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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 1-2700
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EL PASO NATURAL GAS COMPANY
(Exact Name of Registrant as Specified in its Charter)
<Table>
DELAWARE 74-0608280
(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 $1.00 per share. Shares outstanding on August 6,
2001: 1,000
EL PASO NATURAL GAS COMPANY MEETS THE CONDITIONS OF GENERAL INSTRUCTION
H(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS REPORT WITH A REDUCED
DISCLOSURE FORMAT AS PERMITTED BY SUCH INSTRUCTION.
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PART I -- FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
EL PASO NATURAL GAS COMPANY
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....................................... $138 $118 $279 $240
---- ---- ---- ----
Operating expenses
Operation and maintenance.............................. 44 44 85 86
Merger-related costs................................... 94 -- 102 --
Depreciation, depletion, and amortization.............. 18 17 35 33
Taxes, other than income taxes......................... 7 7 15 15
---- ---- ---- ----
163 68 237 134
---- ---- ---- ----
Operating income (loss).................................. (25) 50 42 106
Other income, net........................................ (2) -- (2) --
---- ---- ---- ----
Income (loss) before interest and income taxes........... (27) 50 40 106
---- ---- ---- ----
Non-affiliated interest and debt expense................. 22 22 45 50
Affiliated interest income, net.......................... (16) (18) (35) (39)
Income taxes............................................. (12) 18 11 37
---- ---- ---- ----
(6) 22 21 48
---- ---- ---- ----
Net income (loss)........................................ $(21) $ 28 $ 19 $ 58
==== ==== ==== ====
Comprehensive income (loss).............................. $(21) $ 28 $ 19 $ 58
==== ==== ==== ====
</Table>
See accompanying notes.
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EL PASO NATURAL GAS COMPANY
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................................. $ 1 $ --
Accounts and notes receivable, net
Customer............................................... 164 128
Affiliates............................................. 998 1,001
Other.................................................. 5 5
Materials and supplies.................................... 35 33
Other..................................................... 8 10
------ ------
Total current assets.............................. 1,211 1,177
------ ------
Property, plant, and equipment, at cost..................... 2,729 2,667
Less accumulated depreciation, depletion, and
amortization.............................................. 1,053 1,032
------ ------
1,676 1,635
Additional acquisition cost assigned to utility plant,
net....................................................... 74 76
------ ------
Total property, plant, and equipment, net......... 1,750 1,711
------ ------
Other assets................................................ 94 105
------ ------
Total assets...................................... $3,055 $2,993
====== ======
LIABILITIES AND STOCKHOLDER'S EQUITY
Current liabilities
Accounts payable
Trade.................................................. $ 86 $ 66
Affiliates............................................. 3 7
Other.................................................. 14 4
Short-term borrowings (including current maturities of
long-term debt)........................................ 414 280
Taxes payable............................................. 102 99
Other..................................................... 113 84
------ ------
Total current liabilities......................... 732 540
------ ------
Long-term debt, less current maturities..................... 658 873
------ ------
Other
Deferred income taxes..................................... 230 227
Other..................................................... 204 126
------ ------
434 353
------ ------
Commitments and contingencies
Stockholder's equity
Preferred stock, 8%, par value $0.01 per share; authorized
1,000,000 shares; issued 500,000 shares; stated at
liquidation value...................................... 350 350
Common stock, par value $1 per share; authorized and
issued 1,000 shares.................................... -- --
Additional paid-in capital................................ 710 710
Retained earnings......................................... 171 167
------ ------
Total stockholder's equity........................ 1,231 1,227
------ ------
Total liabilities and stockholder's equity........ $3,055 $2,993
====== ======
</Table>
See accompanying notes.
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EL PASO NATURAL GAS COMPANY
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................................................ $ 19 $ 58
Adjustments to reconcile net income to net cash from
operating activities
Depreciation, depletion, and amortization.............. 35 33
Deferred income tax expense............................ 3 33
Risk-sharing revenue................................... (16) (17)
Non-cash portion of merger-related costs............... 92 --
Working capital changes, net of non-cash transactions..... 4 (27)
Other..................................................... 3 (2)
----- -----
Net cash provided by operating activities......... 140 78
----- -----
Cash flows from investing activities
Purchases of property, plant, and equipment............... (68) (157)
Net change in other affiliated advances................... 9 481
Other..................................................... 1 3
----- -----
Net cash provided by (used in) investing
activities....................................... (58) 327
----- -----
Cash flows from financing activities
Net repayments of commercial paper........................ (81) (405)
Revolving credit borrowings............................... 100 150
Revolving credit repayments............................... (100) (150)
----- -----
Net cash used in financing activities............. (81) (405)
----- -----
Increase in cash and cash equivalents....................... 1 --
Cash and cash equivalents
Beginning of period....................................... -- --
----- -----
End of period............................................. $ 1 $ --
===== =====
</Table>
See accompanying notes.
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EL PASO NATURAL GAS COMPANY
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 discussed in Note 3), 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 stockholder's 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 Hedging Activities
We use derivatives to mitigate, or hedge cash flow risks associated with
power prices. We account for these derivatives under the provisions of Statement
of Financial Accounting Standards (SFAS) No. 133, Accounting for Derivatives and
Hedging Activities. Under SFAS No. 133, we record the derivatives we use at
their fair value, with an offsetting amount recorded in other comprehensive
income. This is done to the extent the derivative is effective, or to the extent
that changes in the derivative's value offset changes in the values of the item
being hedged. To the extent these changes do not offset one another, or to the
extent the derivative and the hedged item are ineffective, value changes are
recorded in earnings.
At the time we enter into a derivative contract, we formally document the
relationship between the derivative and the hedged item. 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. Amounts
recorded in other comprehensive income on hedge positions that have either been
discontinued or are not anticipated to occur remain for the original term of the
hedged transaction or are transferred to earnings depending on the basis on
which hedge accounting was discontinued.
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 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
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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. ACQUISITIONS
In March 2000, we purchased the All American Pipeline, a crude oil
transportation system, for $129 million. The system consists of 1,088 miles of
pipeline which runs from McCamey, Texas to the Emidio Station near Bakersfield,
California. On May 7, 2001, the Federal Energy Regulatory Commission (FERC)
issued an order granting us authorization to convert the 785 miles that extends
from McCamey, Texas to Ehrenberg, Arizona to a natural gas pipeline. This
pipeline will add approximately 230 million cubic feet per day to our
transportation system.
3. MERGER-RELATED COSTS
During the quarter and six months ended June 30, 2001, we incurred
merger-related costs of $94 million and $102 million associated with El Paso
Corporation's merger with The Coastal Corporation. These costs consist of
employee severance, retention, and transition costs for severed employees, and
business and operational integration costs related to the relocation of our
headquarters from El Paso, Texas to Colorado Springs, Colorado.
4. ACCOUNTING FOR HEDGING ACTIVITIES
During the second quarter of 2001, we entered into derivative instruments
to hedge the price risk associated with the cost of electricity used in our
operations. At June 30, 2001, we had less than $1 million, net of income taxes,
of deferred losses on these derivative instruments recorded in accumulated other
comprehensive income. These deferred amounts will be reclassified into earnings
during the next 12 months and will offset currently anticipated purchases of
electricity and will produce a determinable cash flow stream.
5. 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 7.5%. We had the following
short-term borrowings, including current maturities of long-term debt:
<Table>
<Caption>
JUNE 30, DECEMBER 31,
2001 2000
-------- ------------
(IN MILLIONS)
Commercial paper............................................ $199 $280
Current maturities of long-term debt........................ 215 --
---- ----
$414 $280
==== ====
</Table>
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. We are a designated borrower under the new facility and, as
such, are 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.
For the six months ended June 30, 2001, we accrued $14 million in dividends
payable on our 8% preferred stock.
6. COMMITMENTS AND CONTINGENCIES
Legal Proceedings
A number of El Paso entities 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). We are a defendant in most of these lawsuits. These
cases
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contend generally that El Paso entities acted alone or in combination with other
unrelated companies to create artificially high prices for natural gas in
California, and that El Paso Merchant Energy's acquisition of capacity on our
pipeline system was utilized to manipulate the market for natural gas in
California. We removed each of these cases to federal courts 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.
On August 19, 2000, a main transmission line owned and operated by us
ruptured at the crossing of the Pecos River near Carlsbad, New Mexico. Twelve
individuals at the site were fatally injured. Eleven lawsuits brought on behalf
of the 12 deceased persons have been filed against us and El Paso for damages
for personal injuries and wrongful death (a list of the Carlsbad cases is
included in Part II, Item 1, Legal Proceedings). In March 2001, we settled all
claims in the Heady cases, and in June 2001, we settled the claims in the
Jennifer Smith case. Payments for the claimants in the settled cases will be
fully covered by insurance. We are cooperating with the National Transportation
Safety Board in an investigation into the facts and circumstances concerning the
possible causes of the rupture. In addition, on June 20, 2001, the U.S.
Department of Transportation's Office of Pipeline Safety issued a Notice of
Proposed Violation to us. The Notice alleged five probable violations of its
regulations (a list of the alleged five probable violations is included in Part
II, Item 1, Legal Proceedings), proposed fines totaling over $2.5 million, and
proposed corrective actions. On July 20, 2001, we contested the proposed
violations in our response to the Office of Pipeline Safety.
In 1997, we and a number of our 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 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.
We and a number of our 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.
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 $29 million for
expected remediation costs. In addition, we expect to make capital expenditures
for environmental matters of approximately $11 million in the aggregate for the
years 2001 through 2006. These expenditures primarily relate to compliance with
clean air regulations.
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
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respect to four sites under the Comprehensive Environmental Response,
Compensation and Liability Act (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
$16 million and $20 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.
Rates and Regulatory Matters
In February 2001, we completed our open season on 1,221 million cubic feet
per day of capacity under contract with our affiliate, El Paso Merchant Energy
Company (EPME) through May 2001, and all of the available capacity was
subscribed. Contracts were awarded to 30 different entities at published tariff
rates for a duration from 17 months to 15 years, including EPME who was awarded
271 million cubic feet per day. Also, customers and other groups may dispute new
and renewed contracts, and 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.
In April 2000, the California Public Utilities Commission (CPUC) filed a
complaint with FERC alleging that our 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 us 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 we 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 of 2001.
Several of our customers have filed complaints requesting that FERC order
us to cease and desist from selling primary firm delivery point capacity at the
Southern California Gas Company Topock delivery point in excess of the
downstream capacity available at that point and to cease and desist from
overselling firm mainline capacity on the east-end of our mainline system.
Various technical conferences have been held regarding these matters. In May
2000, the parties agreed to use FERC's alternative dispute resolution services
to resolve these matters. A series of alternative dispute resolution meetings
were held during the summer of 2000 but have failed to produce a settlement. In
October 2000, FERC ordered us to make a one time allocation of available
delivery point capacity at the Southern California Gas Company Topock delivery
point among affected firm shippers, but deferred action on east-end and
systemwide capacity allocation issues. In
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February 2001, FERC issued an order accepting our tariff filing affirming the
results of the Topock delivery point allocation process and directing us to
formulate a system wide capacity allocation methodology. In March 2001, we filed
our proposed system-wide allocation methodology with FERC. In April 2001, the
February 2001 FERC order was appealed by a customer. Also in April 2001, two new
complaints were filed with FERC by our on-system customers alleging that we have
oversold firm system capacity, failed to maintain our facilities necessary to
meet the capacity needs of our firm shippers, and are abrogating the firm
contracts held by our shippers. In July 2001, a technical conference was
conducted by FERC in an Order No. 637 proceeding that addressed our system-wide
capacity allocation proposal, Order No. 637 compliance issues, and segmentation
of our system. A second technical conference is scheduled for the end of August
2001.
Two groups of our customers, those within California and those east of
California, have recently filed complaints with FERC. The filings involve a
dispute over the allocation of pipeline capacity. In July 2001, twelve parties
composed of California customers, natural gas producers, and natural gas
marketers, filed a complaint against us with FERC. The complaint alleges that
our full requirements contracts with our east of California customers should be
converted to contracts with specific volumetric entitlements, that we should be
required to expand our interstate pipeline system, and that firm shippers who
experience reductions in their nominated gas volumes should be awarded demand
charge credits. We filed our response to this complaint on August 2, 2001. In
July 2001, ten parties, most of which are east of California full-requirement
contract customers, filed a complaint against us with FERC, alleging that we
violated the Natural Gas Act of 1938 and breached our contractual obligations by
failing to expand our system in order to serve the needs of the full-requirement
contract shippers. The complainants have requested that FERC require us to show
cause why we should not be required to augment our system capacity. We filed our
response to this complaint on August 6, 2001, and requested that both groups'
complaints be consolidated for future proceedings.
Our current rate settlement establishes, among other things, base rates
through December 31, 2005. According to the settlement, our base rates began
escalating annually in 1998 as a result of inflationary factors. We have the
right to increase or decrease our base rates if changes in laws or regulations
result in increased or decreased costs in excess of $10 million a year. In
addition, all of our settling customers participate in risk sharing provisions
under our rate case settlement. Under these provisions, we are to receive cash
payments totaling $295 million for a portion of the risk we assumed from
capacity relinquishments by our customers at the end of 1997. The cash received
is deferred, and we recognize this deferral in revenues ratably over the risk
sharing period. As of June 30, 2001, we had unearned risk sharing revenues of
approximately $80 million and had $33 million remaining to be collected from
customers under this provision. If we remarket our relinquished capacity to
customers above certain dollar levels specified in the rate settlement, we may
be obligated to refund a portion of the excess to customers. Under this
provision, we refunded $14 million of 2000 revenues to customers during 2000 and
2001, and as of June 30, 2001, we established a refund obligation of
approximately $21 million. Both the risk and revenue sharing provisions of the
rate settlement extend through 2003. One unresolved matter in our current rate
settlement involves the application of our existing fuel recovery mechanism as
it relates to compression facilities that were abandoned. An appeal was filed in
the Fifth Circuit Court of Appeals and was recently transferred to the D.C.
Circuit Court of Appeals.
We will continue to evaluate the application of regulatory accounting
principles as there are changes in the regulatory and economic environment.
Things that may influence this assessment are:
- inability to recover cost increases due to rate caps and rate case
moratoriums;
- inability to recover capitalized costs, including an adequate return on
those costs through the ratemaking process;
- excess capacity;
- discounting rates in the markets we serve; and
- impacts of ongoing initiatives in, and deregulation of, the natural gas
industry.
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While we cannot predict with certainty the final outcome or timing of the
resolution of all of our rates and regulatory matters, the outcome of our
current re-contracting and capacity subscription efforts, or the impact 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.
7. 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 advanced $986 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 advanced $995 million.
In addition, we enter into transactions with other El Paso subsidiaries and
unconsolidated affiliates, including El Paso Merchant Energy, in the ordinary
course of our business to transport, sell and/or purchase natural gas. Services
provided by or to these affiliates are based on the same terms as
non-affiliates.
At June 30, 2001, we had accounts receivable from other related parties of
$12 million and $6 million at December 31, 2000. In addition, we had accounts
payable to other related parties of $3 million at June 30, 2001, versus $7
million at December 31, 2000.
8. 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.
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ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
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
Below are the operating results and an analysis of those results for the
quarters and six months ended June 30:
<Table>
<Caption>
QUARTER ENDED SIX MONTHS ENDED
----------------- -------------------
2001 2000 2001 2000
------- ------- -------- --------
(IN MILLIONS, EXCEPT VOLUME AMOUNTS)
Operating revenues................................ $ 138 $ 118 $ 279 $ 240
Operating expenses................................ (163) (68) (237) (134)
Other income, net................................. (2) -- (2) --
------ ------ ------ ------
Earnings (losses) before interest and income
taxes........................................ $ (27) $ 50 $ 40 $ 106
====== ====== ====== ======
Throughput volumes (BBtu/d)(1).................... 4,552 4,000 4,688 3,969
====== ====== ====== ======
</Table>
- ---------------
(1) BBtu/d means billion British thermal units per day.
Included in our results of operations for the quarter and six months ended
June 30, 2001, are merger-related costs of $94 million and $102 million
associated with El Paso Corporation's merger with The Coastal Corporation in
January 2001. These costs include employee severance, retention, and transition
costs, as well as business and operational integration costs, all of which are
related to the relocation of our headquarters from El Paso, Texas to Colorado
Springs, Colorado.
Second Quarter 2001 Compared to Second Quarter 2000
Operating revenues for the quarter ended June 30, 2001, were $20 million
higher than the same period in 2000. The increase was due to higher reservation
revenues as a result of a larger portion of our capacity earning maximum tariff
rates compared to the same period in 2000, and higher throughput from increased
deliveries to California and other western states.
Operating expenses for the quarter ended June 30, 2001, were $95 million
higher than the same period in 2000. The increase was primarily due to
merger-related costs incurred related to the relocation of our headquarters from
El Paso, Texas to Colorado Springs, Colorado as part of El Paso's merger with
Coastal.
Six Months Ended 2001 Compared to Six Months Ended 2000
Operating revenues for the six months ended June 30, 2001 were $39 million
higher than the same period in 2000. The increase was due to higher reservation
revenues as a result of a larger portion of our capacity earning maximum tariff
rates compared to the same period in 2000, and higher throughput from increased
deliveries to California and other western states.
Operating expenses for the six months ended June 30, 2001 were $103 million
higher than the same period in 2000. The increase was primarily due to
merger-related costs incurred related to the relocation of our headquarters as
part of El Paso's merger with Coastal.
10
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NON-AFFILIATED INTEREST AND DEBT EXPENSE
Non-affiliated interest and debt expense for the six months ended June 30,
2001, was $5 million lower than the same period in 2000 primarily due to net
decreased commercial paper balances in 2001, lower
short-term interest rates, and increased capitalized interest from higher
project expenditures.
AFFILIATED INTEREST INCOME, NET
Affiliated interest income, net for the quarter and six months ended June
30, 2001, was $2 million and $4 million lower than the same periods in 2000 due
to lower short-term interest rates and decreased average advances to El Paso in
2001 under our cash management program.
INCOME TAXES
The income tax benefit for the quarter ended June 30, 2001, was $12
million, resulting in an effective tax rate of 36 percent. Income tax expense
for the quarter ended June 30, 2000, was $18 million, resulting in an effective
tax rate of 39 percent. The income tax expenses for the six months ended June
30, 2001 and 2000, were $11 million and $37 million, resulting in effective tax
rates of 37 percent and 39 percent. Our effective tax rates were different than
the statutory rate of 35 percent in all periods primarily due to state income
taxes.
NEW ACCOUNTING PRONOUNCEMENTS NOT YET ADOPTED
See Item 1, Financial Statements, Note 8, which is incorporated herein by
reference.
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13
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 are 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 6, which is incorporated
herein by reference.
The eleven Carlsbad lawsuits are as follows: three were filed in district
court in Harris County, Texas (Diane Heady, et al v. El Paso Energy Corporation
(EPEC) and EPNG, filed September 7, 2000, and settled in March 2001; Richard
Heady, et al v. EPEC and EPNG, filed February 15, 2001, and settled in March
2001; and Geneva Smith, et al v. EPEC and EPNG, filed October 23, 2000), two
were filed in federal district court in Albuquerque, New Mexico (Dawson, as
Personal Representative of Kirsten Janay Sumler, v. EPEC and EPNG, filed
November 8, 2000, and Jennifer Smith, et al v. EPEC and EPNG, filed August 29,
2000, and settled in June 2001), and six were filed in state district court in
Carlsbad, New Mexico (Chapman, as Personal Representative of the Estate of Amy
Smith Heady, v. EPEC, EPNG, and John Cole, filed February 9, 2001; and Chapman,
as Personal Representative of the Estate of Dustin Wayne Smith, v. EPEC, EPNG
and John Cole; Chapman, as Personal Representative of the Estate of Terry Wayne
Smith, v. EPNG, EPEC, and John Cole; Green, as Personal Representative of the
Estate of Jesse Don Sumler, v. EPEC, EPNG, and John Cole; Rackley, as Personal
Representative of the Estate of Glenda Gail Sumler, v. EPEC, EPNG, and John
Cole; and Rackley, as Personal Representative of the Estate of Amanda Sumler
Smith, v. EPEC, EPNG, and John Cole, all filed March 16, 2001).
The alleged five probable violations of the regulations of the Department
of Transportation's Office of Pipeline Safety are: 1) failure to perform
appropriate tasks to prevent corrosion, with an associated proposed fine of
$500,000; 2) failure to investigate and minimize internal corrosion, with an
associated proposed fine of $1,000,000; 3) failure to consider unusual operating
and maintenance conditions and respond appropriately, with an associated
proposed fine of $500,000; 4) failure to follow company procedures, with an
associated proposed fine of $500,000; and 5) failure to maintain topographical
diagrams, with an associated proposed fine of $25,000.
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; 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
None.
ITEM 5. OTHER INFORMATION
None.
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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
------- -----------
*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 such 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 NATURAL GAS COMPANY
Date: August 10, 2001 /s/ GREG G. GRUBER
------------------------------------
Greg G. Gruber
Senior 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)
15
17
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>