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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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 JUNE 30, 2001
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 1-9864
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EL PASO TENNESSEE PIPELINE CO.
(Exact Name of Registrant as Specified in its Charter)
<Table>
DELAWARE 76-0233548
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification No.)
EL PASO BUILDING
1001 LOUISIANA STREET
HOUSTON, TEXAS 77002
(Address of Principal Executive Offices) (Zip Code)
</Table>
Registrant's Telephone Number, Including Area Code: (713) 420-2600
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 $.01 per share. Shares outstanding on August 6,
2001: 1,971
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PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO TENNESSEE PIPELINE CO.
CONDENSED CONSOLIDATED STATEMENTS OF INCOME
(IN MILLIONS)
(UNAUDITED)
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------- -----------------
2001 2000 2001 2000
------ ------ ------- ------
Operating revenues...................................... $8,050 $3,980 $18,162 $6,847
------ ------ ------- ------
Operating expenses
Cost of natural gas and other products................ 7,568 3,541 17,059 6,036
Operation and maintenance............................. 179 129 372 262
Merger-related costs and asset impairments............ 43 -- 72 --
Depreciation, depletion, and amortization............. 52 55 126 113
Taxes, other than income taxes........................ 18 16 42 35
------ ------ ------- ------
7,860 3,741 17,671 6,446
------ ------ ------- ------
Operating income........................................ 190 239 491 401
------ ------ ------- ------
Other income
Earnings from unconsolidated affiliates............... 36 21 57 18
Other, net............................................ 50 11 74 56
------ ------ ------- ------
86 32 131 74
------ ------ ------- ------
Income before interest, income taxes, and extraordinary
items................................................. 276 271 622 475
------ ------ ------- ------
Non-affiliated interest and debt expense................ 37 33 78 72
Affiliated interest expense, net........................ 44 24 109 35
Income taxes............................................ 75 74 147 120
------ ------ ------- ------
156 131 334 227
------ ------ ------- ------
Income before extraordinary items....................... 120 140 288 248
Extraordinary items, net of income taxes................ 38 -- 38 77
------ ------ ------- ------
Net income.............................................. $ 158 $ 140 $ 326 $ 325
====== ====== ======= ======
</Table>
See accompanying notes.
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EL PASO TENNESSEE PIPELINE CO.
CONDENSED CONSOLIDATED BALANCE SHEETS
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
-------- ------------
ASSETS
Current assets
Cash and cash equivalents................................. $ 193 $ 179
Accounts and notes receivable, net
Customer............................................... 3,214 2,828
Affiliates............................................. 1,020 194
Other.................................................. 308 262
Inventory................................................. 59 84
Assets from price risk management activities.............. 2,139 4,283
Deferred charges.......................................... 226 423
Other..................................................... 291 160
------- -------
Total current assets.............................. 7,450 8,413
------- -------
Property, plant, and equipment, at cost
Pipelines................................................. 2,604 2,554
Power facilities.......................................... 506 351
Gathering and processing systems.......................... 2,473 2,543
Other..................................................... 101 96
------- -------
5,684 5,544
Less accumulated depreciation, depletion, and
amortization.............................................. 958 843
------- -------
4,726 4,701
Additional acquisition cost assigned to utility plant,
net....................................................... 2,281 2,287
------- -------
Total property, plant, and equipment, net......... 7,007 6,988
------- -------
Other assets
Investments in unconsolidated affiliates.................. 2,064 2,070
Assets from price risk management activities.............. 1,942 1,638
Other..................................................... 864 356
------- -------
4,870 4,064
------- -------
Total assets...................................... $19,327 $19,465
======= =======
</Table>
See accompanying notes.
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EL PASO TENNESSEE PIPELINE CO.
CONDENSED CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
(IN MILLIONS, EXCEPT SHARE AMOUNTS)
(UNAUDITED)
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
-------- ------------
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities
Accounts and notes payable
Trade.................................................. $ 4,180 $ 3,156
Affiliates............................................. 3,126 3,760
Other.................................................. 234 179
Short-term borrowings (including current maturities of
long-term debt)........................................ 213 356
Liabilities from price risk management activities......... 1,408 2,880
Other..................................................... 672 701
------- -------
Total current liabilities......................... 9,833 11,032
------- -------
Long-term debt, less current maturities..................... 1,576 1,845
------- -------
Other
Liabilities from price risk management activities......... 1,519 898
Deferred income taxes..................................... 1,758 1,647
Other..................................................... 1,028 838
------- -------
4,305 3,383
------- -------
Commitments and contingencies
Minority interests.......................................... 179 51
------- -------
Stockholders' equity
Preferred stock, Series A, no par; authorized 20,000,000
shares; issued 6,000,000 shares; stated at liquidation
value.................................................. 300 300
Common stock, par value $0.01 per share; authorized
100,000 shares; issued 1,971 shares.................... -- --
Additional paid-in capital................................ 1,964 1,962
Retained earnings......................................... 1,263 949
Accumulated other comprehensive income.................... (93) (57)
------- -------
Total stockholders' equity........................ 3,434 3,154
------- -------
Total liabilities and stockholders' equity........ $19,327 $19,465
======= =======
</Table>
See accompanying notes.
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EL PASO TENNESSEE PIPELINE CO.
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
(IN MILLIONS)
(UNAUDITED)
<Table>
<Caption>
SIX MONTHS ENDED
JUNE 30,
------------------
2001 2000
------- -----
Cash flows from operating activities
Net income................................................ $ 326 $ 325
Adjustments to reconcile net income to net cash from
operating activities
Depreciation, depletion, and amortization.............. 126 113
Deferred income tax expense............................ 160 45
Extraordinary items.................................... (59) (128)
Net gain on the sale of assets......................... -- (23)
Undistributed earnings in unconsolidated affiliates.... (10) 3
Non-cash portion of merger-related costs and asset
impairments........................................... 38 --
Other.................................................. (19) --
Working capital changes, net of non-cash transactions..... 2,776 (606)
Other..................................................... (146) 15
------- -----
Net cash provided by (used in) operating
activities....................................... 3,192 (256)
------- -----
Cash flows from investing activities
Purchases of property, plant, and equipment............... (252) (219)
Net proceeds from the sale of assets...................... 113 418
Additions to investments.................................. (219) (501)
Proceeds from the sale of investments..................... 5 89
Other..................................................... 13 24
------- -----
Net cash used in investing activities............. (340) (189)
------- -----
Cash flows from financing activities
Net borrowings (repayments) of commercial paper........... (47) (514)
Payments to retire long-term debt......................... (364) (1)
Net change in other affiliated advances payable........... (2,406) 831
Increase in notes payable to unconsolidated affiliates.... -- 67
Decrease in notes payable to unconsolidated affiliates.... (9) (82)
Dividends paid............................................ (12) (12)
Capital contributions..................................... -- 160
------- -----
Net cash provided by (used in) financing
activities....................................... (2,838) 449
------- -----
Increase in cash and cash equivalents....................... 14 4
Cash and cash equivalents
Beginning of period....................................... 179 32
------- -----
End of period............................................. $ 193 $ 36
======= =====
</Table>
See accompanying notes.
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EL PASO TENNESSEE PIPELINE COMPANY
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
AND CHANGES IN ACCUMULATED OTHER COMPREHENSIVE INCOME
(IN MILLIONS)
(UNAUDITED)
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------- -----------------
COMPREHENSIVE INCOME 2001 2000 2001 2000
-------------------- ----- ----- ------- ------
Net income.................................................. $158 $140 $ 326 $325
Foreign currency translation adjustments.................. (12) (4) (20) (2)
Unrealized net gains from cash flow hedging activity
Cumulative-effect transition adjustment (net of tax of
$66)................................................. -- -- (154) --
Reclassification of initial cumulative-effect
transition adjustment at original value (net of tax
of $5 and $66)....................................... 12 -- 128 --
Additional reclassification adjustments for changes in
initial value to settlement date (net of tax of $66
and $66)............................................. 98 -- 98 --
Unrealized mark-to-market gains arising during period
(net of tax of $84 and $61).......................... 195 -- (88) --
---- ---- ----- ----
Comprehensive income........................................ $451 $136 $ 290 $323
==== ==== ===== ====
</Table>
<Table>
<Caption>
ACCUMULATED OTHER COMPREHENSIVE INCOME 2001 2000
-------------------------------------- ----- ----
Beginning balances as of December 31, 2000 and 1999......... $ (57) $(29)
Foreign currency translation adjustments.................. (20) (1)
Unrealized net gains (losses) from cash flow hedging
activity
Cumulative-effect transition adjustment, net of
taxes................................................. (154) --
Reclassification of initial cumulative-effect
transition adjustment at original value, net of
taxes................................................. 128 --
Additional reclassification adjustments for changes in
initial value to settlement date, net of taxes........ 98 --
Unrealized mark-to-market losses arising during period,
net of taxes.......................................... (88) --
----- ----
Balance as of June 30, ..................................... $ (93) $(30)
===== ====
</Table>
See accompanying notes.
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EL PASO TENNESSEE PIPELINE CO.
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)
1. BASIS OF PRESENTATION
Our 2000 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 financial statements as of June 30,
2001, and for the quarters and six months ended June 30, 2001 and 2000, are
unaudited. The balance sheet as of December 31, 2000, is derived from the
audited balance sheet included in our Annual Report on Form 10-K. 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 (except for merger-related costs and asset impairments as
discussed in Note 2), 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 prior period
information also includes reclassifications which were made to conform to the
current period presentation. These reclassifications have no effect on our
reported net income or stockholders' equity.
Our accounting policies are consistent with those discussed in our Form
10-K, except as discussed below. You should refer to the Form 10-K for a further
discussion of those policies.
Accounting for Price Risk Management Activities
Our business activities expose us to a variety of risks, including
commodity price risk, interest rate risk, and foreign currency risk. Our
corporate risk management group identifies risks associated with our businesses
and determines which risks we want to manage and which types of instruments we
should use to manage those risks.
With the adoption of Statement of Financial Accounting Standards (SFAS) No.
133, Accounting for Derivatives and Hedging Activities, we now record all
derivative instruments on the balance sheet at their fair value. These
instruments consist of two types, those derivatives entered into and held to
mitigate, or hedge a particular risk, and those that are entered into and held
for purposes other than risk mitigation, such as those in our trading
activities. Those instruments that do not qualify as hedges are recorded at
their fair value with changes in fair value reported in current period earnings.
For those instruments entered into to hedge risk, and which qualify as hedges
under SFAS No. 133, the appropriate accounting treatment depends on each
instrument's intended use and how it is designated. Derivative instruments that
qualify as hedges may be designated as:
- hedges of the fair value of a recognized asset or liability or of an
unrecognized firm commitment (fair value hedges);
- hedges of a forecasted transaction or of the variability of cash flows to
be received or paid related to a recognized asset or liability (cash flow
hedges);
- foreign currency fair value or cash flow hedges (foreign currency
hedges); or
- hedges of a net investment in a foreign operation (net investment
hedges).
In addition to its designation, a hedge must be effective. To be effective,
the value of the derivative or its resulting cash flows must substantially
offset changes in the value or cash flows of the item being hedged. If it is
determined that the hedge is no longer effective, hedge accounting is
discontinued prospectively. Hedge accounting is also discontinued when:
- the derivative instrument expires or is sold, terminated, or exercised;
- it is no longer probable that the forecasted transaction will occur;
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- the hedged firm commitment no longer meets the definition of a firm
commitment; or
- management determines that the designation of the derivative instrument
as a hedge is no longer appropriate.
At the time we enter into a hedge, we formally document relationships
between the hedging instrument and the hedged items. This documentation
includes:
- the nature of the risk being hedged;
- our risk management objectives and strategies for undertaking the hedging
activity;
- a description of the hedged item and the derivative instrument used to
hedge the item;
- a description of how effectiveness is tested at the inception of the
hedge; and
- how effectiveness will be tested on an ongoing basis.
When hedge accounting is discontinued, the derivative instrument continues
to be carried on the balance sheet at its fair value. However, any further
changes in its fair value are recognized in current period earnings. Accounting
for the item that was being hedged differs depending on how the hedge was
originally designated. Our accounting policies for derivative instruments used
in our business that qualify as hedges are discussed below:
<Table>
<Caption>
IMPACT OF THE DISCONTINUATION OF HEDGE
TYPE OF HEDGE ACCOUNTING TREATMENT ACCOUNTING ON ITEM BEING HEDGED
- ------------- -------------------- --------------------------------------
Fair value Changes in the fair value of the When hedge accounting is discontinued,
derivative and changes in the fair the hedged asset or liability is no
value of the related asset or longer adjusted for changes in fair
liability attributable to the value. When hedge accounting is
hedged risk are recorded in current discontinued because the hedged item
period earnings, generally as a no longer meets the definition of a
component of revenue in the case of firm commitment, any asset or
a sale or as a component of the liability that was recorded related to
cost of products in the case of a the firm commitment is removed from
purchase. the balance sheet and recognized in
current period earnings.
Cash flow Changes in the fair value of the When hedge accounting is discontinued
derivative are recorded in other because it is unlikely that the
comprehensive income for the forecasted transaction will occur,
portion of the change in value of gains or losses that were accumulated
the derivative that is effective. in other comprehensive income related
The ineffective portion of the to the forecasted transaction will be
derivative is recorded in earnings recognized immediately in earnings.
in the current period. When a cash flow hedge is
Classification in the income de-designated, but the forecasted
statement of the ineffective transaction is still probable, the
portion is based on the income accumulated amounts remain in other
classification of the item being comprehensive income until the
hedged. forecasted transaction occurs. At that
time, the accumulated amounts are
recognized in earnings.
</Table>
Because our business activities encompass all aspects of the wholesale
energy marketplace, including the gathering, processing, treating, transmission,
and the purchase and sale of highly liquid energy commodities, our normal
business contracts may qualify as derivative instruments under the provisions of
SFAS No. 133. As a result, we evaluate each of our commercial contracts to see
if derivative accounting is appropriate. Contracts that meet the criteria of a
derivative are then evaluated to determine whether they qualify as a "normal
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purchase" or a "normal sale" as those terms are defined in SFAS No. 133. If they
qualify as normal purchases and normal sales, we may exclude them from SFAS No.
133 treatment. We also evaluate our contracts for "embedded" derivatives.
Embedded derivatives have terms that are not clearly and closely related to the
terms of the contract in which they are included. If embedded derivatives exist,
they are accounted for separately from the host contract as derivatives, with
changes in their fair value recorded in current period earnings.
2. MERGER-RELATED COSTS AND ASSET IMPAIRMENTS
During the quarter and six months ended June 30, 2001, we incurred
merger-related costs associated with El Paso Corporation's merger with The
Coastal Corporation and asset impairments as follows:
<Table>
<Caption>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
-------- ----------
2001 2001
-------- ----------
(IN MILLIONS)
Merger-related costs........................................ $ 5 $34
Asset impairments........................................... 38 38
--- ---
$43 $72
=== ===
</Table>
Merger-Related Costs
Our merger-related costs consisted of the following:
<Table>
<Caption>
QUARTER SIX MONTHS
ENDED ENDED
JUNE 30, JUNE 30,
-------- ----------
2001 2001
-------- ----------
(IN MILLIONS)
Employee severance, retention, and transition costs......... $ 1 $ 5
Make-whole commitments...................................... 4 25
Other....................................................... -- 4
--- ---
$ 5 $34
=== ===
</Table>
Employee severance, retention, and transition costs include direct payments
to, and benefit costs for, severed employees and early retirees that occurred as
a result of El Paso's merger-related workforce reduction and consolidation.
Make-whole commitments relate to a series of payments we will make to El Paso
Energy Partners L.P. in connection with the Federal Trade Commission's (FTC)
ordered divestiture of interests in assets owned by the partnership.
Asset Impairments
During the quarter ended June 30, 2001, we incurred an asset impairment
charge of $38 million resulting from Merchant Energy's impairment of its East
Asia Power investment in the Philippines. This write down was a result of weak
economic conditions causing a permanent decline in the value of our investment.
We continue to hold this investment.
3. EXTRAORDINARY ITEMS
As a result of El Paso's merger with Coastal, we were required by the FTC
to sell our Midwestern Gas Transmission system. We completed this sale in April
2001. Net proceeds were approximately $95 million, and we recognized an
extraordinary gain of $38 million, net of income taxes of $21 million.
During the first quarter of 2000, we sold East Tennessee Natural Gas
Company to comply with an FTC order related to El Paso's merger with Sonat Inc.
Net proceeds from the sale were approximately $386 million, and we recognized an
extraordinary gain of $77 million, net of income taxes of $51 million.
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4. ACCOUNTING FOR HEDGING ACTIVITIES
On January 1, 2001, we adopted the provisions of SFAS No. 133, and recorded
a cumulative-effect adjustment of $154 million, net of income taxes, in
accumulated other comprehensive income to recognize the fair value of all
derivatives designated as cash flow hedging instruments. The majority of the
initial charge related to hedging forecasted sales of natural gas for 2001 and
2002. During the quarter and six months ended June 30, 2001, $12 million and
$128 million, net of income taxes, of this initial transition adjustment was
reclassified to earnings as a result of hedged sales and purchases during the
period, and an additional $3 million of this adjustment will be reclassified by
the end of 2001.
A majority of our commodity sales and purchases are at spot market or
forward market prices. We use futures, forward contracts, and swaps to limit our
exposure to fluctuations in the commodity markets and allow for a fixed cash
flow stream from these activities. As of June 30, 2001, the value of cash flow
hedges included in accumulated other comprehensive income was an unrealized loss
of $16 million, net of income taxes. Of this amount, we estimate that $1 million
will be reclassified from accumulated other comprehensive income over the next
12 months. Reclassifications occur upon physical delivery of the hedged
commodity and the corresponding expiration of the hedge. The maximum term of our
cash flow hedges is 1 year.
Our other comprehensive income includes a loss of $27 million representing
our proportionate share of amounts recorded in other comprehensive income by our
unconsolidated affiliates that use derivatives as cash flow hedges. The maximum
term of these cash flow hedges is 2 years, excluding hedges relating to interest
rates on variable debt.
For the quarter and six months ended June 30, 2001, we recognized net gains
of $12 million and $13 million, net of income taxes, related to the ineffective
portion of all cash flow hedges.
5. INVENTORY
Our inventory consisted of the following:
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
-------- ------------
(IN MILLIONS)
Natural gas in storage...................................... $ 24 $ 58
Materials and supplies, and other........................... 35 26
---- ----
Total............................................. $ 59 $ 84
==== ====
</Table>
6. DEBT AND OTHER CREDIT FACILITIES
At June 30, 2001, our weighted average interest rate on short-term
borrowings was 4.6%, and at December 31, 2000, it was 7.6%. We had the following
short-term borrowings, including current maturities of long-term debt:
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
-------- ------------
(IN MILLIONS)
Notes payable to unconsolidated affiliates.................. $ -- $ 9
Commercial paper............................................ 168 215
Current maturities of long-term debt........................ 45 132
---- ----
$213 $356
==== ====
</Table>
Acquisition of PG&E's Texas Midstream Operations
In connection with our acquisition of PG&E's Texas Midstream operations in
December 2000, we assumed $527 million in debt. In February 2001, we redeemed
$293 million of the assumed debt.
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Revolving Credit Facility
In June 2001, El Paso replaced its $2 billion, 364-day revolving credit
facility with a renewable $3 billion, 364-day revolving credit and competitive
advance facility. Tennessee Gas Pipeline (TGP) is a designated borrower under
this facility and, as such, is liable for any amounts outstanding under this
facility. The interest rate varies and was LIBOR plus 50 basis points at June
30, 2001. No amounts were outstanding under this facility at June 30, 2001.
Other
In addition to the items discussed above, during the six months ended June
30, 2001, we retired long-term debt with the aggregate principal amount of
approximately $71 million.
7. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
EPME and several of our affiliates were named defendants in eight purported
class action or citizen lawsuits and one individual lawsuit filed in 2000 and
2001 in California state courts (a list of the California cases is included in
Part II, Item 1, Legal Proceedings). These cases contend generally that our
entities acted alone or in combination with other unrelated companies to create
artificially high prices for natural gas in California, and that EPME's
acquisition of capacity on the El Paso Natural Gas Company (EPNG) pipeline
system, an affiliated pipeline system, was utilized to manipulate the market for
natural gas in California. We removed each of these cases to federal court and
have requested that they be consolidated for all pretrial activities. In June
2001, the Federal Judicial Panel on Multi-District Litigation granted our
consolidation motion relating to four of the lawsuits, sending them to the U.S.
District Court in Nevada. In July 2001, the remaining five cases were
conditionally consolidated to the Nevada District Court. The Nevada court has
scheduled oral arguments in September 2001 on the issue of whether some or all
of these cases should be remanded to the California State Court system for all
further proceedings.
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, in the U.S. Bankruptcy Court in Connecticut claiming EPME
improperly cancelled its contracts with PCA during the summer of 1998. The
trustee alleged we breached contracts damaging PCA in the amount of $120
million. In May 2001, we agreed to settle this matter for a cash payment of $3
million. In a related matter, PCA appealed the Federal Energy Regulatory
Commission's (FERC) 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, which
ruled in FERC's favor.
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 14 companies, including us
and some of our current and former affiliates, related 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. Settlement
discussions are ongoing.
In 1997, a number of our subsidiaries and affiliates were named defendants
in actions brought by Jack Grynberg on behalf of the U.S. Government under the
False Claims Act. Generally, these complaints allege
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an industry-wide conspiracy to under report the heating value as well as the
volumes of the natural gas produced from federal and Native American lands,
which deprived the U.S. Government of royalties. These matters have been
consolidated for pretrial purposes (In re: Natural Gas Royalties Qui Tam
Litigation, U.S. District Court for the District of Wyoming). In May 2001, the
court denied the defendants' motions to dismiss.
A number of our subsidiaries and affiliates were named defendants in
Quinque Operating Company, et al v. Gas Pipelines and Their Predecessors, et al,
filed in 1999 in the District Court of Stevens County, Kansas. This class action
complaint alleges that the defendants mismeasured natural gas volumes and
heating content of natural gas on non-federal and non-Native American lands. The
Quinque complaint was transferred to the same court handling the Grynberg
complaint and has now been sent back to Kansas State Court for further
proceedings.
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 polychlorinated biphenyls (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 and received
water discharge permits from the agency for its Kentucky compressor stations.
The relevant Kentucky compressor stations are being characterized and remediated
under a 1994 consent order with the EPA.
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 will have a
material adverse effect on our financial position, operating results, 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 June 30, 2001, we had a reserve of approximately $116 million for
expected remediation costs. In addition, we expect to make capital expenditures
for environmental matters of approximately $103 million in the aggregate for the
years 2001 through 2006. These expenditures primarily relate to compliance with
clean air regulations.
Since 1988, TGP has been engaged in an internal project to identify and
deal with the presence of PCBs and other substances, including those on the EPA
List of Hazardous Substances, at compressor stations and other facilities it
operates. While conducting this project, TGP has been in frequent contact with
federal and state regulatory agencies, both through informal negotiation and
formal entry of consent orders, to ensure that its efforts meet regulatory
requirements.
In May 1995, following negotiations with its customers, TGP filed a
Stipulation and Agreement (the Environmental Stipulation) with the Federal
Energy Regulatory Commission (FERC) that established a mechanism for recovering
a substantial portion of the environmental costs identified in its internal
project. The Environmental Stipulation was effective July 1, 1995, and all
amounts have been collected from customers. Refunds may be required to the
extent actual eligible expenditures are less than amounts collected.
TGP is a party in proceedings involving federal and state authorities
regarding the past use of a lubricant containing PCBs in its starting air
systems. TGP executed a consent order in 1994 with the EPA governing the
remediation of the relevant 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.
11
13
We have been designated and have received notice that we could be
designated, or have been asked for information to determine whether we could be
designated, as a Potentially Responsible Party (PRP) with respect to eight
active sites under CERCLA or state equivalents. We have sought to resolve our
liability as a PRP at these CERCLA sites, as appropriate, through
indemnification by third parties and/or settlements which provide for payment of
our allocable share of remediation costs. As of June 30, 2001, we have estimated
our share of the remediation costs at these sites to be between approximately $1
million and $2 million and have provided reserves that we believe are adequate
for such costs. Since the cleanup costs are estimates and are subject to
revision as more information becomes available about the extent of remediation
required, and because in some cases we have asserted a defense to any liability,
our estimates could change. Moreover, liability under the federal CERCLA statute
is joint and several, meaning that we could be required to pay in excess of our
pro rata share of remediation costs. Our understanding of the financial strength
of other PRPs has been considered, where appropriate, in the determination of
our estimated liabilities. We presently believe that the costs associated with
these CERCLA sites will not have a material adverse effect on our financial
position, operating results, or cash flows.
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. For a further discussion of specific environmental
matters, see Legal Proceedings above.
Rates and Regulatory Matters
In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with FERC alleging that EPNG's sale of approximately 1.2 billion cubic
feet per day of California capacity to EPME was anticompetitive and an abuse of
the affiliate relationship under FERC's policies. In August 2000, the CPUC filed
a motion requesting that the contract between EPNG and EPME be terminated. Other
parties in the proceedings have requested that the original complaint be set for
hearing and that EPME pay back any profits it has earned under the contract. In
March 2001, FERC established a hearing, before an administrative law judge, to
address the issue of whether EPNG and/or EPME had market power and, if so, had
exercised it. The hearing on the anticompetitive issue concluded in May 2001. In
June 2001, FERC issued an order granting the request of the CPUC and others to
allow the administrative law judge to take evidence on the affiliate abuse
issue. The hearing for the purpose of taking evidence on this issue concluded on
August 6, 2001, with final briefs due by September 9, 2001. We expect the
administrative law judge to issue a decision in the fourth quarter 2001.
In June 2001, the Western Australia regulators issued a draft rate decision
at lower than expected levels for the Dampier-to-Bunbury pipeline owned by EPIC
Energy Australia Trust (EPIC), in which we have a 33 percent ownership interest.
EPIC's management is currently analyzing the impact of the draft rate decision
on its current and anticipated future operating results, the results of which
could impact our investment.
While we cannot predict with certainty the final outcome or the timing of
the resolution of all of our rates and regulatory matters, 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.
12
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8. SEGMENT INFORMATION
We segregate our business activities into three distinct operating
segments: Pipelines, Merchant Energy, and Field Services. 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 expense and income taxes (EBIT). The following are our results as of
and for the periods ended June 30:
<Table>
<Caption>
QUARTER ENDED JUNE 30, 2001
----------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES OTHER(1) TOTAL
--------- -------- -------- -------- -------
(IN MILLIONS)
Revenues from external customers............... $ 151 $ 7,813 $ 85 $ 1 $ 8,050
Intersegment revenues.......................... 19 9 61 (89) --
Merger-related costs and asset impairments..... -- 39 4 -- 43
Operating income............................... 65 92 25 8 190
EBIT........................................... 72 176 20 8 276
Segment assets................................. 4,996 10,485 2,928 918 19,327
</Table>
<Table>
<Caption>
QUARTER ENDED JUNE 30, 2000
----------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES OTHER(1) TOTAL
--------- -------- -------- -------- -------
(IN MILLIONS)
Revenues from external customers............... $ 172 $ 3,674 $ 134 $ -- $ 3,980
Intersegment revenues.......................... 18 2 16 (36) --
Operating income (loss)........................ 80 136 24 (1) 239
EBIT........................................... 85 164 25 (3) 271
Segment assets................................. 4,872 6,704 1,116 262 12,954
</Table>
<Table>
<Caption>
SIX MONTHS ENDED JUNE 30, 2001
----------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES OTHER(1) TOTAL
--------- -------- -------- -------- -------
(IN MILLIONS)
Revenues from external customers............... $ 350 $17,399 $ 412 $ 1 $18,162
Intersegment revenues.......................... 39 30 138 (207) --
Merger-related costs and asset impairments..... 1 39 32 -- 72
Operating income............................... 176 283 23 9 491
EBIT........................................... 185 407 21 9 622
Segment assets................................. 4,996 10,485 2,928 918 19,327
</Table>
<Table>
<Caption>
SIX MONTHS ENDED JUNE 30, 2000
----------------------------------------------------
MERCHANT FIELD
PIPELINES ENERGY SERVICES OTHER(1) TOTAL
--------- -------- -------- -------- -------
(IN MILLIONS)
Revenues from external customers............... $ 368 $ 6,232 $ 246 $ 1 $ 6,847
Intersegment revenues.......................... 35 9 31 (75) --
Operating income (loss)........................ 174 186 46 (5) 401
EBIT........................................... 185 247 50 (7) 475
Segment assets................................. 4,872 6,704 1,116 262 12,954
</Table>
- ---------------
(1) Includes Corporate, eliminations, and other non-operating segment
activities.
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9. INVESTMENTS 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 ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------- ----------------
2001 2000 2001 2000
----- ----- ----- -----
(IN MILLIONS) (IN MILLIONS)
Operating results data
Revenues and other income................. $ 208 $ 199 $ 448 $ 345
Costs and expenses........................ (164) (154) (354) (305)
Income from continuing operations......... 44 45 94 40
Net income................................ 36 21 57 18
</Table>
10. TRANSACTIONS WITH RELATED PARTIES
We participate in El Paso's cash management program which matches
short-term cash excesses and requirements of participating affiliates, thus
minimizing total borrowing from outside sources. We had borrowed $1,777 million
at June 30, 2001, at a market rate of interest which was 4.2% at June 30, 2001.
At December 31, 2000, we had borrowed $3,691 million.
At June 30, 2001, we had accounts receivable from other related parties of
$1,020 million and $194 million at December 31, 2000. In addition, we had
accounts payable to other related parties of $1,349 at June 30, 2001, versus $69
million at December 31, 2000. These balances were incurred in the normal course
of business.
11. NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
Business Combinations
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141, Business Combinations. This statement requires that all transactions
that fit the definition of a business combination be accounted for using the
purchase method and prohibits the use of the pooling of interests method for all
business combinations initiated after June 30, 2001. This statement also
establishes specific criteria for the recognition of intangible assets
separately from goodwill and requires unallocated negative goodwill to be
written off immediately as an extraordinary item. This standard will have an
impact on any business combination we undertake in the future. We are currently
evaluating the effects of this pronouncement on our historical financial
statements.
Goodwill and Other Intangible Assets
In July 2001, the FASB issued SFAS No. 142, Goodwill and Other Intangible
Assets. This statement requires that goodwill no longer be amortized but
intermittently tested for impairment at least on an annual basis. Other
intangible assets are to be amortized over their useful life and reviewed for
impairment in accordance with the provisions of SFAS No. 121, Accounting for the
Impairment of Long-Lived Assets and Long-Lived Assets to be Disposed of. An
intangible asset with an indefinite useful life can no longer be amortized until
its useful life becomes determinable. This statement has various effective
dates, the most significant of which is January 1, 2002. We are currently
evaluating the effects of this pronouncement.
Accounting for Asset Retirement Obligations
In July 2001, the FASB approved for issuance SFAS No. 143, Accounting for
Asset Retirement Obligations. This statement requires companies to record a
liability relating to the retirement and removal of assets used in their
business. The liability is discounted to the present value, and the related
asset value is increased by the amount of the resulting liability. Over the life
of the asset, the liability will be accreted to its future value and eventually
extinguished when the asset is taken out of service. The provisions of this
statement are effective for fiscal years beginning after June 15, 2002. We are
currently evaluating the effects of this pronouncement.
14
16
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS(1)
The information contained in Item 2 updates, and you should read it 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, 2000, in addition to
the financial statements and notes presented in Item 1, Financial Statements, of
this Quarterly Report on Form 10-Q.
RESULTS OF OPERATIONS
For the quarter ended June 30, 2001, we had net income of $158 million
versus $140 million for the quarter ended June 30, 2000. The 2001 results
included merger-related costs and asset impairments totaling $43 million, or $26
million after taxes. In addition, we recorded extraordinary gains totaling $38
million, net of income taxes, as a result of FTC ordered sales of our Midwestern
Gas Transmission system. Net income, excluding the effects of these charges, and
extraordinary items, would have been $146 million in 2001 versus $140 million in
2000, or an increase of 4 percent.
For the six months ended June 30, 2001, we had net income of $326 million
versus $325 million for the six months ended June 30, 2000. The 2001 results
included merger-related costs and asset impairments totaling $72 million, or $48
million after taxes. In addition, we recorded extraordinary gains totaling $38
million, net of income taxes, as a result of FTC ordered sales of our Midwestern
Gas Transmission system. For the six months ended June 30, 2000, we recorded
extraordinary gains on FTC ordered sales of our East Tennessee Natural Gas
Company totaling $77 million, net of income taxes. Net income, excluding the
after-tax effects of these charges, and extraordinary items, would have been
$336 million in 2001 versus $248 million in 2000, or an increase of 35 percent.
SEGMENT RESULTS
Our business activities are segregated into three segments: Pipelines,
Merchant Energy, and Field Services. These segments are strategic business units
that offer a variety of different energy products and services and each requires
different technology and marketing strategies. Operating revenues and expenses
by segment include intersegment revenues and expenses which are eliminated in
consolidation. Because changes in energy commodity prices have a similar impact
on both our operating revenues and cost of products sold from period to period,
we believe that gross margin (revenue less cost of sales) provides a more
accurate and meaningful basis for analyzing operating results for the trading
portion of Merchant Energy and the Field Services segment. For a further
discussion of our individual segments see Item 1, Financial Statements, Note 8.
The segment results presented below include merger-related costs and asset
impairments as discussed above:
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
-------------- ----------------
2001 2000 2001 2000
---- ---- ----- -----
(IN MILLIONS)
EARNINGS BEFORE INTEREST EXPENSE AND INCOME TAXES
Pipelines............................................... $ 72 $ 85 $185 $185
Merchant Energy......................................... 176 164 407 247
Field Services.......................................... 20 25 21 50
---- ---- ---- ----
Segment total......................................... 268 274 613 482
Corporate and other, net................................ 8 (3) 9 (7)
---- ---- ---- ----
Consolidated EBIT..................................... $276 $271 $622 $475
==== ==== ==== ====
</Table>
- ---------------
(1) Below is a list of terms that are common to our industry and used throughout
our Management's Discussion and Analysis:
<Table>
Btu = British thermal unit
BBtu/d = billion British thermal units per day
BBtue/d = billion British thermal unit equivalents per day
MMBtu = million British thermal units
MMWh = thousand megawatt hours
</Table>
15
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PIPELINES
Our Pipelines segment operates our interstate pipeline businesses. Each
pipeline system operates under a separate tariff that governs its operations and
rates. Operating results for our pipeline systems have generally been stable
because the majority of the revenues are based on fixed reservation charges. As
a result, we expect changes in this aspect of our business to be primarily
driven by regulatory actions and contractual events. Commodity or
throughput-based revenues account for a smaller portion of our operating
results. These revenues vary from period to period, and system to system, and
are impacted by factors such as weather, operating efficiencies, competition
from other pipelines, and fluctuations in natural gas prices. Results of
operations of the Pipelines segment were as follows for the periods ended June
30:
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
---------------- ----------------
2001 2000 2001 2000
------ ------ ------ ------
(IN MILLIONS, EXCEPT VOLUME AMOUNTS)
Operating revenues............................ $ 170 $ 190 $ 389 $ 403
Operating expenses............................ (105) (110) (213) (229)
Other income.................................. 7 5 9 11
------ ------ ------ ------
EBIT........................................ $ 72 $ 85 $ 185 $ 185
====== ====== ====== ======
Throughput volumes (BBtu/d)(1)................ 4,111 4,027 4,589 4,447
====== ====== ====== ======
</Table>
- ---------------
(1) Throughput volumes exclude those relating to pipeline systems sold in
connection with our Coastal and Sonat mergers including the Midwestern Gas
Transmission and East Tennessee Natural Gas systems.
Second Quarter 2001 Compared to Second Quarter 2000
Operating revenues for the quarter ended June 30, 2001, were $20 million
lower than the same period in 2000. The decrease was due to lower 2001 revenues
resulting from contract remarketing during 2000 and lower rates on throughput in
2001 as a result of a higher proportion of short versus long hauls compared to
2000. Also contributing to the decrease were contract quantity reductions and
cancellations on TGP's pipeline by customers of East Tennessee Natural Gas
Company resulting from the FTC's order to El Paso to sell its East Tennessee
system in the first quarter of 2000, and the impact of the sale of the
Midwestern Gas Transmission system in April 2001. Partially offsetting the
decrease was the impact of higher prices on sales of excess natural gas in 2001.
Operating expenses for the quarter ended June 30, 2001, were $5 million
lower than the same period in 2000. The decrease was due to lower depreciation
expenses from the retirement of assets, reduced operating and depreciation
expenses due to the sale of Midwestern, and lower corporate allocations and
operating expenses as a result of cost savings following El Paso's merger with
Coastal in January 2001.
Six Months Ended 2001 Compared to Six Months Ended 2000
Operating revenues for the six months ended June 30, 2001, were $14 million
lower than the same period in 2000. The decrease was due to lower 2001 revenues
resulting from contract remarketing during 2000 and lower rates on throughput in
2001 as a result of a higher proportion of short versus long hauls compared to
2000. Also contributing to the decrease was the sale of East Tennessee,
including contract quantity reductions or cancellations on TGP's pipeline by
customers of East Tennessee resulting from the FTC's order to El Paso to sell
East Tennessee and the impact of the sale of Midwestern. Partially offsetting
the decrease was the impact of higher prices on sales of excess natural gas.
Operating expenses for the six months ended June 30, 2001, were $16 million
lower than the same period in 2000. The decrease was due to lower project
development costs, lower depreciation expenses resulting from the retirement of
assets, reduced operating and depreciation expenses from the sales of Midwestern
and East Tennessee, and lower corporate allocations and operating expenses as a
result of cost savings following El Paso's merger with Coastal.
16
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MERCHANT ENERGY
Merchant Energy is involved in a wide range of activities in the wholesale
energy marketplace, including trading and risk management, asset ownership, and
financial services. Each market served by Merchant Energy is highly competitive
and is influenced directly or indirectly by energy market economics.
Merchant Energy's trading and risk management activities provide energy
trading and energy management solutions for its customers and affiliates
involving primarily natural gas and power. The segment maintains a substantial
trading portfolio that manages its risk across multiple commodities and over
seasonally fluctuating energy demands.
Merchant Energy's asset ownership activities include a 20 percent ownership
interest in Chaparral Investors, L.L.C., an entity established to acquire, hold,
and manage domestic power generation assets. During the six months ended June
30, 2001, Merchant Energy earned $74 million in fee-based revenues from
Chaparral, and was reimbursed $10 million for operating expenses. For the six
months ended June 30, 2000, fee-based revenues were $40 million, and expense
reimbursements were $10 million.
In the financial services area, Merchant Energy owns EnCap Investments and
Enerplus Global Energy Management, Inc., and conducts other energy financing
activities. EnCap manages three separate oil and natural gas investment funds in
the U.S., and serves as an investment advisor to one fund in Europe. EnCap also
holds investments in emerging energy companies, and earns a return from these
investments. In 2000, Merchant Energy acquired Enerplus, a Canadian investment
management company, through which it conducts fund management activities similar
to EnCap, but in Canada. Below are Merchant Energy's operating results and an
analysis of these results for the periods ended June 30:
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------- -------------------
2001 2000 2001 2000
-------- ------- -------- -------
(IN MILLIONS, EXCEPT VOLUME AMOUNTS)
Trading gross margin...................... $ 143 $ 141 $ 346 $ 191
Operating and other revenues.............. 71 49 165 101
Operating expenses........................ (122) (54) (228) (106)
Other income.............................. 84 28 124 61
-------- ------- -------- -------
EBIT................................. $ 176 $ 164 $ 407 $ 247
======== ======= ======== =======
</Table>
Volumes
<Table>
Physical
Natural gas (BBtue/d)................ 9,187 6,081 10,324 5,818
Power (MMWh)......................... 44,538 22,412 79,930 46,148
Financial settlements (BBtue/d)......... 120,929 72,705 145,077 82,144
</Table>
Second Quarter 2001 Compared to Second Quarter 2000
Trading gross margin consists of revenues from commodity trading and
origination activities less the cost of commodities sold. For the quarter ended
June 30, 2001, these trading gross margins were $2 million higher than the same
period in 2000. Higher deal origination activities during the second quarter of
2001 were partially offset by the impact of lower 2001 power price volatility
and reserves related to our activities in California during the second quarter
of 2001.
In October 2000, Coastal, our affiliate, terminated their Engage joint
venture with WestCoast Energy, Inc. In the transaction, they assumed the U.S.
portion of Engage and WestCoast assumed the Canadian operations. As a result,
they began consolidating these U.S. operations and conducting trading
activities. In February 2001, Coastal transferred these contracts, which
included Engage's marketing contracts and other
17
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assets, to El Paso Merchant Energy, our subsidiary in exchange for 22 percent of
the shares of El Paso Merchant Energy. These shares had an estimated fair value
of approximately $135 million.
Merchant Energy is a provider of power and natural gas to the state of
California. During the latter half of 2000 and continuing into 2001, California
experienced sharp increases in natural gas prices and wholesale power prices due
to energy shortages resulting from a combination of unusually warm summer
weather followed by high winter demand, low gas storage levels, lower
hydroelectric power generation, maintenance downtime of significant generation
facilities, and price caps that discouraged power movement from other nearby
states into California. The increase in power prices caused by the imbalance of
natural gas and power supply and demand coupled with electricity price caps
imposed on rates allowed to be charged to California electricity customers has
resulted in large cash deficits of the two major California utilities, Southern
California Edison and Pacific Gas and Electric. As a result, both utilities have
defaulted on payments to creditors and have accumulated substantial
under-collections from customers. This resulted in their credit ratings being
downgraded in 2001 from above investment grade to below investment grade, and in
April 2001, Pacific Gas & Electric filed for bankruptcy. Both utilities have
filed for emergency rate increases with the CPUC and are working with the state
authorities to restore the companies' financial viability. We have historically
been one of the largest suppliers of energy to California, and we are actively
participating with all parties in California to be a part of the long-term,
stable solution to California's energy needs. We have established reserves that
we believe are sufficient to cover our exposure to these issues. As a result, we
do not believe, based on information known to date, these matters will have a
material impact on our operating results.
Our investee, Chaparral, has ownership interests in 11 power plants in the
state of California. As of June 30, 2001, customers of these facilities had only
partially paid for power generated. This, coupled with Pacific Gas and
Electric's bankruptcy declaration, has resulted in an event of default under the
terms of each facility's loan agreement. Operations of these plants have been
reduced, and each facility continues to take necessary actions to enforce the
terms of its power purchase agreement. Management of Chaparral has indicated
that it believes existing reserves against potential uncollectible accounts are
adequate. We do not believe, based on information known to date, that these
matters will have a material impact on our operating results. However, our
management fee from Chaparral is based on the value of its assets. As a result,
if the value of these power plants is permanently reduced, it could have a
similar effect on our management fee in future years.
Operating and other revenues consist of revenues from consolidated
international power generation facilities and revenues from the financial
services and asset management businesses of Merchant Energy. For the quarter
ended June 30, 2001, operating revenues were $22 million higher than the same
period in 2000. The increase resulted from higher management fees from Chaparral
and the acquisition and consolidation of the CEBU power project in the
Philippines during the first quarter of 2001.
Operating expenses for the quarter ended June 30, 2001, were $68 million
higher than the same period in 2000. The increase was due to the write-down of
our investment in the East Asia power project in the Philippines due to weak
economic conditions which caused a permanent decline in the value of that
investment and higher professional fees and salaries resulting from the
expansion of our operations in Europe, Asia, South America and in our liquefied
natural gas business. Also contributing to the increase were higher operating
expenses from the consolidation of the CEBU power project.
18
20
Other income for the quarter ended June 30, 2001, was $56 million higher
than the same period in 2000. The increase resulted from agency and marketing
fees received in the second quarter of 2001 for a Brazilian power transaction,
as well as increased equity earnings on unconsolidated power project
investments.
Six Months Ended 2001 Compared to Six Months Ended 2000
Trading gross margin for the six months ended June 30, 2001, was $155
million higher than the same period in 2000. The increase was primarily due to
higher margins from natural gas trading activities in the first six months of
2001 resulting from increased trading volumes and price volatility. Partially
offsetting these increases were lower deal origination activities in the first
half of 2001 and 2001 reserves for our activities in California.
Operating and other revenues for the six months ended June 30, 2001, were
$64 million higher than the same period in 2000. The increase was a result of
higher management fees from Chaparral, the acquisition and consolidation of the
CEBU power project in the Philippines and revenues from Enerplus which was
acquired in August 2000.
Operating expenses for the six months ended June 30, 2001, were $122
million higher than the same period in 2000. The increase was due to the
write-down of our investment in the East Asia power project in the Philippines
and higher professional fees and salaries resulting from the expansion of our
operations in Europe, Asia, South America and in our liquefied natural gas
business. Also contributing to the increase were higher operating expenses from
the consolidation of the CEBU power project.
Other income for the six months ended June 30, 2001, was $63 million higher
than the same period in 2000. The increase was a result of a marketing and
agency fee on a Brazilian power transaction in the second quarter of 2001, as
well as increased equity earnings on unconsolidated power project investments.
FIELD SERVICES
Field Services provides a variety of services for the midstream component
of our operations, including gathering and treating of natural gas, processing
and fractionation of natural gas, natural gas liquids, and natural gas
derivative products, such as ethane, propane, and butane. Field Services
attempts to balance its earnings from its activities through a combination of
fixed fee-based and market-based services.
Our gathering and treating operations earn margins substantially from fixed
fee-based services; however, some of these operations earn margins from
market-based rates. Revenues for these commodity rate services are the product
of the market price, usually related to the monthly natural gas price index, and
the volume gathered.
Processing and fractionation operations earn a margin based on fixed-fee
contracts, percentage-of-proceeds contracts, and make-whole contracts.
Percentage-of-proceeds contracts allow us to retain a percentage of the product
as a fee for processing or fractionation service. Make-whole contracts allow us
to retain the extracted liquid products and return to the producer a Btu
equivalent amount of natural gas. Under our percentage-of-proceeds contracts and
make-whole contracts, Field Services may have more sensitivity to price changes
during periods when natural gas and natural gas liquids prices are volatile.
19
21
Field Services' operating results and an analysis of these results are as
follows for each of the periods ended June 30:
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
JUNE 30, JUNE 30,
------------------ ------------------
2001 2000 2001 2000
------- ------- ------- -------
(IN MILLIONS, EXCEPT VOLUMES AND PRICES)
Gathering, treating, and processing margin...... $ 100 $ 61 $ 209 $ 121
Operating expenses.............................. (75) (37) (186) (75)
Other income (loss)............................. (5) 1 (2) 4
------ ------ ------ ------
EBIT.......................................... $ 20 $ 25 $ 21 $ 50
====== ====== ====== ======
Volumes and prices
Gathering and treating
Volumes (BBtu/d)........................... 5,709 2,945 5,626 2,994
====== ====== ====== ======
Prices ($/MMBtu)........................... $ 0.12 $ 0.16 $ 0.13 $ 0.16
====== ====== ====== ======
Processing
Volumes (inlet BBtu/d)..................... 2,495 1,119 2,224 1,055
====== ====== ====== ======
Prices ($/MMBtu)........................... $ 0.16 $ 0.19 $ 0.18 $ 0.18
====== ====== ====== ======
</Table>
Second Quarter 2001 Compared to Second Quarter 2000
Total gross margin for the quarter ended June 30, 2001, was $39 million
higher than the same period in 2000. The increase was a result of higher
gathering and treating margins, which increased approximately 35 percent,
primarily due to higher volumes as a result of our acquisition of PG&E's Texas
Midstream operations in December 2000. Processing margins during the second
quarter of 2001 were also higher, almost tripling those levels during the same
period in 2000, as a result of contributions from the processing operations
acquired from PG&E and higher natural gas and natural gas liquids prices in the
San Juan Basin. Lower average rates of gathering and treating and processing in
2001 compared to 2000 were due to the different mix of assets resulting from the
acquisition of PG&E.
Operating expenses for the quarter ended June 30, 2001, were $38 million
higher than the same period in 2000. The increase was a result of higher
operating costs and tax and depreciation expenses from the addition of PG&E's
Texas Midstream operations, and merger-related costs arising from commitments
made to Energy Partners related to FTC ordered sales of assets owned by the
partnership.
Six Months Ended 2001 Compared to Six Months Ended 2000
Total gross margin for the six months ended June 30, 2001, was $88 million
higher than the same period in 2000. The increase was a result of higher
gathering and treating margins, which increased approximately 49 percent,
primarily due to higher San Juan gathering rates, along with higher volumes as a
result of our acquisition of PG&E's Texas Midstream operations. Processing
margins in 2001 were also higher, increasing 115 percent over 2000, as a result
of contributions from the processing operations acquired from PG&E and higher
natural gas and natural gas liquids prices in the San Juan Basin. Lower average
rates of gathering and treating and processing in 2001 compared to 2000 were due
to the different mix of assets resulting from the acquisition of PG&E.
Operating expense for the six months ended June 30, 2001, were $111 million
higher than the same period in 2000. The increase was a result of higher
operating costs and tax and depreciation expenses from the addition of PG&E's
Texas Midstream operations, and merger-related costs arising from commitments
made related to FTC ordered sales of assets owned by Energy Partners.
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NON-AFFILIATED INTEREST AND DEBT EXPENSE
Non-affiliated interest and debt expense for the quarter and six months
ended June 30, 2001, was $4 million and $6 million higher than the same periods
in 2000 primarily due to long-term debt assumed by Field Services in relation to
its acquisition of PG&E's Texas Midstream operations in December 2000 and
decreased capitalized interest related to Merchant Energy's completion of the
West Georgia power facility in June 2000.
AFFILIATED INTEREST EXPENSE, NET
Affiliated interest expense, net for the quarter and six months ended June
30, 2001, was $20 million and $74 million higher than the same periods in 2000
due to an increase in advances from El Paso for ongoing capital projects,
investment programs, and operating requirements, offset by lower short-term
interest rates.
INCOME TAXES
The income tax expenses for the quarters ended June 30, 2001 and 2000, were
$75 million and $74 million, resulting in effective tax rates of 38 percent and
35 percent. Our effective tax rates were different than the statutory tax rate
of 35 percent primarily due to the following:
- state income taxes;
- earnings from unconsolidated affiliates where we anticipate receiving
dividends; and
- foreign income not taxed in the U.S., but taxed at foreign rates.
The income tax expenses for the six months ended June 30, 2001 and 2000,
were $147 million and $120 million, resulting in effective tax rates of 34
percent and 33 percent. Our effective tax rates were different than the
statutory tax rate of 35 percent primarily due to the following:
- state income taxes;
- earnings from unconsolidated affiliates where we anticipate receiving
dividends; and
- foreign income not taxed in the U.S., but taxed at foreign rates.
LIQUIDITY AND CAPITAL RESOURCES
CASH FROM OPERATING ACTIVITIES
Net cash provided by our operating activities was $3,192 million for the
six months ended June 30, 2001, compared to net cash used of $256 million for
the same period of 2000. The increase was primarily due to liquidations of net
derivative trading positions during the first half of 2001, coupled with the
impact of lower commodity prices. Partially offsetting these increases were cash
payments in 2001 for charges related to broker and over-the-counter margins and
higher interest payments.
CASH FROM INVESTING ACTIVITIES
Net cash used in our investing activities was $340 million for the six
months ended June 30, 2001. Our investing activities principally consisted of
additions to property, plant, and equipment primarily in our Field Services and
Pipelines segments for expansion and construction projects. We also had
additions to joint ventures and investments in unconsolidated affiliates,
primarily related to our investment in two international power companies located
in Brazil and China. Cash inflows from investment-related activities included
proceeds from the sale of our Midwestern Gas Transmission system.
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CASH FROM FINANCING ACTIVITIES
Net cash used in our financing activities was $2,838 million for the six
months ended June 30, 2001. During 2001, we retired long-term debt, repaid
short-term borrowings, paid dividends, and paid advances to El Paso.
We expect that future funding for our working capital needs, 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, the issuance of new long-term debt or
equity, and/or contributions from El Paso.
COMMITMENTS AND CONTINGENCIES
See Item 1, Financial Statements, Note 7, which is incorporated herein by
reference.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Item 1, Financial Statements, Note 11, which is incorporated herein by
reference.
CAUTIONARY STATEMENT FOR PURPOSES OF THE "SAFE HARBOR" PROVISIONS OF THE PRIVATE
SECURITIES LITIGATION REFORM ACT OF 1995
This report contains or incorporates by reference forward-looking
statements within the meaning of the Private Securities Litigation Reform Act of
1995. Where any forward-looking statement includes a statement of the
assumptions or bases underlying the forward-looking statement, we caution that,
while we believe these assumptions or bases to be reasonable and to be made in
good faith, assumed facts or bases almost always vary from the actual results,
and the differences between assumed facts or bases and actual results can be
material, depending upon the circumstances. Where, in any forward-looking
statement, we or our management express an expectation or belief as to future
results, that expectation or belief is expressed in good faith and is believed
to have a reasonable basis. We cannot assure you, however, that the statement of
expectation or belief will result or be achieved or accomplished. The words
"believe," "expect," "estimate," "anticipate" and similar expressions will
generally identify forward-looking statements.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
This information updates, and you should read it in conjunction with,
information disclosed in Part II, Item 7A in our Annual Report on Form 10-K for
the year ended December 31, 2000, in addition to the information presented in
Items 1 and 2 of this Quarterly Report on Form 10-Q.
There have been no material changes in our quantitative and qualitative
disclosures about market risks from those reported in our Annual Report on Form
10-K for the year ended December 31, 2000.
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PART II -- OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
See Part I, Item 1, Financial Statements, Note 7, which is incorporated
herein by reference.
The California cases are: four filed in the Superior Court of Los Angeles
County (Continental Forge Company, et al v. Southern California Gas Company, et
al, filed September 25, 2000; and Berg v. Southern California Gas Company, et
al, filed December 18, 2000); (The City of Los Angeles, et al v. Southern
California Gas Company, et al and The City of Long Beach, et al v. Southern
California Gas Company, et al, both filed March 20, 2001); two filed in the
Superior Court of San Diego County (John W.H.K. Phillip v. El Paso Merchant
Energy and John Phillip v. El Paso Merchant Energy, both filed December 13,
2000); and three filed in the Superior Court of San Francisco County (Sweetie's,
et al v. El Paso Corporation, et al, filed March 22, 2001; Philip Hackett, et al
v. El Paso Corporation, et al, filed May 9, 2001; and California Dairies, Inc.,
et al v. El Paso Corporation, et al, filed May 21, 2001). The four cases filed
in 2000 were the cases consolidated for pretrial activities.
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
We held our annual meeting of stockholders on May 21, 2001. Proposals
presented for a stockholders vote included the election of one director by
holders of EPTPC's 8 1/4% Cumulative Preferred Stock, Series A, and the election
of five Directors by EPC, the sole holder of EPTPC's Common Stock.
The one director nominated to be elected by the holder of EPTPC's 8 1/4%
Cumulative Preferred Stock Series A was elected with the following voting
results:
<Table>
<Caption>
FOR WITHHELD
--------- --------
Kenneth L. Smalley.......................................... 3,321,770 95,130
</Table>
Each of the five directors nominated to be elected by the common
stockholder were elected with the following voting results:
<Table>
<Caption>
FOR WITHHELD
----- --------
William A. Wise............................................. 1,971 0
H. Brent Austin............................................. 1,971 0
Joel Richards III........................................... 1,971 0
Britton White, Jr. ......................................... 1,971 0
Jeffrey I. Beason........................................... 1,971 0
</Table>
There were no broker non-votes for the election of directors.
ITEM 5. OTHER INFORMATION
None.
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ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K
a. Exhibits
<Table>
<Caption>
EXHIBIT
NUMBER DESCRIPTION
------- -----------
*10.A -- $3,000,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement, dated as of June 11, 2001, by
and among El Paso 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, ABN
Amro Bank, N.V., and Citibank, N.A., as co-documentation
agents for the Lenders, and Bank of America, N.A. and
Credit Suisse First Boston, as co-syndication agents for
the Lenders.
</Table>
Undertaking
We hereby undertake, 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 our long-term debt not filed herewith for the reason that the
total amount of securities authorized under any of these instruments does
not exceed 10 percent of our total consolidated assets.
b. Reports on Form 8-K
None.
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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 TENNESSEE PIPELINE CO.
Date: August 10, 2001 /s/ H. BRENT AUSTIN
------------------------------------
H. Brent Austin
Executive Vice President and
Chief Financial Officer
Date: August 10, 2001 /s/ JEFFREY I. BEASON
------------------------------------
Jeffrey I. Beason
Senior Vice President and Controller
(Chief Accounting Officer)
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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
------- -----------
*10.A -- $3,000,000,000 364-Day Revolving Credit and Competitive
Advance Facility Agreement, dated as of June 11, 2001, by
and among El Paso 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, ABN
Amro Bank, N.V., and Citibank, N.A., as co-documentation
agents for the Lenders, and Bank of America, N.A. and
Credit Suisse First Boston, as co-syndication agents for
the Lenders.
</Table>
26