<PAGE> 1
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
---------------------
FORM 10-Q
(Mark One)
[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-14365
---------------------
EL PASO ENERGY CORPORATION
(Exact Name of Registrant as Specified in its Charter)
<TABLE>
<S> <C>
DELAWARE 76-0568816
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO ENERGY BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
</TABLE>
Registrant's Telephone Number, Including Area Code: (713) 420-2131
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate the number of shares outstanding of each of the issuer's classes
of common stock, as of the latest practicable date.
Common Stock, par value $3.00 per share. Shares outstanding on November 6,
2000: 233,968,803
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<PAGE> 2
PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS, EXCEPT PER COMMON SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
---------------- -----------------
2000 1999 2000 1999
------ ------ ------- ------
<S> <C> <C> <C> <C>
Operating revenues.......................................... $6,987 $3,262 $14,320 $8,137
------ ------ ------- ------
Operating expenses
Cost of gas and other products............................ 6,293 2,633 12,122 6,223
Operation and maintenance................................. 214 250 650 719
Merger-related costs and asset impairment charges......... -- 58 46 193
Ceiling test charges...................................... -- -- -- 352
Depreciation, depletion, and amortization................. 150 145 443 434
Taxes, other than income taxes............................ 34 32 111 108
------ ------ ------- ------
6,691 3,118 13,372 8,029
------ ------ ------- ------
Operating income............................................ 296 144 948 108
------ ------ ------- ------
Other income
Equity investment earnings................................ 63 33 101 82
Interest income........................................... 13 12 41 32
Net gain on sales of assets............................... 4 1 28 23
Other, net................................................ 11 16 21 38
------ ------ ------- ------
91 62 191 175
------ ------ ------- ------
Income before interest, income taxes, and other charges..... 387 206 1,139 283
------ ------ ------- ------
Interest and debt expense................................... 140 119 390 331
Minority interest........................................... 32 12 81 20
Income tax expense (benefit)................................ 71 29 213 (23)
------ ------ ------- ------
243 160 684 328
------ ------ ------- ------
Income (loss) before preferred dividends of subsidiary,
extraordinary gain, and
cumulative effect of accounting change.................... 144 46 455 (45)
Preferred stock dividends of subsidiary..................... 7 7 19 19
------ ------ ------- ------
Income (loss) before extraordinary gain and cumulative
effect of accounting change............................... 137 39 436 (64)
Extraordinary gain, net of income taxes..................... -- -- 89 --
Cumulative effect of accounting change, net of income
taxes..................................................... -- -- -- (13)
------ ------ ------- ------
Net income (loss)........................................... $ 137 $ 39 $ 525 $ (77)
====== ====== ======= ======
Comprehensive income (loss)................................. $ 132 $ 35 $ 518 $ (89)
====== ====== ======= ======
Basic earnings per common share
Income (loss) before extraordinary gain and cumulative
effect of accounting change............................. $ 0.59 $ 0.17 $ 1.89 $(0.28)
Extraordinary gain, net of income taxes................... -- -- 0.39 --
Cumulative effect of accounting change, net of income
taxes................................................... -- -- -- (0.06)
------ ------ ------- ------
Net income (loss)......................................... $ 0.59 $ 0.17 $ 2.28 $(0.34)
====== ====== ======= ======
Diluted earnings per common share
Income (loss) before extraordinary gain and cumulative
effect of accounting change............................. $ 0.57 $ 0.17 $ 1.83 $(0.28)
Extraordinary gain, net of income taxes................... -- -- 0.37 --
Cumulative effect of accounting change, net of income
taxes................................................... -- -- -- (0.06)
------ ------ ------- ------
Net income (loss)......................................... $ 0.57 $ 0.17 $ 2.20 $(0.34)
====== ====== ======= ======
Basic average common shares outstanding..................... 231 228 230 227
====== ====== ======= ======
Diluted average common shares outstanding................... 244 231 242 227
====== ====== ======= ======
Dividends declared per common share......................... $ 0.21 $ 0.20 $ 0.62 $ 0.60
====== ====== ======= ======
</TABLE>
See accompanying notes.
1
<PAGE> 3
EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
2000 1999
------------- ------------
<S> <C> <C>
ASSETS
Current assets
Cash and cash equivalents................................. $ 169 $ 545
Accounts and notes receivable, net........................ 3,099 1,662
Materials and supplies.................................... 76 74
Assets from price risk management activities.............. 2,202 233
Other..................................................... 311 397
------- -------
Total current assets.............................. 5,857 2,911
Property, plant, and equipment, net......................... 10,448 10,261
Investments in unconsolidated affiliates.................... 2,809 2,029
Assets from price risk management activities................ 1,575 413
Other....................................................... 1,057 1,043
------- -------
Total assets...................................... $21,746 $16,657
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts and notes payable................................ $ 3,266 $ 1,658
Short-term borrowings (including current maturities of
long-term debt)........................................ 1,825 1,344
Liabilities from price risk management activities......... 1,166 197
Other..................................................... 999 499
------- -------
Total current liabilities......................... 7,256 3,698
Long-term debt, less current maturities..................... 4,566 5,223
Noncurrent affiliated notes payable......................... 425 --
Deferred income taxes....................................... 1,962 1,738
Liabilities from price risk management activities........... 790 95
Other....................................................... 1,110 1,263
Commitments and contingencies
Company-obligated preferred securities of El Paso Energy
Capital Trust I and IV.................................... 625 325
Minority interest........................................... 1,581 1,368
Stockholders' equity
Common stock, par value $3 per share; authorized
750,000,000 shares; issued 242,218,516 and 238,542,335
shares, respectively................................... 727 716
Additional paid-in capital................................ 1,480 1,367
Retained earnings......................................... 1,590 1,207
Accumulated other comprehensive income.................... (36) (29)
Treasury stock (at cost); 8,558,324 and 8,947,565 shares,
respectively.................................... (269) (273)
Deferred compensation..................................... (61) (41)
------- -------
Total stockholders' equity........................ 3,431 2,947
------- -------
Total liabilities and stockholders' equity........ $21,746 $16,657
======= =======
</TABLE>
See accompanying notes.
2
<PAGE> 4
EL PASO ENERGY CORPORATION
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30,
------------------
2000 1999
------- -------
<S> <C> <C>
Cash flows from operating activities
Net income (loss)......................................... $ 525 $ (77)
Adjustments to reconcile net income (loss) to net cash
from operating activities
Depreciation, depletion, and amortization.............. 443 434
Ceiling test charges................................... -- 352
Deferred income tax expense (benefit).................. 234 (25)
Net gain on sale of assets............................. (28) (23)
Undistributed earnings in equity investees............. (65) (58)
Non-cash portion of merger-related charges............. -- 121
Extraordinary gain on sales............................ (149) --
Other.................................................. (15) (4)
Change in price risk management activities................ (1,467) (248)
Other working capital changes, net of non-cash
transactions........................................... 278 (49)
Other..................................................... (61) (48)
------- -------
Net cash provided by (used in) operating
activities....................................... (305) 375
------- -------
Cash flows from investing activities
Purchases of property, plant, and equipment............... (992) (719)
Net proceeds from the sale of assets...................... 500 27
Additions to investments.................................. (1,188) (841)
Proceeds from the sale of investments..................... 261 50
Change in cash deposited in escrow related to an equity
investee............................................... 24 (101)
Repayment of notes receivable from Chaparral.............. 647 --
Cash paid for acquisitions, net of cash received.......... (197) (141)
------- -------
Net cash used in investing activities............. (945) (1,725)
------- -------
Cash flows from financing activities
Net repayments of commercial paper and short-term notes... (121) (296)
Revolving credit borrowings............................... 545 532
Revolving credit repayments............................... (520) (922)
Net proceeds from the issuance of long-term debt.......... -- 1,781
Payments to retire long-term debt......................... (121) (186)
Increase in notes payable to Chaparral.................... 633 --
Increase (decrease) in notes payable to equity
investees.............................................. (15) 101
Net proceeds from issuance of Company-obligated preferred
securities of El Paso Energy Capital Trust IV.......... 293 --
Net proceeds from issuance of minority interests in
subsidiaries .......................................... 245 493
Dividends paid............................................ (140) (160)
Other..................................................... 75 16
------- -------
Net cash provided by financing activities......... 874 1,359
------- -------
Increase (decrease) in cash and cash equivalents............ (376) 9
Cash and cash equivalents
Beginning of period............................... 545 104
------- -------
End of period..................................... $ 169 $ 113
======= =======
</TABLE>
See accompanying notes.
3
<PAGE> 5
EL PASO ENERGY CORPORATION
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
Our 1999 Annual Report on Form 10-K includes a summary of our significant
accounting policies and other disclosures. You should read it in conjunction
with this Quarterly Report on Form 10-Q. The condensed consolidated financial
statements at September 30, 2000, and for the quarters and nine months ended
September 30, 2000 and 1999, are unaudited. The condensed consolidated balance
sheet at December 31, 1999, is derived from the audited financial statements.
These financial statements have been prepared pursuant to the rules and
regulations of the U.S. Securities and Exchange Commission and do not include
all disclosures required by accounting principles generally accepted in the
United States. In our opinion, we have made all adjustments, all of which are of
a normal, recurring nature, to fairly present our interim period results.
Information for interim periods may not necessarily indicate the results of
operations for the entire year due to the seasonal nature of our businesses. The
financial information for the quarter and nine months ended September 30, 1999,
includes the combined historical results of El Paso Energy Corporation and Sonat
Inc. to reflect our October 1999 merger with Sonat, which was accounted for as a
pooling of interests. The prior period information also includes
reclassifications which were made to conform to the current presentation. These
reclassifications have no effect on our reported net income or stockholders'
equity.
Ceiling Test Charges
Under the full cost method of accounting for natural gas and oil
properties, we perform quarterly ceiling tests to ensure that the carrying value
of natural gas and oil properties is not overstated. At March 31, 1999, our
capitalized costs exceeded this ceiling test limit by $352 million. This
write-down is included as ceiling test charges in our statements of income.
Cumulative Effect of Accounting Change
In the first quarter of 1999, we adopted the American Institute of
Certified Public Accountants Statement of Position 98-5, Reporting on the Costs
of Start-Up Activities. This statement required companies to expense start-up
and organization costs as incurred and expense any such costs that existed on
their balance sheet. We adopted the pronouncement effective January 1, 1999, and
reported a charge of $13 million, net of income taxes, as a cumulative effect of
an accounting change.
2. MERGERS AND ACQUISITIONS
Coastal
In January 2000, we entered into a definitive agreement to merge with The
Coastal Corporation. In the merger, we will convert each share of Coastal's
common stock and Class A common stock into 1.23 shares of our common stock. We
will exchange Coastal's outstanding convertible preferred stock for our common
stock on the same basis as if we had converted the preferred stock into
Coastal's common stock immediately prior to the merger. At September 30, 2000,
the total value of the transaction was approximately $23 billion, including $7
billion of assumed debt and preferred equity. We will account for the
transaction as a pooling of interests. On May 5, 2000, Coastal's stockholders
approved and adopted the merger agreement and our stockholders approved the
issuance of the common shares in connection with the merger. On July 26, 2000,
the Federal Energy Regulatory Commission (FERC) approved the merger. We expect
the transaction to close in the fourth quarter of 2000 once we have received all
necessary approvals, including the approval by the Federal Trade Commission
(FTC).
Coastal is a diversified energy holding company. It is engaged, through its
subsidiaries and joint ventures, in natural gas transmission, storage,
gathering, processing and marketing; natural gas and oil exploration and
production; and petroleum refining, marketing and distribution. It owns
interests in approximately
4
<PAGE> 6
18,000 miles of natural gas pipelines extending across the midwestern and the
Rocky Mountain areas of the United States and has proved reserves of 3.6 Tcfe.
Texas Midstream Operations
In January 2000, we entered into an agreement to purchase the natural gas
and natural gas liquids businesses of PG&E Gas Transmission, Texas Corporation,
and PG&E Gas Transmission Teco, Inc. The value of the transaction is
approximately $840 million, including assumed debt of $561 million. On October
25, 2000, we signed an FTC consent decree to allow us to complete this
acquisition. As part of the normal review process, the consent decree must be
approved by the FTC. We are also finalizing a similar agreement with the State
of Texas. We expect both agreements to become final and the transaction to close
in the fourth quarter of 2000. We will account for the transaction as a purchase
and will include the acquired assets and operations in our Field Services
segment. Some of these acquired operations may be appropriate for acquisition by
El Paso Energy Partners, the master-limited partnership of which we are the
general partner.
The businesses we are acquiring consist of 8,500 miles of intrastate
natural gas transmission pipelines, nine natural gas processing plants that
currently process 1.5 Bcf/d, and a 7.2 Bcf natural gas storage field. They also
own significant natural gas liquids pipelines and fractionation facilities.
Merger Costs
As we complete our proposed Coastal and Texas Midstream transactions and
begin to integrate the activities and operations of these businesses, we will
incur transaction, severance, transition, and other merger-related charges that
will have a significant impact on our results of operations and financial
position. These costs may include, but are not limited to, write-offs or
write-downs of duplicate assets, charges to relocate assets and employees,
contract termination charges, and charges to align accounting policies and
practices. During the third quarter of 2000, we announced a plan to combine our
pipeline operations with Coastal's pipeline operations. Under the consolidation
plan, El Paso Natural Gas Company's (EPNG) operations will be relocated from El
Paso, Texas to Colorado Springs, Colorado, and ANR Pipeline Company, a
subsidiary of Coastal, will be relocated from Detroit, Michigan, to Houston,
Texas. In addition to merger-related charges, we will be required to sell assets
as a condition of the FTC to completing these transactions.
Under current accounting rules, some of our merger-related costs will be
accrued at the merger date, while others will be expensed as incurred. All
accrued merger-related costs in a pooling of interests transaction, such as our
proposed merger with Coastal, will be recorded in our results of operations. In
a purchase transaction, such as our proposed Texas Midstream acquisition, these
costs will be included as a component of our purchase price.
In October 2000, we entered into an agreement with a third-party to sell
our interest in Oasis Pipeline Company. The sale is contingent upon the approval
of the FTC and the Texas Attorney General. We expect to incur a loss on this
transaction of approximately $20 million, net of income taxes. However, we do
not expect this sale or any other required sales, individually or in total, to
have a material adverse effect on our ongoing financial position, results of
operations, or cash flows.
3. EXTRAORDINARY GAIN
During the first quarter of 2000, we sold East Tennessee Natural Gas
Company and Sea Robin Pipeline Company to comply with an FTC order related to
our merger with Sonat. Net proceeds from the sales were $457 million and we
recognized an extraordinary gain of $89 million, net of income taxes of $60
million. In May 2000, we also disposed of our one-third interest in Destin
Pipeline Company to comply with the same FTC order. Net proceeds from this sale
were $159 million and no material gain or loss was recognized on the
transaction.
5
<PAGE> 7
4. EARNINGS PER SHARE
Our computations of basic and diluted earnings per common share are
presented below.
<TABLE>
<CAPTION>
QUARTER ENDED SEPTEMBER 30,
------------------------------------
2000 1999
--------------- ------------------
BASIC DILUTED BASIC DILUTED(1)
----- ------- ----- ----------
(IN MILLIONS, EXCEPT PER
COMMON SHARE AMOUNTS)
<S> <C> <C> <C> <C>
Income before extraordinary gain and cumulative effect of
accounting change........................................ $ 137 $ 137 $ 39 $ 39
Interest on trust preferred securities................... -- 3 -- --
----- ----- ----- -----
Adjusted net income........................................ $ 137 $ 140 $ 39 $ 39
===== ===== ===== =====
Average common shares outstanding.......................... 231 231 228 228
Effect of dilutive securities
Restricted stock......................................... -- -- -- --
Stock options............................................ -- 5 -- 3
Trust preferred securities............................... -- 8 -- --
----- ----- ----- -----
Average common shares outstanding.......................... 231 244 228 231
===== ===== ===== =====
Earnings per common share.................................. $0.59 $0.57 $0.17 $0.17
===== ===== ===== =====
</TABLE>
---------------
(1) Adding trust preferred securities to potential average common shares
outstanding would have increased earnings per share for the quarter ended
September 30, 1999. Therefore, the trust preferred securities and the
interest on these securities have not been factored into diluted earnings
per share for this period.
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
---------------------------
2000 1999(1)
---------------- -------
BASIC DILUTED BASIC
----- ------- -------
(IN MILLIONS, EXCEPT PER
COMMON SHARE AMOUNTS)
<S> <C> <C> <C>
Income (loss) before extraordinary gain and cumulative
effect of accounting change............................... $ 436 $ 436 $ (64)
Interest on trust preferred securities.................... -- 8 --
----- ----- ------
Adjusted income (loss) before extraordinary gain and
cumulative effect of accounting change................. 436 444 (64)
Extraordinary gain, net of income taxes................... 89 89 --
Cumulative effect of accounting change, net of income
taxes.................................................. -- -- (13)
----- ----- ------
Adjusted net income (loss).................................. $ 525 $ 533 $ (77)
===== ===== ======
Average common shares outstanding........................... 230 230 227
Effect of dilutive securities
Restricted stock.......................................... -- -- --
Stock options............................................. -- 4 --
Trust preferred securities................................ -- 8 --
----- ----- ------
Average common shares outstanding........................... 230 242 227
===== ===== ======
Earnings per common share
Adjusted income (loss) before extraordinary gain and
cumulative effect of accounting change................. $1.89 $1.83 $(0.28)
Extraordinary gain, net of income taxes................... 0.39 0.37 --
Cumulative effect of accounting change, net of income
taxes.................................................. -- -- (0.06)
----- ----- ------
Net income (loss)......................................... $2.28 $2.20 $(0.34)
===== ===== ======
</TABLE>
---------------
(1) Adding potentially dilutive securities to average common shares outstanding
for the nine months ended September 30, 1999, would have reduced the loss
per share. Therefore, the diluted loss per share was not presented for that
period.
6
<PAGE> 8
5. PROPERTY, PLANT, AND EQUIPMENT
Our property, plant, and equipment consisted of the following at September
30, 2000 and December 31, 1999:
<TABLE>
<CAPTION>
2000 1999
------- -------
(IN MILLIONS)
<S> <C> <C>
Property, plant, and equipment, at cost
Natural Gas Transmission.................................. $ 7,903 $ 8,121
Merchant Energy........................................... 248 200
International............................................. 313 316
Field Services............................................ 1,269 1,220
Production................................................ 5,811 5,415
Corporate and other....................................... 235 196
------- -------
15,779 15,468
Less accumulated depreciation and depletion................. 7,699 7,656
------- -------
8,080 7,812
Additional acquisition cost assigned to utility plant, net
of accumulated amortization............................... 2,368 2,449
------- -------
Total property, plant, and equipment, net................... $10,448 $10,261
======= =======
</TABLE>
6. DEBT AND OTHER CREDIT FACILITIES
Since the beginning of 2000, we:
- established, borrowed and repaid $250 million under a non-committed line
of credit;
- redeemed the Hattiesburg Gas Storage Company's 8.12% Secured Guaranteed
Notes due 2005 in an aggregate principal amount of $36 million;
- formed the El Paso Energy Capital Trust IV, a Delaware statutory business
trust, and issued $300 million variable rate preferred securities, as
described in Note 11;
- established a $1 billion commercial paper program for El Paso Energy in
addition to TGP's and EPNG's current programs;
- redeemed DeepTech's 12% Notes Due 2000, in an aggregate principal amount
of $82 million;
- received funds, which were used to pay down short-term borrowings and for
other corporate purposes, from Chaparral Investors as described in Note
9; and
- increased our credit facilities as described below.
In August 2000, we replaced our $1,250 million 364-day renewable revolving
credit and competitive advance facility with a $2 billion facility and our $750
million 3-year revolving credit and competitive advance facility with a $1
billion facility. EPNG and Tennessee Gas Pipeline Company (TGP) are also
designated borrowers under these new facilities. The interest rate for these
facilities varies and would have been LIBOR plus 50 basis points on September
30, 2000. The available credit under these facilities is expected to be used for
general corporate purposes including, but not limited to, supporting our
commercial paper programs.
7
<PAGE> 9
At September 30, 2000, our weighted average interest rate on short-term
borrowings was 6.8% and at December 31, 1999, it was 6.6%. We had the following
short-term borrowings, including current maturities of long-term debt, at
September 30, 2000 and December 31, 1999:
<TABLE>
<CAPTION>
2000 1999
------ ------
(IN MILLIONS)
<S> <C> <C>
Commercial paper............................................ $1,095 $1,217
Other credit facilities..................................... 60 35
Current maturities of long-term debt........................ 945 92
------ ------
2,100 1,344
Reclassification to long-term debt.......................... (275) --
------ ------
$1,825 $1,344
====== ======
</TABLE>
In October 2000, we issued $300 million ($296 million, net of issuance
costs) aggregate principal amount 8.05% medium-term notes due 2030. The proceeds
were used to repay $275 million of commercial paper borrowings with the
remainder used for other corporate purposes. As a result of this transaction, we
classified $275 million of short-term borrowings as long-term debt in our
September 30, 2000 balance sheet.
In November 2000, we terminated an interest rate swap with a notional
amount of $600 million and a termination date of July 2001. The swap was
originally put into place to swap the 6.625% fixed interest rate on our July
1999, $600 million aggregate principal Senior Notes due 2001 with a variable
interest rate. The termination of the swap did not have a material impact on our
financial results.
7. COMMITMENTS AND CONTINGENCIES
Rates and Regulatory Matters
Each of our pipeline systems has contracts covering a portion of its firm
transportation capacity with various terms of maturity, and each operates in
different markets and regions with different competitive and regulatory
pressures which can impact its ability to renegotiate and renew existing
contracts, or enter into new long-term firm transportation commitments.
Currently, approximately 70 percent of TGP's capacity is subject to firm
contracts, with an average term in excess of five years, that will expire after
2001. In March 2000, Southern Natural Gas Company (SNG) extended its firm
transportation and storage contracts until 2005 or later, substantially all of
which were at the maximum tariff rates allowed under its settlement. EPNG has 27
percent of its capacity subscribed under shorter-term contracts. On each of our
pipeline systems, we are aggressively pursuing the renegotiation and renewal of
expiring contracts, and the sale of excess capacity under firm transportation
arrangements. However, we are uncertain if future contracts will be on terms as
favorable to us as those that currently exist. Also, customers and other groups
may dispute new or renewed contracts. As a result, we cannot be sure that
regulators or other jurisdictional bodies will not intercede in our
re-contracting process and alter the ultimate outcome of our efforts.
All of EPNG's customers who were parties to its rate case settlement
participate in risk sharing provisions under the settlement. As of September 30,
2000, EPNG had unearned risk sharing revenues of $104 million and had $43
million remaining to be collected from customers under this provision. If
revenue from remarketing its relinquished capacity to customers exceeds certain
dollar levels specified in the risk sharing agreement, EPNG may be obligated to
refund a portion of the excess to customers. Under this provision, EPNG refunded
$15 million for 1999 revenues to customers and, as of September 30, 2000, has
reserved $9 million against 2000 revenues. The risk sharing provisions of the
rate settlement extend through 2003, at which time EPNG will be at risk for all
unsubscribed, excess capacity on its system.
As changes in the regulatory and economic environment evolve and our
pipelines continue to experience discounting of rates and unsubscribed capacity,
we will continue to evaluate the application of regulatory accounting
principles. Factors which could impact this assessment include an inability to
recover cost increases under rate caps and rate case moratoriums, an inability
to recover capitalized costs, including an adequate return on those costs
through the ratemaking process, excess capacity or significant discounting of
8
<PAGE> 10
rates in the markets we serve, and the impacts of ongoing initiatives in, and
deregulation of, the natural gas industry.
While we cannot predict with certainty the final outcome or timing of the
resolution of rates and regulatory matters, the outcome of our current
re-contracting and capacity subscription efforts, or the outcome of ongoing
industry trends and initiatives, we believe the ultimate resolution of these
issues will not have a material adverse effect on our financial position,
results of operations, or cash flows.
Legal Proceedings
In November 1993, TransAmerican Natural Gas Corporation filed a complaint
in a Texas state court against us which sought approximately $7.5 billion in
actual and punitive damages related to our 1990 settlement agreement with
TransAmerican and others. TransAmerican's complaint advanced ten causes of
action. Some of the causes of action were previously dismissed. Trial on the
remaining claims began on
May 1, 2000. During the trial commencement, all claims against all defendants
were settled. The settlement had no material adverse effect on our financial
position, results of operations, or cash flows.
In April 1996, a former employee of TransAmerican filed a related case in
Harris County, Texas, Vickroy E. Stone v. Godwin & Carlton, P.C., et al.,
seeking other damages in unspecified amounts related to litigation consulting
work allegedly performed for various entities, including EPNG, in cases
involving TransAmerican. In June 1998, the court granted our motion for summary
judgment and dismissed all claims in the Stone litigation. In May 2000, the
Texas Court of Appeals in Houston, Texas, upheld the trial court's rulings,
except for one claim relating to failure to pay Stone a bonus and, in September
2000, the Court of Appeals denied motions for rehearing. EPNG has filed a
petition for review with the Texas Supreme Court. Based on information available
at this time, we believe that the claims asserted against us in this case have
no factual or legal basis.
In February 1998, the United States and the State of Texas filed in a U.S.
District Court a Comprehensive Environmental Response, Compensation and
Liability Act (CERCLA) cost recovery action against fourteen companies,
including some of our current and former affiliates, relating to the Sikes
Disposal Pits Superfund Site located in Harris County, Texas. The suit claims
that the United States and the State of Texas have spent over $125 million in
remediating Sikes, and seeks to recover that amount plus interest from the
defendants to the suit. The Environmental Protection Agency (EPA) has recently
indicated that it may seek an additional amount up to $30 million plus interest
in indirect costs from the defendants under a new cost allocation methodology.
Defendants are challenging this allocation policy. Although an investigation
relating to Sikes is ongoing, we believe that the amount of material, if any,
disposed at Sikes by our former affiliates was small, possibly de minimis.
However, the plaintiffs have alleged that the defendants are each jointly and
severally liable for the entire remediation costs and have also sought a
declaration of liability for future response costs such as groundwater
monitoring.
TGP is a party in proceedings involving federal and state authorities
regarding the past use of a lubricant containing polychlorinated biphenyls
(PCBs) in its starting air systems. TGP has executed a consent order with the
EPA governing the remediation of some compressor stations and is working with
the EPA and the relevant states regarding those remediation activities. TGP is
also working with the Pennsylvania and New York environmental agencies regarding
remediation and post-remediation activities at the Pennsylvania and New York
stations.
In November 1988, the Kentucky environmental agency filed a complaint in a
Kentucky state court alleging that TGP discharged pollutants into the waters of
the state and disposed of PCBs without a permit. The agency sought an injunction
against future discharges, an order to remediate or remove PCBs, and a civil
penalty. TGP entered into agreed orders with the agency to resolve many of the
issues raised in the original allegations, has received water discharge permits
from the agency for its Kentucky compressor stations, and continues to work to
resolve the remaining issues. The relevant Kentucky compressor stations are
being characterized and remediated under the consent order with the EPA.
9
<PAGE> 11
A number of our subsidiaries are named defendants in actions brought by
Jack Grynberg on behalf of the U.S. Government under the False Claims Act.
Generally, these complaints allege an industry-wide conspiracy to under report
the heating value as well as the volumes of the natural gas produced from
federal and Native American lands, which deprived the U.S. Government of
royalties. We have also been named defendants in a similar class action suit,
Quinque Operating Company v. Gas Pipelines. This complaint alleges that the
defendants mismeasured natural gas volumes and heating content of natural gas on
non-federal and non-Native American lands. The Quinque complaint was transferred
to the same court handling the Grynberg complaint. We believe both complaints
are without merit.
In 1999, our production company was sued in Clint Miller, et. al. v. Sonat
Exploration Company, et. al., as a result of the blowout of a well in Bienville,
Louisiana which resulted in the deaths of seven individuals and injuries to four
others. The plaintiffs sought in excess of $5 billion in compensatory and
punitive damages against us and our co-defendents. As of September 30, 2000, we
have reached settlements with all the plaintiffs in this case. We are now taking
appropriate action and negotiating to recover the settlement amounts from other
defendants, non-operating working interest owners, and insurance carriers. At
this time, we believe it is probable that we will recover the amounts funded
under these settlements.
On August 19, 2000, a main transmission line owned and operated by EPNG
ruptured at the crossing of the Pecos River near Carlsbad, New Mexico resulting
in the deaths of twelve individuals. In September 2000, we were served with a
complaint for damages in Heady, et al. v. EPEC and EPNG, filed in state district
court in Harris County, Texas, brought on behalf of four persons. In October
2000, we were served with a complaint for damages in Smith v. EPEC and EPNG,
filed in federal district court in Albuquerque, New Mexico, brought on behalf of
another person. Both complaints are for damages for personal injuries and
wrongful death. Our response in each case is due November 24, 2000. Also, in
October 2000, Smith v. EPNG and EPEC was filed against us in state district
court in Harris County, Texas for damages. To date, the plaintiff has not served
us with this complaint. The National Transportation Safety Board is conducting
an investigation into the cause of the rupture.
In August 2000, the Liquidating Trustee in the bankruptcy of Power
Corporation of America (PCA) sued El Paso Merchant Energy (EPME), and several
other power traders, claiming EPME improperly cancelled its contracts with PCA
during the summer of 1998. The trustee alleges we breached contracts damaging
PCA in the amount of $120 million. We have entered into a joint defense
agreement with the other defendants. In a related matter, PCA appealed the
FERC's ruling that power marketers such as EPME did not have to give 60 days
notice to cancel its power contracts under the Federal Power Act. PCA has
appealed this decision to the United States Court of Appeals. Oral arguments in
this case are scheduled for January 16, 2001.
We are also a named defendant in numerous lawsuits and a named party in
numerous governmental proceedings arising in the ordinary course of our
business.
While the outcome of the matters discussed above cannot be predicted with
certainty, we do not expect the ultimate resolution of these matters to have a
material adverse effect on our financial position, results of operations, or
cash flows.
Environmental
We are subject to extensive federal, state, and local laws and regulations
governing environmental quality and pollution control. These laws and
regulations require us to remove or remedy the effect on the environment of the
disposal or release of specified substances at current and former operating
sites. As of September 30, 2000, we had reserved $235 million for expected
environmental costs.
In addition, we expect to make capital expenditures of approximately $3
million in 2000 and a total of $120 million for the years 2001 through 2007 for
environmental matters primarily relating to compliance with air regulations and
control of water discharges. Some of our subsidiaries have been designated, have
received notice that they could be designated, or have been asked for
information to determine whether they could be designated as a potentially
responsible party with respect to 29 active sites under CERCLA.
10
<PAGE> 12
It is possible that new information or future developments could require us
to reassess our potential exposure related to environmental matters. We may
incur significant costs and liabilities in order to comply with existing
environmental laws and regulations. It is also possible that other developments,
such as increasingly strict environmental laws and regulations, and claims for
damages to property, employees, other persons and the environment resulting from
our current or past operations, could result in substantial costs and
liabilities in the future. As this information becomes available, or other
relevant developments occur, we will adjust our accrual amounts accordingly.
While there are still uncertainties relating to the ultimate costs we may incur,
based upon our evaluation and experience to date, we believe the recorded
reserves are adequate.
8. SEGMENT INFORMATION
We segregate our business activities into five distinct operating segments:
- Natural Gas Transmission;
- Merchant Energy;
- International;
- Field Services; and
- Production.
These segments are strategic business units that provide a variety of
energy products and services. They are managed separately, as each business unit
requires different technology and marketing strategies. We measure segment
performance using earnings before interest and taxes (EBIT). At the beginning of
2000, we transferred EnCap Investments L.L.C. from the Field Services segment to
the Merchant Energy segment. All periods presented have been restated for this
change.
<TABLE>
<CAPTION>
AS OF AND FOR THE QUARTER ENDED SEPTEMBER 30, 2000
------------------------------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES PRODUCTION OTHER(A) TOTAL
------------ -------- ------------- -------- ---------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from external
customers.................. $ 331 $ 6,367 $ 20 $ 165 $ 100 $ 4 $ 6,987
Intersegment revenues........ 40 2 -- 24 34 (100) --
Operating income (loss)...... 182 53 (4) 22 52 (9) 296
EBIT......................... 207 81 24 30 52 (7) 387
Segment assets............... 8,661 6,838 1,726 1,683 1,713 1,125 21,746
</TABLE>
<TABLE>
<CAPTION>
AS OF AND FOR THE QUARTER ENDED SEPTEMBER 30, 1999
------------------------------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES PRODUCTION OTHER(A) TOTAL
------------ -------- ------------- -------- ---------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from external
customers.................. $ 380 $2,717 $ 14 $ 106 $ 27 $ 18 $ 3,262
Intersegment revenues........ 15 24 -- 18 103 (160) --
Merger-related costs and
asset impairment charges... 17 36 -- -- 5 -- 58
Operating income (loss)...... 151 (47) (10) 13 34 3 144
EBIT......................... 166 (33) 12 22 32 7 206
Segment assets............... 8,811 2,680 1,281 1,463 1,244 901 16,380
</TABLE>
---------------
(a) Includes corporate, eliminations, and other non-operating segment
activities.
11
<PAGE> 13
<TABLE>
<CAPTION>
AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2000
------------------------------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES PRODUCTION OTHER(A) TOTAL
------------ -------- ------------- -------- ---------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from external
customers.................. $1,071 $12,536 $ 75 $ 425 $ 207 $ 6 $14,320
Intersegment revenues........ 106 18 -- 57 195 (376) --
Merger-related costs and
asset impairment charges... -- -- -- -- -- 46 46
Operating income (loss)...... 575 246 (11) 65 159 (86) 948
EBIT......................... 621 283 69 85 159 (78) 1,139
Segment assets............... 8,661 6,838 1,726 1,683 1,713 1,125 21,746
</TABLE>
<TABLE>
<CAPTION>
AS OF AND FOR THE NINE MONTHS ENDED SEPTEMBER 30, 1999
------------------------------------------------------------------------------------
NATURAL
GAS MERCHANT FIELD
TRANSMISSION ENERGY INTERNATIONAL SERVICES PRODUCTION OTHER(A) TOTAL
------------ -------- ------------- -------- ---------- -------- -------
(IN MILLIONS)
<S> <C> <C> <C> <C> <C> <C> <C>
Revenues from external
customers.................. $1,179 $6,542 $ 43 $ 281 $ 80 $ 12 $ 8,137
Intersegment revenues........ 47 32 -- 56 260 (395) --
Merger-related costs and
asset impairment charges... 17 36 -- -- 5 135 193
Ceiling test charges......... -- -- -- -- 352 -- 352
Operating income (loss)...... 570 (38) (29) 35 (277) (153) 108
EBIT......................... 610 (20) 31 73 (278) (133) 283
Segment assets............... 8,811 2,680 1,281 1,463 1,244 901 16,380
</TABLE>
---------------
(a) Includes corporate, eliminations, and other non-operating segment
activities.
9. INVESTMENT IN UNCONSOLIDATED AFFILIATES
We hold investments in various affiliates which we account for using the
equity method of accounting. Summarized financial information for our
proportionate share of these investments is as follows:
<TABLE>
<CAPTION>
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
--------------- -------------
2000 1999 2000 1999
------ ------ ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Operating results data
Revenues and other income.............................. $325 $246 $813 $690
Costs and expenses..................................... 262 197 688 564
Income from continuing operations...................... 63 49 125 126
Net income............................................. 63 33 101 82
</TABLE>
East Asia Power
At December 31, 1999, we held a 92 percent ownership interest in East Asia
Power Resources Corporation. In March 2000, we converted our investment into a
50/50 joint venture with a third party. In the transaction, we received $85
million, net of transaction costs, and recognized a $20 million benefit. At the
time of the conversion, our investment in East Asia Power was $131 million. East
Asia Power owns and operates seven power generation facilities in the
Philippines and one plant in China, with a total generating capacity of 412
megawatts. Electric power generated by the facilities is supplied to a
diversified base of customers, including National Power Corporation, the
Philippine state-owned utility, private distribution companies and industrial
users.
12
<PAGE> 14
Chaparral Investors
During the first quarter of 2000, Chaparral completed its acquisitions of
several domestic non-utility generation assets including equity interests in
eleven natural gas-fired combined generation facilities in California, two
natural gas-fired electric generation plants located in Dartmouth, Massachusetts
and Pawtucket, Rhode Island, and all the outstanding shares of Bonneville
Pacific Corporation, which owns a 50 percent interest in a power generation
facility. Chaparral also acquired several operating companies which provide the
services required to operate and maintain these newly acquired facilities and a
natural gas service company which provides fuel procurement services to eight of
Chaparral's natural gas-fired combined generation facilities in California.
Chaparral acquired these assets from us in exchange for notes payable in the
amount of $385 million. In March 2000, Chaparral's third-party investor
increased its overall investment in Chaparral by $1,027 million. The proceeds
were used by Chaparral to repay $647 million of notes from us, to make a $278
million contribution to a trust as provided in the Chaparral agreement, to
invest in a note with us, and to fund transaction costs. Also, in March 2000, we
issued mandatorily convertible preferred stock to a trust we control. Upon the
occurrence of certain negative events, the trustee of the trust may be required
to remarket this preferred stock on terms that are designed to generate $1
billion to distribute to the third party investor.
Under our management agreement with Chaparral, we earn a performance-based
management fee. We are also reimbursed for expenses we incur on behalf of
Chaparral. For 2000, our management fee related to Chaparral has been
established at $100 million. This fee includes an $80 million performance-based
component and a $20 million reimbursement for costs we will incur on behalf of
Chaparral. This fee is collected and recognized ratably throughout the year as
management services are provided.
El Paso Energy Partners
During the third quarter of 2000, El Paso Energy Partners, the
master-limited partnership in which we are the general partner, completed a
public offering of 4.6 million common units. The offering reduced our common
unit ownership interest from 32.5 percent to 28.4 percent. This transaction had
no effect on our general partner interest or our non-managing member interest.
Also, in the third quarter, we received $170 million of Series B 10% Cumulative
Redeemable Preference Units in exchange for the transfer to the partnership of
the natural gas storage businesses of Crystal Gas Storage, Inc., our wholly
owned subsidiary.
10. MINORITY INTEREST
In May 2000, we formed Clydesdale Associates, L.P., a limited partnership,
and several other separate legal entities to generate funds to invest in capital
projects and other assets. We contributed $55 million into this structure and a
third-party investor contributed $250 million. The third-party investor is
entitled to an adjustable preferred return derived from the net income of the
partnership. Clydesdale used the proceeds to invest in a note receivable with
us. The third-party's contributions are collateralized by production properties,
rental income from real estate assets, and notes receivable from us. We have the
option to acquire the third-party's interest in the structure at any time prior
to May 2005. If we do not exercise this option, or if the agreement is not
extended, the note receivable will mature and a portion of the proceeds will be
used to redeem the third-party investor's interest in the structure. The assets,
liabilities, and operations of the partnership and the other entities involved
in this transaction are included in our consolidated financial statements. The
third-party investor's interest is included as minority interest in our balance
sheets and their preferred return is included in minority interest in our
statements of income.
11. COMPANY-OBLIGATED PREFERRED SECURITIES
In May 2000, we formed El Paso Energy Capital Trust IV which issued $300
million of preferred securities to a third party investor. These preferred
securities pay cash distributions at a floating rate equal to the three-month
LIBOR plus 75 basis points. As of September 30, 2000, the floating rate was
7.43%. These preferred securities must be redeemed by Trust IV no later than
November 30, 2003. Proceeds from the sale of the securities were used by Trust
IV to purchase a series of our floating rate senior debentures whose yield and
maturity terms mirror those of Trust IV's preferred securities. The sole assets
of Trust IV are these floating rate senior debentures. We guarantee the
obligations of Trust IV related to its preferred securities. At the time Trust
IV issued the preferred securities, we also agreed to issue $300 million of
equity securities, including, but not limited to, our common stock in one or
more public offerings prior to May 31, 2003.
13
<PAGE> 15
12. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Accounting for Derivative Instruments and Hedging Activities
In June of 1998, the Financial Accounting Standards Board (FASB) issued
Statement of Financial Accounting Standards (SFAS) No. 133, Accounting for
Derivative Instruments and Hedging Activities. In June of 1999, the FASB
extended the adoption date of SFAS No. 133 through the issuance of SFAS No. 137,
Deferral of the Effective Date of SFAS 133. In June 2000, the FASB issued SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities, which also amended SFAS No. 133. SFAS No. 133, and its amendments
and interpretations, establishes accounting and reporting standards for
derivative instruments, including derivative instruments embedded in other
contracts, and derivative instruments used for hedging activities. It will
require that we measure all derivative instruments at their fair value, and
classify them as either assets or liabilities on our balance sheet, with a
corresponding offset to income or other comprehensive income depending on their
designation, their intended use, or their ability to qualify as hedges under the
standard.
We will adopt SFAS No. 133 beginning January 1, 2001, and will apply the
standard to all derivative instruments that exist on that date, except for
derivative instruments embedded in other contracts. As provided for in SFAS No.
133, we will apply the provisions of the standard to derivative instruments
embedded in other contracts issued, acquired, or substantively modified after
December 31, 1998.
We use a variety of derivative instruments to conduct both energy trading
activities and to hedge risks associated with commodity prices, foreign
currencies and interest rates. The derivative instruments we use in commodity
trading activities are currently recorded at their fair value in our financial
statements under the provisions of Emerging Issues Task Force Issue No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities. As a result, SFAS No. 133 will not impact our accounting for these
instruments.
Based on commodity prices and quarter ending interest rates existing at
September 30, 2000, we estimate that the impact on our financial statements of
adopting SFAS No. 133 on January 1, 2001, will be to record a charge to other
comprehensive income which could range from $450 to $500 million, and a charge
to income which could range from $0 to $30 million. These amounts will be
classified as a cumulative effect of a change in accounting principle. The
majority of the initial charge to other comprehensive income relates to
contracts to sell the natural gas we expect to produce through the end of 2001.
The amounts that will be recorded upon adoption of SFAS No. 133 may
materially differ from those disclosed above since the amounts recorded will be
based on the fair values that exist at the adoption date. In addition, further
interpretation and guidance from the standard setting groups on the proper
application of SFAS No. 133's provisions may also substantially alter these
estimates.
Revenue Recognition in Financial Statements
In December 1999, the Securities and Exchange Commission issued Staff
Accounting Bulletin (SAB) No. 101, Revenue Recognition in Financial Statements,
to provide guidance for revenue recognition issues and disclosure requirements.
SAB No. 101 offers guidelines, examples, and explanations for certain matters
relating to the recognition of revenue and will be effective for us in the
fourth quarter of 2000. We do not believe the adoption of SAB No. 101 will have
a material impact on our financial position, results of operations, or cash
flows.
Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities
In September 2000, the FASB issued SFAS No. 140, Accounting for Transfers
and Servicing of Financial Assets and Extinguishments of Liabilities, which
replaces SFAS No. 125. This statement revises the standards for accounting for
securitizations and other transfers of financial assets and collateral and
requires certain disclosures, but carries over most of SFAS No. 125's provisions
without reconsideration. This standard has various effective dates, the earliest
of which is for fiscal years ending after December 15, 2000. We are currently
evaluating the effects of this pronouncement.
14
<PAGE> 16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS(1)
The information contained in this section updates, and should be read in
conjunction with, information disclosed in Part II, Items 7, 7A, and 8, in our
Annual Report on Form 10-K for the year ended December 31, 1999, in addition to
the financial statements and notes presented in Item 1 of this Quarterly Report
on Form 10-Q.
RECENT DEVELOPMENTS
MERGER WITH THE COASTAL CORPORATION
In January 2000, we entered into a definitive agreement to merge with
Coastal. In the merger, we will convert each share of Coastal's common stock and
Class A common stock into 1.23 shares of our common stock. We will exchange
Coastal's outstanding convertible preferred stock for our common stock on the
same basis as if we had converted the preferred stock into Coastal's common
stock immediately prior to the merger. At September 30, 2000, the total value of
the transaction was approximately $23 billion, including $7 billion of assumed
debt and preferred equity. We will account for the transaction as a pooling of
interests. On May 5, 2000, Coastal's stockholders approved and adopted the
merger agreement and our stockholders approved the issuance of the common shares
in connection with the merger. On July 26, 2000, the FERC approved the merger.
We expect the transaction to close in the fourth quarter of 2000 once we have
received all necessary approvals, including the approval by the FTC.
Coastal is a diversified energy holding company. It is engaged, through its
subsidiaries and joint ventures, in natural gas transmission, storage,
gathering, processing and marketing; natural gas and oil exploration and
production; and petroleum refining, marketing and distribution. It owns
interests in approximately 18,000 miles of natural gas pipelines extending
across the midwestern and the Rocky Mountain areas of the United States and has
proved reserves of 3.6 Tcfe.
PURCHASE OF TEXAS MIDSTREAM OPERATIONS
In January 2000, we entered into an agreement to purchase the natural gas
and natural gas liquids businesses of PG&E Gas Transmission, Texas Corporation,
and PG&E Gas Transmission Teco, Inc. The value of the transaction is
approximately $840 million, including assumed debt of $561 million. On October
25, 2000, we signed an FTC consent decree to allow us to complete this
acquisition. As part of the normal review process, the consent decree must be
approved by the FTC. We are also finalizing a similar agreement with the State
of Texas. We expect both agreements to become final and the transaction to close
in the fourth quarter of 2000. We will account for the transaction as a purchase
and will include the acquired assets and operations in our Field Services
segment. Some of these acquired operations may be appropriate for acquisition by
El Paso Energy Partners, the master-limited partnership of which we are the
general partner.
The businesses we are acquiring consist of 8,500 miles of intrastate
natural gas transmission pipelines, nine natural gas processing plants that
currently process 1.5 Bcf/d, and a 7.2 Bcf natural gas storage field. They also
own significant natural gas liquids pipelines and fractionation facilities.
---------------
(1) As generally used in the energy industry and in this document, the following
terms have the following meanings:
<TABLE>
<S> <C> <C> <C> <C> <C>
Bbl = barrel MMBtu = million British thermal units
BBtu/d = billion British thermal units per day Mcf = thousand cubic feet
Bcf/d = billion cubic feet per day MMcf/d = million cubic feet per day
MBbls = thousand barrels Tcfe = trillion cubic feet of gas equivalents
</TABLE>
When we refer to natural gas and oil in "equivalents," we are doing so to
compare quantities of oil with quantities of natural gas or to express these
different commodities in a common unit. In calculating equivalents, we use a
generally recognized standard in which one Bbl is equal to approximately six
Mcf.
15
<PAGE> 17
MERGER COSTS
As we complete our proposed Coastal and Texas Midstream transactions and
begin to integrate the activities and operations of these businesses, we will
incur transaction, severance, transition, and other merger-related charges that
will have a significant impact on our results of operations and financial
position. These costs may include, but are not limited to, write-offs or
write-downs of duplicate assets, charges to relocate assets and employees,
contract termination charges, and charges to align accounting policies and
practices. During the third quarter of 2000, we announced a plan to combine our
pipeline operations with Coastal's pipeline operations. Under the consolidation
plan, EPNG's operations will be relocated from El Paso, Texas to Colorado
Springs, Colorado, and ANR Pipeline Company, a subsidiary of Coastal, will be
relocated from Detroit, Michigan, to Houston, Texas. In addition to
merger-related charges, we will be required to sell assets as a condition of the
FTC to completing these transactions.
Under current accounting rules, some of our merger-related costs will be
accrued at the merger date, while others will be expensed as incurred. All
accrued merger-related costs in a pooling of interests transaction, such as our
proposed merger with Coastal, will be recorded in our results of operations. In
a purchase transaction, such as our proposed Texas Midstream acquisition, these
costs will be included as a component of our purchase price.
In October 2000, we entered into an agreement with a third-party to sell
our interest in Oasis Pipeline Company. The sale is contingent upon the approval
of the FTC and the Texas Attorney General. We expect to incur a loss on this
transaction of approximately $20 million, net of income taxes. However, we do
not expect this sale or any other required sales, individually or in total, to
have a material adverse effect on our ongoing financial position, results of
operations, or cash flows.
RESULTS OF OPERATIONS
For the quarter ended September 30, 2000, our net income was $137 million
versus $39 million for the same period in 1999. EBIT was $387 million for the
quarter ended September 30, 2000, versus $206 million for the same period in
1999. Growth in earnings of our non-regulated segments contributed to the
increase in consolidated EBIT and amounted to 47 percent of our overall third
quarter 2000 EBIT. Partially offsetting this increase were higher interest and
debt expense and income taxes in the third quarter of 2000.
For the nine months ended September 30, 2000, our net income was $525
million versus a net loss of $77 million for the same period in 1999. EBIT was
$1,139 million for the nine months ended September 30, 2000 versus $283 million
for the same period in 1999, with our non-regulated business units comprising
approximately 45 percent of our 2000 total. Stronger performance in all of our
non-regulated segments and a gain on the sales of our East Tennessee and Sea
Robin pipeline systems in compliance with the FTC order related to our 1999
merger with Sonat contributed to the increase. The variance was further impacted
by a first quarter 1999 ceiling test write-down in our Production segment under
the full cost accounting method and merger costs related to Sonat in the second
quarter of 1999. These increases were offset by higher interest and debt expense
and income taxes during 2000.
16
<PAGE> 18
SEGMENT RESULTS
Our September 30, 1999, financial information includes the combined
historical results of El Paso Energy and Sonat to reflect our October 1999
merger with Sonat, which was accounted for as a pooling of interests.
<TABLE>
<CAPTION>
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------- ---------------
2000 1999 2000 1999
----- ----- ------ -----
(IN MILLIONS)
<S> <C> <C> <C> <C>
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Natural Gas Transmission................................... $207 $166 $ 621 $ 610
Merchant Energy............................................ 81 (33) 283 (20)
International.............................................. 24 12 69 31
Field Services............................................. 30 22 85 73
Production................................................. 52 32 159 (278)
---- ---- ------ -----
Segment total............................................ 394 199 1,217 416
Corporate, net............................................. (7) 7 (78) (133)
---- ---- ------ -----
Consolidated EBIT........................................ $387 $206 $1,139 $ 283
==== ==== ====== =====
</TABLE>
NATURAL GAS TRANSMISSION
<TABLE>
<CAPTION>
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------ ------------------
2000 1999 2000 1999
------- ------- ------- -------
(IN MILLIONS, EXCEPT VOLUME AMOUNTS)
<S> <C> <C> <C> <C>
Operating revenues.................................. $ 371 $ 395 $ 1,177 $ 1,226
Operating expenses.................................. (189) (244) (602) (656)
Other income........................................ 25 15 46 40
------- ------- ------- -------
EBIT.............................................. $ 207 $ 166 $ 621 $ 610
======= ======= ======= =======
Throughput volumes (BBtu/d)
TGP............................................... 4,226 4,197 4,651 4,845
EPNG.............................................. 4,617 3,992 4,185 3,956
SNG............................................... 1,848 2,562 2,231 2,698
Equity investments (our share).................... 827 1,378 1,074 1,120
------- ------- ------- -------
Total throughput.......................... 11,518 12,129 12,141 12,619
======= ======= ======= =======
</TABLE>
Third Quarter 2000 Compared to Third Quarter 1999
Operating revenues for the quarter ended September 30, 2000, were $24
million lower than the same period in 1999. This decrease was due to the impact
of our sale of the East Tennessee Pipeline and Sea Robin systems in the first
quarter of 2000. Also contributing to the decrease was the impact of customer
settlements in 2000 on TGP, lower rates as a result of SNG's May 2000 rate case
settlement, and the elimination of the minimum bill provisions on our Elba
Island facility that the FERC approved for reactivation. These decreases were
partially offset by higher revenues from transportation and other services on
each of our transmission systems and revenues from our January 2000 acquisition
of Crystal Gas Storage, Inc. In August 2000, we transferred Crystal's gas
storage businesses to El Paso Energy Partners in exchange for preference units
of the Partnership.
Operating expenses for the quarter ended September 30, 2000, were $55
million lower than the same period in 1999. The decrease was due to cost
efficiencies following our merger with Sonat, the sales of our East Tennessee
Pipeline and Sea Robin systems, and lower system operating costs. Also
contributing to the decrease was the resolution of a contested rate matter with
a customer of EPNG, revised estimates of regulatory recoveries on EPNG, and
impairment of several SNG expansion projects, all occurring in the third quarter
of 1999. The decrease was partially offset by higher utility costs in the third
quarter of 2000.
17
<PAGE> 19
Other income for the quarter ended September 30, 2000, was $10 million
higher than the same period in 1999 due to increased equity earnings from Citrus
as a result of a one-time gain recorded in 2000 and a gain on the sale of
non-pipeline assets during 2000. The increase was partially offset by lower
allowance for funds used during construction.
Nine Months Ended 2000 Compared to Nine Months Ended 1999
Operating revenues for the nine months ended September 30, 2000, were $49
million lower than the same period in 1999. This decrease was due to the impact
of our sales of the East Tennessee Pipeline and Sea Robin systems in the first
quarter of 2000 as well as the favorable resolution of regulatory issues in 1999
on TGP. Also contributing to the decrease were lower rates as a result of SNG's
May 2000 rate case settlement, lower revenues from relinquished capacity on
EPNG, the impact of customer settlements in 2000 on TGP, and the elimination of
the minimum bill provisions on our Elba Island facility. These decreases were
partially offset by higher revenues from transportation and other services
provided on each of our transmission systems and revenues from our January 2000
acquisition of Crystal Gas Storage, Inc.
Operating expenses for the nine months ended September 30, 2000, were $54
million lower than the same period in 1999. The decrease was due to cost
efficiencies following our merger with Sonat, the sales of our East Tennessee
Pipeline and Sea Robin systems in March 2000, lower system operating costs, and
the favorable impact of FERC's authorization to reactivate SNG's Elba Island
facility in the first quarter of 2000. Also contributing to the decrease was the
resolution of a contested rate matter with a customer of EPNG, revised estimates
of regulatory recoveries on EPNG, and the impairment of several SNG expansion
projects, all occurring in the third quarter of 1999. The decrease was partially
offset by resolutions of TGP's customer imbalance issues in 1999 as well as the
impact of unfavorable producer settlements in the second quarter of 2000 on
EPNG. Additionally, higher utility costs in the third quarter of 2000 also
offset the decrease.
Other income for the nine months ended September 30, 2000, was $6 million
higher than the same period in 1999. The increase was due to higher earnings on
Citrus as a result of a one-time gain recorded in 2000 as well as gains on the
sale of non-pipeline assets in the third quarter of 2000. The increase was
partially offset by the favorable settlement of a regulatory issue in 1999, the
elimination of an asset for the future recovery of costs of the Elba Island
facility, and a lower allowance for funds used during construction.
MERCHANT ENERGY
<TABLE>
<CAPTION>
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
-------------- ---------------
2000 1999 2000 1999
---- ---- ---- -----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Gross margin and other revenues................ $ 78 $ 18 $315 $ 82
Operating expenses............................. (25) (65) (69) (120)
Other income................................... 28 14 37 18
---- ---- ---- -----
EBIT......................................... $ 81 $(33) $283 $ (20)
==== ==== ==== =====
</TABLE>
Third Quarter 2000 Compared to Third Quarter 1999
Total gross margin and other revenues for the quarter ended September 30,
2000, was $60 million higher than the same period in 1999. Commodity market and
trading margins were higher as a result of power price volatility, particularly
in the western United States, asset management fees earned from Chaparral, which
began operations during the latter part of 1999, income from transactions
originated in the third quarter of 2000, and margins on the West Georgia power
project, which began operating in June 2000. The West Georgia plant is a
seasonal peaking facility. These increases were partially offset by transactions
originating in the third quarter of 1999. Other revenues increased in 2000 as a
result of higher earnings from EnCap's financial services activities in the
quarter.
Operating expenses for the quarter ended September 30, 2000 were $40
million lower than the same period in 1999. The decrease was due to
reimbursements in 2000 of general and administrative costs relating to Chaparral
as well as impairments of tangible and intangible assets in the third quarter of
1999 related to our merger with Sonat.
18
<PAGE> 20
Other income for the quarter ended September 30, 2000, was $14 million
higher than the same period in 1999 due to an increase in equity earnings from
power projects and investments, primarily CE Generation.
Nine Months Ended 2000 Compared to Nine Months Ended 1999
Total gross margin and other revenues for the nine months ended September
30, 2000, was $233 million higher than the same period in 1999. Commodity
marketing and trading margins increased due to second and third quarter 2000
price volatility in gas and power markets, asset management fees earned from
Chaparral, which began operations during the latter part of 1999, higher income
from power transactions originated in 2000, and margins on the West Georgia
power project. These increases were partially offset by transactions originating
in 1999. Other revenues increased due to the acquisition of EnCap in March 1999.
Our commodity marketing and trading margins during 2000 have been
significantly impacted by price volatility in the energy markets and the growth
of our trading portfolio in 2000. During periods of high price volatility,
market opportunities exist that can enhance trading portfolio values and improve
operating results. For the remainder of 2000, we anticipate the commodity prices
will continue to be volatile, although not necessarily at the same levels or in
the same markets as we experienced in the second and third quarters. Our margins
are also impacted by asset management fees and cost reimbursements from
Chaparral. These fees should continue through the remainder of 2000. Chaparral
asset management fees for 2001 are expected to be higher than 2000, and such
fees will be finalized in the fourth quarter.
Operating expenses for the nine months ended September 30, 2000, were $51
million lower than the same period in 1999. The decrease was due to
reimbursements in 2000 of general and administrative costs relating to Chaparral
and impairments of tangible and intangible assets in the third quarter of 1999
related to our merger with Sonat.
Other income for the nine months ended September 30, 2000, was $19 million
higher than the same period in 1999 due to higher earnings from power projects
and investments, primarily CE Generation.
INTERNATIONAL
<TABLE>
<CAPTION>
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------- -------------
2000 1999 2000 1999
----- ----- ----- -----
(IN MILLIONS)
<S> <C> <C> <C> <C>
Operating revenues....................................... $ 20 $ 14 $ 75 $ 43
Operating expenses....................................... (24) (24) (86) (72)
Other income............................................. 28 22 80 60
---- ---- ---- ----
EBIT................................................... $ 24 $ 12 $ 69 $ 31
==== ==== ==== ====
</TABLE>
Third Quarter 2000 Compared to Third Quarter 1999
Operating revenues for the quarter ended September 30, 2000, were $6
million higher than the same period in 1999. The increase was due to higher
revenues from the Rio Negro project consolidated in August 1999, offset by
slightly lower revenues from the Manaus project in 2000.
Operating expenses for the quarter ended September 30, 2000, were unchanged
compared to the same period in 1999. Higher costs from the Rio Negro project and
higher project development and general and administrative costs were offset by
lower costs from the Manaus project during 2000.
Other income for the quarter ended September 30, 2000, was $6 million
higher than the same period in 1999. Higher equity earnings from South American
and European investments in 2000, earnings on the Hanwha power generation
project in South Korea acquired in the third quarter of 2000, and higher
interest income were partially offset by gains recorded on the CAPSA equity swap
in the third quarter of 1999.
Nine Months Ended 2000 Compared to Nine Months Ended 1999
Operating revenues for the nine months ended September 30, 2000, were $32
million higher than the same period in 1999. Higher revenues from the Rio Negro
and Manaus projects were partially offset by lower revenues from the EMA
project.
19
<PAGE> 21
Operating expenses for the nine months ended September 30, 2000, were $14
million higher than the same period in 1999. Higher project development and
general and administrative costs as well as higher operating costs from the Rio
Negro project were partially offset by lower operating costs on the Manaus and
EMA projects.
Other income for the nine months ended September 30, 2000, was $20 million
higher than the same period in 1999. The increase was due to the benefit
realized from the formation of our East Asia Power joint venture in March 2000,
a settlement received from our Indonesian project in May 2000, and 2000 equity
swap gains recognized on our CAPSA project, as well as higher interest income.
These increases were partially offset by lower equity earnings from investments
in various international projects, primarily our investment in East Asia Power
in Asia.
FIELD SERVICES
<TABLE>
<CAPTION>
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------- -----------------
2000 1999 2000 1999
------- ------- ------- -------
(IN MILLIONS, EXCEPT VOLUME AMOUNTS)
<S> <C> <C> <C> <C>
Gathering and treating margin.............................. $ 45 $ 41 $ 134 $ 121
Processing margin.......................................... 19 11 51 32
------ ------ ------ ------
Total gross margin............................... 64 52 185 153
Operating expenses......................................... (42) (39) (120) (118)
Other income............................................... 8 9 20 38
------ ------ ------ ------
EBIT..................................................... $ 30 $ 22 $ 85 $ 73
====== ====== ====== ======
Throughput volumes (Bbtu/d)
Gathering and treating................................... 2,871 3,194 2,952 3,270
====== ====== ====== ======
Processing............................................... 1,125 997 1,079 1,036
====== ====== ====== ======
Throughput rates ($/MMBtu)
Gathering and treating................................... $ 0.17 $ 0.14 $ 0.17 $ 0.14
====== ====== ====== ======
Processing............................................... $ 0.17 $ 0.13 $ 0.17 $ 0.11
====== ====== ====== ======
</TABLE>
Third Quarter 2000 Compared to Third Quarter 1999
Total gross margin for the quarter ended September 30, 2000, was $12
million higher than the same period in 1999. Gathering and treating margins
increased due to higher average gathering rates, which are substantially indexed
to natural gas prices, and higher average condensate prices, offset by lower
gathering and treating volumes. The increase was also partially offset by the
March 2000 sale of El Paso Intrastate-Alabama (EPIA) to El Paso Energy Partners.
Processing margins increased due to higher liquids prices in 2000 and the
acquisition, in April 2000, of an interest in the Indian Basin processing
assets.
Operating expenses for the quarter ended September 30, 2000, were $3
million higher than the same period in 1999. The increase is due to higher
depreciation and amortization from assets transferred to Field Services from
EPNG following a FERC order, partially offset by lower operating costs following
the sale of EPIA to El Paso Energy Partners. The increase was also partially
offset by cost recoveries from managed facilities in the third quarter of 2000.
Nine Months Ended 2000 Compared to Nine Months Ended 1999
Total gross margin for the nine months ended September 30, 2000, was $32
million higher than the same period in 1999. Gathering and treating margins
increased due to higher average gathering rates, which are substantially indexed
to natural gas prices, and higher average condensate prices, offset by lower
gathering and treating volumes. The increase was also partially offset by the
sale of EPIA to El Paso Energy Partners. Processing margins increased due to
higher liquids prices in 2000 and the acquisition, in April 2000, of an interest
in the Indian Basin processing assets.
20
<PAGE> 22
Operating expenses for the nine months ended September 30, 2000, were $2
million higher than the same period in 1999 due to higher depreciation and
amortization from assets transferred to Field Services from EPNG following a
FERC order. The increase was partially offset by lower costs for labor and
benefits and operating leases as well as cost recoveries from managed
facilities.
Other income for the nine months ended September 30, 2000, was $18 million
lower than the same period in 1999. The decrease was primarily due to net gains
in 1999 from the sale of our interest in Viosca Knoll, partially offset by a
2000 gain on the sale of a gathering facility in Colorado.
PRODUCTION
<TABLE>
<CAPTION>
QUARTER NINE MONTHS
ENDED ENDED
SEPTEMBER 30, SEPTEMBER 30,
----------------- -----------------
2000 1999 2000 1999
------- ------- ------- -------
(IN MILLIONS, EXCEPT VOLUME AMOUNTS)
<S> <C> <C> <C> <C>
Natural gas............................................ $ 108 $ 104 $ 324 $ 275
Oil, condensate, and liquids........................... 21 26 72 61
Other.................................................. 5 -- 6 4
------- ------- ------- -------
Total operating revenues..................... 134 130 402 340
Operating expenses..................................... (82) (96) (243) (617)
Other expenses......................................... -- (2) -- (1)
------- ------- ------- -------
EBIT................................................. $ 52 $ 32 $ 159 $ (278)
======= ======= ======= =======
Volumes
Natural gas sales (MMcf)............................. 46,297 47,858 139,972 140,714
======= ======= ======= =======
Oil, condensate, and liquid sales (MBbls)............ 1,222 1,500 3,965 4,301
======= ======= ======= =======
Weighted average realized prices
Natural gas ($/Mcf).................................. $ 2.32 $ 2.18 $ 2.31 $ 1.96
======= ======= ======= =======
Oil, condensate, and liquids ($/Bbl)................. $ 17.62 $ 17.62 $ 18.20 $ 14.35
======= ======= ======= =======
</TABLE>
Third Quarter 2000 Compared to Third Quarter 1999
Operating revenues for the quarter ended September 30, 2000, were $4
million higher than the same period in 1999. The increase was due to higher
realized prices for natural gas partially offset by lower volumes. Realized
prices were affected by hedges in place during the period.
We engage in hedging activities on our oil and natural gas production to
obtain more determinable cash flows and to mitigate the risk of downward price
movements on sales of these commodities. We do this through oil and natural gas
swaps.
Operating expenses for the quarter ended September 30, 2000, were $14
million lower than the same period in 1999. The operating expenses reflected
decreased labor costs following our 1999 merger with Sonat as well as asset
impairment charges in the third quarter of 1999, offset by higher depletion
rates during 2000.
Nine Months Ended 2000 Compared to Nine Months Ended 1999
Operating revenues for the nine months ended September 30, 2000, were $62
million higher than the same period in 1999. The increase was due to higher
realized prices for natural gas and oil, condensate and liquids. Realized prices
were affected by hedges in place during the period.
Operating expenses for the nine months ended September 30, 2000, were $374
million lower than the same period in 1999. The decrease was due to full cost
ceiling test charges incurred in the first quarter of 1999, decreased labor
costs following our 1999 merger with Sonat, and asset impairment charges in the
third quarter of 1999. The decrease was partially offset by higher depletion
rates and severance taxes in 2000.
21
<PAGE> 23
CORPORATE, NET
Third Quarter 2000 Compared to Third Quarter 1999
Corporate expenses for the quarter ended September 30, 2000, were $14
million higher than the same period in 1999. The increase was primarily due to
higher equity based compensation costs and lower interest income in the third
quarter of 2000.
Nine Months Ended 2000 Compared to Nine Months Ended 1999
Corporate expenses for the nine months ended September 30, 2000, were $55
million lower than the same period in 1999. The decrease was primarily due to
the receipt of interest income on a note from the Chaparral project and higher
1999 costs related to our merger with Sonat, partially offset by 2000 costs
incurred related to our pending merger with Coastal.
We expect to incur additional merger-related costs throughout the remainder
of 2000 and into 2001 as a result of our pending merger with Coastal.
INTEREST AND DEBT EXPENSE
Interest and debt expense for the quarter and nine months ended September
30, 2000, was $21 million and $59 million higher than the same periods in 1999
primarily due to higher average borrowings for ongoing capital projects,
investment programs, and operating requirements. We anticipate interest and debt
expense will continue to exceed last year's levels throughout the remainder of
2000.
MINORITY INTEREST
Minority interest for the quarter and nine months ended September 30, 2000,
was $20 million and $61 million higher than the same periods in 1999 due to the
formation of Sabine River Investors, L.L.C. in June 1999 and the formation of
Clydesdale Associates, L.P. and Capital Trust IV in May 2000.
INCOME TAX EXPENSE (BENEFIT)
The effective income tax rates for the quarter and nine months ended
September 30, 2000, were 33% and 32%. The effective tax rates were lower than
the statutory rate of 35% due to foreign income that is not taxed in the U.S.,
exclusions of part of the earnings of our unconsolidated equity investees where
we anticipate receiving dividends, and the utilization of loss carryforwards.
This decrease was offset by foreign income taxed at foreign tax rates higher
than U.S. tax rates.
The effective income tax rates for the quarter and nine months ended
September 30, 1999, were 39% and 34%. For both periods, the difference from the
35% statutory rate was primarily due to merger-related costs, offset by foreign
income that is not taxable in the U.S. and exclusions of part of the earnings
from unconsolidated equity investees where we anticipate receiving dividends.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash used in our operating activities was $305 million for the nine
months ended September 30, 2000, compared to net cash provided of $375 million
for the same period of 1999. The decrease was primarily attributable to
increases in our price risk management activities, higher cash payments in 2000
for charges related to the Sonat merger, higher interest payments in 2000, and
higher cash payments for legal settlements.
CASH FROM INVESTING ACTIVITIES
Net cash used in our investing activities was $945 million for the nine
months ended September 30, 2000. Our investing activities consisted of additions
to joint ventures and equity investments, including an increase in our Chaparral
equity investment, the purchase of an additional 18.5% interest in CAPSA, and
the purchase of an investment in Hanwha Energy Co., Ltd. Other additions
included the acquisitions of Crystal Gas Storage, Inc. and Enerplus Global
Management, the All American pipeline assets, an interest in the Indian
22
<PAGE> 24
Basin gas processing plant assets, and expenditures for expansion and
construction projects. Investment activities also included proceeds from the
sales of our East Tennessee pipeline system, Sea Robin pipeline system, El Paso
Intrastate-Alabama pipeline system, our one-third interest in the Destin
pipeline system, the proceeds from the formation of our East Asia Power joint
venture, and the repayment of a note receivable from Chaparral.
CASH FROM FINANCING ACTIVITIES
Net cash provided by our financing activities was $874 million for the nine
months ended September 30, 2000. Cash provided from our financing activities
included the issuance of preferred securities of El Paso Energy Capital Trust
IV, an interest in Clydesdale Associates, L.P., and notes related to Chaparral.
During 2000, we repaid short-term borrowings, paid dividends, and retired
long-term debt.
In August 2000, we replaced our $1,250 million 364-day renewable revolving
credit and competitive advance facility with a $2 billion facility and our $750
million 3-year revolving credit and competitive advance facility with a $1
billion facility. EPNG and TGP are also designated borrowers under these new
facilities. The interest rate for these facilities varies and would have been
LIBOR plus 50 basis points on September 30, 2000. The available credit under
these facilities is expected to be used for general corporate purposes
including, but not limited to, supporting our commercial paper programs.
In October 2000, we issued $300 million ($296 million, net of issuance
costs) aggregate principal amount 8.05% medium-term notes due 2030. The proceeds
were used to repay $275 million of commercial paper borrowings with the
remainder used for other corporate purposes.
The following table reflects quarterly dividends declared and paid on our
common stock:
<TABLE>
<CAPTION>
AMOUNT PER
DECLARATION DATE COMMON SHARE PAYMENT DATE TOTAL AMOUNT
---------------- ------------ ------------ -------------
(IN MILLIONS)
<S> <C> <C> <C>
October 20, 1999........................ $0.200 January 11, 2000 $46
January 17, 2000........................ $0.206 April 3, 2000 $47
April 27, 2000.......................... $0.206 July 3, 2000 $47
July 10, 2000........................... $0.206 October 2, 2000 $48
</TABLE>
In October 2000, we declared a quarterly dividend of $0.206 per share on
our common stock, payable on January 2, 2001, to stockholders of record on
November 30, 2000. Also during the nine months ended September 30, 2000, we paid
dividends of $19 million on the 8 1/4% cumulative preferred stock, Series A of
our subsidiary, El Paso Tennessee Pipeline Co.
We expect that future funding for capital expenditures, acquisitions, other
investing activities, long-term debt retirements, payments of dividends and
other financing expenditures will be provided by internally generated funds,
commercial paper issuances, available capacity under existing credit facilities,
and the issuance of new long-term debt, trust securities, or equity.
COMMITMENTS AND CONTINGENCIES
See Note 7, which is incorporated herein by reference.
OTHER
As part of our ongoing strategy, we may consider assets we acquire or
intend to acquire, as well as assets we own, as potential acquisitions by El
Paso Energy Partners. Any of these transactions would be subject to the approval
of El Paso Energy Partners' unitholders or board of directors, and, as
necessary, appropriate regulatory bodies, as well as subject to a fairness
opinion of a third party on the price to be paid by the partnership.
Since the beginning of 2000, we transferred our El Paso Intrastate-Alabama
pipeline system and our natural gas storage businesses of Crystal Gas Storage,
Inc. to El Paso Energy Partners. The total consideration for these transactions
was $197 million.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Note 12, which is incorporated herein by reference.
23
<PAGE> 25
CAUTIONARY STATEMENT REGARDING
FORWARD-LOOKING STATEMENTS
We have made statements in this document that constitute forward-looking
statements, as that term is defined in the Private Securities Litigation Reform
Act of 1995. These statements are subject to risks and uncertainties.
Forward-looking statements include information concerning possible or assumed
future results of operations. These statements may relate to information or
assumptions about:
- earnings per share;
- capital and other expenditures;
- dividends;
- financing plans;
- capital structure;
- cash flow;
- pending legal proceedings and claims, including environmental matters;
- future economic performance;
- operating income;
- cost savings;
- management's plans; and
- goals and objectives for future operations.
Important factors that could cause actual results to differ materially from
estimates or projections contained in forward-looking statements include, among
others, the following:
- the ability to successfully integrate PG&E's Texas midstream and
Coastal's operations;
- the increasing competition within our industry;
- the timing and extent of changes in commodity prices for natural gas and
power;
- the uncertainties associated with customer contract expirations on our
pipeline systems;
- the potential contingent liabilities and tax liabilities related to our
acquisitions;
- the political and economic risks associated with current and future
operations in foreign countries; and
- the conditions of equity and other capital markets.
These risk factors are more fully described in our other filings with the
Securities and Exchange Commission, including our Annual Report on Form 10-K for
the year ended December 31, 1999.
24
<PAGE> 26
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
This information updates, and should be read in conjunction with,
information disclosed in Part II, Item 7A in our Annual Report on Form 10-K for
the year ended December 31, 1999, in addition to the information presented in
Items 1 and 2 of this Quarterly Report on Form 10-Q.
Presented below is our estimated potential one-day unfavorable impact on
EBIT, as measured by Value at Risk (VAR) calculations, related to contracts held
for trading purposes. The average VAR value is calculated from the month end
values for the first nine months during 2000. The high and low VAR values
represent the highest and lowest month end values during 2000. The VAR
calculation is directly impacted by higher volatility in natural gas and power
prices. Assuming a confidence level of 95 percent and a one-day holding period,
our estimated potential one-day unfavorable impact on EBIT is as follows:
<TABLE>
<CAPTION>
QUARTER ENDED NINE MONTHS ENDED
SEPTEMBER 30, 2000 SEPTEMBER 30, 2000
------------------ ------------------
(IN MILLIONS)
<S> <C> <C>
Highest............................................ $13 $15
Lowest............................................. $ 7 $ 2
Average............................................ $10 $ 7
</TABLE>
Our VAR was approximately $3 million at December 31, 1999, and
approximately $10 million at September 30, 2000.
In May 2000, we exercised our right to terminate our CAPSA Equity Swap
Agreement and to purchase the counterparty's 18.5 percent interest in CAPSA's
common stock secured under the swap agreement for approximately $127 million.
During the third quarter of 2000, we entered into additional hedge
transactions relating to our Production segment activities and entered into
transactions to protect pricing differentials on certain pipeline capacity
contracts.
In November, we terminated an interest rate swap with a notional amount of
$600 million and a termination date of July 2001. The swap was originally put
into place to swap the 6.625% fixed interest rate on our July 1999, $600 million
aggregate principal Senior Notes due 2001 with a variable interest rate. The
termination of the swap did not have a material impact on our financial results.
We have entered into additional Canadian dollar foreign currency forward
purchase and sale contracts subsequent to December 31, 1999. The following table
summarizes the notional amounts, average settlement rates, and fair value for
Canadian dollar foreign currency forward purchase and sale contracts as of
September 30, 2000:
<TABLE>
<CAPTION>
NOTIONAL AMOUNT FAIR VALUE
IN FOREIGN AVERAGE IN
CURRENCY SETTLEMENT U.S. DOLLARS
(IN MILLIONS) RATES (IN MILLIONS)
--------------- ---------- -------------
<S> <C> <C> <C> <C>
Canadian Dollars Purchase.............................. (604) 0.675 $(4)
465 0.673 5
Sell..................................
---
$ 1
===
</TABLE>
The following table summarizes Canadian dollar foreign currency forward
purchase and sale contracts by expected maturity dates along with annual
anticipated cash flow impacts as of September 30, 2000:
<TABLE>
<CAPTION>
EXPECTED MATURITY DATES
----------------------------------------------
2000 2001 2002 2003 2004 THEREAFTER TOTAL
---- ----- ---- ---- ---- ---------- -----
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Canadian Dollars Purchase.............. $(9) $(209) $(74) $(70) $(23) $(23) $(408)
11 162 58 60 22 -- 313
Sell..................
--- ----- ---- ---- ---- ---- -----
$ 2 $ (47) $(16) $(10) $ (1) $(23) $ (95)
Net cash flow
effect................
=== ===== ==== ==== ==== ==== =====
</TABLE>
25
<PAGE> 27
PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Financial Information, Note 7, which is incorporated herein by
reference.
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS
None.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY-HOLDERS
None.
ITEM 5. OTHER INFORMATION
None.
ITEM. 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
1.A -- Restated Distribution Agreement dated October 5, 2000
between the Registrant, Banc of America Securities LLC,
ABN AMRO Incorporated and Chase Securities Inc. (Exhibit
1.1 to the El Paso Energy Form 8-K dated October 18,
2000)
1.B -- Terms Agreement dated October 5, 2000, between the
Registrant, Banc of America Securities LLC, ABN AMRO
Incorporated and Chase Securities Inc. (Exhibit 1.2 to
the El Paso Energy Form 8-K dated October 18, 2000)
1.C -- Calculation Agent Agreement dated October 5, 2000,
between the Registrant and The Chase Manhattan Bank.
(Exhibit 1.3 to the El Paso Energy Form 8-K dated October
18, 2000)
4.E -- Indenture dated as of May 10, 1999, by and between the
Registrant and The Chase Manhattan Bank, as Trustee.
(Exhibit 4.1 to the El Paso Energy Form 8-K dated May 10,
1999)
4.J -- Form of 8.050% Medium Term Senior Note. (Exhibit 4.2 to
the El Paso Energy Form 8-K dated October 18, 2000)
*10.A -- $2,000,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated August 4, 2000, by and
among El Paso Energy Corporation, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company, the several
banks and other financial institutions from time to time
parties to the Agreement, The Chase Manhattan Bank,
Citibank N.A. and ABN Amro Bank, N.V. as co-documentation
agents for the Lenders and Bank of America, N.A. as
syndication agent for the Lenders.
</TABLE>
26
<PAGE> 28
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
*10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive
Advance Facility Agreement dated August 4, 2000, by and
among El Paso Energy Corporation, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company, the several
banks and other financial institutions from time to time
parties to the Agreement, The Chase Manhattan Bank,
Citibank N.A. and ABN Amro Bank, N.V. as co-documentation
agents for the Lenders and Bank of America, N.A. as
syndication agent for the Lenders.
*27 -- Financial Data Schedule
</TABLE>
Undertaking
The undersigned hereby undertakes, pursuant to Regulation S-K, Item
601(b), paragraph (4)(iii), to furnish to the U.S. Securities and Exchange
Commission, upon request, all constituent instruments defining the rights
of holders of long-term debt of El Paso Energy and its consolidated
subsidiaries not filed herewith for the reason that the total amount of
securities authorized under any of such instruments does not exceed 10
percent of the total consolidated assets of El Paso Energy and its
consolidated subsidiaries.
b. Reports on Form 8-K
We filed a current report on Form 8-K, dated July 28, 2000, announcing that
we received approval from FERC on our anticipated merger with Coastal.
We filed a current report on Form 8-K, dated August 18, 2000, updating pro
forma financial statements relating to the proposed merger with The Coastal
Corporation.
We filed a current report on Form 8-K, dated October 18, 2000, filing
exhibits in connection with an offering of medium term notes pursuant to a
Registration Statement on Form S-3.
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<PAGE> 29
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.
EL PASO ENERGY CORPORATION
Date: November 8, 2000 /s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
Date: November 8, 2000 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Chief Accounting Officer)
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<PAGE> 30
INDEX TO EXHIBITS
Each exhibit identified below is filed as a part of this report. Exhibits
not incorporated by reference to a prior filing are designated by an asterisk;
all exhibits not so designated are incorporated herein by reference to a prior
filing as indicated.
<TABLE>
<CAPTION>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
<C> <S>
1.A -- Restated Distribution Agreement dated October 5, 2000
between the Registrant, Banc of America Securities LLC,
ABN AMRO Incorporated and Chase Securities Inc. (Exhibit
1.1 to the El Paso Energy Form 8-K dated October 18,
2000)
1.B -- Terms Agreement dated October 5, 2000, between the
Registrant, Banc of America Securities LLC, ABN AMRO
Incorporated and Chase Securities Inc. (Exhibit 1.2 to
the El Paso Energy Form 8-K dated October 18, 2000)
1.C -- Calculation Agent Agreement dated October 5, 2000,
between the Registrant and The Chase Manhattan Bank.
(Exhibit 1.3 to the El Paso Energy Form 8-K dated October
18, 2000)
4.E -- Indenture dated as of May 10, 1999, by and between the
Registrant and The Chase Manhattan Bank, as Trustee.
(Exhibit 4.1 to the El Paso Energy Form 8-K dated May 10,
1999)
4.J -- Form of 8.050% Medium Term Senior Note. (Exhibit 4.2 to
the El Paso Energy Form 8-K dated October 18, 2000)
*10.A -- $2,000,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement dated August 4, 2000, by and
among El Paso Energy Corporation, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company, the several
banks and other financial institutions from time to time
parties to the Agreement, The Chase Manhattan Bank,
Citibank N.A. and ABN Amro Bank, N.V. as co-documentation
agents for the Lenders and Bank of America, N.A. as
syndication agent for the Lenders.
*10.B -- $1,000,000,000 3-Year Revolving Credit and Competitive
Advance Facility Agreement dated August 4, 2000, by and
among El Paso Energy Corporation, El Paso Natural Gas
Company, Tennessee Gas Pipeline Company, the several
banks and other financial institutions from time to time
parties to the Agreement, The Chase Manhattan Bank,
Citibank N.A. and ABN Amro Bank, N.V. as co-documentation
agents for the Lenders and Bank of America, N.A. as
syndication agent for the Lenders.
*27 -- Financial Data Schedule
</TABLE>
