securities
Options.............................................. - 2,465
Convertible preferred stock.......................... .3 1,244
-------------- -----------
Diluted earnings per share
Income available to common stockholders
plus assumed conversions......................... $ 498.9 216,992 $ 2.30
============== =========== ===========
</TABLE>
<TABLE>
<CAPTION>
For the Year Ended December 31, 1998
-----------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ----------- -----------
<S> <C> <C> <C>
Earnings from continuing operations before
extraordinary items.................................. $ 482.9
Less preferred stock dividends.......................... 6.0
--------------
Basic earnings per share
Income available to common stockholders.............. 476.9 212,543 $ 2.24
===========
Effect of dilutive securities
Options.............................................. - 2,248
Convertible preferred stock.......................... .3 1,317
-------------- -----------
Diluted earnings per share
Income available to common stockholders
plus assumed conversions......................... $ 477.2 216,108 $ 2.21
============== =========== ===========
</TABLE>
27
<PAGE> 29
<TABLE>
<CAPTION>
For the Year Ended December 31, 1997
-----------------------------------------------
Income Shares
(Numerator) (Denominator) Per-Share
(Millions) (Thousands) Amount
-------------- ----------- -----------
<S> <C> <C> <C>
Earnings from continuing operations before
extraordinary items.................................. $ 398.7
Less preferred stock dividends.......................... 17.4
--------------
Basic earnings per share
Income available to common stockholders.............. 381.3 211,892 $ 1.80
===========
Effect of dilutive securities
Options.............................................. - 1,798
Convertible preferred stock.......................... .4 1,412
-------------- -----------
Diluted earnings per share
Income available to common stockholders plus
assumed conversions.............................. $ 381.7 215,102 $ 1.77
============== =========== ===========
</TABLE>
NOTE 15. LITIGATION, ENVIRONMENTAL AND REGULATORY MATTERS
LITIGATION. In December 1992, certain of Colorado's natural gas lessors in
the West Panhandle Field filed a complaint in the U.S. District Court, Northern
District of Texas, claiming underpayment of royalties, breach of fiduciary duty,
fraud and negligent misrepresentation. Management believes that CIG has numerous
defenses to the lessors' claims, including (i) that the royalties were properly
paid, (ii) that the majority of the claims were released by written agreement
and (iii) that the majority of the claims are barred by the statute of
limitations. In March of 1995, the trial court granted a partial summary
judgment in favor of CIG, holding that the four-year statute of limitations had
not been tolled and the releases are valid and dismissing all tort claims and
claims for breach of any duty of disclosure. The remaining claim for
underpayment of royalties was tried to a jury which, in May 1995, made findings
favorable to CIG. On June 7, 1995, the trial court entered a judgment that the
lessors recover no monetary damages from CIG and permanently estopping the
lessors from asserting any claim based on an interpretation of the contract
different than that asserted by CIG in the litigation. The lessors' motion for a
new trial was denied on July 18, 1997, and both parties filed appeals. On June
7, 1996, the same plaintiffs sued CIG in state court in Amarillo, Texas, for
underpayment of royalties. CIG removed the second lawsuit to federal court which
granted a stay of the second suit pending the outcome of the first lawsuit. Oral
arguments were heard before the Fifth Circuit Court of Appeals on December 4,
1998, and the parties are awaiting the Court's decision.
In October 1996, the Company, along with several subsidiaries, was named
as a defendant in a suit filed by several former and current African American
employees in the U.S. District Court, Southern District of Texas ("Texas suit").
The Texas suit alleges racially discriminatory employment policies and
practices. Coastal vigorously denies these allegations and has filed responsive
pleadings. Plaintiffs' counsel are seeking to have the Texas suit certified as a
class action of all former and current African American employees and initially
claimed compensatory and punitive damages of $400 million. In February 1999, in
response to Coastal's motion to deny class certification, plaintiffs' counsel
obtained permission from the Court to delete all claims for compensatory and
punitive damages and to seek equitable relief only.
In January 1998, the plaintiffs in the Texas suit amended their suit to
exclude ANR Pipeline employees from the potential class. A new suit was then
filed in state court in Wayne County, Michigan, seeking to have the Michigan
suit certified as a class action of African American employees of ANR Pipeline
and seeking unspecified damages as well as attorneys and expert fees. ANR
Pipeline has filed responsive pleadings denying these allegations. In August
1999, the court denied plaintiffs' motion to have the Michigan suit certified as
a class action. Plaintiffs filed with the Michigan Court of Appeals an
application for leave to appeal the denial of the class certification. On
November 5, 1999, the Michigan Court of Appeals denied the application for leave
to appeal.
Two legal proceedings, one in federal court and the other in state court,
have been instituted against a number of gas pipeline companies and their
affiliates, including Coastal and several of its subsidiaries. The plaintiffs in
each suit seek damages for the alleged undermeasurement of the heating value and
the volume of natural gas. In the federal proceeding, Jack Grynberg filed 77
separate False Claim Act suits in September 1997 against natural gas
transmission
28
<PAGE> 30
companies and producers, gatherers, and processors of natural gas, seeking
unspecified damages which could include treble damages for the maximum period
permitted by law (potentially as much as ten years) and penalties of up to
$10,000 per false claim. In addition to the measurement claims, these suits also
allege that the defendants undervalued the gas in paying royalties. The Coastal
defendants were sued in the U.S. District Courts of Colorado and the Eastern
District of Michigan. In April 1999, the U.S. Department of Justice notified the
Company that the United States will not intervene in these cases at this time.
The MultiDistrict Litigation Panel has consolidated the Grynberg suits with
several other Grynberg cases for pre-trial proceedings in Wyoming. The
defendants have filed a motion to dismiss which will be argued in March of 2000.
In the state proceedings, the Quinque Operating Company, on behalf of
itself and subclasses of gas producers, royalty owners, overriding royalty
owners, and state taxing authorities, in May 1999 instituted a legal proceeding
in State Court in Stevens County, Kansas against over 200 gas companies,
including several Coastal subsidiaries. The Quinque suit seeks unspecified
actual, punitive and treble damages for the alleged undermeasurement of all
natural gas measured in the United States from non-federal and non-Indian lands
since 1974. The plaintiffs are seeking certification of a national class of all
similarly situated gas producers, royalty owners, overriding royalty owners, and
state taxing authorities. The suit has been removed to the U.S. District Court
for the District of Kansas. The plaintiffs have filed a motion to remand the
case back to the state court, and several defendants have filed a motion under
the MultiDistrict Litigation rules to have the suit transferred to Wyoming and
consolidated with the Grynberg proceedings for pre-trial proceedings.
Numerous other lawsuits and other proceedings which have arisen in the
ordinary course of business are pending or threatened against the Company or its
subsidiaries.
Although no assurances can be given and no determination can be made at
this time as to the outcome of any particular lawsuit or proceeding, the Company
believes there are meritorious defenses to substantially all such claims and
that any liability which may finally be determined should not have a material
adverse effect on the Company's consolidated financial position or results of
operations.
ENVIRONMENTAL MATTERS. The Company's operations are subject to extensive
and evolving federal, state and local environmental laws and regulations.
Compliance with such laws and regulations can be costly. Additionally,
governmental authorities may enforce the laws and regulations with a variety of
civil and criminal enforcement measures, including monetary penalties and
remediation requirements.
The Company spent approximately $10 million in 1999 on environmental
capital projects and anticipates capital expenditures of approximately $36
million in 2000 in order to comply with such laws and regulations. The majority
of the 2000 expenditures is attributable to projects at the Company's refining,
chemical and terminal facilities. The Company currently anticipates capital
expenditures for environmental compliance of $20 million to $40 million per year
over the next several years.
The Comprehensive Environmental Response, Compensation and Liability Act,
also known as "Superfund," imposes liability for the release of a "hazardous
substance" into the environment. Superfund liability is imposed without regard
to fault and even if the waste disposal was in compliance with the then current
laws and regulations. With the joint and several liability imposed under
Superfund, a potentially responsible party ("PRP") may be required to pay more
than its proportional share of such costs. Certain subsidiaries of the Company
and a company in which Coastal owns a 50% interest have been named as a PRP in
various "Superfund" waste disposal sites. At the nine sites for which there is
sufficient information, total cleanup costs are estimated to be approximately
$609 million, and the Company estimates its pro-rata exposure, to be paid over a
period of years, is approximately $8 million and has made appropriate
provisions. At ten other sites, the EPA is currently unable to provide the
Company with an estimate of total cleanup costs and, accordingly, the Company is
unable to calculate its share of those costs.
Additionally, certain subsidiaries of the Company have been named as PRPs
in four state sites. At one site, the North Carolina Department of Health,
Environmental and Natural Resources has estimated the total cleanup costs to
be approximately $50 million, but the Company believes the subsidiary's
activities at this site were de minimis. At a second state site, the Florida
Department of Environmental Protection has demanded reimbursement of its costs,
which total $100,000, and suitable remediation. The Company believes the
subsidiary's activities at the Florida site were de minimis. At a third site,
the owner of the California site has estimated the total cleanup costs to be
approximately $40 million, but
29
<PAGE> 31
the Company believes the subsidiary's activities at this site were de minimis.
At the fourth site, the Texas Natural Resource Conservation Commission has
estimated the total cleanup costs to be approximately $2 million, but the
Company believes the subsidiary's activities at this site were de minimis.
Future information and developments, including legislative and enforcement
developments, will require the Company to continually reassess the expected
impact of these environmental matters. However, the Company has evaluated its
total environmental exposure based on currently available data, including its
potential joint and several liability, and believes that compliance with all
applicable laws and regulations will not have a material adverse impact on the
Company's consolidated financial position or results of operations.
REGULATORY MATTERS. On July 29, 1998, the FERC issued a "Notice of
Proposed Rulemaking," in which the FERC has proposed a number of significant
changes to the industry, including, among other things, removal of price caps in
the short-term market (less than one year), capacity auctions, changed reporting
obligations, the ability to negotiate terms and conditions of all services,
elimination of the requirement of a matching term cap on the renewal of existing
contracts, and a review of its policies for approving capacity construction. On
the same day, the FERC also issued a "Notice of Inquiry" soliciting industry
input on various matters affecting the pricing of long-term service and
certificate pricing in light of changing market conditions. On February 9, 2000,
the FERC issued a final rule implementing certain of the changes that were
discussed in these two proposals. Among other things, the final rule: (a)
removes the price ceilings for short-term secondary market capacity releases for
a trial period through September 30, 2002; (b) permits pipelines to propose
seasonally and term-differentiated rates; (c) revises requirements relating to
pipeline scheduling procedures, capacity segmentation and penalties; (d) narrows
the right-of-first-refusal granted to long-term shippers to retain their
capacity; and (e) expands pipeline reporting requirements. Coastal's interstate
pipeline subsidiaries will seek clarification of certain aspects of the final
rule.
On September 15, 1999, the FERC issued a Policy Statement addressing the
certification and pricing of new pipeline construction projects. Under the
Policy Statement, applicants must first satisfy a threshold pricing requirement
of demonstrating that their projects can be constructed without subsidies from
existing customers. Second, the applicants must show that any adverse impacts of
the project on identified interests (existing customers of the applicant, other
existing pipelines and their captive customers, landowners and the surrounding
communities) are outweighed by its benefits. On October 19, 1999, Coastal's
interstate pipeline subsidiaries sought clarification and/or rehearing of the
Policy Statement insofar as it does not apply directly to those projects filed
for approval under the FERC's "optional certificate" regulations. Other parties
also sought rehearing of this and other aspects of the Policy Statement. On
February 9, 2000, the FERC issued an order which, among other things, held that
the Policy Statement balancing criteria would apply to new optional certificate
applications while it receives comments on its companion notice proposing to
eliminate its optional certificate regulations.
On May 30, 1997, WIC filed with the FERC to increase its rates by
approximately $5.7 million annually. On June 27, 1997, the FERC accepted the
filing effective as of December 1, 1997, subject to refund. The FERC staff and
certain participants in the proceeding raised a number of issues relating to
WIC's rates, revenue requirements and the treatment of an "exit fee" which WIC
had received in conjunction with the termination of a transportation service
agreement. WIC and most of the parties subsequently reached a settlement
resolving all issues in the case. That settlement was ultimately approved by the
FERC on June 21, 1999 (the "June 21, 1999 settlement"). Two parties opposed the
settlement and the FERC initially severed them from the settlement and ordered a
separate hearing on their issues. However, on October 13, 1999, the FERC
determined that the settlement should also apply to those parties as well,
inasmuch as WIC had filed a new rate case (discussed below) which would become
effective before any decision could be reached and implemented. The FERC denied
rehearing of the October 13, 1999 Order on December 21, 1999. The two parties
who had objected to the settlement have the right to seek judicial review of
this order.
On July 1, 1999, WIC filed with the FERC a new rate case to increase its
rates by approximately $8 million annually (based on the rates determined under
the June 21, 1999 settlement). On July 29, 1999, the FERC issued its
order accepting the rate filing and suspending it for five months to become
effective on January 1, 2000. The order also set the case for hearing, which is
currently scheduled to commence in the second half of 2000. WIC has filed to
place its new rates into effect on January 1, 2000, and is collecting those
rates subject to refund.
Certain other regulatory issues remain unresolved among CIG, ANR Pipeline,
ANR Storage Company and WIC, their customers, their suppliers and the FERC. The
Company has made provisions which represent management's
30
<PAGE> 32
assessment of the ultimate resolution of these issues. As a result, the Company
anticipates that these regulatory matters will not have a material adverse
effect on its consolidated financial position or results of operations. While
the Company estimates the provisions to be adequate to cover potential adverse
rulings on these and other issues, it cannot estimate when each of these issues
will be resolved.
NOTE 16. QUARTERLY RESULTS OF OPERATIONS (UNAUDITED)
Results of operations by quarter for the years ended December 31, 1999 and
1998 were (Millions of Dollars Except per Share):
<TABLE>
<CAPTION>
Quarter Ended
----------------------------------------------------------------------
March 31, 1999 June 30, 1999 Sept. 30, 1999 Dec. 31, 1999
-------------- ------------- -------------- -------------
<S> <C> <C> <C> <C>
Operating revenues......................... $ 1,709.6 $ 1,892.1 $ 2,060.1 $ 2,535.4
Less purchases............................. 945.9 1,184.3 1,295.5 1,723.0
---------- ----------- ---------- ----------
763.7 707.8 764.6 812.4
Other income and expenses.................. 629.2 614.5 662.5 643.4
---------- ----------- ---------- ----------
Net earnings .............................. $ 134.5 $ 93.3 $ 102.1 $ 169.0
========== =========== ========== ==========
Basic earnings per share................... $ .63 $ .44 $ .48 $ .79
========== =========== ========== ==========
Diluted earnings per share................. $ .62 $ .43 $ .47 $ .78
========== =========== ========== ==========
</TABLE>
<TABLE>
<CAPTION>
Quarter Ended
----------------------------------------------------------------------
March 31, 1998 June 30, 1998 Sept. 30, 1998 Dec. 31, 1998*
-------------- ------------- -------------- --------------
<S> <C> <C> <C> <C>
Operating revenues......................... $ 1,956.5 $ 1,924.4 $ 1,661.6 $ 1,825.7
Less purchases............................. 1,186.4 1,176.8 966.9 1,046.7
---------- ----------- ---------- ----------
770.1 747.6 694.7 779.0
Other income and expenses.................. 645.3 656.1 602.9 604.2
---------- ----------- ---------- ----------
Earnings from continuing operations........ 124.8 91.5 91.8 174.8
Discontinued operations.................... (1.9) 3.1 (2.3) (37.4)
---------- ----------- ---------- ----------
Net earnings............................... $ 122.9 $ 94.6 $ 89.5 $ 137.4
========== =========== ========== ==========
Basic earnings per share:
From continuing operations.............. $ .57 $ .42 $ .43 $ .82
Discontinued operations................. (.01) .02 (.01) (.18)
---------- ----------- ---------- ----------
Net basic earnings per share............ $ .56 $ .44 $ .42 $ .64
========== =========== ========== ==========
Diluted earnings per share:
From continuing operations.............. $ .56 $ .42 $ .42 $ .81
Discontinued operations................. (.01) .01 (.01) (.17)
---------- ----------- ---------- ----------
Net diluted earnings per share ......... $ .55 $ .43 $ .41 $ .64
========== =========== ========== ==========
</TABLE>
*Includes a $58.6 million gain ($38.1 million net of income taxes, or $.18 per
share) from the sale of certain non-core natural gas processing and gathering
assets.
NOTE 17. MERGER
Coastal and El Paso Energy Corporation ("El Paso Energy") announced on
January 18, 2000 the execution of definitive agreements for the merger of
Coastal and El Paso Energy. Each share of Coastal common stock and Class A
common stock will be converted on a tax-free basis (except for cash paid in lieu
of fractional shares) into 1.23 shares of El Paso Energy common stock. The
outstanding convertible preferred stock of Coastal will be exchanged tax free
(except for cash paid in lieu of fractional shares) for El Paso Energy common
stock on the same basis as if the preferred stock had been converted into
Coastal common stock immediately prior to the merger. It is expected that the
merger will be completed during the fourth quarter of 2000 and be accounted for
as a pooling of interests. The merger is subject to various conditions,
particularly federal regulatory approval.
31
<PAGE> 33
SUPPLEMENTAL INFORMATION ON OIL AND GAS PRODUCING ACTIVITIES (UNAUDITED)
Reserves; capitalized costs; costs incurred in oil and gas acquisition,
exploration and development activities; results of operations; and the
standardized measure of discounted future net cash flows are presented for the
exploration and production segment. Natural gas systems reserves and the related
standardized measure of discounted future net cash flows are separately
presented for natural gas systems operations. All of the Company's proved
properties are located in North America (United States and Canada). The reserve
tables that follow report on United States operations and do not include
approximately 78,000 MMcf equivalents of Canadian proved reserves discovered
during the fourth quarter of 1999.
ESTIMATED QUANTITIES OF PROVED RESERVES (DOMESTIC)
<TABLE>
<CAPTION>
Natural Gas Exploration
Systems and Production
----------- --------------------------
Developed Developed Undeveloped Total
----------- --------- ----------- ---------
<S> <C> <C> <C> <C>
Natural Gas (MMcf):
------------------
1999.................................................. 197,649 1,625,713 1,643,350 3,466,712
1998.................................................. 211,761 1,287,207 1,028,167 2,527,135
1997.................................................. 248,248 953,235 551,031 1,752,514
Oil, Condensate and Natural Gas Liquids (000 barrels):
-----------------------------------------------------
1999.................................................. 249 33,690 23,188 57,127
1998.................................................. 237 31,894 20,153 52,284
1997.................................................. 349 27,016 12,778 40,143
</TABLE>
Changes in proved reserves since the end of 1996 are shown in the following
table.
<TABLE>
<CAPTION>
Oil, Condensate and
Natural Gas Natural Gas Liquids
(MMcf) (000 barrels)
---------------------------- ----------------------------
Natural Exploration Natural Exploration
Gas and Gas and
Total Proved Reserves Systems Production Systems Production
- --------------------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C>
Total, end of 1996.............................. 267,927 1,188,605 391 44,071
-------- ---------- ------- ---------
Production during 1997.......................... (38,135) (159,127) (57) (4,957)
Extensions and discoveries...................... 8,870 305,319 - 5,775
Acquisitions.................................... - 252,219 - 2,340
Sales of reserves in-place...................... - (56,894) - (6,739)
Revisions of previous quantity estimates and
other..................................... 9,586 (25,856) 15 (696)
-------- ---------- ------- ---------
Total, end of 1997.............................. 248,248 1,504,266 349 39,794
-------- --------- ------- ---------
Production during 1998.......................... (39,058) (185,732) (44) (5,578)
Extensions and discoveries...................... 404 518,529 - 9,185
Acquisitions.................................... - 575,934 - 11,915
Sales of reserves in-place...................... - (25,556) - (1,072)
Revisions of previous quantity estimates and
other..................................... 2,167 (72,067) (68) (2,197)
-------- ---------- ------- ---------
Total, end of 1998.............................. 211,761 2,315,374 237 52,047
-------- ---------- ------- ---------
Production during 1999.......................... (35,634) (230,542) (24) (4,475)
Extensions and discoveries...................... - 745,565 - 5,354
Acquisitions.................................... - 539,274 - 11,377
Sales of reserves in-place...................... - (39,908) - (805)
Revisions of previous quantity estimates and
other..................................... 21,522 (60,700) 36 (6,620)
-------- ---------- ------- ---------
Total, end of 1999.............................. 197,649 3,269,063 249 56,878
======== ========== ======= =========
</TABLE>
32
<PAGE> 34
Total proved reserves for natural gas systems exclude storage gas and
liquids volumes. The natural gas systems storage gas volumes are 221,509,
225,853 and 213,571 MMcf and storage liquids volumes are approximately 301,000,
232,000 and 209,000 barrels at December 31, 1999, 1998 and 1997, respectively.
Total proved reserves for natural gas equivalents include approximately 152,000,
162,000 and 32,000 MMcf associated with volumetric production payments sold to
unaffiliated entities by the Company for the years 1999, 1998 and 1997,
respectively.
All of the Company's proved reserves are located in North America (United
States and Canada). Other international activities are connected with the
evaluation of various concessions. The statistical tables on capitalized costs
report on worldwide operations while the reserve and cash flow tables are for
properties located in the United States. Other international investments are
periodically reviewed for impairment.
CAPITALIZED COSTS RELATING TO EXPLORATION AND PRODUCTION ACTIVITIES (WORLDWIDE)
(Millions of Dollars)
<TABLE>
<CAPTION>
December 31,
--------------------
1999 1998
-------- --------
<S> <C> <C>
Proved and Unproved Properties:
- ------------------------------
Proved properties....................................................................... $ 3,234 $ 2,508
Unproved properties..................................................................... 536 312
-------- --------
3,770 2,820
Accumulated depreciation, depletion and amortization.................................... (904) (765)
-------- --------
$ 2,866 $ 2,055
======== ========
</TABLE>
The Company follows the full-cost method of accounting for oil and gas
properties.
COSTS EXCLUDED FROM AMORTIZATION (DOMESTIC)
(Millions of Dollars)
The following table summarizes the costs related to unevaluated properties
and major development projects which are excluded from amounts subject to
amortization at December 31, 1999. The Company regularly evaluates these costs
to determine whether impairment has occurred. The majority of these costs are
expected to be evaluated and included in the amortization base within three
years.
<TABLE>
<CAPTION>
Years Costs Incurred
--------------------------------------------------------------
Prior to
Total 1999 1998 1997 1997
--------- --------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
Property acquisition............................. $ 277 $ 137 $ 121 $ 15 $ 4
Exploration...................................... 123 89 28 4 2
Development...................................... 64 36 21 6 1
Capitalized interest............................. 22 20 2 - -
--------- --------- -------- -------- --------
$ 486 $ 282 $ 172 $ 25 $ 7
========= ========= ======== ======== ========
</TABLE>
33
<PAGE> 35
COSTS INCURRED IN OIL AND GAS ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES (WORLDWIDE)
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
---------------------------------
1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
Property acquisition costs:
Proved................................................................. $ 154 $ 129 $ 48
Unproved............................................................... 152 133 49
Exploration costs............................................................ 168 123 83
Development costs............................................................ 593 540 388
</TABLE>
RESULTS OF OPERATIONS FOR EXPLORATION AND PRODUCTION ACTIVITIES (DOMESTIC)
(Millions of Dollars)
<TABLE>
<CAPTION>
Year Ended December 31,
--------------------------------
1999 1998 1997
-------- -------- --------
<S> <C> <C> <C>
Revenues:
Sales..................................................................... $ 451 $ 333 $ 227
Transfers................................................................. 113 111 240
-------- -------- --------
Total.................................................................. 564 444 467
-------- -------- --------
Production costs............................................................. (104) (89) (92)
Operating expenses........................................................... (50) (44) (34)
Depreciation, depletion and amortization..................................... (223) (195) (171)
-------- -------- --------
187 116 170
Income tax expense........................................................... (59) (33) (52)
-------- -------- --------
Results of operations for producing activities (excluding corporate
overhead and interest costs).............................................. $ 128 $ 83 $ 118
======== ======== ========
</TABLE>
The average domestic amortization rate per equivalent Mcf was $0.87 in
1999, $0.89 in 1998 and $0.91 in 1997. Depreciation, depletion and amortization
excludes provisions for the impairment of international projects of $10.0
million in 1999, $9.1 million in 1998 and $10.7 million in 1997.
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS RELATING TO
PROVED OIL AND GAS RESERVE QUANTITIES (DOMESTIC). Future cash inflows for the
years ended December 31, 1999 and 1998 from the sale of proved reserves and
estimated production and development costs as calculated by the Company's
engineers and reviewed by Huddleston & Co., Inc., the Company's independent
engineer, are discounted by 10% after they are reduced by the Company's estimate
for future income taxes. The amount for 1997 was calculated by Huddleston. The
calculations are based on year-end prices and costs, statutory tax rates and
nonconventional fuel source tax credits that relate to existing proved oil and
gas reserves in which the Company has mineral interests.
34
<PAGE> 36
The standardized measure is not intended to represent the market value of
reserves and, in view of the uncertainties involved in the reserve estimation
process, including the instability of energy markets as evidenced by changes in
both natural gas and crude oil prices, may be subject to material future
revisions (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
-----------------------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------------- ----------------------------
Natural Gas Exploration Natural Gas Exploration Natural Gas Exploration
Systems and Production Systems and Production Systems and Production
----------- -------------- ----------- -------------- ----------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Future cash inflows.......... $ 229 $ 8,250 $ 256 $ 4,939 $ 291 $ 4,190
Future production and
development costs......... (74) (2,674) (79) (1,909) (87) (1,479)
Future income tax expenses... (49) (1,265) (57) (584) (67) (635)
----------- ----------- ----------- ----------- ----------- -----------
Future net cash flows........ 106 4,311 120 2,446 137 2,076
10% annual discount for
estimated timing of cash
flows..................... (41) (1,556) (51) (865) (57) (651)
----------- ----------- ----------- ----------- ----------- -----------
Standardized measure of
discounted future net
cash flows................ $ 65 $ 2,755 $ 69 $ 1,581 $ 80 $ 1,425
=========== =========== =========== =========== =========== ===========
</TABLE>
Future net cash flows include approximately $190 million for 1999, $156
million for 1998 and $38 million for 1997 related to volumes dedicated to
volumetric production payments sold to unaffiliated entities by the Company.
Principal sources of change in the standardized measure of discounted
future net cash flows during each year are (Millions of Dollars):
<TABLE>
<CAPTION>
Year Ended December 31,
------------------------------------------------------------------------------------
1999 1998 1997
------------------------- ------------------------- ----------------------------
Natural Gas Exploration Natural Gas Exploration Natural Gas Exploration
Systems and Production Systems and Production Systems and Production
----------- -------------- ----------- -------------- ----------- ---------------
<S> <C> <C> <C> <C> <C> <C>
Sales and transfers, net of
production costs............. $ (36) $ (474) $ (34) $ (338) $ (34) $ (373)
Net changes in prices and
production costs............. (5) 734 3 (334) (53) (906)
Extensions and discoveries...... - 606 - 430 10 322
Acquisitions.................... - 643 - 317 - 289
Sales of reserves in-place...... - (33) - (21) - (117)
Development costs incurred
during the period that
reduced estimated future
development costs............ - 102 - 115 - 11
Revisions of previous quantity
estimates, timing and other.. 28 (234) 6 (322) (34) (392)
Accretion of discount........... 6 136 8 141 17 233
Net change in income taxes...... 3 (306) 6 168 34 398
----------- ----------- ----------- ----------- ----------- -----------
Net change...................... $ (4) $ 1,174 $ (11) $ 156 $ (60) $ (535)
=========== =========== =========== =========== =========== ===========
</TABLE>
None of the amounts include any value for natural gas systems storage gas
and liquids volumes, which was approximately 41 Bcf for CIG, 117 Bcf for ANR
Pipeline, 63 Bcf for Mid Michigan Gas Storage Company and 301,000 barrels of
liquids for CIG at the end of 1999.
35
<PAGE> 37
(b) Pro forma financial information:
The following unaudited pro forma condensed combined financial information
gives effect to the merger using the pooling of interests method of accounting.
This information is presented to show the estimated impact of the merger as if
our companies had always been combined. This presentation assumes the issuance
of approximately 270 million shares of El Paso Energy common stock in connection
with the merger. The Unaudited Pro Forma Condensed Combined Statements of Income
are prepared as if we completed the merger as of January 1, 1997, and the
Unaudited Pro Forma Condensed Combined Balance Sheet was prepared as if we
completed the merger on December 31, 1999.
The accompanying Notes to Unaudited Pro Forma Condensed Combined Financial
Statements explain the assumptions used in preparing the financial information,
and do not reflect cost savings from operating efficiencies or other
improvements we may achieve by combining our companies. The historical financial
information for Coastal includes certain reclassifications to conform to El Paso
Energy's presentation. These reclassifications have no impact on income from
continuing operations or total stockholders' equity.
Accounting policy differences and intercompany balances between El Paso
Energy and Coastal are not expected to be material and, accordingly, adjustments
have not been included in these statements.
We are providing this financial information for illustrative purposes only.
It does not necessarily indicate what the operating results and financial
position of the combined company might have been had the merger been completed
at the beginning of the earliest period presented, nor does it necessarily
indicate what the combined company's operating results and financial position
will be following the merger.
The accompanying unaudited pro forma financial information should be read
in conjunction with:
- the audited consolidated financial statements and other financial
information included in El Paso Energy's Annual Report on Form 10-K
for the fiscal year ended December 31, 1999, including the notes to
those financial statements; and
- the audited consolidated financial statements of Coastal for the fiscal
year ended December 31, 1999, including the notes to those financial
statements, included in Item 7(a) of this Form 8-K.
36
<PAGE> 38
UNAUDITED PRO FORMA CONDENSED COMBINED BALANCE SHEET
AS OF DECEMBER 31, 1999
(IN MILLIONS)
<TABLE>
<CAPTION>
ASSETS
EL PASO
ENERGY COASTAL COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Total current assets............................... $ 2,911 $ 2,924 $ $ 5,835
Property, plant and equipment, net................. 10,261 9,337 19,598
Other.............................................. 3,485 2,862 6,347
------- ------- ----- -------
Total assets............................. $16,657 $15,123 $ $31,780
======= ======= ===== =======
LIABILITIES & STOCKHOLDERS' EQUITY
Total current liabilities.......................... $ 3,702 $ 3,038 $ 70 (a) $ 6,783
(27)(b)
------- ------- ----- -------
Long-term debt, less current maturities............ 5,223 4,798 10,021
------- ------- ----- -------
Deferred income taxes.............................. 1,738 1,814 3,552
------- ------- ----- -------
Other.............................................. 1,354 785 2,139
------- ------- ----- -------
Company-obligated preferred securities of
consolidated trusts.............................. 325 300 625
------- ------- ----- -------
Minority interest.................................. 1,368 451 1,819
------- ------- ----- -------
Stockholders' equity
Cumulative preferred stock....................... -- -- (c)
Class A common stock............................. -- -- (c)
Common stock..................................... 716 73 735 (c) 1,524
Additional paid-in capital....................... 1,367 1,032 (868)(c) 1,531
Retained earnings................................ 1,207 2,965 (70)(a) 4,129
27 (b)
Other............................................ (343) (133) 133 (c) (343)
------- ------- ----- -------
Total stockholders' equity............... 2,947 3,937 (43) 6,841
------- ------- ----- -------
Total liabilities and stockholders'
equity................................. $16,657 $15,123 $ $31,780
======= ======= ===== =======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma
Condensed Combined Financial Statements.
37
<PAGE> 39
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1999
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
EL PASO
ENERGY COASTAL COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Operating revenues................................ $10,581 $8,197 $ $18,778
------- ------ ---- -------
Operating expenses
Cost of gas and other products.................. 7,974 5,149 13,123
Operation and maintenance....................... 979 1,587 2,566
Merger-related and asset impairment charges..... 557 557
Ceiling test charges............................ 352 352
Depreciation, depletion, and amortization....... 609 479 1,088
Taxes, other than income taxes.................. 146 100 246
------- ------ ---- -------
10,617 7,315 17,932
------- ------ ---- -------
Operating income (loss)........................... (36) 882 846
Other income, net................................. 227 146 373
------- ------ ---- -------
Income before interest, income taxes, and minority
interest........................................ 191 1,028 1,219
------- ------ ---- -------
Interest and debt expense......................... 453 323 776
Minority interest................................. 36 25 61
Income tax expense (benefit)...................... (81) 174 93
------- ------ ---- -------
408 522 930
------- ------ ---- -------
Income (loss) from continuing operations before
preferred dividends of subsidiaries............. (217) 506 289
Preferred stock dividends of subsidiaries......... 25 7 32
------- ------ ---- -------
Income (loss) from continuing operations.......... (242) 499 257
Dividends on preferred stock...................... --
------- ------ ---- -------
Income (loss) from continuing operations available
to common stockholders.......................... $ (242) $ 499 $ $ 257
======= ====== ==== =======
Basic earnings (loss) per share from continuing
operations available to common stockholders..... $ (1.06) $ 0.52
======= =======
Diluted earnings (loss) per share from continuing
operations available to common stockholders..... $ (1.06)(d) $ 0.51(d)
======= =======
Basic average common shares outstanding........... 228 269(e) 497
======= ==== =======
Diluted average common shares outstanding......... 239 (d) 269(e) 508(d)
======= ==== =======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma
Condensed Combined Financial Statements.
38
<PAGE> 40
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1998
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
EL PASO
ENERGY COASTAL COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Operating revenues................................ $9,500 $7,368 $ $16,868
------ ------ --- -------
Operating expenses
Cost of gas and other products.................. 6,970 4,377 11,347
Operation and maintenance....................... 956 1,587 2,543
Merger-related and asset impairment charges..... 15 15
Ceiling test charges............................ 1,035 1,035
Depreciation, depletion and amortization........ 624 443 1,067
Taxes, other than income taxes.................. 138 88 226
------ ------ --- -------
9,738 6,495 16,233
------ ------ --- -------
Operating income (loss)........................... (238) 873 635
Other income, net................................. 186 94 280
------ ------ --- -------
Income (loss) before interest, income taxes, and
minority interest............................... (52) 967 915
------ ------ --- -------
Interest and debt expense......................... 387 295 682
Minority interest................................. 12 16 28
Income tax expense (benefit)...................... (170) 166 (4)
------ ------ --- -------
229 477 706
------ ------ --- -------
Income (loss) from continuing operations before
preferred dividends of subsidiaries............. (281) 490 209
Preferred stock dividends of subsidiaries......... 25 7 32
------ ------ --- -------
Income (loss) from continuing operations.......... (306) 483 177
Dividends on preferred stock...................... 6 6
------ ------ --- -------
Income (loss) from continuing operations available
to common stockholders.......................... $ (306) $ 477 $ $ 171
====== ====== === =======
Basic earnings (loss) per share from continuing
operations available to common stockholders..... $(1.35) $ 0.35
====== =======
Diluted earnings (loss) per share from continuing
operations available to common stockholders..... $(1.35)(d) $ 0.34(d)
====== =======
Basic average common shares outstanding........... 226 268(e) 494
====== === =======
Diluted average common shares outstanding......... 237 (d) 268(e) 505(d)
====== === =======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma
Condensed Combined Financial Statements.
39
<PAGE> 41
UNAUDITED PRO FORMA CONDENSED COMBINED STATEMENT OF INCOME
FOR THE YEAR ENDED DECEMBER 31, 1997
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
<TABLE>
<CAPTION>
EL PASO
ENERGY COASTAL COMBINED
HISTORICAL HISTORICAL ADJUSTMENTS PRO FORMA
---------- ---------- ----------- ---------
<S> <C> <C> <C> <C>
Operating revenues................................ $10,015 $9,730 $ $19,745
------- ------ --- -------
Operating expenses
Cost of gas and other products.................. 7,308 6,864 14,172
Operation and maintenance....................... 966 1,610 2,576
Merger-related and asset impairment charges..... 50 50
Depreciation, depletion, and amortization....... 639 433 1,072
Taxes, other than income taxes.................. 138 90 228
------- ------ --- -------
9,101 8,997 18,098
------- ------ --- -------
Operating income.................................. 914 733 1,647
Other income, net................................. 94 119 213
------- ------ --- -------
Income before interest and income taxes........... 1,008 852 1,860
------- ------ --- -------
Interest and debt expense......................... 344 308 652
Income tax expense................................ 234 138 372
------- ------ --- -------
578 446 1,024
------- ------ --- -------
Income from continuing operations before preferred
dividends of subsidiaries....................... 430 406 836
Preferred stock dividends of subsidiaries......... 25 7 32
------- ------ --- -------
Income from continuing operations................. 405 399 804
Dividends on preferred stock...................... 17 17
------- ------ --- -------
Income from continuing operations available to
common stockholders............................. $ 405 $ 382 $ $ 787
======= ====== === =======
Basic earnings per share from continuing
operations available to common stockholders..... $ 1.81 $ 1.60
======= =======
Diluted earnings per share from continuing
operations available to common stockholders..... $ 1.77 $ 1.58
======= =======
Basic average common shares outstanding........... 224 268(e) 492
======= === =======
Diluted average common shares outstanding......... 229 268(e) 497
======= === =======
</TABLE>
See accompanying Notes to the Unaudited Pro Forma
Condensed Combined Financial Statements.
40
<PAGE> 42
NOTES TO UNAUDITED PRO FORMA CONDENSED COMBINED FINANCIAL STATEMENTS
(a) This amount reflects estimated transaction costs, including legal,
accounting, filing, printing and financial advisory services fees we
estimate we will incur in connection with the merger.
(b) This amount represents the income tax consequences of the $70 million of
estimated transaction costs associated with the merger, and was calculated
by multiplying $70 million by an assumed income tax rate of 38%.
(c) These numbers reflect the exchange in the merger of 1.23 shares of El Paso
Energy common stock for each outstanding share of Coastal's common stock and
each share of Coastal's Class A common stock, 9.133 shares of El Paso Energy
common stock for each outstanding share of Coastal's Series A and Series B
convertible preferred stock, 17.980 shares of El Paso Energy common stock
for each outstanding share of Coastal's Series C convertible preferred
stock, and the cancellation of $133 million of Coastal treasury stock. These
numbers also include the issuance of an estimated 5.3 million shares of El
Paso Energy common stock in exchange for Coastal stock options and
restricted stock. The number of shares issued for Coastal's stock options
and restricted stock was determined based on the fair value of these options
and shares and based on the average of the high and the low prices of El
Paso Energy's common stock on February 18, 2000, which was $37.50.
(d) As required by the accounting rules, we calculated diluted earnings (loss)
per common share for 1999 and 1998 by excluding from the number of common
shares outstanding, those securities which, if included, would have caused
us to show greater earnings or a lower loss per common share.
(e) We determined these adjustment amounts by multiplying the average
outstanding shares of Coastal's common stock, Class A common stock, and
convertible preferred stock for each period by the applicable exchange ratio
contemplated by the merger agreement. Each period also includes the issuance
of an estimated 5.3 million shares of El Paso Energy common stock for
Coastal's stock options and restricted stock.
41
<PAGE> 43
(c) Exhibits.
12.1 -- Ratio of earnings to combined fixed charges and preferred
stock dividends.
23.1 -- Consent of Deloitte & Touche LLP, Independent Auditors.
23.2 -- Consent of Huddleston & Co., Inc.
42
<PAGE> 44
SIGNATURE
Pursuant to the requirements of the Securities Exchange Act of 1934, as
amended, the registrant has duly caused this report to be signed on its behalf
by the undersigned thereunto duly authorized.
EL PASO ENERGY CORPORATION
By: /s/ JEFFREY I. BEASON
----------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Chief Accounting Officer)
Date: March 10, 2000
43
<PAGE> 45
INDEX TO EXHIBITS
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
- ------- -----------
<S> <C>
12.1 -- Ratio of earnings to combined fixed charges and preferred stock
dividends.
23.1 -- Consent of Deloitte & Touche LLP, Independent Auditors.
23.2 -- Consent of Huddleston & Co., Inc.
</TABLE>
44
<PAGE> 1
EXHIBIT 12.1
EL PASO ENERGY
COMPUTATION OF EARNINGS TO FIXED CHARGES AND
RATIO OF EARNINGS TO COMBINED FIXED CHARGES AND
PREFERRED AND PREFERENCE STOCK DIVIDEND REQUIREMENTS
<TABLE>
<CAPTION>
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
1999 1998 1997
-------- -------- ---------
<S> <C> <C> <C>
(DOLLARS IN MILLIONS)
Earnings
Pre-Tax income (loss) before preferred
dividends of subsidiary and cumulative
effect of accounting change $ (298) $ (451) $ 664
Minority interest in consolidated
subsidiaries 37 8 4
Income from equity investees (96) (84) (53)
------- ------- -------
Pre-Tax income (loss) from
continuing operations before minority
interest in consolidated subsidiaries
and income from equity investees (357) (527) 615
Fixed charges 552 453 381
Distributed income of equity investees 44 24 19
Capitalized interest (23) (9) (9)
Preferred stock dividend requirements of
consolidated subsidiaries (34) (40) (38)
Minority interest in consolidated
subsidiaries (37) (8) (4)
------- ------- -------
Totals earnings available for
fixed charges $ 145 $ (107) $ 964
======= ======= =======
Fixed charges
Interest and debt expense $ 470 $ 388 $ 332
Interest component of rent 12 13 11
Preferred stock dividend
requirement 34 40 38
Fixed charges portion of Minority
interest in consolidated
subsidiaries 36 12 --
------- ------- -------
Total fixed charges $ 552 $ 453 $ 381
======= ======= =======
Ratio of earnings to fixed charges (1) -- (2) -- (2) 2.53
======= ======= =======
</TABLE>
(1) The ratio of earnings to combined fixed charges and preferred and preference
stock dividend requirements for the periods presented is the same as the
ratio of earnings to fixed charges since El Paso Energy has no outstanding
preferred stock or preference stock and, therefore, no dividend
requirements.
(2) Earnings were inadequate to cover fixed charges by $407 million and $560
million for 1999 and 1998, respectively.
For purposes of calculating these ratios: (i)"fixed charges" represent
interest cost (exclusive of interest on rate refunds), amortization of debt
costs, the estimated portion of rental expense representing the interest
factor, pretax preferred stock dividend requirements of consolidated
subsidiaries, and minority interests in consolidated subsidiaries; and (ii)
"earnings" represent the aggregate of pre-tax income (loss) from continuing
operations before adjustment for minority interest in consolidated
subsidiaries and income from equity investees, fixed charges, and
distributed income of equity investees, less capitalized interest, minority
interest in consolidated subsidiaries, and preferred stock dividend
requirements of consolidated subsidiaries.
<PAGE> 1
EXHIBIT 23.1
INDEPENDENT AUDITORS' CONSENT
We consent to the incorporation by reference in the registration statements of
El Paso Energy Corporation on Form S-3 (File Nos. 333-42713, 333-61039 and
333-86049) and Form S-8 (File Nos. 333-26813, 333-26823, 333-26831, 33-46519,
33-49956, 33-51851, 33-57553, 333-75781, 333-78949, 333-78951, 333-78979,
333-94717 and 333-94719) of our report dated February 8, 2000, appearing in this
Current Report on Form 8-K under the Securities Exchange Act of 1934 of El Paso
Energy Corporation.
DELOITTE & TOUCHE LLP
Houston, Texas
March 8, 2000
<PAGE> 1
EXHIBIT 23.2
CONSENT OF HUDDLESTON & CO., INC.
We consent to the incorporation by reference in this Current Report of El Paso
Energy Corporation on Form 8-K of our report under the captions "Business-Gas
System Reserves" and "Supplemental Information on Oil and Gas Producing
Activities (Unaudited)" appearing in and incorporated by reference in the
Annual Report on Form 10-K of The Coastal Corporation for the year ended
December 31, 1999, and to the reference to us under the heading "Supplemental
Information on Oil and Gas Producing Activities (Unaudited)" in this Current
Report.
HUDDLESTON & CO., INC.
/s/ PETER D. HUDDLESTON
-----------------------------
Peter D. Huddleston, P.E.
President
Houston, Texas
March 8, 2000
